3.0.3.2.1 Inservice Inspection Program (ISI) Program

Summary of Technical Information in the Application In LRA Section B.2.1, the applicant

described the ISI Program as an existing program that is consistent, with an exception, to the

GALL AMP XI.M1, "ASME Section X1 Inservice Inspection, Subsections IWB, IWC, and IWD."

The applicant stated that the program is in accordance with the requirements of ASME Code

Section XI, Division 1, Subsections IWA, IWB, IWC, IWD, IWE, IWF, IWL, 1998 Edition through

the 2000 Addenda, Mandatory Appendices, Inspection Program B of IWA-2432, and approved

ASME Code Cases.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. The staff reviewed the exception to determine whether the

AMP, with the exception, is adequate to manage the aging effects for which the LRA credits it.

The staff also confirmed that the applicant's program contains all of the elements of the GALL

Report. The staff conducted onsite interviews with the applicant to confirm these results.

The staff noted the applicant had indicated that the current scope of the program applies to the

ASME Code Section XI, 1998 Edition, inclusive of the 2000 Addenda. The program description

in the GALL AMP XI.M1 states that the GALL Report applies to inspection, repair, and

replacement activities for ASME Code components covered in the ASME Code

Section XI, 2001 Edition, inclusive of the 2003 Addenda. The staff noted that the applicant

clarified that the use of the ASME Code Section XI, 1998 Edition, inclusive of the 2000

Addenda, is consistent with the program description statement in GALL AMP XI.M1 because

the SOC on 10 CFR Part 54 clarifies that acceptable editions of the ASME Code Section XI are

those acceptable endorsed editions of the ASME Code Section XI up through the most recently

endorsed edition of the Code mentioned in 10 CFR 50.55a. The staff verified that the SOC on

10 CFR Part 54 does include this clarification, and that based on this clarification, use of the

ASME Code Section Xl, 1998 Edition, inclusive of the 2000 Addenda, is consistent with the

Code edition mentioned in the program description of GALL AMP XI.M1. Based on this review,

the staff finds the applicant's crediting of the ASME Code Section XI, 1998 Edition, inclusive of

the 2000 Addenda (for aging management) is consistent with the criteria in GALL AMP XI.M1.

In comparing the elements in the applicant's program to those in the GALL AMP XI.M1, the

staff noted the program elements in the applicant's AMP claim of consistency with the GALL

Report were consistent with the GALL AMP XI.M1 with the exception of program elements

aspects identified below. The staff determined that additional information was required to

complete its review.

The staff noted that the applicant had not identified the parameters or aging effect that the

program manages in either the "scope of program," "parameters monitored/inspected," or

"detection of aging effects" program elements for the AMP.

In RAI B.2.1-1, dated June 12, 2008, the staff requested that the applicant identify the

parameters or aging effects that are within the scope of and are managed by the ISI Program.

In the response to RAI B.2.1-1, dated July 14, 2008, the applicant stated that during the period

of extended operation, the ISI Program is credited to manage the following aging

effects/mechanisms for components within the reactor coolant system, including the RV and RV

internals:

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* Cracking due to stress corrosion cracking, intergranular stress corrosion cracking, and

irradiation-assisted stress corrosion cracking

* Loss of material due to general, pitting, and crevice corrosion

* Loss of fracture toughness due to thermal aging embrittlement of CASS components

The applicant also stated that loss of fracture toughness due to thermal aging embrittlement of

CASS components is managed via the detection of cracking and the monitoring of crack

growth.

The staff finds the applicant's response partially addressed the staff's inquiry raised in

RAI B.2.1-1, because the applicant has identified the aging effects managed by the ISI

Program. However, the staff noted that, in LRA Table 3.1.2-3, the applicant credits the ISI

Program to manage loss of fracture toughness of CASS recirculation pump thermal barriers.

The staff also noted that the thermal barriers in the pumps (which provide a Class 1 to Class 2

interface) may not actually be accessible for inspection. The staff further noted that UT

volumetric techniques, to date, cannot distinguish between UT signals that come from the

CASS microstructures, from those that result from crack and/or flaw indications in the CASS

material. Given that thermal aging of CASS can lead to a lower fracture toughness and

cracking, the staff issued a follow-up RAI.

In RAI B.2.1-1R, dated October 27, 2008, the staff requested that the applicant describe the

aging management of the primary recirculation pump CASS thermal barrier cover, specifically

addressing the aging management of cracking that could occur between the pump shaft cavity

and the reactor building closed-cooling water (RBCCW) cooling water cavity; and identify what

inspection techniques will be used to perform these inspections.

In the response to RAI B.2.1-1R, dated November 17, 2008, the applicant stated that the use of

the ISI Program to manage the aging effect of thermal aging embrittlement is consistent with

the GALL Report Item IV.C1-3, for Class 1 pump casings. The applicant further stated that PPL

identified the thermal barrier as a separate component of the pump, even though it is part of the

pump cover. The applicant further stated that the pump cover has a series of passages, created

by machining and drilling, to allow cooling water, from the RBCCW system, to be circulated

through the portion of the casing that surrounds the pump shaft, and that the portion of the

pump cover that contains these passages and performs the cooling function is called the

thermal barrier. The applicant also stated that since the thermal barrier is the same cast

component as the pump cover, the ISI Program is also credited for managing loss of fracture

toughness for the RCPB of the thermal barrier, which includes the portion of the pump cover

between the pump shaft cavity and the cooling water cavity of the RBCCW system.

The staff reviewed the applicant's response and noted that GALL Report Item IV.C1-3 states

that programs corresponding to the GALL AMP XI.M1 are acceptable programs to credit for

management of loss of fracture toughness in ASME Code Class 1 CASS pump casings. The

staff noted that, like the pump casings, the CASS pump covers also provide a portion of the

RCPB portions of the pumps. The staff finds that since the thermal barrier is part of the pump

cover, the use of this AMP to manage the aging effects of the pump cover is an acceptable

equivalency for managing the aging effect of the thermal barrier, which is normally not

accessible.

Based on the review, the staff finds the applicant's response to RAI B.2.1-1 R acceptable

because the applicant has adequately described the aging management of the primary

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recirculation pump CASS thermal barrier cover and has identified the inspection techniques it

will use to perform these inspections. On the basis that the thermal barrier is part of the

recirculation pump cover and that the GALL Report Item IV.C1-3 recommends that the ISI

Program be credited to manage reduction of fracture toughness of CASS recirculation pump

casings and covers, the staff also finds the applicant's basis for crediting the ISI program for

aging management of reduction of fracture toughness to be acceptable for these components.

Therefore, the staff's concerns described in RAI B.2.1-1R are resolved.

The staff noted that the license renewal basis document for the ISI Program indicates that the

criteria, in particular staff-approved BWRVIP reports, may be used in lieu of applicable ASME

Code Section XI ISI requirements for ASME Code Class 1, 2, or 3 components.

In RAI B.2.1-2, dated June 12, 2008, the staff requested that the applicant address the basis for

crediting the BWRVIP report criteria in lieu of the ASME Code Section XI requirements that are

implemented under the ISI Program and for requesting clarification whether or not proposals to

use staff-approved BWRVIP guideline criteria in lieu of applicable ASME Code Section XI

requirements will be submitted for staff approval.

In the response to RAI B.2.1-2, dated July 14, 2008, the applicant stated that all proposals to

use staff-approved BWRVIP guideline criteria in lieu of applicable ASME Code Section XI

requirements will be submitted for staff approval as part of the relief request submittals for each

10-year ISI Inspection Plan, in accordance with 10 CFR 50.55a.

Based on the review, the staff finds the applicant's response to RAI B.2.1-2 acceptable because

the applicant has confirmed that it will submit all proposals to use BWRVIP guidance criteria in

lieu of ASME Code Section XI requirements for staff approval as part of 10 CFR 50.55a(a)(3)

relief requests for the 10-year ISI Plans. Therefore, the staff's concern described in RAI B.2.1-2

is resolved.

The staff noted that the "corrective actions" program element discussion in the basis document

for the ISI Program indicates that the corrective actions for the program will be implemented

through implementation of the applicant's 10 CFR Part 50, Appendix B, Quality Assurance

Program.

In RAI B.2.1-3, dated June 12, 2008, the staff requested that the applicant clarify how

implementation of the SSES 10 CFR Part 50, Appendix B, Quality Assurance Program will

ensure that the corrective actions for ASME Code Class 1, 2, or 3 components will be

implemented, in accordance with applicable corrective actions in ASME Code Section XI Article

IWB-3000, or its sub-articles, paragraphs, or subparagraphs; in staff-approved ASME Code

Cases endorsed for use in the latest staff-issued version of RG 1.147; or through the staff's

relief request process defined in 10 CFR 50.55a.

In the response to RAI B.2.1-3, dated July 14, 2008, the applicant stated that the ISI Program

and governing procedures specify compliance with ASME Code Section XI corrective actions

for defects found in Class 1, 2, or 3 components and includes use of the acceptance standards

in the applicable sections of IWB-3000. The applicant also stated that the approved 10-Year ISI

plan describes the use of staff-approved ASME Code Cases endorsed for use in the latest

staff-issued version of RG 1.147 and when alternative standards are necessary, staff approval

is obtained through the NRC Relief Request process.

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The applicant further stated that the QA program specifies audits of the ISI Program every two

years, following established auditing procedures, and that these audits are conducted in

accordance with assessment basis documents that provide guidelines specific to the addressed

topic. The applicant clarified that the SSES audit guideline for the ISI Program explicitly

addresses compliance with 10 CFR 50.55a and related regulatory requirements and

commitments.

The staff reviewed the response and noted that the ISI Program specifies compliance with

ASME Code Section XI corrective actions, including acceptance standards in the applicable

sections of IWB-3000. Furthermore, the staff noted that the applicant performs QA audits of its

ISI Program every two years as required by the QA program, and verified that these QA audits

are performed to ensure the corrective actions for the program are implemented in accordance

with the corrective actions requirements in the ASME Code Section XI, staff-approved ASME

Code Cases, or in accordance with acceptable alternative correction action programs requested

and approved through the staff's 10 CFR 50.55a(a)(3) alternative ISI program process (i.e.,

through the staff's IS[ program relief request process).

Based on this review, the staff finds the applicant's response to RAI B.2.1-3 acceptable

because the applicant has implemented its QA program to ensure that the corrective actions

are in compliance with either 10 CFR 50.55a and applicable ASME Code Section XI corrective

action requirements, staff-approved ASME Code Cases, or acceptable alternative correction

action programs that are approved through the staff's 10 CFR 50.55a(a)(3) alternative ISI

program process, and because the applicant's program conforms to the recommendations in

the "corrective actions" program element in the GALL AMP XI.M1. Therefore, the staffs

concerns described in RAI B.2.1-3 are resolved.

Exception 1. The applicant has taken an exception to the "detection of aging effects"

program element in the GALL AMP XI.M1. In this exception, the applicant proposed to use

a risk-informed ISI methodology in lieu of the ASME Code Section XI tables for determining

the inspection samples of particular ASME Code Class welds.

The staff noted that use of risk-informed ISI methodologies and programs must be

requested and approved by the staff, in accordance with the staff's alternative program

relief request provisions in 10 CFR 50.55a(a)(3). Consistent with this requirement, the staff

makes the following statement in Chapter 1 of the GALL Report, Revision 1, Volume 2, for

proposals to use alternative programs in lieu of complying with applicable ASME Code

Section XI requirements:

If an applicant seeks relief from specific requirements of 10 CFR 50.55a

and Section XI of the ASME Code for the period of extended operation,

the applicant will need to re-apply for relief through the 10 CFR 50.55a

relief request process once the operating license for the facility has

been renewed.

The staff verified that the risk-informed ISI program for Units 1 and 2 was approved in a

staff-issued SE dated September 28, 2005. The staff also noted that the risk-informed ISI

program relief request was only approved for the 3rd 10-Year ISI interval for Units 1 and 2 and

that risk-informed ISI has yet to be proposed and approved for any of the 10-Year ISI intervals

within the scope of the period of extended operation for Units 1 and 2.

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In RAI B.2.1-5, dated June 12, 2008, the staff requested that the applicant commit to request

relief for use of risk-informed ISI within 12 months before the start of each 10-Year ISI interval,

if the applicant was planning on using a risk-informed ISI methodology for the 4 th 10-Year ISI

intervals or subsequent 10-Year ISI intervals for Units 1 and 2.

In the response to RAI B.2.1-5, dated July 14, 2008, the applicant revised the LRA to remove

the statement that identifies the use of risk-informed ISI as an exception to the GALL

AMP XI.M1. The applicant stated that since the use of risk-informed ISI at SSES must be

approved pursuant to 10 CFR 50.55a(a)(3), it is not considered to be an exception to the GALL

Report.

Based on its review, the staff finds the applicant's response to RAI B.2.1-5 acceptable because

the applicant has removed the use of risk-informed ISI as an exception to the GALL Report.

The staff determines that the applicant need not make an LRA commitment to request relief for

the use of risk-informed ISI in future intervals because the applicant is already committed to

seek approval for the use of risk-informed ISI, in accordance with 10 CFR 50.55a(a)(3).

Therefore, the staff's concern described in RAI B.2.1-5 is resolved.

Based on its review, the staff finds the applicant's ISI Program consistent with the program

elements of the GALL AMP XI.M1 and therefore is acceptable.

Operatingi Experience. The staff reviewed the applicant's OE basis document for safety

significant OE relevant to the aging management of ASME Code Class 1, 2, and 3 components.

The staff noted that the applicant only provided an overall OE summary statement in the

"operating experience" program element for the Inservice Inspection Program and did not

provide any examples of SSES specific and generic OE that would demonstrate that the AMP is

accomplishing its intended objective.

During the onsite review of this AMP, the staff determined the license renewal basis binder for

the Inservice Inspection Program included two CRs on circumferential flaw indications that were

recorded for the safe end welds of the Unit 1 N2J recirculation outlet nozzle and N1 B

recirculation inlet nozzle, resulting from previous augmented UT examinations performed on

these weld locations. The staff noted that the augmented inspections of these safe-end welds

are credited in accordance with the BWR Stress Corrosion Cracking Program, and are

implemented through augmented inspections performed under the ISI Program. The staff

determined that these CRs are significant because the applicable safe-end welds are ASME

Code Class 1 RCPB locations, and because a complete circumferential weld failure of the

nozzle safe-end components could result in a loss-of-coolant accident for the facility.

Thus, even though the staff verified that the applicant had listed the experience as relevant OE

for the BWR Stress Corrosion Cracking Program and had taken appropriate corrective actions

of the flaw indications by performing weld overlays of the components, the staff felt that the

applicant should have mentioned these flaw indications as relevant OE for the Inservice

Inspection Program, in the same manner that the CRs were listed as relevant OE for the BWR

Stress Corrosion Cracking Program. The staff also noted that the applicant did not specify

which staff-approved weld overlay methodology was applied to the repair of the flaw indications

(i.e., cracks) in the recirculation inlet and outlet nozzles.

In RAI B.2.1-4, part a, dated June 12, 2008, the staff requested that the applicant amend the

LRA to list these circumferential crack safe-end nozzle events as relevant OE for the "operating

experience" program element in ISI Program. In RAI B.2.1-4, part b, the staff requested that the

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applicant identify the particular weld overlay methodology (along with its reference basis) used

for the repairs of these safe-end nozzle indications, and clarify whether the overlay

methodology required a flaw tolerance evaluation of the flaw indications and; if so, explain

whether the analysis is a time-limited aging analysis (TLAA) for the application.

In the response to RAI B.2.1-4, part a, dated July 14, 2008, the applicant amended the LRA to

add the relevant experience of the ultrasonic inspection of the N1 B and N2J recirculation

nozzle-safe end welds that revealed indications which were determined to be flaws. These

welds are dissimilar metal welds and the indications were typical of SCC in Alloy 82/182 weld

material.

The applicant stated that the flaws were repaired using full-structural weld overlays, based on

the standard weld overlay defined in NUREG-0313, Revision 2, "Technical Report on Material

Selection and Processing Guidelines for BWR Coolant Pressure Boundary Piping," and the

weld overlay design was based on the requirements of ASME Code Section XI, IWB-3640 and

Code Case N-504-2. The applicant further stated that the weld overlays were applied using

Inconel 52, a material highly resistant to IGSCC, and that subsequent inspections performed in

2008, indicated no cracking in the weld overlays at the N1B and N2J nozzle-safe end weld

locations.

In response to part b, the applicant stated:

The flaws were repaired using full structural weld overlays that were designed

to bound all cracking conditions in the nozzle-safe end (NOZ-SE) weld area,

using the Standard Weld Overlay defined in NUREG-0313, Revision 2. The weld

overlay design was based on the requirements of ASME Section XI, IWB-3640

and Code Case N-504-2. The weld overlay design conservatively assumed the

flaws were through-wall and extended entirely around the pipe. No credit was

taken for any remaining ligament in the original NOZ-SE welds. The weld

overlays were applied using Inconel 52, a material highly resistant to IGSCC.

The overlay welding methods result in compressive loads on the area beneath

the overlay, thereby limiting the potential for further growth of the existing flaws.

The overlay design also included a crack initiation and growth analysis, which

demonstrated that the overlay will have a very low susceptibility for crack

initiation and growth during the life of repair, due to the high IGSCC-resistance of

the Inconel 52 alloy used in the overlay. Post-repair inspections assured the

quality of the repair, and ongoing inspection requirements for the overlay and the

underlying base material will identify any future degradation. The ASME Code

required no flaw tolerance evaluations to be performed as part of the design

basis for these repairs. There were no design basis analyses performed for the

weld overlay repairs that constitute a TLAA.

The staff reviewed the applicant's response and noted that specific plant OE was identified. The

applicant also provided the methodology used to perform the weld overlay repair. The staff

concurs that use of Inconel 52 as weld material will provide a very low susceptibility for crack

initiation and growth. Since no design basis analyses were performed and because ongoing

inspections will be performed to manage aging, the staff finds that there are no TLAAs to be

evaluated. However, Paragraph (g) of the Code Case mandates performance of an evaluation

of the flaws that are left in place as part of the alternative repair weld overlay technology

required by ASME Code.

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In follow-up RAI B.2.1-4R, dated October 27, 2008, the staff requested that the applicant

explain what it did to meet paragraph (g) of staff-approved ASME Code Case N-504-2, and

whether a flaw growth assessment was performed in accordance with the Code Case, to clarify

whether the flaw tolerance evaluation was effective for the remainder of the current licensed

lives of Units 1 and 2.

In the response to RAI B.2.1-4R, dated November 17, 2008, the applicant stated:

The weld overlay repairs for the SSES Unit 1 NI B and N2J recirculation

nozzle-to-safe-end welds were designed to the requirements of ASME

Section XI, IWB-3640 and Code Case N-504-2. Additionally, the repairs were

"full structural overlays," or Standard Weld Overlays, as defined in Section 4.4 of

NUREG-0313 Revision 2. As such, the overlay repairs were designed with the

assumption that the underlying flaw was entirely through-wall and completely

around the circumference of the component. No credit was taken for any

remaining ligament in the repair location. The design of the overlays provides the

necessary wall thickness to satisfy the flaw evaluation procedures of IWB-3640,

in accordance with Code Case N-504-2 paragraph (f)(1), and ensures the

structural adequacy of the component for all design loading conditions. This

design approach is consistent with hundreds of similar overlay repairs on BWR

recirculation nozzles and other IGSCC-susceptible components in the industry

since 1985.

When the overlays were designed, there was conclusive evidence from past and

present volumetric examinations that flaw growth had been arrested by the

application of the Mechanical Stress Improvement Process (MSIP) in 1993

(for the N2J) and 1995 (for the N1B). The volumetric examination data was

Reviewed by PPL, General Electric, and EPRI NDE experts. The consensus

conclusion was that the flaws had not grown since the application of MSIP. The

lack of flaw growth between the time of MSIP application and 2004 confirmed

that the residual compressive stress in the welds from MSIP, combined with the

benefits of HWC implementation in January 1999, had effectively eliminated

further IGSCC. It was also recognized that weld overlay repairs would impose

additional compressive stress in the welds. Therefore, it was concluded that

there would be no, or negligible, flaw growth due to IGSCC into the future.

Since there was no flaw growth projected to exceed the assumed flaw in the

overlay design, a flaw growth assessment and a flaw tolerance evaluation to

demonstrate the structural adequacy for a predicted flaw size at the end of a

specific operating interval (e.g., 40 years or 60 years) were not necessary. The

full structural overlay, as designed with an assumed through-wall crack around

the entire circumference in accordance with IWB-3640 and Code Case N-504-2,

will remain structurally adequate for the operating life of the plant.

Code Case N-504-2 paragraph (g)(2) requires a weld repair evaluation to

demonstrate that the requirements of IWB-3640 are satisfied for the design life

of the repair, considering potential flaw growth. As discussed above, the potential

flaw growth was determined to be zero, or negligible, such that the flaw assumed

in the overlay design remains bounding for the life of the component. Therefore,

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the calculations performed to determine the required design size and thickness

of the overlays serves as the evaluation required by Code Case N-504-2

paragraph (g)(2). Since those calculations are not dependent on any flaw growth

assessments, they are not time-limited aging analyses (TLAA).

The staff reviewed the applicant's response and Code Case N-504-2 paragraph (g)(2) and

determined that the Code Case requires an assumed flaw size and a flaw growth analysis for

the life of the plant. The staff noted that, for the applicant's full structural overlay repairs, the

applicant assumed that the underlying flaw was entirely through wall and around the

circumference, and no credit was taken for any remaining ligament. The staff also noted that

the applicant indicated that the structural overlays place the flaw in the original weld material in

compression, such that the growth of the flaw is mitigated from growing into the weld overlay

repair material.

Based on the review, the staff finds the applicant's response to RAI B.2.1-4R acceptable

because the applicant has provided an acceptable basis for concluding that structural overlays

are an acceptable alternative repair for ASME Code Class piping components and that the

overlays need not be within the scope of a TLAA, because they are implemented pursuant to

staff-approved ASME Code Case and because the overlays place the original flaw in

compression, such that the flaws are mitigated from growing into the overlay weld repair

material. Therefore, the staff's concern described in RAI B.2.1-4R is resolved.

The staff confirmed that the OE program element satisfies the criterion defined in the GALL

Report and the guidance found in SRP-LR Section A.1.2.3.10. Therefore, the staff finds this

program element acceptable.

UFSAR Supplement. The applicant provided the UFSAR supplement summary for the ISI

Program in LRA Section A1.2.23 and Commitment No. 1 in Table A-I. The staff reviewed this

section and determines that the UFSAR supplement summary description for the ISI Program

conforms to the staff's recommended UFSAR supplement SRP-LR Table 3.1-2. The staff finds

that the applicant has committed (Commitment No. 1) to ongoing implementation of its ISI

Program aging management of those in-scope components for which the AMP is credited and

linked this commitment to UFSAR Supplement Summary Section A. 1.2.23 for the ISI Program.

Based on this review, the staff finds that UFSAR Supplement Summary Section A. 1.2.23, when

coupled to LRA Commitment No. 1, provides an acceptable UFSAR supplement summary

description of the applicant's ISI Program.

The staff determines that the information in the UFSAR supplement is an adequate summary

description of the program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of the audit and review of the applicant's ISI Program and the

applicant's responses to the staff's RAIs, the staff finds all program elements consistent with

the GALL Report. The staff concludes that the applicant has demonstrated that effects of aging

will be adequately managed so that the intended function(s) will be maintained consistent with

the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also

reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate

summary description of the program, as required by 10 CFR 54.21(d) and therefore is

acceptable.

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3.0.3.2.2 BWR CRD Return Line Nozzle Program

Summary of Technical Information in the Application. In LRA Section B.2.6, the applicant

described the BWR Control Rod Drive (CRD) Return Line Nozzle Program as an existing

program that is consistent with an exception with GALL AMP XI.M6, "BWR Control Rod Drive

Return Line Nozzle." The applicant stated that the BWR CRD Return Line Nozzle Program

monitors the effects of cracking on the intended function of the CRD return line nozzle by

performing ISIs in conformance with the ASME Code, Section XI, Subsection IWB, Table IWB

2500-1.

Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the

GALL Report. The staff also confirmed that the plant program contains all of the elements of

the referenced the GALL Report. The staff conducted onsite interviews with the applicant to

confirm these results.

Exception 1. The BWR CRD Return Line Nozzle Program takes an exception to the

"acceptance criteria" program element to the GALL AMP XI.M6. In this exception the applicant

proposed to use a weld overlay methodology as an alternative corrective action repair

technique for flaws that are detected in the CRD return line nozzles or their pressure boundary

welds, including the CRD return line cap-to-nozzle welds. The staff noted the applicant

indicated that the weld overlay repair methodology will be implemented in accordance with the

requirements of 10 CFR 50.55a. The staff also noted that the applicant did not indicate that this

exception was applicable to the "corrective actions" program element for the BWR CRD Return

Line Nozzle Program.

In RAI B.2.6-1, dated July 23, 2008, the staff requested that the applicant commit to perform an

ASME Code Section XI repair of the leaking component, unless the weld overlay repair

methodology is submitted for staff review and approval and is granted in accordance with the

requirements of 10 CFR 50.55a(a)(3). The staff requested that the applicant provide the basis

for not applying the exception on the weld overlay methodology to the "corrective actions"

program element in the GALL AMP XI.M6.

In its response to RAI B.2.6-1, dated August 22, 2008, the applicant amended the LRA to revise

the exception to the "acceptance criteria" element of LRA Section B.2.6 and to add to

Commitment No. 6 the following:

PPL will implement weld overlay repairs in accordance with ASME Section XI

and NRC-approved Code Cases. If no NRC-approved Code Case exists for the

weld overlay, PPL will obtain NRC approval prior to implementing the repair in

accordance with 10 CFR 50.55a.

The applicant also provided a basis for not including an exception to the "corrective actions"

program element in the GALL AMP XI.M6, stating:

Any identified cracks or indications in the CRD return line nozzle are evaluated

under the rules of ASME Section XI. If the evaluation determines that a repair is

required, the design and implementation of the repair is governed by the SSES

ASME Section XI repair program, which requires the repair to meet Code

requirements unless relief is granted by the NRC. Furthermore, in accordance

with the SSES ISI Program, when cracks or indications are identified, a condition

report is written and, at that point, the SSES corrective action program also

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controls the resolution of the condition. Both the SSES ASME Section XI repair

program and the SSES corrective action program meet the requirements of 10

CFR 50, Appendix B.

The corrective action element of GALL XI.M6 includes the statement that "As

discussed in the appendix to this report, the staff finds the requirements of

10 CFR Part 50, Appendix B, acceptable to address the corrective actions."

Since the SSES ASME Section XI repair program and the SSES corrective

action program both meet the requirements of 10 CFR 50, Appendix B, the

corrective actions that would be taken in accordance with those programs are

consistent with GALL.

Based on the review, the staff finds the applicant's response to RAI B.2.6-1 acceptable because

the applicant has included a commitment for the implementation of weld overlays. The staff

notes that the applicant evaluates any identified cracks or indications in compliance with ASME

Code Section X1. The staff determines that the applicant's evaluation and repair is performed in

accordance with ASME Code Section Xl and along with the applicant's Corrective Action

Program, both meet the requirements of 10 CFR Part 50, Appendix B. Therefore, the staff's

concern described in RAI B.2.6.1 is resolved.

Based on the review, the staff finds the applicant's BWR CRD Return Line Nozzle Program

acceptable because it conforms to the recommended GALL AMP XI.M6, with an exception.

Operating Experience. The staff reviewed the applicant's OE basis document for safety

significant OE relevant to the aging management of CRD return line nozzle welds components.

The staff noted in the OE discussion, the applicant indicated that, prior to initial startup of

Units 1 and 2, the applicant cut and capped the CRD return line and the CRD return line nozzle

to eliminate CRD return line flow from the plant design.

The staff finds this statement acceptable because it conforms to the criterion in the

"preventative actions" program element of the GALL AMP XI.M6 which states that cutting and

capping of CRD return lines, without rerouting the return line flow, is an acceptable mitigation

technique for CRD return line nozzle programs.

The staff also noted that in the "operating experience" program element discussion for this

AMP, the applicant stated that it has been implementing the required ASME Code Section XI

inspections and the recommended augmented NUREG-0619, "BWR Feedwater Nozzle and

Control Rod Driven Return Line Nozzle Cracking" inspections. The applicant further stated that

to date, inspections of the capped CRD return line nozzles and the required surface

examination and volumetric examinations did not indicate any evidence of flaw indications in the

capped CRD return line nozzle inner blend radii or their associated ASME Code Class 1 welds.

The staff verified that the applicant had implemented the recommended augmented UT and/or

dye penetrate test (PT) inspections of the CRD return line cap-to-nozzle welds and nozzle inner

blend radii that required inspection during the 1 1th and 12th RFOs for Unit 1 (i e, U 111 RIO and

Ul 12RIO) and during the 9th RFO for Unit 2 (i.e., U209RIO). The staff verified that the

applicant's UT and PT examinations of these CRD return line nozzle locations did not indicate

the presence of any recordable flaw indications in the nozzle welds or inner blend radii.

Based on this review, the staff confirms that the applicant has been performing the augmented

UT and PT inspections of CRD return line nozzle inner blend radii and cap-to-nozzle welds in

accordance with its BWR CRD Return Line Nozzle Program. The staff further confirms that the

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applicant's program has been implemented in accordance with an augmentation of the ISI

Program requirements of ASME Code Section XI, as modified by the recommended augmented

inspection criteria in NUREG-0619. Based on this review, the staff finds that the RFO and IRs

provide acceptable confirmation that the applicant is implementing the recommended

augmented inspections and that currently, there are no SSES-specific OE for the CRD return

line nozzles or their associated pressure boundary welds, including the cap-to-nozzle welds.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and the guidance found in SRP-LR Section A.1.2.3.10. Therefore,

the staff finds this program element acceptable.

UFSAR Supplement. The applicant provided the UFSAR supplement summary for its BWR

CRD Return Line Nozzle Program in LRA Section A. 1.2.5 and Commitment No. 6 in Table A-I.

The staff reviewed this section and confirms that the UFSAR supplement summary description

for the BWR CRD Return Line Nozzle Program conforms to SRP-LR Table 3.1-2. The staff also

confirms that the applicant has committed (Commitment No. 6) to ongoing implementation of

the BWR CRD Return Line Nozzle Program for aging management of those SSES in-scope

components for which the AMP is credited and linked this commitment to UFSAR Supplement

Section A. 1.2.23 for this AMP. In response to RAI B.2.6-1, dated August 22, 2008, the applicant

revised Commitment No. 6 to state that if no staff-approved Code Case exists for the weld

overlay; PPL will obtain staff approval, prior to implementing the repair pursuant to

10 CFR 50.55a.

Based on this review, the staff finds that UFSAR Supplement Section A. 1.2.5, when coupled

with LRA Commitment No. 6, provides an acceptable UFSAR supplement summary description

of the applicant's BWR CRD Return Line Nozzle Program because it is consistent with the

UFSAR supplement summary description in the SRP-LR.

The staff determines that the information in the UFSAR supplement is an adequate summary

description of the program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of its review of the applicant's BWR CRD Return Line Nozzle

Program and the applicant's response to the staff's RAI, the staff finds all program elements

consistent with the GALL Report. In addition, the staff reviewed the exception and its

justification and determines that the AMP, with the exception, is adequate to manage the aging

effects for which the LRA credits it. The staff concludes that the applicant has demonstrated

that effects of aging will be adequately managed so that the intended function(s) will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and

concludes that it provides an adequate summary description of the program, as required by

10 CFR 54.21(d) and therefore is acceptable.

3.0.3.2.3 BWR Penetrations Program

Summary of Technical Information in the Application. In LRA Section B.2.8, the applicant

described the existing BWR Penetrations Program as consistent, with an exception, with the

GALL AMP XI.M8, "BWR Penetrations." The applicant stated that this program is used to

manage the effects of aging that are applicable to the RV penetration nozzle components and

their associated penetration welds. The applicant also stated that the exception is taken on the

"scope of program" program element in the GALL AMP XI.M8 to include the RV flange leakoff

penetration nozzle, vessel drain penetration nozzle, CRD penetration nozzles, and incore flux

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monitor penetration nozzles, as additional components that are within the scope of the

AMP (i.e. in addition to the standby liquid control (SLC) nozzles and RV instrument penetration

nozzles).

Staff Evaluation. During the audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. The staff reviewed the exception below to determine

whether the AMP, with the exception, is adequate to manage the aging effects for which the

LRA credits it. The staff also confirmed that the plant program contains all of the elements of

the referenced GALL Report. The staff conducted onsite interviews with the applicant to confirm

these results.

Exception. The staff noted that the applicant's program takes an exception to the "scope of

program" program element to the GALL AMP XI.M8. In this exception, the applicant identified

that the BWR Penetrations Program is credited for managing the effects of aging for the vessel

flange leakoff penetration, RV drain penetrations, CRD penetrations, and incore flux monitor

penetrations, in addition to the SLC/core AP nozzle and the RV instrumentation nozzles.

The applicant's BWR Penetrations Program is based on the recommended augmented

inspection and flaw evaluation guidelines found in BWRVIP Proprietary Topical Report

Nos. TR-107286 and TR-108695, "BWR Vessel and Internals Project, BWR Standby Liquid

Control System/Core Plate AP Inspection and Flaw Evaluation Guidelines (BWRVIP-27)" and

"BWR Vessel and Internals Project, Instrument Penetration Inspection and Flaw Evaluation

Guidelines (BWRVIP-49), " respectively. The staff approved BWRVIP-27 in a SE dated

December 20, 1999. The staff approved BWRVIP-49 in a SE dated September 1, 1999 and

noted that the scope of BWRVIP-27 is limited to SLC/core plate AP line nozzles and that the

scope of BWRVIP-49 is limited to BWR instrument penetrations.

In RAI B.2.8-1, dated July 23, 2008, the staff requested that the applicant provide its basis for

extending the scope of the GALL AMP XI.M8 to the RV flange leakoff line penetrations, RV

drain penetrations, CRD penetrations, and incore flux monitor penetrations, and for concluding

that the scope of either the BWRVIP-27 or BWRVIP-49 recommendations are applicable to the

materials of fabrication, design aspects, and fabrication processes used in the fabrication of

these additional penetrations.

In the response to RAI B.2.8-1, dated August 27, 2008, the applicant stated:

The basis for extending the scope of GALL AMP XI.M8 to the RV drain

penetrations, CRD penetrations, and incore flux monitor penetrations is that

GALL Chapter IV, item IV.A1-5 recommends crediting the BWR Penetrations

Program and the BWR Water Chemistry Program to manage cracking for these

components. In addition to the RV drain penetrations, CRD penetrations, and

incore flux monitor penetrations, which are named in GALL Item IV.A1-5, PPL

extended this program to the RV flange leak off penetrations. While these

penetrations are not named in GALL Item IV.AI-5, the BWR Penetrations

Program, as specifically defined for SSES in the program basis document, is an

appropriate program to credit for managing cracking for these penetrations.

The BWR Penetrations Program comparison to GALL, as stated in the program

basis document, includes the details for aging management for all penetrations

within the scope of the program. The program will inspect all in-scope

penetrations in accordance with the requirements of ASME Section XI,

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augmented by the recommendations of approved BWRVIP reports. Inspections

are scheduled in accordance with ASME Section XI, and examination results are

evaluated in accordance ASME Section Xl, IWB-3000. Acceptance of

components for continued service is in accordance with ASME Section XI and,

when applicable, BWRVIP guidance.

The SSES BWR Penetrations Program manages the CRD and flux monitor

penetrations in accordance with the NRC-approved guidance in BWRVIP-47-A

and BWRVIP-74-A. The RV flange leak off penetrations and the RV drain

penetrations are being managed by NRC-approved guidance in BWRVIP-74-A.

Thus, all penetrations are being managed by BWRVIP guidance that the NRC

has previously approved as adequate for the period of extended operation.

The staff reviewed the GALL Report, item IV.A1-5 and notes that it does include CRD stub

tubes, instrumentation, incore flux monitors and vessel drain line, and the recommended

AMP to manage the aging effects is GALL AMP XI.M8. The staff also reviewed BWRVIP-47-A,

and BWRVIP-74-A and concludes that these documents address CRD and flux monitor

penetrations and are applicable.

Based on the review, the staff finds the applicant's response to RAI B.2.8-1 acceptable because

the applicant has appropriately provided the basis for extending the scope of the GALL

AMP XI.M8 to the RV flange leakoff line penetrations, RV drain penetrations, CRD penetrations,

and incore flux monitor penetrations. Therefore, the staff's concern described in RAI B.2.8-1 is

resolved.

Review of License Renewal Applicant Action Items. In the SEs on Topical Report BWRVIP-27,

BWRVIP-47, BWRVIP-49, and BWRVIP-74 the staff issued the following renewal applicant

action items common to the staff's evaluations on the reports:

1. Applicants for license renewal will be responsible for describing any such

commitments and identifying how such commitments will be controlled. Any

deviations from the aging management programs within this BWRVIP report

described as necessary to manage the effects of aging during the period of

extended operation and to maintain the functionality of the reactor vessel

components or other information presented in the report, such as materials of

construction, will have to be identified by the renewal applicant and evaluated on a

plant-specific basis in accordance with 10 CFR 54.21(a)(3) and (c)(1).

The applicant provided both the staff's renewal applicant action item descriptions and its

responses to these actions items in LRA Appendix C, Tables BWRVIP-27-A, BWRVIP-47-A,

BWRVIP-49-A and BWRVIP-74-A. The applicant stated that the BWRVIP program

administratively requires (a licensee imposed requirement) the applicant to implement the

applicable BWRVIP inspection and flaw evaluation guidelines (including those in BWRVIP-27,

BWRVIP-47, BWRVIP-49, and BWRVIP-74) at SSES and that procedures administratively

mandate the applicant to write a justification for any deviations from the recommended criteria

in the applicable BWRVIP inspection and flaw evaluation guidelines. The applicant also stated it

has not yet identified any deviations from its implementation of the BWRVIP-27, BWRVIP-47,

BWRVIP-49, and BWRVIP-74 inspection and flaw evaluation guidelines, and commits to further

implementation of the staff-approved versions of the BWRVIP-27, BWRVIP-47, BWRVIP-49,

and BWRVIP-74 guidelines, in order to ensure that the aging effects applicable to the SLC/core

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plate AP nozzles, RV instrumentation nozzles and other RV nozzles within the scope of the

program will be managed, for the period of extended operation.

The staff confirms that the applicant has provided a commitment (Commitment No. 8) for

continued implementation of the recommended inspection and flaw evaluation guideline

recommendations, and that the commitment has been placed on UFSAR Supplement

Section A. 1.2.7. The staff finds that the applicant has adequately addressed the staff's renewal

applicant action item on BWRVIP-27, BWRVIP-47, BWRVIP-49, and BWRVIP-74 because it

clarified that SSES would not deviate from the recommended inspection and flaw evaluation

criteria, and because the applicant has committed to continued implementation of the guidelines

in these reports.

Based on this review, the staff concludes that the applicant has adequately addressed the

staff's first renewal applicant action item on BWRVIP-27, BWRVIP-47, BWRVIP-49, and

BWRVIP-74. Therefore, this renewal applicant action item is resolved.

2. Those applicants for license renewal referencing the BWRVIP-27 report for the

DP/SLC vessel penetration/nozzle and safe end extensions shall ensure that the

programs and activities specified as necessary in the BWRVIP-27 document are

summarily described in the UFSAR supplement. Those applicants for license

renewal referencing the BWRVIP-49 report for the instrument penetrations shall

insure that the programs and activities specified as necessary in the BWRVIP-49

report are summarily described in the UFSAR supplement. Those applicants for

license renewal referencing the BWRVIP-47 report for the lower plenum shall

insure that the programs and activities specified as necessary in the BWRVIP-47

report are summarily described in the UFSAR supplement. Those applicants for

license renewal referencing the BWRVIP-74 report for the RPV components shall

ensure that the programs and activities specified as necessary in the BWRVIP-74

report are summarily described in the UFSAR supplement

The applicant stated that LRA Section A includes the UFSAR supplement for the BWR

Penetrations Program. The staff confirmed that the applicant provides the UFSAR supplement

summary description for the BWR Penetrations Program in UFSAR Supplement

Section A.1.2.7. The staff also confirmed that LRA Section A.1.2.7 includes BWRVIP-27 and

BWRVIP-49. However, in response to RAI B.2.8-1, dated August 27, 2008, the applicant added

BWRVIP-47 and BWRVIP-74, which are not included in the UFSAR summary description. In a

follow-up RAI B.2.8-1R, dated October 17, 2008, the staff requested that the applicant address

this issue.

In the response to RAI B.2.8-1 R, dated November 11, 2008, the applicant revised the LRA to

include BWRVIP-47-A and BWRVIP-74-A in the descriptions of the BWR Penetrations Program

in LRA Sections A.1.2.7 and B.2.8. The applicant revised the last sentences of A.1.2.7 and

program description of B.2.7 as follows:

BWRVIP-27-A report addresses the standby liquid control system nozzle or housing, the

BWRVIP-47-A report addresses the control rod drive and flux monitor penetrations in

the lower plenum, the BWRVIP-49-A report provides guidelines for instrument

penetrations, and the BWRVIP-74-A report addresses the reactor vessel flange leakoff

penetrations and the reactor vessel drain penetrations.

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The staff reviewed the applicant response and notes that the applicant has appropriately

identified BWRVIP-47-A and BWRVIP-74-A in the program description and in the UFSAR

supplement. Based on this review, the staff finds the applicant response acceptable and

concludes that the applicant has adequately addressed the staff's second renewal applicant

action item on BWRVIP-27, BWR-47, BWRVIP-49 and BWRVIP-74. Therefore, this renewal

applicant action item is resolved.

3. Those applicants for license renewal referencing BWRVIP-27 for the AP/SLC

vessel penetration/nozzle and safe end extensions shall ensure that the inspection

strategy described in the BWRVIP-27 report does not conflict or result in any

changes to their technical specifications. Those applicants for license renewal

referencing BWRVIP-49 for the instrument penetrations shall ensure that the

inspection strategy described in the BWRVIP-49 document does not conflict or

result in any changes to their technical specifications. Those applicants for license

renewal referencing BWRVIP-47 for the lower plenum shall ensure that the

inspection strategy described in the BWRVIP-47 document does not conflict or

result in any changes to their technical specifications. Those applicants for license

renewal referencing the BWRVIP-74 report for the RPV components shall ensure

that the inspection strategy described in the BWRVIP-74 report does not conflict or

result in any changes to their technical specifications. If technical specification

changes do result, then the applicant should ensure that those changes are

included in its application for license renewal.

The applicant stated that its implementation of the inspection strategies in BWRVIP-27,

BWRVIP-47 and BWRVIP-49 will not result in the need for any changes of the TS for either

Unit 1 or Unit 2. The staff reviewed the TSs for Units 1 and 2 and confirmed that, while the

methods in BWRVIP-27, BWRVIP-47, and BWRVIP-49 may constitute alternative

staff-approved inspection guidelines for the ASME Code Class 1 RV penetration nozzle welds,

the TSs for SSES do not include any requirements to implement the ASME Code Section XI ISI

programs, neither do they include BWRVIP-27, BWRVIP-47 or BWRVIP-49 augmented

inspection program criteria. The staff also confirmed that the applicant's TSs are derived from

operational, surveillance, and administrative control-based requirements and that, instead, the

ISI Program requirements and BWRVIP-27, BWRVIP-47, and BWRVIP-49 augmented

inspection process are implemented through the applicant's ASME Code Section XI ISI

program, in accordance with 10 CFR 50.55a. Thus, based on this review, the staff concludes

that the applicant has provided an adequate basis for concluding that its implementation of the

guidelines in BWRVIP-27, BWRVIP-47, and BWRVIP-49 will not conflict with or result in any

necessary changes in the SSES TSs. Based on this review, the staff concludes that the

applicant has adequately addressed the staff's third renewal applicant action item on BWRVIP27, BWRVIP-47, and BWRVIP-49. Therefore, this renewal applicant action item is resolved.

In the SE for BWRVIP-27, the staff included an additional fourth license renewal applicant

action item. In this action item, the staff stated that BWR applicants referencing the BWRVIP27 report should identify and evaluate the projected fatigue cumulative usage factors (CUFs) for

their SLC/core plate AP nozzles as a potential TLAA for the application. The applicant stated

that the only analysis on the SLC/core plate AP nozzles that meets the definition of a TLAA is

the CUF analysis for the SLC/core plate AP nozzles and that the TLAA analysis for these

nozzle components is provided in LRA Section 4.3.1. The staff confirmed that the applicant has

included its metal fatigue CUF analysis for the N-10 SLC/core plate AP nozzles in LRA

Section 4.3.1 and that LRA Table 4.3-2 includes both the design basis CUFs and the 60-year

projected CUFs for N-10 SLC/core plate AP nozzles. Based on this review, the staff finds that

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the applicant has met this renewal applicant action item because, consistent with the action

item, the applicant has identified the CUF analysis for these nozzles as a TLAA, and has

provided this TLAA in LRA Section 4.3.1. The staff evaluates this TLAA in SER Section 4.3.1.

Therefore, this renewal applicant action item is resolved.

Based on the review of the exception, and resolution of the related RAI, the staff finds the BWR

Penetrations Program consistent with the program elements of GALL AMP XI.M8, with an

exception and therefore is acceptable.

Operatingq Experience. The staff reviewed the applicant's "operating experience" program

element discussions in the BWR Penetrations Program and in the license renewal basis

document for this AMP. The staff noted that the "operating experience" program element in the

license renewal basis document indicated that the applicant had reviewed the last five Inservice

Inspection Outage Summary Reports for Units 1 and 2 and that the ISIs or augmented ISIs

performed on the penetration nozzles did not identify any relevant flaw indications. The staff

confirmed that, although the applicant has not yet identified any relevant indications for the

penetrations within the scope of this AMP, it has recorded flaw indications and initiated

appropriate CR action requests on flaw indications identified in some of the RV internal

components. These actions are part of the applicant's in-vessel visual inspections performed on

its BWR RV internals, and which is another BWRVIP Report-based AMP.

The staff finds the applicant's "operating experience" program element acceptable because the

applicant's augmented inspection process used to implement the BWRVIP-based augmented

inspections of the RV penetration nozzles and RV internals components has actual detected

and recordable RV internals indications that are within the scope of the BWR Vessel Internals

Program. This demonstrates that the applicant's BWRVIP-based augmented inspection

process for its RV penetration nozzles and RV internal components is effective. The staff also

finds the OE acceptable because the applicant has committed (Commitment No. 8) to

continued implementation of the BWR Penetration Program and; implementation of the

guidelines in BWRVIP-27 for SLC/core plate AP nozzles, the BWRVIP-47 for CRD and flux

monitor penetrations in the lower plenum, the BWRVIP-49 for RV instrument penetration

nozzles, and the BWRVIP-74 for RV flange leakoff penetrations and the RV drain penetrations.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and the guidance found in SRP-LR Section A. 1.2.3.10. Therefore,

the staff finds this program element acceptable.

UFSAR Supplement. The applicant provided the UFSAR supplement summary for the BWR

Penetrations Program in LRA Section A.1.2.7 and Commitment No. 8 in Table A-I. The staff

reviewed this section and notes that in response to RAI B.2-1 R, dated November 11, 2008, the

applicant revised the UFSAR supplement to add BWRVIP-49 and BWRVIP-74. The staff

confirms that that applicant has committed (Commitment No. 8) to continue implementation of

the recommended inspection and flaw evaluation guidelines. The staff finds that the applicant's

UFSAR supplement summary description for the BWR Penetrations Program, with this revision,

conforms to the staff's recommended UFSAR supplement in SRP-LR Table 3.1-2.

Based on this review, the staff finds that UFSAR Supplement Section A. 1.2.7, when coupled

with Commitment No. 8, provides an acceptable UFSAR supplement summary description of

the applicant's BWR Penetrations Program because it is consistent with the UFSAR

supplement summary description in the SRP-LR.

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The staff determines that the information in the UFSAR supplement is an adequate summary

description of the program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of its review of the applicant's BWR Penetrations Program and the

applicant's response to the staff RAls, the staff determines that those program elements for

which the applicant claimed consistency with the GALL Report are consistent. In addition, the

staff reviewed the exception and its justification and determines that the AMP, with the

exception, is adequate to manage the aging effects for which the LRA credits it. The staff

concludes that the applicant has demonstrated that effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the

UFSAR supplement for this AMP and concludes that it provides an adequate summary

description of the program, as required by 10 CFR 54.21 (d) and therefore is acceptable.

3.0.3.2.4 BWR Vessel Internals Program

Summary of Technical Information in the Application. In LRA Section B.2.9, the applicant

described the existing BWR Vessel Internals Program as consistent, with an enhancement, with

the GALL AMP XI.M9, "BWR Vessel Internals." The applicant stated that this program is used

to manage cracking, loss of material, and reduction of fracture toughness for various

subcomponents of the RV internals.

Staff Evaluation. During the audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. The staff reviewed the enhancement to determine whether

the AMP, with the enhancement, is adequate to manage the aging effects for which the LRA

credits it. The staff noted that the program elements in the applicant's AMP claim of consistency

with the GALL Report were consistent with the GALL AMP XI.M9, with the exception of the

issue identified below that the staff determined required additional clarification. The staff also

confirmed that the plant program contains all of the elements of the referenced the GALL

Report. The staff conducted onsite interviews with the applicant to confirm these results.

The staff noted that the scope of the BWR Vessel Internals Program includes Topical Report

BWRVIP-76, which has been approved by the staff and which provides the BWRVIP's

recommended inspection and flaw evaluation guidelines for BWR core shrouds. BWRVIP-76,

Appendix C (a) provides guidance to evaluate structural integrity of the core shroud welds

exposed to neutron radiation during plant operation, (b) discusses the use of generic fracture

mechanics analyses for establishing inspection intervals for core shroud welds containing

cracks, and (c) provides the notch fracture toughness values for irradiated stainless steel

materials. The data in this appendix suggest that the fracture toughness values for stainless

steel materials tends to decrease with increasing exposure to neutron fluences greater than

1 E21 n/cm2 (E> 1 MeV). In August 2006, the BWRVIP issued staff-approved Topical Report

No. BWRVIP-100-A, "Updated Assessment of the Fracture Toughness of Irradiated Stainless

Steel for BWR Core Shrouds," which discussed and provided updated fracture toughness

results for irradiated stainless steel materials. The BWRVIP-100-A report identified that the

fracture toughness values for irradiated stainless steel material may actually be lower than

those previously documented in the staff-approved version of BWRVIP-76.

In RAI B.2.9-3, dated July 23, 2008, the staff requested that the applicant clarify whether the

results and recommendations in the staff-approved BWRVIP-100-A are within the scope of the

BWR Vessel Internals Program and; if yes, clarify how the recommendations in BWRVIP-100-A

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will be used in conjunction with the recommendations in BWRVIP-76 for evaluations of cracking

in core shrouds.

In the response to RAI B.2.9-3, dated August 27, 2008, the applicant stated that LRA

Sections A. 1.2.10 and B.2.9 state that the BWR Vessel Internals Program includes inspection

and flaw evaluation that conforms to the guidelines of applicable and staff-approved BWRVIP

reports. As such, BWRVIP-100-A is currently within the scope of the BWR Vessel Internals

Program. Under this AMP, the applicant is committed to following the current, staff-approved

BWRVIP guidance for managing cracking of the core shroud, during the period of extended

operation.

The applicant also stated that the current, staff-approved BWRVIP guidance for evaluating

flaws in the high-fluence core shroud welds is documented in BWRVIP-76, BWRVIP-99, and

BWRVIP-100-A and requires the use of the updated fracture toughness results for irradiated

stainless steel materials from BWRVIP-1 00-A. The applicant further stated that until

BWRVIP-76 Appendix C is revised as recommended in BWRVIP-100-A, only those shroud

welds that have fluences less than 1 E21 n/cm 2 will have their inspection intervals determined

using BWRVIP- 76, Table 2-1. For shroud welds that have fluences greater than 1 E21 n/cm2,

the inspection intervals will be determined on a case specific basis, in accordance with the

guidance provided in BWRVIP-99 and BWRVIP-100-A.

Based on the review, the staff finds the applicant's response to RAI B.2.9-3 acceptable because

the applicant has adequately clarified its use of the latest staff approved BWRVIP-1 OOA for core

shroud welds that have fluences greater than 1E21 n/cm 2 and BWRVIP-76 for core shroud

welds that have fluences less than 1 E21 n/cm 2. The staff determines that the applicant has

satisfactorily described how it proposes to use BWRVIP-76 and BWRVIP-100-A in conjunction

with each other and has committed to follow the current staff-approved BWRVIP guidance to

manage cracking of core shroud welds. Therefore, the staff's concern described in RAI B.2.9-3

is resolved.

Separately, during the TLAA review, the staff found that irradiation assisted stress corrosion

cracking (IASCC) was not discussed in LRA Section 4.0, but was mentioned in LRA Appendix C

regarding SSES's responses to BWRVIP report application action items. Therefore, RAI 4.7.3-2

was issued to request SSES (1) to address IASCC in austenitic stainless steel RPV internals in

the TLAA section to build the connection between LRA Section 4.0 and LRA Appendix C, and

(2) to make a commitment to address all BWRVIP-76 (LR) requirements and conditions as

modified by the NRC SER on this report, to be issued after the NRC review of BWRVIP-76 (LR)

is completed.

Regarding Item (1) of RAI 4.7.3-2, the staff found out later that the issue has been addressed

thoroughly in Section 3.0.3.2.4. Therefore, there is no longer a need to address IASCC in

Section 4.0. Regarding Item (2) of RAI 4.7.3-2, the applicant stated that in addition to the

actions implemented under LRA AMP B.2.9, specific requirements imposed for certain

components for license renewal were addressed in LRA Appendix C. Further, a new

commitment (Commitment No. 56) was added to LRA Table A-1 to address any future

conditions, requirements, or limitations imposed by the NRC's SER for BWRVIP-76 (LR).

Hence, RAI 4.7.3-2 is resolved.

In the review of the program basis document, the staff determined that the applicant is crediting

the BWR Vessel Internals Program to manage the aging effects of reduction in fracture

toughness for core shroud, core plate, top-guide components, orificed and peripheral fuel

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support pieces, CRD tubes, jet pump assemblies and their subcomponents, and incore dry

tubes from the source range and intermediate range monitors. The staff has confirmed that the

program credits the augmented inspection and flaw evaluation criteria in staff-approved

BWRVIP topical reports as the basis for managing the aging effects applicable to SSES RV

and RV internal components. Loss (reduction) of fracture toughness is not an aging effect "per

se," but, instead, refers to a change that may occur in the fracture toughness material property

over time.

In RAI B.2.9-4, dated July 23, 2008, the staff requested that the applicant explain how the

recommended BWRVIP report guidelines within the scope of the BWR Vessel Internals

Program BWRVIP, will accomplish adequate management of reduction of fracture toughness in

these RV internal components. The staff also requested that the applicant justify why the

applicable BWRVIP inspection and flaw evaluation guidelines for these RV internal components

are considered to be capable of managing reduction of fracture toughness in the components,

and clarify the methodology or methodologies in these reports credited for management of this

aging effect.

In the response to RAI B.2.9-4, dated August 27, 2008, the applicant stated that the orificed

fuel support pieces are CASS, and reduction of fracture toughness is managed by the Thermal

Aging and Neutron Embrittlement of Cast Austenitic Stainless Steel (CASS) Program, and not

by the BWR Vessel Internals Program, as shown in LRA Table 3.1.2-2.

The applicant further stated:

The remaining reactor vessel (RV) internals components are the core shroud,

core plate, top guide, fuel support pieces (peripheral), control rod guide tubes, jet

pump assemblies, and incore dry tubes. These components are all addressed in

specific BWRVIP reports. The applicable BWRVIP inspection and flaw

evaluation guidelines for these RV internal components are considered to be

capable of managing ROFT because the inspections are designed to detect

cracking, and, if cracking is detected, the inspection intervals will be adjusted

based on crack growth rates that are determined by evaluations that include the

effects of ROFT. The examination methods in the BWRVIP reports include

ultrasonic examination and visual examination of the RV internal components,

when accessible, for the detection of cracks. These same methods are credited

for managing ROFT, since ROFT is managed as cracking is identified,

evaluated, and monitored in components with fluence values exceeding the

threshold for ROFT.

Based on the review, the staff finds the applicant's response to RAI B.2.9-4 acceptable because

the applicant has adequately explained that the BWRVIP guidelines provide examination

methods and evaluation techniques to detect cracking, and inspection intervals are adjusted

based on the results of the inspection. The staff finds that the guidelines will also manage

reduction of fracture toughness, since fluence is one of the key factors affecting the crack

growth rate, which increases as fluence increases the yield strength of the material (i.e.,

reduces fracture toughness). Therefore, the staff's concern described in RAI B.2.9-4 is

resolved.

The staff noted that BWRVIP-76, Appendix C provides guidance to evaluate structural integrity

of the core shroud welds which is affected by the exposure to neutron radiation during the

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service. In this appendix, the BWRVIP discusses the use of generic fracture mechanics

analyses for establishing inspection intervals for the core shroud welds with cracks, and

previous data suggests that the fracture toughness values tend to decrease when stainless

steel materials are exposed to neutron fluence. BWRVIP-76, Appendix C provides notch

toughness values which can be used for irradiated stainless steel materials.

In RAI B.2.9-5, dated July 23, 2008, the staff requested that the applicant clarify whether the

results and recommendations in the staff-approved BWRVIP-100-A are within the scope of the

BWR Vessel Internals Program and; if yes, clarify how the recommendations in BWRVIP-100-A

will be used in conjunction with the recommendations in BWRVIP-76 for evaluations of cracking

in core shrouds.

In the response to RAI B.2.9-5, dated August 27, 2008, the applicant stated that its response to

RAI B.2.9-3, above, addresses RAI B.2.9-5. The staff acknowledges that RAI B.2.9-3 requested

the same information as RAI B.2.9-5 and finds that the applicant's response to RAI B.2.9-3 also

is acceptable for RAI B.2.9-5. Therefore, the staff's concern described in RAI B.2.9-5 is

resolved.

Enhancement 1. The staff noted that the applicant's program indicated that the "scope of

program" program element for the BWR Vessel Internals Program will be enhanced to require

augmented inspection of the SSES top guide grid beams and beam-to-beam crevice slots. The

augmented inspections of these components will include completion of five percent of the total

population of grid beams and beam-to-beam crevice slots within six years of entering the period

of extended operation, with completion of an additional five percent within 12 years of entering

the period of extended operation. The applicant stated that the scope of inspections will focus

on those grid beams and beam-to-beam crevice slots with neutron fluences projected to be

greater than 5.0 x 1020 n/cm2 (E > 1.0 MeV) at 60 years.

The staff noted that GALL AMP XI.M9 indicates that the industry's augmented inspection and

flaw evaluation guidelines for BWR top guides and their subcomponents are provided in Topical

Report No. BWRVIP-26. The staff issued its SE on BWRVIP-26 in a letter to the BWRVIP

owners group dated December 7, 2000. In this letter, the staff endorsed the BWRVIP owners

group's recommended augmented inspection for BWR top guides and their subcomponents.

However, these augmented inspection guidelines did not provide any recommendations for

BWR top guide grid beam locations and beam-to-beam crevice slots. In the staff's updated

GALL Report guidance, as described in the GALL AMP XI.M9, the staff took the position that

augmented inspections should be performed on the top guide grid beam and beam-to-beam

crevice slots to address the potential for IASCC to occur in these top guide locations.

Specifically, the staff makes the following recommendation in GALL AMP XI.M9:

Alternatively, if the neutron fluence for the limiting top guide location is projected

to exceed the threshold for IASCC after entering the period of extended

operation, inspect 5% of the top guide locations (EVT-1) within six years after the

date projected for exceeding the threshold. An additional 5% of the top guide

locations will be inspected within twelve years after the date projected for

exceeding the threshold.

The staff's recommendation-in the GALL AMP XI.M9 is predicated on the fact that an

applicant for license renewal of its BWR facility has not yet detected any signs of cracking

in the top guide grid beams and beam-to-beam crevice locations. The staff noted that the

applicant's proposed enhancement calling for augmented inspections of the SSES top

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guide grid beam and beam-to beam locations conforms to the recommendations in GALL

AMP XI.M9, as long as there has not been any evidence of cracking in these top guide

locations.

In RAI B.2.9-1, dated June 12, 2008, the staff requested that the applicant clarify whether it had

performed any augmented inspections of the top guide grid beam and beam-to-beam crevice

slot locations to date and; if so, summarize the inspection results of the augmented

examinations performed on these top guide components.

In its response to RAI B.2.9-1, dated July 14, 2008, the applicant stated:

The Unit 1 top guide beam and beam-to-beam crevice slot locations were

inspected in 2004 during the thirteenth refueling outage. Twelve fuel cell

locations were examined using the VT-3 inspection method. The Unit 1 top guide

was inspected again in 2008. At that time, the top guide beam and beam-tobeam crevice slots at one cell location were inspected using the EVT- 1

inspection method. No recordable indications were found in either Unit 1

inspection.

The Unit 2 top guide beam and beam-to-beam crevice slot locations at twentyone fuel cell locations were inspected in the Unit 2 eleventh refueling outage in

2003 using the VT-3 inspection method. In 2007, four additional fuel cell

locations in the Unit 2 vessel were inspected using the VT-3 inspection method.

No recordable indications were found in either Unit 2 inspection.

Based on the review, the staff finds the applicant's response to RAI B.2.9-1 acceptable because

the applicant has clarified that it has performed augmented inspections of the top guide grid

beam and beam-to-beam crevice slot locations and no recordable indications were found.

Therefore, the staff's concern described in RAI B.2.9-1 is resolved.

On the basis that the applicant has performed inspections of the top guide locations using

appropriate inspection techniques, and no recordable indications were found, the staff finds the

enhancement acceptable, because the implementation of the enhancement will make the

applicant's program consistent with the GALL AMP XI.M9. The staff verified that the applicant

has incorporated its enhancement of the BWR Vessel Internals Program in Commitment No. 9

in LRA Table A-1 and was placed on UFSAR Supplement Section A.1.2.10.

However, in response to RAI 4.3-4, dated November 25, 2008, the applicant stated that since

the submittal of the LRA, the BWR Vessel Internals Program has been revised to include

requirements to inspect the top guide. The applicant further stated that the BWR Vessel

Internals Program now requires that at least 10 percent of the grid beam cells containing control

rod drives and/or blades will be inspected every twelve years, with at least five percent of the

inspections performed within the first six years of each twelve year interval. The applicant also

stated that the top guide locations to be inspected are those subject to neutron fluence levels

that exceed the IASCC threshold of 5.OE+20 n/cm 2, and that the inspections will be performed

using the enhanced visual inspection technique, EVT-1.

Furthermore, in response to RAI 4.3-4, the applicant stated that PPL will continue to perform

inspections on at least 10 percent of the top guide locations, every twelve years, during the

period of extended operation. The applicant accordingly revised the LRA to delete the

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enhancement from LRA Section B.2.9, UFSAR Supplement Section A.1.2.10, and LRA

Table A-1 (Commitment No. 9).

In a teleconference held on December 18, 2008, the staff discussed with the applicant, the

degree of detail needed for implementing augmented inspections of top guide grid-to-beam and

beam-to-beam locations. In this teleconference, the staff established that the applicant would

need to commit to augmented inspections of the top guide locations or amend its response to

RAI 4.3-4. Any amended response to RAI 4.3-4 should discuss the corrective actions and

sample expansion criteria that the applicant would implement, if augmented inspections of the

top guide grid-to-beam and beam-to-beam locations detected cracking in the components.

In a letter dated December 29, 2008, the applicant submitted a supplemental response

amending the LRA to include a commitment for augmented inspections of the top guide

grid-to-beam and beam-to-beam locations, in UFSAR Supplement A.1.2.10. Specifically, the

applicant committed to the following activities for the top guide grid-to-beam and beam-to-beam

locations:

PPL will continue to perform inspections on at least 10% of the top guide grid

beam cells containing control rod drives/blades every twelve years during the

period of extended operation, with at least 5% of the inspections being

performed within the first six years of each twelve year interval. The top guide

locations to be inspected are those subject to neutron fluence levels that exceed

the IASCC threshold of 5.OE+20 n/cm2 . The inspections will be performed using the enhanced visual inspection technique, EVT-1.

The staff finds that the applicant's amendment for augmented inspection of the top guide

grid-to-beam and beam-to-beam locations acceptable because the applicant's Commitment

No. 9 for augmented inspection of these top guide locations is consistent with the staff's

recommended augmented inspection criteria for the locations in the "detection of aging effects"

program element in GALL AMP XI.M9.

Review of License Renewal Applicant Action Items. LRA Appendix C provides the applicant's

responses to the staff's renewal applicant action items on the BWRVIP-based reports within the

scope of the BWR Vessel Internals Program. The applicant's program also includes an

enhancement to perform augmented inspections of the SSES top guide grid beam and beamto-beam crevice slots. The staff evaluates the applicant's responses to the staff's renewal

applicant action items later in this section.

The staff's license renewal applicant action items for the BWRVIP Topical Reports within the

scope of a BWR Vessel Internals Program are provided in specific staff SEs issued to the

BWRVIP with respect to their inspection and flaw evaluation guidelines.

The following table summarizes the topical reports within the scope of the applicant's BWR

Vessel Internals Program and the staff's SEs issued on these topical reports.

Component BWRVIP Todical NRC SER'Date, ,SER, Accession

Report Refer'ence ___________ Nuber

RV Components BWRVIP-74-A 10/18/01 ML012920549

Core Shroud BWRVIP-38 03/01/01 ML010600211

Support and

Attachments

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Core Shroud BWRVIP-76

Core Support Plate BWRVIP-25 12/07/00 ML003775989

Core Spray Lines BWRVIP-18 12/07/00 ML003775973

and Spargers

Top Guide BWRVIP-26 12/07/00 ML003776110

Jet Pump BWRVIP-41 05/01/01 ML011310322

Assemblies

RV Lower Plenum BWRVIP-47 12/07/00 ML003775765

Components

The staff confirmed that the applicant has responded to the staff's renewal applicant actions

items on these BWRVIP reports in LRA Appendix C. The staff noted that the staff's first three

renewal applicant action items all dealt with: (a) identifying any deviations not conforming to the

BWRVIP's recommended guidelines in these topical reports, (b) identifying any TSs that may

require license amendments as a result implementing the BWRVIP guideline

recommendations, pursuant to 10 CFR 50.90, and (c) ensuring the UFSAR supplement for the

BWR Vessel Internals Program had incorporated an appropriate UFSAR supplement summary

description for the BWRVIP recommended activities.

The staff evaluated the applicant's responses to the first three renewal applicant action items.

With respect to the applicant's responses, the staff finds that the applicant had, in all cases,

properly identified the renewal applicant action items and provided an acceptable basis for

responding to and resolving them.

Beyond the first three renewal applicant action items, the staff finds that the applicant had in all

cases properly identified the renewal applicant action items and provided an acceptable basis

for responding to and resolving them, with the following exceptions:

In renewal applicant action item No. 5 on BWRVIP-25, the staff stated that "until such time as

an expanded technical basis for not inspecting the rim hold-down bolts is approved by the staff,

applicants referencing the BWRVIP-25 report for license renewal should continue to perform

inspections of the rim hold-down bolts."

In response to renewal applicant action item No. 5 on BWRVIP-25, the applicant stated that the

re-inspection strategy for SSES currently does not include any further bolt inspections. The

applicant stated that this strategy is justified by the results of the baseline inspections, which

found no crack indications, and a plant-specific analysis, which determined that adequate bolt

preload will be retained after 60 years of operation, even if the bolts contain cracks. The

applicant further stated that prior to entering the period of extended operation, PPL will either

(a) request staff approval of the justification for not inspecting the core plate hold-down bolts,

(b) implement a revised inspection strategy, approved by the staff, to ensure an adequate

number of bolts are intact, and to prevent lateral displacement of the core plate, or (c) install

core plate wedges to structurally replace lateral load resistance provided by the bolts.

The staff determines that the applicant has not included this re-inspection strategy commitment

in the LRA Table A-I. However, in response to RAI 4.7.3-1, dated October 18, 2007, the

applicant committed (Commitment No. 55) to either obtain staff approval for plant-specific

analyses to justify not inspecting the bolts or to install core plate wedges.

On this basis, the staff finds that the applicant has properly addressed renewal applicant action

item No. 5 on BWRVIP-25 and provided an acceptable basis for responding to and resolving it.

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In renewal applicant action item No. 4 for BWRVIP-26, the staff stated that "Due to IASCC

susceptibility of the subject safety-related components, applicants referencing the BWRVIP-26

report for license renewal should identify and evaluate the projected accumulated neutron

fluence as a potential TLAA issue."

In response to renewal applicant action item No. 4 for BWRVIP-26, the applicant stated that

"accumulated neutron fluence for the top guide is not a TLAA for SSES. The top guide will

exceed the threshold fluence levels for IASCC identified in BWRVIP-26-A. The aging effect is

managed per the inspection recommendations in BWRVIP- 26-A. This strategy for managing

IASCC in the top guide addresses the issue raised in renewal applicant action item No. 4 on

BWRVIP-26 and will ensure that the proposed inspections will monitor for cracking in those top

guide locations that have the highest probability of initiating IASCC."

The neutron fluence methodology for the RVs and RV internal components has been approved

by the staff and is assessed in SER Section 4.2.1. Based on this assessment, the staff

concludes that the applicant has taken a conservative approach to managing IASCC of the top

guides and further concludes that the applicant's aging management strategy is an acceptable

alternative to providing a beyond-CLB TLAA, as otherwise might have been done to satisfy

renewal applicant action item No. 4 on BWRVIP-26. Therefore, renewal applicant action item

No. 4 on BWRVIP-26 is considered resolved.

Operatinci Experience. The staff reviewed the applicant's "operating experience" program

element discussions in the BWR Vessels Internals Program and in the license renewal basis

document for this AMP. The staff noted that the applicant has not identified any relevant

SSES-specific or generic OE in the "operating experience" program element discussion for the

BWR Vessels Internals Program. The staff also noted that the license renewal program

documents for this AMP does include several CRs/Action Requests that reported the

occurrence of flaw indications (cracks) in the core spray sparger brackets, core shroud

circumferential welds and some of jet pump assembly components (i.e., jet pump restrainers,

wedges, and rods). The staff also observed that the applicant has dispositioned these flaw

indications as acceptable (i.e., "as-is") for further service without the need for repair or

replacement of the components at this time.

In RAI B.2.9-2, dated June 12, 2008, the staff requested that the applicant justify why the flaw

indications in the core spray sparger brackets, core shroud welds, and jet pump assembly

components have not been identified as relevant OE for the BWR Vessels Internals Program,

and explain its basis for leaving the flaws in these components in service (i.e., acceptable "asis") without repair or replacement of the impacted components. The staff also requested that

the applicant state, with a technical justification, what the inspection frequencies and sample

sizes will be for re-inspecting these RV internal components, during the period of extended

operation.

In the response to RAI B.2.9-2, dated July 14, 2008, the applicant stated that PPL has identified

flaw indications in the core spray sparger brackets, core shroud welds, and jet pump assembly

components. The applicant also stated that all identified flaws allowed to remain in-service (i.e.,

acceptable "as-is") have been evaluated in accordance with the applicable BWRVIP

documents.

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The applicant amended the LRA to add the relevant information to the "operating experience"

program element of LRA Section B.2.9 as follows:

For core shroud horizontal welds, initial indications were found in Units 1 and 2 in

1995. Subsequent inspections were performed in each outage since 1995. Most

of the horizontal welds in both units exhibited some degree of cracking. To date,

the flaws detected have been evaluated using the methods and criteria defined

in BWRVIP-76, and found structurally adequate until the next inspection. Future

inspections are scheduled for 2009 for Unit 2 and 2010 for Unit 1. Results of the

inspection and evaluation determine the frequency of the next inspection.

For core spray sparger brackets, a flaw was first identified in Unit 1 in 1996 and

in Unit 2 in 1997. These flaws were reexamined in 2004 and 2005, and three

more flaws were identified in the shroud plate base metal area. These flaws were

evaluated using the guidance and criteria of BWRVIP-76 and found to have

adequate structural margin. The core spray sparger brackets are currently

inspected in every outage. The recent inspections of the flaws that were

identified in 2004 and 2005 did not find any further growth in the flaws.

The jet pump holddown beams on all Unit 1 and Unit 2 jet pumps were replaced

in 1993 and 1994, respectively, in response to industry experience. In 2001,

excessive jet pump wedge wear and set screw gaps were observed on the Unit 2

jet pumps. Similar observations were made in 2002 on Unit 1. In 2003 (for

Unit 2) and 2004 (for Unit 1), modifications were installed, including machining

labyrinth seals in 20 jet pump inlet mixers (to reduce flow induced vibration),

replacing several wedges, and machining several restrainer bracket pads.

Subsequent inspections have revealed additional minor wedge and rod wear.

These components will continue to be monitored in accordance with BWRVIP41, and repairs or modifications made as required to ensure the jet pumps are

properly supported.

Based on the review, the staff finds the applicant's response to RAI B.2.9-2 acceptable because

the applicant has provided plant-specific operating experience relative to the BWR Vessel

Internals Program. The staff determines that the applicant will perform inspections on these

components at every outage, and the results will be evaluated using the guidance and criteria

provided in staff-approved BWRVIP documents that determine the next set of inspections.

Therefore, the staff's concern described in RAI B.2.9-2 is resolved.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and the guidance found in SRP-LR Section A. 1.2.3.10. Therefore,

the staff finds this program element acceptable.

UFSAR Supplement. The applicant provided its UFSAR supplement summary for its BWR

Vessel Internals Program in LRA Section A. 1.2.10 and Commitment No. 9 in Table A-1. The

staff confirms that the UFSAR supplement summary description for the BWR Vessel Internals

Program conforms to the staff's recommended UFSAR supplement described in SRP-LR

Table 3.1-2. The staff also confirms that by letter dated December 29, 2008, the applicant has

committed (Commitment No. 9) to the enhancement of the program to implement augmented

inspections of the SSES top guide grid beam and beam-to-beam crevice slot locations, during

the period of extended operation. The staff finds the applicant's commitment for the augmented

inspections of the top guide grid beam and beam-to-beam locations are acceptable because

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they conform to the staff's recommended augmented inspection criteria in the "detection of

aging effects" program element in GALL AMP XI.M9.

Based on this review, the staff finds that UFSAR Supplement Section A.1.2.10, when coupled

with the letter dated December 29, 2008, provides an acceptable UFSAR supplement summary

description of the applicant's BWR Vessel Internals Program because it is consistent with the

SRP-LR and because the UFSAR supplement includes Commitment No. 9 on augmented

inspection bases for top guide grid beam and beam-to-beam locations.

The staff determines that the information in the UFSAR supplement is an adequate summary

description of the program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of the review of the applicant's BWR Vessel Internals Program and

the applicant's response to the staff's RAls, including deletion of the enhancement, the staff

finds all program elements consistent with the GALL Report. The staff concludes that the

applicant has demonstrated that effects of aging will be adequately managed so that the

intended function(s) will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement

for this AMP and concludes that it provides an adequate summary description of the program,

as required by 10 CFR 54.21(d) and therefore is acceptable.

3.0.3.2.5 Bolting Integrity Program

Summary of Technical Information in the Application. The LRA Section B.2.12 describes the

existing Bolting Integrity Program as consistent, with five exceptions and one enhancement,

with GALL AMP XI.M18, "Bolting Integrity." The Bolting Integrity Program includes, through

other credited programs, the periodic inspection of bolting for indication of degradation such as

leakage, loss of material, or cracking.

Prior to the period of extended operation, the Bolting Integrity Program will include a specific

precaution against the use of sulfur (sulfide) containing compounds as a lubricant for bolted

connections.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. During its on-site review, the staff reviewed the applicant's

on-site documentation supporting the applicant's conclusion that the program elements are

consistent with the elements in the GALL report. The staff also interviewed the applicant's

technical staff.

The staff reviewed the enhancement and exceptions to determine whether the AMP, is

adequate to manage the aging effects for which the LRA credits it.

In the LRA, the applicant stated that the AMP B.2.12 is an existing program that is consistent

with GALL AMP XI.M18, "Bolting Integrity" with exceptions and an enhancement. The

exceptions affect the scope of program, preventive actions, parameters monitored or inspected,

detection of aging effects, monitoring and trending, and acceptance criteria GALL Report

program elements. The enhancement affects the preventive actions program element, and

includes a precaution against using compounds containing sulfur as a lubricant for bolting.

During its on-site review, the staff reviewed the applicant's on-site documentation supporting

the applicant's conclusion that the program elements are consistent with the elements in the

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GALL report. The staff interviewed the applicant's technical staff and reviewed on-site

documents.

In comparing the program elements in the applicant's program to those in GALL AMP XI.M18,

the staff found that the GALL Report "corrective actions" program element was not cited as

including an exception even though the bolting integrity program does not explicitly address the

guidelines outlined in EPRI NP-5769 as recommended by the GALL Report. By letter dated

June 30, 2008, the staff issued RAI B.2.12-2 requesting the applicant provide more information

on the basis for this exception.

By letter dated July 28, 2008, the applicant responded to RAI B.2.12-2 by stating that the AMP

B.2.12 follows the guidelines and recommendations of EPRI NP-5067 and EPRI TR-104213,

instead of EPRI NP-5769 and NUREG-1339, and revised its AMP B.2.12 description in the LRA

to identify this as an exception to the corrective actions program element. Based on the

amendments made to the LRA, the staff found the applicant's response to be acceptable.

Exception 1. LRA Section B.2.12 states an exception to the following GALL Report program

elements: scope of program, parameters monitored or inspected, detection of aging effects,

monitoring and trending, and acceptance criteria- Specifically, the exception stated:

The inspection of structural bolting (including component support bolting) for

indication of potential problems is accomplished under the ISI Program - IWF

and Structures Monitoring Program, consistent with the corresponding NUREG1801 items.

The staff reviewed the scope of the Bolting Integrity Program in the GALL Report, and found

that it primarily applies to the ASME code piping and components, including high strength

bolting used in NSSS component supports where the actual yield strength is greater than 150

ksi. Other structural bolting used in supports, including expansion and anchor bolts are

managed under ASME Code, Section Xl, Subsection IWF (B.2.36) in accordance with GALL

Report. The applicant stated that there is no high strength bolting where the actual yield

strength is greater than 150 ksi. The staff finds that this 150 ksi limit is a specified value in the

GALL Report wherein structural bolting with a yield strength below this value is not included in

the scope of the AMP B.2.12. On the basis of its review as described above, the staff finds that

this exception is acceptable.

Exception 2. LRA Section B.2.12 states an exception to the following GALL Report program

elements: scope of program, and preventive actions. Specifically, the exception stated:

The Bolting Integrity Program does not explicitly address the guidelines outlined

in EPRI NP-5769 or as delineated in NUREG-1339. However, the Bolting

Integrity Program does rely on the recommendations of the manufacturer/vendor

and the industry, contained in EPRI documents NP-5067 and TR-104213, and

will include a precaution against the use of any sulfur (sulfide) containing

compound as a lubricant.

The staff reviewed the guidance documents, and determined that EPRI TR-104213 is a

guidance document endorsed by the GALL AMP XI.M18, however the guidance document

EPRI NP-5067 is not specifically endorsed. By letter dated June 30, 2008, the staff issued RAI

B.2.12-3 requesting additional information from the applicant detailing the differences between

the guidance documents.

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By letter dated July 28, 2008, the applicant responded to RAI B.2.12-3 by stating that although

the AMP B.2.12 follows the guidelines and recommendations of EPRI NP-5067 and EPRI TR104213, instead of EPRI NP-5769 and NUREG-1339, the Bolting Integrity Program still meets

the intent of the GALL Report recommendations. The applicant referenced a point-by-point

comparison of the two sets of documents dated April 1, 2005 (ML051020128). This comparison

was previously accepted by the NRC, and found to adequately address the bolting guidelines in

the GALL Report. Based on the justification provided, the staff finds the applicant's response to

be acceptable.

Exception 3. LRA Section B.2.12 states an exception to the GALL Report program element

parameters monitored or inspected. Specifically, the exception stated:

Loss of preload/loss of pre-stress is not an aging effect requiring management

for SSES bolting since SSES systems operate below the 700 *F threshold where

stress relaxation becomes a plausible age-related concern. Improper bolting

application or maintenance issues that might result in loss of preload are current

plant operational (design) concerns, as supported by site operating experience,

and are not related to aging.

The staff reviewed the GALL Report and SRP-LR on the management of loss of preload, and

finds that the management of loss of preload is also addressed in the GALL Report program

element, preventive actions. Proper maintenance practices requiring the application of an

appropriate preload must exist. Additionally, the applicant states in its LRA that loss of preload

is not an aging effect requiring management since it does not reach the 700 OF threshold at

which loss of preload due to thermal effects aging mechanism occurs. However, loss of preload

is identified in the GALL Report to include not only thermal effects, but also gasket creep and

self loosening as other aging mechanisms. The aging mechanisms of gasket creep and self

loosening are not properly discussed in this exception, and appears to imply that loss of preload

due to gasket creep and/or self loosening are not accounted for by the applicant. Therefore, by

letter dated September 23, 2008, the staff issued RAI B.2.12-5 requesting additional

information from the applicant regarding the management of loss of preload.

By letter dated October, 22, 2008, the applicant responded to RAI B.2.12-5 by providing its

technical basis for the exclusion of the loss of preload aging effect by addressing the three

aging mechanisms which could lead to loss of preload- thermal effects, gasket creep, and self

loosening. The applicant referenced EPRI document 1010639 which states that "Loss of

preload is not an applicable aging effect." This document is not endorsed by the GALL AMP

XI.M18, and contradicts the GALL Report, which specifically identifies loss of preload as an

aging effect with these three aging mechanisms. The staff recognizes that the conditions which

lead to loss of preload by thermal effects may not exist at SSES, and also that indications for

loss of preload are being monitored while monitoring for leakage, loss of material, and cracking.

However, the guidance from the GALL AMP XI.M18 and EPRI NP-5067, which the applicant

follows, indicates that loss of preload due to thermal effects, gasket creep, and self loosening is

in fact an aging effect requiring management. The staff finds that though it is possible to

monitor for indications of loss of preload such as leakage, the loss of preload aging effect still

must be an aging effect which is managed by the AMP B.2.12. However the applicant's

response to part (c) of RAI B.2.12-5 appears to directly contradict this important distinction.

The staff discussed their concerns with the applicant in a teleconference on October 27, 2008.

By letter dated November 4, 2008, the applicant supplemented its response to RAI B.2.12-5,

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letter dated October, 22, 2008, by clarifying that although the loss of preload aging effect is not

included in any of the AMR line items in the LRA, the AMP B.2.12 still "provides for the

management of loss of preload for all in-scope, pressure-retaining bolted closures at SSES."

With this distinction, the staff finds the applicant's response and exception to be acceptable.

Exception 4. LRA Section B.2.12 states an exception to the GALL Report program element

monitoring and trending. Specifically, the exception stated:

Periodic inspection of bolting, other than of the Class 1, 2 and 3 bolting

performed by the ISI Program, is performed through the System Walkdown

Program, including follow-up inspections if leakage is detected. The frequency

of follow-up inspections is established by engineering evaluation of the identified

problem. SSES operating experience has not shown a need for a set frequency

(e.g., daily) applicable to all cases involving bolting.

The staff reviewed the GALL Report "monitoring and trending" program element and found that

the recommendation for leak rate to be monitored on a particularly defined schedule was not

clear in the applicant's bolting integrity program. Therefore, by letter dated June 30, 2008, the

staff issued RAI B.2.12-1 requesting additional information on the applicant's leak rate

monitoring schedule.

By letter dated July 28, 2008, the applicant stated that in cases of leakage on bolting

connections for pressure retaining components (not covered by ASME Section XI), the

inspection frequency is determined by engineering evaluation of the problem. The applicant

stated that this is achieved at SSES through the plant minor deficiency monitoring program,

which establishes the guidelines for identifying, monitoring, tracking, and disposition of minor

deficiencies, such as leaks, that are discovered during walk downs. For any leak, an evaluation

is completed to determine the actions required based on the severity of the leak and the

potential to impact normal operations and safety. Furthermore, if the leak rate changes, further

evaluation is performed to determine the actions required. Based on the justification provided,

the staff found the applicant's response and exception to be acceptable.

Exception 5. LRA Section B.2.12 states an exception to the GALL Report program element

acceptance criteria. Specifically, the exception stated:

The program does not specify acceptance criteria for bolting. However, the ISI

Program and the System Walkdown Program, through which the periodic visual

inspection of mechanical components within the scope of license renewal are

performed, do include acceptance criteria for evidence of degradation of

components, including the bolting.

The staff finds that the applicant properly addresses the intent of the GALL Report program

element acceptance criteria through the implementation of its corrective action program as well

as through the acceptance criteria identified in the Inservice Inspection Program and System

Walkdown Program. Therefore, the staff finds this exception to be acceptable.

Enhancement. LRA Section B.2.12 states an enhancement to the GALL Report program

element preventive actions. Specifically, the enhancement stated:

The program will include a specific precaution against the use of sulfur (sulfide)

containing compounds, such as molybdenum disulfide (MoS2), as a lubricant for

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threaded fasteners (bolting), to further preclude the potential for stress corrosion

cracking.

The staff reviewed EPRI-5769, Volume 1, Section 11 and found that it specifically identifies

lubricants containing molybdenum disulfides as a common factor in several SCC related

failures. The applicant's enhancement directly addresses this issue, as it commits to include a

specific precaution against the use of compounds containing sulfur (sulfide), including

molybdenum disulfide (MoS 2), as a lubricant for bolting. When implemented prior to the period

of extended operation, AMP B.2.12 will be consistent with the recommendations of GALL AMP

XI.M18. On the basis of the guidance of the GALL Report, the staff finds this to be acceptable.

Operatinq Experience. The staff also reviewed the operating experience described in LRA

Section B.2.12. The applicant stated that "No instances of cracking or age-related loss of

preload have been identified for bolting/fasteners, though some corroded bolting or facing

surfaces (e.g., from general corrosion or leakage) have been identified at SSES." To verify the

accuracy of this statement, the staff reviewed a sample of condition reports, and interviewed

the applicant's technical staff to confirm that the plant-specific operating experience did not

reveal any degradation not bounded by industry experience. A 2002 condition report described

the degraded condition of a total of 26 corroded bolts on the Al and A2 diesel generator

intercoolers. Upon further questioning of the applicant's staff and review of the CR, the staff

discovered that the applicant performed additional investigation and evaluation to determine the

root cause of the corroded bolts to be moisture and warm conditions. As a result, all 26 bolts

were replaced, and proper corrective actions were demonstrated. This report as well as other

condition reports reviewed by the staff during the audit helped to confirm the applicant's

statement above, and helped to demonstrate that proper corrective actions are taken to

address bolting issues.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program

element acceptable.

UFSAR Supplement. In LRA Section A.1.2.2 and Commitment No. 12 in Table A-i, the

applicant provided the UFSAR Supplement for the Bolting Integrity Program. The staff reviewed

this section and finds it acceptable because it is consistent with the corresponding program

description in SRP-LR Table 3.1-2.The staff determines that the information in the UFSAR

supplement is an adequate summary description of the program, as required by 10 CFR

54.21(d).

The staff verified that, Commitment No. 12 in the LRA Table A-1, includes a brief description of

the enhancement and committed to enhancing the program to include specific precautions

regarding the use of lubricants for threaded fasteners prior to the period of extended operation.

Conclusion. The staff has reviewed the information provided in Section B.2.12 of the LRA

Appendix B and additional information provided by the applicant by letters dated July 28, 2008,

October 22, 2008, and November 4, 2008. On the basis of its review as discussed above, the

staff concludes that the applicant has demonstrated that those program elements for which the

applicant claimed consistency with the GALL Report are consistent with the GALL Report.

In addition, the staff reviewed the exceptions and the associated justifications, and determined

that the AMP, with the exceptions, is adequate to manage the aging effects for which it is

credited. Also, the staff has reviewed the enhancement and confirmed that the implementation

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of the enhancement prior to the period of extended operation would result in the existing AMP

being consistent with the GALL Report AMP to which it was compared. The staff concluded

that the applicant demonstrated that the effects of aging will be adequately managed so that

the intended functions of these components will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the

UFSAR supplement for this AMP and concluded that it provides an adequate summary

description of the program, as required by 10 CFR 54.21(d).

3.0.3.2.6 Piping Corrosion Program

Summary of Technical Information in the Application. LRA Section B.2.13 describes the Piping

Corrosion Program as an existing program that is consistent, with exceptions and'

enhancements, with GALL Report AMP XI.M20, "Open-Cycle Cooling Water System." The

applicant stated that this program fully meets the intent of NRC GL 89-13, "Service Water

System Problems Affecting Safety-Related Equipment." The applicant further stated that the

program is a combination of condition monitoring program (consisting of inspections,

surveillances, and testing to detect the presence of, and to assess the extent of, fouling and

loss of material) and a mitigation program (consisting of chemical treatments and cleaning

activities to minimize fouling and loss of material).

Staff Evaluation. During the audit, the staff reviewed the applicant's claim of consistency with

the GALL Report. The staff reviewed the applicant's on-site documentation supporting the

applicant's conclusion that the program elements are consistent with the elements in the GALL

report. The staff also interviewed the applicant's technical staff.

In comparing the elements in the applicant's program to those in the GALL AMP XI.M20, the

staff noted that the program elements in the applicant's AMP claimed to be consistent with the

GALL were consistent with the corresponding program element criteria recommended in the

program elements of GALL AMP XI.M20 with the exception of the "scope of program" program

element aspect as identified below that the staff determined was in need of additional

clarification. The staff also confirmed that the plant program contains all of the elements of the

referenced GALL Report.

The staff reviewed the applicant's license renewal basis document and confirmed that the

program scope includes the systems and components that could be affected by piping

corrosion.

In LRA Table 3.2.2-7, Standby Gas Treatment System (SGTS), the Piping Corrosion Program

is credited for managing the aging effect of loss of material for loop seal piping and valve

bodies. However, a review of the license renewal basis document for the Piping Corrosion

Program indicated that SGTS is not included in the scope of the Piping Corrosion Program. The

staff issued RAI B.2.13-1 by letter dated May 30, 2008, requesting the applicant to justify why it

is not included and to justify how the Piping Corrosion Program will manage the aging effects of

these components in SGTS.

In the letter dated June 30, 2008, the applicant responded to RAI B.2.13-1 by amending the

Piping Corrosion Program. This is discussed in the Enhancement 1 section.

The staff reviewed the exceptions and enhancements to determine whether the AMP, with the

exceptions and enhancements is adequate to manage the aging effects for which the LRA

credits it.

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Exception 1. In LRA Section B.2.13, the applicant stated an exception to the "preventive

actions" program element that system components are lined or coated only where necessary to

protect the underlying metal surfaces. The GALL AMP XI.M20 recommends that system

components are lined or coated.

The GALL Report Volume 2 Chapter VII for the Open-Cycle Cooling Water System includes

piping, piping components and piping elements made of steel (with or without coatings),

stainless steel and copper alloy materials. The GALL Report recognizes that steel components

may be coated or uncoated. Based on this review, the staff finds the exception acceptable

because the applicant is using materials that are appropriate for the system and has lined or

coated steel where necessary to protect the underlying material.

Exception 2. In LRA Section B.2.13, the applicant stated an exception to the "monitoring and

trending" program element that inspection frequencies are based on operating conditions and

past history; flow rates, water quality, lay-up and heat exchanger design. The GALL

AMP XI.M20 recommends testing and inspections be performed annually and during RFOs.

The staff issued RAI B.2.13-5 by letter dated May 30, 2008, to request the applicant to confirm

if these frequencies are in accordance with the information provided in GL 89-13 concerning a

routine inspection and maintenance program and Section D, "frequency of testing and

maintenance," in GL 89-13, Supplement 1, and if not, to justify why the GALL recommended

frequencies are not followed.

By letter dated August 22, 2008, the applicant responded to RAI B.2.13-5 stating that the

inspection frequencies are in accordance with PPL commitments under NRC GL 89-13. The

applicant further stated that inspection and cleaning frequencies are based on PPL heat

exchanger's operating conditions and past history with flow rates, water quality, layup, and heat

exchanger design all being considered. The applicant further stated that the frequency has

been established in order to identify inherent problems before failures occur. In its response to

GL 89-13, dated February 23, 1990, the applicant stated that "instead of conducting a testing

program PPL committed to replacing the cooling coils of difficult to inspect heat exchangers,

laboratory testing of a fouled coil and a prototype of the replacement coil, and a comprehensive

program that includes scheduling of maintenance, methods of cleaning, inspection criteria,

reporting, and personnel qualification. Based on past monitoring, PPL has demonstrated that

existing activities and their frequency have been acceptable to detect degradation prior to the

loss of component intended function and will remain adequate for the period of extended

operation. The frequency of inspections is in accordance with the information provided in NRC

GL 89-13."

NRC GL 89-13 Supplement 1, Section III.D.3, states, "{f}requent regular maintenance is an

acceptable alternative to Recommended Action II, which calls for heat exchanger performance

testing. A licensee or applicant can choose to routinely maintain the heat exchangers instead of

testing them. Either the frequency of maintenance or the frequency of testing should be

determined to ensure that the equipment will perform the intended safety functions during the

intervals between maintenance or tests." The staff also reviewed the applicant's response to the

NRC GL 89-13 and also reviewed the results of the laboratory testing that the applicant had

attached to NRC GL 89-13 response.

NRC GL 89-13 Supplement 1 provides for regular maintenance and testing as an alternate for

performance testing. The staff noted that the applicant performs periodic inspection in

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accordance with its response to GL 89-13 and has considered flow rates, water quality, layup,

and heat exchanger design when determining the frequency, and has addressed appropriate

inspection and acceptance criteria. The staff reviewed the plant OE and noted that the applicant

has identified and documented age related degradation as found during various inspection

activities. On this basis, the staff finds that the frequencies as established by the applicant are

appropriate and the Piping Corrosion Program will adequately manage age related degradation

through the period of extended operation. The staff finds the applicant response to RAI B.2.13-

5 to be acceptable and finds this exception to GALL AMP XI.M20 to be acceptable.

Exception 3. In a response to GL 89-13, SSES took an exception to heat transfer capability

testing. The GALL AMP XI.M20, in the parameters monitored/inspected program element,

recommends testing to ensure heat transfer capabilities. In LRA Section B.2.13, the applicant

has not taken an exception to this program element. The staff issued RAI B.2.13-3 by letter

dated May 30, 2008, requesting the applicant to justify why no exception is taken in the

application.

In a letter dated June 30, 2008, the applicant responded to RAI B.2.13-3 that there is no test

program at SSES to verify heat transfer capability. The applicant amended the application to

include an additional exception to the Piping Corrosion Program in the "scope of program"

element. The staff evaluates this exception below:

In the letter dated June 30, 2008, the applicant amended the application to include an additional

exception to the Piping Corrosion Program in the "scope of program" element as follows:

NUREG-1 801 states that the guidelines of NRC GL 89-13 include a test program

to verify heat transfer capabilities. There is no test program at SSES to verify the

heat transfer capability. In response to GL 89-13, PPL conducted laboratory

testing of cooling coils to demonstrate adequate heat transfer capability.

The applicant had performed laboratory testing of a representatively fouled ECCS room cooler

cooling coil, and of prototypes representing replacement cooling coils, under post-accident

conditions that demonstrated adequate heat transfer capability. This is documented in PPL

correspondence to NRC dated June 11, 1992 that provided the May 1992 Confirmatory

response to NRC GL 89-13. Additionally, the applicant has been monitoring heat exchangers in

response to NRC GL 89-13 and has demonstrated that existing activities are able to detect

degradation prior to loss of component intended function and will remain adequate for the

period of extended operation.

The staff reviewed the above referenced applicant correspondence and the OE discussion that

was provided in the applicant's license renewal basis document for the Piping Corrosion

Program. On the basis that the applicant has met the NRC GL 89-13 recommended actions

and OE has demonstrated that the program activities can detect aging degradation prior to loss

of component intended function, the staff finds the applicant response acceptable and finds this

exception to GALL AMP XI.M20 to be acceptable.

Based on the review, the staff finds the applicant's Piping Corrosion Program acceptable

because it conforms to the recommended GALL AMP XI.M20, "Open-Cycle Cooling Water

System" with enhancements and exceptions.

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Enhancement 1. In the letter dated June 30, 2008, the applicant responded to RAI B.2.13-1 that

the LRA Table correctly credited the Piping Corrosion Program and the basis document should

have included the SGTS loop seals in the scope of the Piping Corrosion Program.

The applicant amended the LRA Section B.2.13, Piping Corrosion Program with an

enhancement in the "scope of program" program element to include the SGTS loop seals.

Similar changes were made to the UFSAR Supplement Section A. 1.2.38 and the commitment

No. 13 in LRA Table A-I.

The applicant also stated that the internal environment for the loop seals is raw water from the

service water system and upon inclusion of the loop seals within the scope of the program, they

will be monitored and inspected for loss of material in accordance with the specifications.

The staff reviewed the response and the associated changes to the LRA and finds the

response and the changes acceptable because the applicant correctly added the SGTS loop

seals to the scope of the program. The staff concurs that with the inclusion of the loop seals

within the scope of the program, the Piping Corrosion Program will adequately manage the

aging effects of these components similar to the other service water system components that

are included in the scope of this program. Based on this review, the staff finds the

enhancement acceptable because implementation of the enhancement will make the Piping

Corrosion Program consistent with the GALL AMP XI.M20, "Open-Cycle Cooling Water

System."

Enhancement 2. In the letter dated October 21, 2008, in response to NRC regional inspection

of the LRA, the applicant added the following enhancement to the "monitoring and trending"

program element of LRA Section B.2.13.

The program will incorporate performance, documentation and trending of

opportunistic visual inspections (during normal maintenance/repair activities).

The applicant also revised the UFSAR supplement and Commitment No. 13 to include this

enhancement.

The staff reviewed the enhancement and associated changes and finds the response and the

changes acceptable because the implementation of the enhancement will make the Piping

Corrosion Program consistent with the GALL AMP XI.M20, "Open-Cycle Cooling Water System"

for monitoring and trending of the inspection results.

The staff noted that the current "scope of program" program element, as described in the LRA,

does not include commitments for two GL 89-13 guidelines incorporated in GALL AMP XI.M20.

The specific components of the GL 89-13 program missing from the Piping Corrosion Program

are a system walkdown inspection to ensure compliance with the CLB and a review of

maintenance, operating, and training practices and procedures. The staff issued RAI B.2.13-2

by letter dated May 30, 2008, requesting the applicant to justify why this not an exception to the

GALL AMP.

In the letter dated June 30, 2008, the applicant responded to RAI B.2.13-2 that the program

description for GALL AMP XI.M20 states that the Open-Cycle Cooling Water System Program

relies on implementation of the recommendations of GL 89-13. The applicant had provided

responses to GL 89-13 via a series of correspondence with the NRC. The recommended action

in GL 89-13 for system walkdown was documented in PPL correspondence to the NRC dated

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February 23, 1990, and dated December 14, 1990. PLA-3349 also documented the

recommended action for the review of the procedures. These two actions are one-time actions

arising out of GL 89-13 and are unrelated to aging management.

The staff reviewed the response and the referenced applicant correspondence and finds that

the applicant has taken the appropriate actions as recommended by GL 89-13 and is consistent

with the GALL AMP XI.M20 program description and therefore has justified why an exception to

the GALL AMP is not required. Based on this review, the staff finds the applicant's response

acceptable.

Operatingi Experience. The staff reviewed the applicant's OE described in LRA Section B.2.13

and interviewed the applicant's technical personnel to confirm that the plant-specific OE did not

reveal any aging effects not bounded by the GALL Report. The staff also confirmed that

applicable aging effects and industry and plant-specific OE have been reviewed by the

applicant and are evaluated in the GALL Report.

In the "operating experience" program element of LRA Section B.2.13, the LRA states that

SSES has programs in place with OE to demonstrate that the effects of aging on the service

water systems, and on the safety-related heat exchangers that they serve, will be effectively

managed during the period of extended operation. The staff issued RAI B.2.13-4 by letter dated

May 30, 2008, requesting the applicant to provide some specific examples of issues that were

found in the condition reports.

In the letter dated June 30, 2008, the applicant responded to RAI B.2.13-4 by providing several

specific examples of OE. These included service water piping leaks, UT pipe wall thickness

measurements that were below minimum requirements, tube wall erosion found during eddy

current testing, erosion damage on end covers of heat exchangers, pitting damage on stator

coolers and coatings damage on the waterbox divider. These were found during performance of

testing and inspections of piping and heat exchangers. The staff finds that the applicant has

provided specific plant OE and taken the appropriate corrective action to demonstrate that the

effects of aging on the service water systems, and on the safety-related heat exchangers that

they serve, will be adequately managed during the period of extended operation. Based on this

review, the staff finds the applicant response acceptable.

The staff also reviewed the applicant's "operating experience" described in the applicant's

license renewal basis document for the Piping Corrosion Program. The staff reviewed a sample

of condition reports and confirmed that the applicant had identified age related degradation and

implemented appropriate corrective actions.

Furthermore, the staff confirmed that the applicant has addressed OE identified after the

issuance of the GALL Report. The staff finds that the applicant's Piping Corrosion Program with

has been effective in identifying, monitoring, and correcting the effects of age related

degradation in service water piping systems and can be expected to ensure that effects of

aging will be adequately managed during the period of extended operation.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP LR Section A. 1.2.3.10. The staff finds this program

element acceptable.

UFSAR Supplement. In LRA Section A.1.2.38 and Commitment No. 13 in Table A-1 the

applicant provided the UFSAR supplement for the Piping Corrosion Program. The staff verified

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that the UFSAR supplement summary description for the Piping Corrosion Program was in

conformance with the staff's recommended UFSAR supplement for the Open-Cycle Cooling

Water System Program provided in Table 3.3-2 of the SRP-LR.

In the letters dated June 30, 2008, and October 21, 2008, the applicant amended the UFSAR

supplement to include the enhancements to add Stand-By Gas Treatment System loop seals to

the scope of the program and to incorporate performance, documentation and trending of

opportunistic inspections and revised Commitment No. 13 in Table A-1 accordingly.

Based on this review, the staff finds that UFSAR supplement Section A.1.2.38 as amended,

provides an acceptable UFSAR supplement summary description of the applicant's Piping

Corrosion Program because it is consistent with those UFSAR supplement summary

description in the SRP-LR for the Open-Cycle Cooling Water System Program.

The staff determines that the information in the UFSAR supplement is an adequate summary

description of the program, as required by 10 CFR 54.21(d).

Conclusion. Based on the review of the applicant's Piping Corrosion Program and the

applicant's response to the staff RAIs, the staff finds all program elements consistent with the

GALL Report. In addition, the staff reviewed the exceptions and their justifications and

determines that the AMP, with the exceptions, is adequate to manage the aging effects for

which the LRA credits it. Also, the staff reviewed the enhancements and confirmed that its

implementation through Commitment No. 13 prior to the period of extended operation would

make the existing AMP consistent with the GALL Report AMP to which it was compared. The

staff concludes that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the

UFSAR supplement as amended for this AMP and concludes that it provides an adequate

summary description of the program, as required by 10 CFR 54.21(d).

3.0.3.2.7 Closed Cooling Water Chemistry Program

Summary of Technical Information in the Application. LRA, Section B.2.14 describes

AMP B.2.14 "Closed Cooling Water Chemistry Program" as an existing program that is

consistent with the GALL AMP XI.M21 "Closed-Cycle Cooling Water System" with an exception

to the following program elements, "parameters monitored/inspected," "detection of aging

effects," "monitoring and trending" and "acceptance criteria."

The applicant stated that this program is a mitigation program for damage due to loss of

material and cracking for components within the closed cooling water system and for

components that are served by the closing cooling water system that are exposed to treated

water. The applicant also stated that the program is consistent with EPRI water chemistry

guidelines that manage conditions that could lead to loss of material or cracking with the use of

proper monitoring and corrosion inhibitors.

Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the

Gall Report. AMP XI.M21, "Closed-Cycle Cooling Water System" with an exception to the

following program elements: parameters monitored/inspected, detection of aging effects,

monitoring and trending and acceptance criteria.

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In comparing the seven program elements in the applicant's program to those in GALL

AMP XI.M21, the staff noted that the program elements in the applicant's AMP claimed to be

consistent with the GALL Report were consistent with the corresponding program element

criteria recommended in the program elements of GALL AMP XI.M21 with the exception of one

program element, "operating experience," and those exceptions taken by the applicant that the

staff felt there was a need for additional clarification and for which RAIs were issued. The staff

also issued an RAI to clarify statements made by the applicant in LRA Section B.2.14 pertaining

to a supplemental one-time inspection. The "operating experience" program element is

discussed separately below.

Based on the staffs review of LRA Section B.2.14, the staff noted that the applicant states that

the Closed Cooling Water Chemistry Program is supplemented by a one-time inspection to

ensure the effectiveness of the program, either the AMP B.2.22 "Chemistry Program

Effectiveness Inspection" or the AMP B.2.24 "Heat Exchanger Inspection." The staff determined

that clarification was needed and, therefore, by letter dated July 10, 2008, the staff issued

RAI B.2.14-2 requesting the applicant to clarify if the appropriate one-time inspection will be

performed for all AMR Table 2 line items credited with using AMP B.2.14 and to identify which

one-time inspection, if any, will be used for any applicable AMR Table 2 line items that credit

AMP B.2.14 for aging management. The applicant responded to RAI B.2.14-2, in a letter dated

August 12, 2008. The applicant clarified that the one-time inspection performed as part of the

AMP B.2.22, "Chemistry Program Effectiveness Inspection" will be used to supplement

AMP B.2.14, "Closed Cooling Water Chemistry Program" in all instances where AMP B.2.14 is

credited for aging management in LRA Table-2 items, with the exception of the Diesel Jacket

Water Cooling System. The staff noted that the one-time inspection will not be performed on

the Diesel Jacket Water Cooling System because corrosion monitoring probes were installed to

identify actual corrosion rates. The staff further noted that these probes were installed following

an inspection performed at the same time as a 20-year overhaul of the system. The staff

confirmed that the applicant amended the LRA to indicate that AMP B.2.22 will supplement

AMP B.2.14, in order to perform a one-time inspection to identify degradation or confirm the

lack of degradation. On the basis of its review, the staff finds the applicant's response

acceptable because the applicant has clarified that the AMP B.2.22, "Chemistry Program

Effectiveness Inspection" is the one-time inspection that will supplement AMP B.2.14, unless

otherwise noted, which will be capable of identifying any evidence or confirm the lack of any

degradation that is occurring that may affect the intended functions of those components that

credit AMP B.2.14 for aging management, during the period of extended operation.

The staff reviewed the exception to determine whether the program, with exception, is adequate

to manage the aging effects for which it is credited.

Exception. GALL AMP XI.M21 recommends the use of performance and functional testing to

ensure the "acceptable functioning" of the closed cooling water system or components served

by this system. The staff noted that the applicant's program takes an exception to the

"parameters monitored/inspected," "detection of aging effects," "monitoring and trending" and

"acceptance criteria" program elements in that performance and functional testing will not be

performed.

The staff also noted that the applicant's program will monitor the emergency diesel generator

jacket water subsystem and heat-exchangers served by the closed cooling waters which are

supplemented by a one-time inspection to confirm the effectiveness of AMP B.2.14. Therefore,

by letter dated July 10, 2008, the staff issued RAI B.2.14-1 requesting the applicant to clarify

whether or not performance and functional testing are within the scope of the closed cooling

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water chemistry program, and if not to provide the basis for not including them in the scope of

the program. The staff further asked the applicant in RAI B.2.14-1 to clarify whether the onetime inspection is being performed instead of the periodic inspections recommended in GALL

AMP XI.M21 and if so, to justify how a one-time inspection is capable of accomplishing the

same tasks as the periodic inspections recommended by the GALL Report. Additionally, the

staff asked the applicant to clarify how a one-time inspection would be capable of trending

corrosion data for the components within scope of the program when only one round of

inspections are performed.

The applicant responded to RAI B.2.14-1 in a letter dated August 12, 2008. In this letter the

applicant stated that the conditions that could lead to the onset and the spread of loss of

material and cracking are managed by the proper control and monitoring of corrosion inhibitors

in accordance with EPRI water chemistry guidelines. The applicant further stated that system

parameters would only be affected when the degradation in the system had progressed to a

significant amount. The staff noted that the applicant will control the water chemistry in

accordance with EPRI guidelines, industry and plant-specific OE and periodic evaluation of the

water chemistry parameters. The staff noted that the applicant has performed a review of its

plant-specific OE, which indicated that the aging effects of loss of material and cracking are not

expected to occur and the Closed Cooling Water Chemistry Program has been effective is

mitigating these aging effects. The applicant stated in the LRA that they will be performing a

one-time inspection with the AMP B.2.22 "Chemistry Program Effectiveness Inspection" to

identify evidence or confirm the lack of any degradation that is occurring that may affect the

intended functions of these components during the period of extended operation. The applicant

stated that this one-time inspection will inspect a representative sample of components that are

exposed to low flow and stagnant areas where accumulation of contaminants might occur

making these components more susceptible to loss of material and components that are

exposed to temperatures greater than 140°F which are susceptible to cracking. The staff noted

that this one-time inspection will utilize a combination of volumetric and visual inspection

techniques (such as VT-1 or VT-3). The staff noted that in most cases the use of functional and

performance testing will verify that the component's active functions can be accomplished. The

staff further noted that testing the active functions of components with performance and

functional testing are governed by the requirements of the Maintenance Rule (10 CFR 50.65).

By letter dated September 30, 2008, as a result of a NRC Regional Inspection the applicant

amended this exception in LRA Section B.2.14 in which the applicant clarified that periodic

inspections will not be performed, however based on the implementation and inspection results

from the one-time inspection that will be performed as part of AMP B.2.22 this may result in the

establishment of periodic inspection activities. On the basis of its review, the staff finds the

applicant's response acceptable because (1) the applicant will be monitoring and maintain the

water chemistry in accordance with EPRI guidelines (2) will be performing a one-time inspection

in accordance with the recommendations of GALL AMP XI.M32 "One-Time Inspection" to

identify evidence or confirm the lack of any degradation that is occurring that may affect the

intended functions of the these components during the period of extended operation and (3) the

applicant may establish periodic activities based on the implementation and inspection results

from the one-time inspection performed as part of AMP B.2.22.

On the basis of its review, the staff finds the applicant's exception acceptable because (1) the

applicant will monitor and maintain water chemistry in accordance with the EPRI guidelines to

mitigate loss of material and cracking which has been proven to be successful based on plantspecific OE, (2) the applicant will be performing a one-time inspection in accordance with the

recommendations of GALL AMP XI.M32 "One-Time Inspection" for the aging effects of loss of

material and cracking, and (3) the applicant will be selecting representative sample of

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components with low-flow and stagnant areas which are more susceptible to degradation

because of accumulating contaminants for the one-time inspections.

Operating Experience. The staff reviewed the applicant's OE described in the applicant's

license renewal basis document for the Closed Cooling Water Chemistry Program. The

applicant stated in the LRA that this program incorporates EPRI closed cooling water guidelines

and also has been incorporating site-specific and industry wide OE. The staff noted that the

applicant performs periodic external and internal assessments of the program's performance to

identify any strengths and adverse trends.

During its review, the staff noted that the OE revealed issues with the diesel jacket water

corrosion/microbiological control in 1999 and some degradation of components were noted by

inspections during a 20-year overhaul during the same time period. The applicant took

corrective actions by flushing the jacket water and considered different biocide/corrosion

inhibitor treatments. The staff noted that the applicant installed instantaneous corrosion probes

to monitor corrosion rates. However the staff determined that additional information was needed

for its review and therefore, by letter dated July 10, 2008, the staff issued RAI B.2.14-3

requesting the applicant to clarify whether the addition of alternative biocides or corrosion

inhibitors was actually implemented as a corrective action for the diesel jack water system

components that are exposed to closed cooling water. If so, clarify whether any supplemental

inspections have been performed since the time of the change in the biocide control compound

or corrosion inhibitor to verify its effectiveness in managing microbiological organism growth or

corrosion of the component surfaces that are exposed to closed cooling water; if not, and a

change in biocide control compound or corrosion inhibitors is planned, clarify when the change

will be performed and whether any supplemental inspections are planned to confirm its

effectiveness to manage microbiological organism growth or corrosion in the components. The

applicant responded to RAI B.2.14-3, by letter dated August 12, 2008. The applicant stated that

during 1999 the biocide treatment used by SSES was glutaraldhyde, but was discontinued and

changed to the alternative biocide isothiazoline. The staff noted that this alternative biocide is

currently in use and since its implementation in 1999, the more recent supplemental inspections

of the diesel generators have indicated no significant degradation. The applicant stated that the

supplemental inspections were performed to confirm the effectiveness of this new biocide

treatment. The applicant stated that the recent review in 2007 of the water chemistry samples

have shown that the chemistry parameters have been maintained in specification, corrosive

metal levels are low, and biological activity is negligible. On the basis of its review, the staff

finds the applicant's response acceptable because the applicant took corrective actions with the

use of alternate biocide treatments following the discovery of degradation in the diesel jacket

cooling water system and recent inspections have shown no significant degradation in the

system.

The staff finds the applicant's Closed Cooling Water Chemistry Program has been effective in

identifying, monitoring and correcting the effects of aging and the existing program OE did not

reveal any degradation not bounded by industry experience.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A. 1.2.3.10. The staff finds this program

element acceptable.

UFSAR Supplement. The staff reviewed the UFSAR Supplement summary description that was

provided in LRA Section A. 1.2.13 and Commitment No. 45 in Table A-1 for the Closed Cooling

Water Chemistry Program. The staff verified that, in LRA Commitment No. 45 of UFSAR

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Supplement Table A-i, the applicant committed to the ongoing implementation of the Closed

Cooling Water Chemistry Program for aging management of those in-scope components that

the AMP is credited. The staff also verified that the applicant has placed this commitment on

UFSAR Supplement summary description A. 1.2.13 for the Closed Cooling Water Chemistry

Program.

Based on this review, the staff finds that UFSAR Supplement Section A.1.2.13 provides an

acceptable UFSAR Supplement summary description of the applicant's Closed Cooling Water

Chemistry Program because it is consistent with the UFSAR Supplement summary description

in the SRP-LR and because the summary description includes the bases for determining that

aging effects will be managed. Therefore, the staff concludes that the UFSAR supplement for

this AMP provides an adequate summary description of the program, as described by

10 CFR 54.21(d).

Conclusion. On the basis of the review of the applicant's Closed Cooling Water Chemistry

Program, the staff determines that those program elements for which the applicant claimed

consistency with the GALL Report are consistent. The staff reviewed the exception , the

justification and determined that the AMP, with the exception, is adequate to manage the aging

effects for which the LRA credits it. In addition the staff reviewed the applicant's responses to

the staff's RAI and its evaluation is documented above. The staff concludes that the applicant

has demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this

AMP and concludes that it provides an adequate summary description of the program, as

required by 10 CFR 54.21(d).

3.0.3.2.8 Fire Protection Program

Summary of Technical Information in the Application. LRA Section B.2.16 describes the Fire

Protection Program as an existing program that is consistent with an exception with the GALL

AMP XI.M26, Fire Protection. The applicant stated that this program performs periodic visual

inspections and functional tests, as appropriate, of fire dampers, fire barrier walls, ceilings and

floors, fire rated penetration seals (fire stops), fire wraps, fireproofing, and fire doors to ensure

that functionality and operability are maintained.

Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the

GALL Report. The staff reviewed the exception to determine whether the AMP, with the

exception, is adequate to manage the aging effects for which the LRA credits it. In comparing

the elements in the applicant's program to those in GALL AMP XI.M26, the staff noted that the

program elements in the applicant's AMP claimed to be consistent with GALL were consistent

with the corresponding program element criteria recommended in the program elements of

GALL AMP XI.M26. The staff also confirmed that the plant program contains all of the elements

of the referenced GALL Report. Onsite interviews were also held to confirm these results.

The staff reviewed the exception to determine whether the AMP, with the exception, is

adequate to manage the aging effects for which the LRA credits it.

Exception 1. In the LRA, the applicant identified the following exception to the "scope",

"parameters monitored/inspected," "detection of aging effects," "monitoring and trending" and

"acceptance criteria" program elements:

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With respect to the halon/carbon dioxide (C0 2) suppression systems and the fuel

oil supply line for the diesel-driven fire pump, inspections and tests included in

the Fire Protection Program (and addressed in the Technical Requirements

Manual) are not credited with aging management but do provide for periodic

observation of the related components. While halon/C0 2 and fuel supply line

internal conditions are not directly inspected or evaluated during these tests and

inspections, they do provide indirect confirmation of whether degradation has

occurred, prior to a loss of function.

The staff issued RAI B.2.16-1 by letter dated May 30, 2008, requesting the applicant to provide

justification why these tests and inspections are not credited for license renewal, and why the

internal surfaces are not inspected.

In the letter dated June 30, 2008, the applicant stated in response to part a.1 of RAI B.2.16-1

that Halon/CO2 spray nozzles, tubing and valve body fabricated from stainless steel and copper

alloy are not susceptible to aging in indoor air environment. The staff reviewed the GALL Report

and noted that items VII.J-1 5 and V.F-3 identify no aging effects for stainless steel and copper

alloy material in indoor air external environment. The applicant stated in part a.2 of RAI

B.2.16-1 that consistent with the GALL Report; there are no aging effects for material in a dry

gas internal environment. The staff reviewed the GALL Report and noted that items VII.J-4 and

VII.J-19 identify no aging effect for a dry gas environment. The applicant further stated in part

a.3 of RAI B.2.16-1 that the System Walkdown Program is credited for managing the aging

effects on the external surfaces of steel components in Halon/C0 2 system. The staff noted that

this is consistent with the GALL Report that recommends the GALL AMP XI.M36, External

Surfaces Monitoring.

The applicant finally stated in response to part b of RAI B.2.16-1 that for the diesel enginedriven fire pump, the Fuel Oil Chemistry Program and Chemistry Program Effectiveness

Inspection are credited to manage the aging effects. The staff reviewed LRA Table 3.3.2-13

and noted that aging effects of copper tubing in a fuel oil environment is managed by the Fuel

Oil Chemistry and Chemistry Effectiveness Inspection Programs, which is consistent with the

GALL Report.

Because the applicant is consistent with the GALL Report recommendations, the staff finds the

applicant response acceptable and concurs that because there are no aging effects, the

internal surfaces of Halon/C0 2 system components do not need to be inspected and the

internal surfaces of diesel engine-driven fire pump tubing are inspected as part of the sample

population in the Chemistry Effectiveness Inspection Program. Based on this review, the staff

finds this exception acceptable.

Based on the review of the exception, and resolution of the related RAI as described above, the

staff finds the Fire Program consistent with program elements of GALL AMP XI.M26, with

acceptable exceptions, and therefore acceptable.

Operating Experience. The staff reviewed the applicant's OE described in LRA Section B.2.16

and interviewed the applicant's technical personnel to confirm that the plant-specific OE did not

reveal any aging effects not bounded by the GALL Report. The staff also confirmed that

applicable aging effects and industry and plant-specific OE have been reviewed by the

applicant and are evaluated in the GALL Report.

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The staff also reviewed the applicant's OE described in the applicant's license renewal basis

document for the Fire Protection Program. The staff reviewed a sample of condition reports and

confirmed that the applicant had identified age related degradation and implemented

appropriate corrective actions. The staff found examples of fire door issues, penetration seal

cracking and fire door seal degradation. The staff noted that several condition reports have

been written against fire door degradation that determined that the fire door degradations were

related to human performance and inadequate fire door installation. Isolated cases of fire rated

penetration seal cracking and fire door seal degradation have also been identified. Corrective

actions included additional personnel training, repair, and/or replacement activities. The staff

did not find any age related degradation in Halon/C0 2 systems.

Furthermore, the staff confirmed that the applicant has addressed OE identified after the

issuance of the GALL Report. The staff finds that the applicant's Fire Protection Program, with

the corrective actions discussed in the LRA, has been effective in identifying, monitoring, and

correcting the effects of age related degradation in fire protection systems and can be expected

to ensure that the systems and components within the scope of this program will continue to

perform their intended functions consistent with the current licensing basis for the period of

extended operation.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP LR Section A.1.2.3.10. The staff finds this program

element acceptable.

UFSAR Supplement. In LRA Section A1.2.18 and Commitment No. 15 in Table A-i, the

applicant provided the UFSAR supplement for the Fire Protection Program. The staff verified

that the UFSAR supplement summary description for the Fire Protection Program was in

conformance with the staff's recommended UFSAR supplement for the Fire Protection Program

provided in Table 3.3-2 of the SRP-LR. In Table A-i, the applicant has committed via

Commitment No. 15 to implement the existing program through the period of extended

operation.

Based on this review, the staff finds that UFSAR supplement Section A1.2.18 provides an

acceptable UFSAR supplement summary description of the applicant's Fire Protection Program

because it is consistent with those UFSAR supplement summary description in the SRP-LR for

the Fire Protection Program.

The staff determines that the information in the UFSAR supplement is an adequate summary

description of the program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of the review of the applicant's Fire Protection Program and the

applicant's response to the staff's RAI, the staff finds all program elements consistent with the

GALL Report. In addition, the staff reviewed the exception and its justification and determines

that the AMP, with the exception, is adequate to manage the aging effects for which the LRA

credits it. The staff concludes that the applicant has demonstrated that the effects of aging will

be adequately managed so that the intended functions will be maintained consistent with the

CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also

reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate

summary description of the program, as required by 10 CFR 54.21(d).

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3.0.3.2.9 Fire Water System Program

Summary of Technical Information in the Application. LRA Section B.2.17 describes the Fire

Water System Program as an existing program that is consistent with enhancements with the

GALL Report AMP XI.M27, Fire Water System. The applicant stated that this program performs

periodic inspection and testing of the water-based fire suppression systems including hydrant

and hose station inspections, fire main flushing, flow tests, and sprinkler inspections. The

applicant also stated that tests and inspections are generally in accordance with the applicable

National Fire Protection Association (NFPA) recommendations.

Staff Evaluation. During its audit the staff reviewed the applicant's claim of consistency with the

GALL Report. The staff reviewed the enhancements to determine whether the AMP, with the

enhancements is adequate to manage the aging effects for which the LRA credits it. In

comparing the elements in the applicant's program to those in the GALL AMP XI.M27, the staff

noted that the program elements in the applicant's AMP which claimed to be consistent with the

GALL Report were consistent with the corresponding program element. However the "scope of

program" program element aspect as identified below the staff determined needed additional

clarification. The staff also confirmed that the plant program contains all of the elements of the

referenced the GALL Report. Onsite interviews were also held to confirm these results.

The LRA credits the Fire Water System Program for managing loss of material for valve bodies

(deluge) in the SGTS. However, the staff noted the SGTS is not included in the list of systems

in the scope of this program, as identified in the program basis document. The staff issued

RAI B.2.17-1 by letter dated May 30, 2008, requesting the applicant to clarify why the SGTS is

not in-scope.

In the letter dated June 30, 2008, the applicant responded to RAI B.2.17-1 by stating that the

SGTS components are included in the scope of the Fire Water System Program. The applicant

also stated that these components include piping and valves associated with deluge of the

charcoal absorbers. However, since LRA Table 3.2.2-7 only addressed deluge valves, the LRA

Table was amended to include carbon steel deluge piping. The applicant also stated that it

credited the Fire Water System Program to manage loss of material for internal surfaces in a

raw water environment, and the System Walkdown Program to manage loss of material of

external surfaces in an indoor air environment.

Because the added AMR line item is consistent with the GALL Report line VII.G-24 for internal

surfaces, and V.B-3 for external surfaces, the staff finds the addition of this line to be

acceptable. However, the response did not indicate whether the LRA will be amended to

include the SGTS within the scope of the program or provide justification why it was not

included. The staff issued a follow-up RAI B2.17-1R by letter dated July 23, 2008, to resolve

this issue.

In the letter dated August 22, 2008, the applicant responded to RAI B2.17-1 R by stating that

LRA Section B.2.17, Fire Water System Program is an existing program. The specific systems

within the scope of the program are not included in the LRA, however, these systems are

identified in the program basis document. The applicant acknowledged that the SGTS should

have been included in the program basis document, but was inadvertently omitted. The

applicant stated that the deluge valves and piping, located in the fire protection lines to the high

efficiency charcoal adsorber filters, were evaluated with SGTS but is subject to the raw water

environment of the fire protection system and therefore credited the Fire Water System

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Program. The applicant also stated that the SGTS deluge valves and piping are included in the

LRA Table 3.2.2-7, are identified in the Technical Requirements Manual Table 3.7.3.2-1, and

are included in the fire water system procedure that performs the 18-month functional test and

the 18-month visual inspection of the SGTS deluge system.

The staff noted that the valves and piping in question are located in an environment of fire

water but evaluated in the SGTS AMR, and that these lines are included in the fire protection

system testing and inspection procedures as per the requirements in the Technical

Requirements Manual. On this basis, the staff finds that enhancement to the program is not

needed and finds the applicant response to be acceptable.

LRA Table 3.3.2-13 credits the Fire Water System Program to manage reduction in heat

transfer for heat exchanger tubes. However, LRA Section B.2.17 states that this program is

consistent with the GALL AMP XI.M27, which focuses on managing the aging effect of loss of

material and not reduction in heat transfer. The staff issued RAI B.2.17-2 by letter dated

May 30, 2008, requesting the applicant to justify how this program will manage reduction in heat

transfer.

In the letter dated June 30, 2008, the applicant responded to RAI B.2.17-2 by stating that upon

further consideration, the Heat Exchanger Inspection Program has been identified as a more

appropriate program for managing reduction of heat transfer for the diesel engine driven fire

pump heat exchangers. The applicant amended the LRA to credit the Heat Exchanger

Inspection Program in lieu of the Fire Water System Program. The evaluation of the Heat

Exchanger Program is documented in SER Section 3.0.3.1.12.

The staff reviewed the enhancements to determine whether the AMP, with the enhancements,

is adequate to manage the aging effects for which the LRA credits it.

Enhancement 1. In LRA Section B.2.17, the applicant added a program requirement in the

"detection of aging effects," "monitoring and trending," and "acceptance criteria" program

elements to require testing or replacement of sprinkler heads in service for 50 years.

The GALL AMP XI.M27 recommends testing or replacement of sprinkler heads in service for 50

years. On the basis that the enhancement, when implemented, will make the Fire Water

System Program consistent with the GALL Report, the staff finds the enhancement acceptable.

Enhancement 2. In LRA Section B.2.17, the applicant added a program requirement in the

"parameters monitored or inspected" and "detection of aging effects" program elements to

perform ultrasonic testing of representative portions of above ground fire protection piping that

are exposed to water but do not normally experience flow.

By letters dated June 30, 2008, in response to RAI B.2.17-3 and October 21, 2008, in response

to NRC regional inspection of the LRA, the applicant amended the LRA to revise Enhancement

2 as follows:

Ultrasonic testing of representative portions of above ground fire protection

piping that are exposed to water but do not normally experience flow, are

associated with a dry-piping sprinkler system and may contain stagnant water, or

is pre-action or deluge piping that is normally dry, but may have been wetted and

not completely dry, will be performed after the issuance of the renewed license

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but prior to the end of the current operating term and at reasonable intervals

thereafter, based on engineering review of the results.

The GALL AMP XI.M27 recommends wall thickness evaluations of fire protection piping using

non-intrusive testing (e.g., ultrasonic testing) to identify loss of material due to corrosion. By

performing this testing on piping that does not normally experience flow, or may contain

stagnant water or may have been wetted but not completely dry, the applicant has selected

locations that would experience a more aggressive internal environment than piping with full

flow. On the basis that the enhancement, when implemented, will make the Fire Water System

Program consistent with the GALL Report, the staff finds the enhancement acceptable.

Enhancement 3. By letter dated October 21, 2008, in response to NRC regional inspection of

the LRA, the applicant amended the LRA to add another enhancement as follows:

Also, within the 10-year period prior to the period of extended operation, at least

one visual inspection (opportunistic or focused) of the internal surface of buried

fire water piping will be performed. In addition, at least one inspection per year of

'wet' fire protection piping for wall thickness and pipe blockage will be performed

if no opportunistic inspection has been completed.

The applicant also revised the UFSAR supplement and the commitment list to include this

enhancement.

The GALL AMP XI.M27 recommends that as an alternative to non-intrusive testing, the plant

maintenance process may include a visual inspection of internal surface of the fire protection

piping upon each entry to the system for routine or corrective maintenance. By performing the

visual inspection on an opportunistic or focused basis on selected representative locations, and

on the basis that the enhancement, when implemented, will make the Fire Water System

Program consistent with the GALL Report, the staff finds the enhancement acceptable.

Based on its review, the staff finds the applicant's Fire Water System Program acceptable

because it conforms to the recommended GALL AMP XI.M27, Fire Water System with

enhancements.

Operating Experience. The staff reviewed the applicant's OE described in LRA Section B.2.17

and interviewed the applicant's technical personnel to confirm that the plant-specific OE did not

reveal any aging effects not bounded by the GALL Report. The staff also confirmed that

applicable aging effects and industry and plant-specific OE have been reviewed by the

applicant and are evaluated in the GALL Report. Furthermore, the staff confirmed that the

applicant has addressed OE identified after the issuance of the GALL Report. In the "operating

experience" element of LRA Section B.2.17, the LRA states that a search of condition reports

was performed for the Fire Protection System. When conditions were found that required

correction they were repaired in accordance with the site corrective action program. However,

the applicant did not provide any specific OE related to the Fire Water System Program. The

staff issued RAI B.2.17-3 requesting the applicant to provide some specific examples of issues

that were found in the condition reports.

In the letter dated June 30, 2008, the applicant responded to RAI B.2.17-3 by providing several

specific examples of plant OE. The applicant stated that small leaks were identified in different

fire protection piping, which were repaired or the piping replaced; and ultrasonic inspection was

performed on surrounding areas as part of the corrective action.

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On the basis that the applicant has identified specific examples of plant OE and corrective

actions taken, the staff finds the applicant response acceptable.

The staff reviewed some condition reports as part of the OE review and found that several CRs

were written to address through wall leaks in fire water headers in the circulating water

pumphouse area. Stagnant water in low drainage locations inside the pumphouse was

determined to be the cause. The staff issued RAI B.2.17-4 requesting the applicant to address

this issue, (a) to determine what changes are proposed and (b) if these locations are included in

the representative sample picked for UT inspections for wall thickness measurements.

In the letter dated June 30, 2008, the applicant responded to RAI B.2.17-4 by stating that no

changes were proposed to the fire water system to alleviate through wall leaks. The applicant

stated that the leaks were observed in piping that is normally dry, however, stagnant water

collected in low drainage locations, which made the piping system more susceptible to

corrosion. The applicant further stated any leaking piping is identified to engineering for

evaluation, including an operability evaluation. The applicant further stated that the Fire Water

System program manages the aging by performing evaluations of issues that are identified

during station activities. The applicant amended LRA Section B.2.17, Fire Water System

Program, to revise the enhancement for wall thickness measurement by UT, to include

representative portions of above ground piping in the dry-pipe sprinkler system, which may

contain stagnant water. The applicant also revised the UFSAR Supplement and the

Commitment List to include the revised enhancement.

The staff reviewed the amendment and finds that with the changes to the enhancement to

include stagnant water locations in the representative sample for UT, the Fire Water System

Program will provide further assurance that aging effects are managed and these components

will continue to perform their intended functions consistent with the current licensing basis for

the period of extended operation. Based on this review, the staff finds the applicant response

acceptable.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP LR Section A.1.2.3.10. The staff finds this program

element acceptable.

UFSAR Supplement. In LRA Section A.1.2.19, Commitment No. 46 in Table A-i, and letters

dated June 30, 2008, and October 21, 2008, the applicant provided the UFSAR supplement for

the Fire Water System Program. The staff verified that the UFSAR supplement summary

description for the Fire Water System Program was in conformance with the staff's

recommended UFSAR supplement for the Fire Water System Program provided in Table 3.3-2

of the SRP-LR.

The applicant committed to enhance its program to require testing or replacement of sprinkler

heads in service for 50 years, and to perform UT of representative portions of above ground fire

protection piping that are exposed to water but do not normally experience flow or are

associated with a dry-pipe sprinkler system and may contain stagnant water, or is pre-action or

deluge piping that is normally dry, but may have been wetted and not completely dry. The

applicant also committed to enhance its program to perform within the 10-year period prior to

the period of extended operation, at least one visual inspection (opportunistic or focused) of the

internal surface of buried fire water piping, and at least one inspection per year of 'wet' fire

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protection piping for wall thickness and pipe blockage if no opportunistic inspection has been

completed.

Based on this review, the staff finds that UFSAR supplement Section A.1.2.19 provides an

acceptable UFSAR supplement summary description of the applicant's Fire Water System

Program because it is consistent with those UFSAR supplement summary description in the

SRP-LR for the Fire Water System Program.

The staff determines that the information in the UFSAR supplement is an adequate summary

description of the program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of the review of the applicant's Fire Water System Program, and the

applicant's response to the staff's RAIs, the staff finds all program elements consistent with the

GALL Report. Also, the staff reviewed the enhancements and confirmed that their

implementation through Commitment No. 46 prior to the period of extended operation will make

the existing AMP consistent with the GALL Report AMP to which it was compared. The staff

concludes that the applicant has demonstrated that the effects of aging effects will be

adequately managed so that the intended functions will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also

reviewed the UFSAR supplement, as amended, for this AMP and concludes that it provides an

adequate summary description of the program, as required by 10 CFR 54.21(d).

3.0.3.2.10 Buried Piping Surveillance Program

Summary of Technical Information in the Application. The LRA Section B.2.18 described the

new Buried Piping Surveillance Program as consistent with GALL AMP XI.M28, "Buried Piping

and Tanks Surveillance," with an exception. This program consists of a prevention program

(consisting of cathodic protection) and a condition monitoring program (consisting of periodic

testing) to manage the loss of material on external surfaces of piping with damaged coatings.

Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the

GALL Report. The staff also confirmed that the plant program contains all of the elements of the

referenced GALL Report. Onsite interviews were also held to confirm these results.

In comparing the elements in the applicant's program to those in GALL AMP XI.M28, the staff

noted that the program elements in the applicant's AMP claimed to be consistent with GALL

were consistent with the corresponding program element criteria recommended in the program

elements of GALL AMP XI.M28 with the exception of the "scope of program" program element

aspect as identified below.

The staff reviewed the exception to determine whether the AMP, with the exception will be

adequate to manage the aging effects for which the LRA credits.

Exception. The applicant stated an exception to the "scope" program element stating that the

"scope of program" element is limited to the sections of buried RHRSW and ESW common

return header piping for which damaged coatings are known to exist. Therefore, the applicant

does not credit coatings in this program for aging management. All other buried piping and

tanks subject to aging management are managed by the Buried Piping and Tanks Inspection

Program. The staff did not agree that this is an exception to the GALL AMP because the GALL

Report recommends either the use of the Buried Piping and Tanks Surveillance Program or the

Buried Piping and Tanks Inspection Program for buried piping and tanks. The staff discussed

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this issue with the applicant and followed up with RAI B.2.18-1 in a letter dated June 13, 2008,

that asked the applicant to explain why this is an exception to the GALL Report AMP. In the

applicant's response to this RAI in a letter dated July 14, 2008, the applicant agreed that this

should not be an exception and amended the LRA to state under "[e]xceptions to NUREG1801," "None."

On the basis of the review, the staff concludes that the applicant's Buried Piping Surveillance

Program provides assurance that either the aging effect is indeed not occurring, or that the

aging effect is occurring so slowly as not to affect the intended function of the component or

structure. The staff finds the applicant's Buried Piping Surveillance Program acceptable

because it conforms to the recommended GALL AMP XI.M28, Buried Piping Surveillance

Program following resolution of the RAI.

The staff has identified one additional area of concern that relates to the rectifiers and the

ground bed anodes and all other equipment associated with the implementation of this AMP.

The staff assumes that these components are not currently safety-related and are not covered

by the 10 CFR-Appendix B program as discussed in Appendix B.1.3 of the LRA. RAI B.2.18-2

was issued to the applicant by a letter dated June 13, 2008, and requested the applicant to

clarify whether these components will remain nonsafety-related, but now fall under the 10 CFR

Part 50 Appendix B program, or whether they will be upgraded to safety-related. In addition, the

staff asked the applicant to indicate whether the failure of one of these components will initiate

a technical specification limited condition of operation and whether there will be a commitment

to cover this equipment under the SSES 10 CFR Appendix B program. In its response dated

July 14, 2008, the applicant responded to RAI B.2.18-2 by stating that rectifiers, ground bed

anodes, and other equipment in-scope for AMP B.2.18 are nonsafety-related and that failure of

these components does not result in entry into a technical specification limited condition of

operation. The applicant also stated that the cathodic protection system has no safety-related

function but are in-scope for license renewal under 10 CFR Part 54.4(a)(2). In the LRA

Section B.1.3, the applicant states:

"The elements of corrective actions, confirmation process, and administrative

controls in the SSES QA Program will be applied to each existing, enhanced,

and new aging management program and activity credited for license renewal,

for both safety-related and nonsafety-related structures and components

determined to require aging management during the period of extended

operation."

The staff noted the systems and components used as part of the Buried Piping Surveillance

Program are in-scope for 10 CFR Part 50 Appendix B and there will be no changes to the LRA

as a result of this response.

The staff requested this information for clarification and the applicant's response addressed the

staffs questions and concerns. On the basis of its review, and because the applicant has

included all SSCs in-scope for license renewal under its existing 10 CFR Appendix B Program

regardless of safety classification, the staff finds the applicant's response acceptable.

Operatinq Experience. The staff also reviewed the applicant's OE, including a sample of

condition reports, and interviewed the applicant's technical staff to confirm that the plantspecific OE did not reveal any degradation not bounded by industry experience. In the

application, the applicant stated that there is no OE demonstrating the effectiveness of the

program because it is a new program.

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The applicant stated that the Buried Piping Surveillance Program is a new program for which

there is no OE and that inspection methods will be consistent with accepted industry practices.

For this program and for other new AMPs where the applicant provided no current plant-specific

OE, the staff issued RAI B.2.1 by letter dated June 10, 2008, asking that the applicant commit

to provide documentation of plant-specific operating experience for staff review after the

program has been implemented, but prior to entering the period of extended operation.

In its letter dated July 8, 2008, the applicant stated that OE for new AMPs described in LRA

Appendix B will be gained as these new programs are implemented during the period of

extended operation. The applicant stated that results of tests, inspections, and other aging

management activities conducted in accordance with these programs will be subject to

confirmation and corrective action elements of the Susquehanna 10 CFR Part 50, Appendix B,

quality assurance program and that results will be subject to NRC review during regional

inspections under existing NRC inspection modules. The applicant stated that these new

programs will be implemented prior to, and continue through, the period of extended operation

and that OE will be gained for these programs as they are implemented. The applicant further

stated that test and inspection results that do not meet acceptance criteria for these new

programs will be evaluated under the station's corrective action program, which includes

requirements for identification of appropriate corrective actions and verification of the

effectiveness of corrective actions.

The staff noted that the applicant's statement that inspection methods will be consistent with

industry practices is consistent with the "operating experience" program element for GALL

AMP XI.28. The staff also noted that post-approval site inspections provide an opportunity for

staff review and assessment of the effectiveness of the applicant's Buried Piping Surveillance

Program after the applicant has developed OE with that program. The staff concludes that the

corrective action program, based on internal and external plant OE, would capture OE in the

future to support the conclusion that the effects of aging are adequately managed. On this

basis, the staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program

element acceptable and concludes that a separate commitment is not necessary.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP LR Section A. 1.2.3.10. The staff finds this program

element acceptable.

UFSAR Supplement. In LRA Section A.1.2.4 and Commitment No. 16 in Table A-i, the

applicant provided the UFSAR supplement for the Buried Piping Surveillance Program. The

staff reviewed this section and determined that the information in the UFSAR Supplement

provides an adequate summary description of the program consistent with the SRP-LR and as

required by 10 CFR 54.21(d).

Conclusion. The staff has reviewed the information provided in Section B.2.18 of the LRA

Appendix B and additional information provided by the applicant by letter dated July 14, 2008.

On the basis of its review as discussed above, the staff concludes that the applicant has

demonstrated that effects of aging of the buried piping will be adequately managed so that the

intended functions of these components will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed

UFSAR supplement and concludes that it provides an adequate summary description of the

program, as required by 10 CFR 54.21(d).

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3.0.3.2.11 Fuel Oil Chemistry Program

Summary of Technical Information in the Application. LRA Section B.2.20 describes the existing

Fuel Oil Chemistry Program as consistent, with exceptions, with GALL AMP XI.M30, "Fuel Oil

Chemistry." The applicant stated that the program is a mitigation program that manages

potential aging effects for plant components in a fuel oil environment. The applicant also stated

that the program manages loss of material and cracking through monitoring and control of fuel

oil contamination, such as water or microbiological organisms, consistent with pertinent plant

technical specifications/requirements and American Society for Testing of Materials (ASTM)

standards. The applicant further stated that exposure to contaminants is minimized by verifying

the quality of new fuel oil before it enters the storage tanks and by periodic sampling to ensure

that the tanks are free of water and particulates.

Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the

GALL Report. The staff reviewed the applicant's AMP evaluation report for the Fuel Oil

Chemistry Program, together with implementing procedures and supporting documentation

related to the program. The staff did not identify any issues requiring further resolution or

clarification for elements of the program that the applicant claimed to be consistent with the

corresponding program element criteria in GALL AMP XI.M30.

The applicant's Fuel Oil Chemistry Program, as described in the LRA, includes three (3)

exceptions to the GALL Report identified by the applicant. These exceptions affect the "scope

of program," the "parameters monitored/inspected" and "acceptance criteria," and the

"monitoring and trending" program elements of the AMP. In response to an issue raised during

a regional inspection of the applicant's program, the applicant identified an additional exception

to the "acceptance criteria" program element and revised the LRA to identify this fourth

exception. The staff reviewed the four (4) exceptions to determine whether the AMP, with

exceptions, is adequate to manage the aging effects for which the LRA credits it. The staff's

evaluation of the exceptions is presented in the following paragraphs.

Exception 1. LRA Section B.2.20 states an exception to the "scope of program" program

element. The applicant stated that although its Fuel Oil Chemistry Program largely focuses on

fuel oil tanks, the program is also applicable to other components exposed to fuel oil, including

the fuel oil supply components of the diesel engine-driven fire pump. The applicant categorized

expansion of the Fuel Oil Chemistry Program to include oil supply components of the diesel

engine-driven fire pump as an exception to the GALL Report.

In evaluating this exception, the staff noted that in the GALL Report the "scope of program"

program element for GALL AMP XI.M30 focuses exclusively on managing the aging of the

interior surfaces of the diesel generator fuel oil supply tanks. The staff also noted that the

material, environment and potential aging effects are identical for both the diesel generator fuel

oil supply components and the diesel engine-driven fire pump fuel oil supply components and

that GALL Table VII.G, item VII.G-21 credits use of the Fuel Oil Chemistry Program for aging

management in the fire protection system. On the basis that the expanded scope of the

applicant's Fuel Oil Chemistry Program encompasses components with material, environment

and potential aging effects identical to the components explicitly identified in the GALL Report,

the staff finds the "scope of program" of the applicant's Fuel Oil Chemistry Program, including

this exception to the GALL Report, to be acceptable.

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Exception 2. LRA Section B.2.20 states an exception to the "parameters monitored/inspected"

and the "acceptance criteria" program elements. The applicant stated that with respect to the

test described in ASTM Standard D2276-00, "Standard Test Method for Particulate

Contaminant in Aviation Fuel by Line Sampling," their program uses the 0.8 pIm pore size filter

called out in the ASTM standard, rather than the 3.0 pm pore size filter recommended in the

GALL Report's description for this program element.

The applicant categorized the use a filter pore size different from what is recommended in the

GALL Report as an exception to the "parameters monitored/ inspected" and the "acceptance

criteria" program elements as described in the GALL Report.

The staff reviewed ASTM Standard D2276-00 and noted that the standard provides a method

for gravimetric measurement of particulate matter in diesel fuel by comparing the weight of a

test filter on which particulate matter is collected against the weight of a control filter through

which the filtered fuel is subsequently passed, then converting the measurements to milligrams

of particulate per liter of filtered fuel. The standard states that tolerable levels of particulate

contaminants have not yet been established for all points in fuel distribution systems. Since

specific levels of particulate are not specified by the standard, the primary purpose of the test is

to ensure that particulate contamination is not increasing outside its normal operating range.

The staff noted that use of a filter with different pore size from what is recommended in the

GALL Report does not invalidate the test procedure, and that the applicant's use of a filter with

smaller pore size than what is recommended in the GALL Report provides a conservative

measurement of particulate concentration relative to the methodology recommended in the

GALL Report. Because the test methodology remains valid with the smaller pore filter and the

measurements with the smaller pore filter are conservative relative to the GALL Report's

recommendation, the-staff finds the "parameters monitored/inspected" and the "acceptance

criteria" elements of the applicant's Fuel Oil Chemistry Program to be acceptable.

Exception 3. LRA Section B.2.20 states an exception to the "monitoring and trending" program

element. The applicant stated that an annual frequency for sampling of fuel for biological

activity is used, along with monthly or quarterly sampling for other contaminants. This is an

exception to the GALL Report's recommendation that water and biological activity or particulate

contamination concentrations be monitored and trended in accordance with the plant's technical

specifications or at least quarterly.

The staff reviewed the applicant's technical specifications and technical requirements manual

and noted that sampling is specified to be done in accordance with industry standards, but no

specific frequency of sampling for biological activity is identified in those documents. The staff

issued RAI B.2.20-1 by letter dated June 23, 2008, asking the applicant what ASTM standard is

used to establish frequency for monitoring fuel oil for biological activity and to provide a basis

and technical justification for its current sampling frequency if no such standard exists or is

used.

The applicant responded in a letter dated July 17, 2008. In that letter the applicant provided the

following discussion in response to RAI B.2.20-1:

The schedule for sampling the emergency diesel generator fuel oil in the fuel oil

storage tanks for biological activity was changed from annually to quarterly

in 2007. No ASTM standard was identified since the sampling frequency now

matches the frequency recommended by GALL. The exception to monitoring and

trending is no longer needed and is deleted.

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The following changes are made to the LRA to delete the monitoring and

trending exception for the Fuel Oil Chemistry Program.

The third bullet under the Exceptions to NUREG-1801, in Section B.2.20 (LRA

Page B-65) is revised by deletion [in its entirety].

On the basis that the applicant revised the fuel oil sampling frequency for biological activity to

be consistent with the recommendations in the GALL Report and revised the LRA to delete the

previously identified exception, the staff finds the "monitoring and trending" program element of

the applicant's Fuel Oil Chemistry Program to be acceptable.

Exception 4. In a letter dated October 21, 2008, the applicant identified an additional exception

to the "detection of aging effects" program element. The applicant stated that UT thickness

measurements are not taken on the bottoms of the diesel generator fuel oil storage tanks

because the fuel oil storage tanks are buried and inaccessible; also internal surfaces are

coated, and coatings would have to be removed in order to perform UT examinations. The

applicant stated that UT examinations of diesel generator fuel oil day tank bottoms will be

conducted as part of the Chemistry Program Effectiveness Inspection. The applicant also made

changes to LRA Section B.2.22, Chemistry Program Effectiveness Inspection, to state that the

bottom of at least two diesel generator fuel oil day tanks will be examined by UT measurements

as part of the CPEI AMP.

In the GALL Report the "detection of aging effects" program element states that degradation of

the diesel fuel oil tank cannot occur without exposure of the tank internal surfaces to

contaminants such as water and microbiological organisms. The program element also states

that an ultrasonic thickness measurement of the tank bottom surfaces ensures that significant

degradation is not occurring.

The staff noted that both the diesel generator fuel oil storage tanks and the diesel generator

fuel oil day tanks are made of carbon steel and are exposed to an interior environment of fuel

oil. The staff noted that the interior surface of the storage tanks are provided with a protective

coating, but the coating is not credited in the LRA for aging mitigation; and the interior surfaces

of the day tanks are not coated. The staff also noted that both the fuel oil storage tanks and the

day tanks are designed so that the interior of the tanks can be visually inspected. The interior of

the fuel oil storage tanks is required by TS to be cleaned every 10 years, and during the

cleaning the surface condition of the tank interior is visually examined. The staff noted that

except for some additional straining and filtering as fuel oil is pumped from the storage tanks to

the day tanks, the interior environments of the storage tanks and the day tanks are identical;

and because both tanks are made of carbon steel, aging effects in the storage tanks and the

day tanks would be similar. Because aging effects in the day tanks and in the storage tanks are

similar, the staff concluded that one-time UT of the bottoms of the day tanks will provide a

reasonable indication of whether wall thinning may be occurring in the storage tank bottoms. In

addition, the requirement for cleaning of the storage tanks every 10 years and visual inspection

of the interior of the storage tanks provides opportunity to detect any degradation in the

protective coating that would be an indication of potential degradation in the storage tank steel

bottoms. Because degradation of the steel storage tank bottoms would be detected before

failure of its intended function could occur, the staff concludes that UT examination of the day

tank bottoms provides an acceptable alternative to UT examination of the storage tank bottoms

and that Exception 4 to the "detection of aging effects" program element is acceptable.

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Based on its review of the exceptions, and resolution of the related RAIs as described above,

the staff finds the Fuel Oil Chemistry Program consistent with program elements of GALL

AMP XI.M30, with acceptable exceptions, and therefore acceptable.

Operatinq Experience. The staff reviewed the applicant's OE described in LRA Section B.2.20.

The applicant stated that review of plant-specific OE did not reveal a loss of component

function or fouling of subject components that contain fuel oil which could be attributed to an

inadequacy of the Fuel Oil Chemistry Program. The applicant also stated that fuel oil delivered

to the site is sampled and analyzed prior to addition to fuel oil storage tanks and periodically

thereafter and that water and sediment is removed, particulates are filtered, and biological

activity is controlled.

During the onsite audit, the staff reviewed the applicant's "operating experience" program

element for the Fuel Oil Chemistry Program. The staff reviewed selected procedures and

completed work packages related to periodic fuel oil chemistry testing and preventive

maintenance on components in the fuel oil storage system. The staff noted that the onsite

documentation supports the applicant's statements with regard to OE for the Fuel Oil Chemistry

Program and that the applicant's OE does not reveal any age related degradation not bounded

by industry experience.

Based on this review, the staff finds that (1) the OE for this AMP demonstrates that the

applicant's Fuel Oil Chemistry Program is achieving its objective of maintaining fuel oil quality

and mitigating potential corrosion of components exposed to fuel oil, and (2) that the applicant

is taking appropriate corrective actions through implementation of this program.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program

element acceptable.

UFSAR Supplement. In LRA Section A.1.2.21,and Commitment No. 47 in Table A-i, the

applicant provided the UFSAR supplement for the Fuel Oil Chemistry Program. The staff noted

that the UFSAR supplement's description for the Fuel Oil Chemistry Program conforms with the

recommended UFSAR supplement for this type of program as described in SRP-LR (NUREG1800, Revision 1). The staff also noted that in Commitment No. 47 of LRA Table A-i, License

Renewal Commitments, the applicant committed to ongoing implementation of the Fuel Oil

Chemistry Program for aging management of applicable components during the period of

extended operation.

Based on this review, the staff finds that the UFSAR supplement summary in LRA

Section A.1.2.21 provides an acceptable description of the applicant's Fuel Oil Chemistry

Program because it is consistent with the UFSAR supplement summary description in the SRPLR for the Fuel Oil Chemistry Program.

The staff determines that the information in the UFSAR supplement is an adequate summary

description of the program as required by 10 CFR 54.21(d).

Conclusion. On the basis of the review of the applicant's Fuel Oil Chemistry Program, including

the LRA changes provided in response to RAI B.2.20-1, the staff finds that those program

elements for which the applicant claimed consistency with the GALL Report are consistent. In

addition, the staff reviewed the exceptions and their justifications and determined that the AMP,

with the exceptions, is adequate to manage the aging effects for which the LRA credits it. The

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staff concludes that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the

UFSAR supplement for this AMP and concludes that it provides an adequate summary

description of the program, as required by 10 CFR 54.21(d).

3.0.3.2.12 Reactor Vessel Surveillance Program

Summary of Technical Information in the Application. LRA Section B.2.21 describes the existing

Reactor Vessel Surveillance Program as consistent, with exception, with GALL AMP XI.M31,

"Reactor Vessel Surveillance."

The Reactor Vessel Surveillance Program, which manages reduction of fracture toughness for

the low-alloy steel RV shell and welds in the beltline region, is a condition-monitoring program

developed in response to 10 CFR Part 50 Appendix H, "Reactor Vessel Material Surveillance

Program Requirements," and part of the Integrated Surveillance Program (ISP) described in

BWRVIP-78, "BWR Integrated Surveillance Program Plan," BWRVIP-86-A, "BWR Vessel and

Internals Project, BWR Integrated Surveillance Program Implementation," and BWRVIP-1 16,

"BWR Vessel And Internals Project, Integrated Surveillance Program Implementation For

License Renewal." BWRVIP-1 16 extends the ISP to cover the period of extended operation.

The applicant will follow BWRVIP ISP requirements and apply ISP data to SSES, Units 1 and 2.

The staff approved the use of the BWRVIP ISP in place of a plant-specific program.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. The staff reviewed the exception to determine whether the

AMP, with the exception, remained adequate to manage the aging effects for which it is

credited.

In LRA Appendix B, AMP B.2.21, the applicant described its AMP to manage irradiation

embrittlement of the RPV through testing that monitors RPV beltline material properties. The

LRA stated that the RPV surveillance program will follow the requirements of the BWRVIP ISP

and will apply the ISP data to the SSES units.

10 CFR Part 50, Appendix H requires that an ISP, which is used as a basis for a facility's RPV

surveillance program, be reviewed and approved by the staff. The ISP to be used by the

applicant is a program that was developed by the BWRVIP, and the applicant will apply the

BWRVIP ISP as the method by which the SSES units will comply with the requirements of

10 CFR Part 50, Appendix H.

The applicant has implemented the BWRVIP ISP based on the BWRVIP-78 report and the

BWRVIP-86-A report. These reports are consistent with the GALL AMP XI.M31 for the period of

the current licenses. The staff concluded that the BWRVIP ISP in BWRVIP-78 and the

BWRVIP-86-A reports is acceptable for BWR licensee implementation provided that all

participating licensees use one or more compatible neutron fluence methodologies acceptable

to the staff for determining surveillance capsule and RPV neutron fluences. The staff's

acceptance of the BWRVIP ISP for the current term at SSES is documented in the staff's SER

dated February 6, 2003, which is addressed in SSES License Amendment 208.

In addition, the BWRVIP developed an updated version of the ISP in the BWRVIP-116 report,

which provides guidelines for an ISP to monitor neutron irradiation embrittlement of the RPV

beltline materials for all U.S. BWR power plants for the license renewal period. The BWRVIP

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ISP identifies capsules that must be tested to monitor neutron radiation embrittlement for all

licensees participating in the ISP and identifies capsules that are available on a "contingency"

basis (deferred capsules). However, no guidance is provided in the BWRVIP-1 16 for continued

use, storage, or testing of deferred capsules. Table 3-3 of the BWRVIP-1 16 report indicates

that both SSES units have deferred capsules.

The applicant stated in LRA AMP B.2.21, and in the UFSAR supplement Section A.1.2.41,

"Reactor Vessel Surveillance Program," that the Reactor Vessel Surveillance Program is part of

the ISP described in BWRVIP-78, BWRVIP-86-A, and BWRVIP-1 16 and it will follow the

requirements of the BWRVIP ISP. BWRVIP-1 16-A has not been issued yet. Therefore,

following the requirements of the BWRVIP ISP, as stated in LRA AMP B.2.21, may not obligate

the applicant to address the additional requirements in the SER on BWRVIP-1 16 dated

March 1, 2006. Hence, the staff issued RAI B.2.21-1, requesting that the applicant make a

commitment to address these additional requirements.

By letter dated October 16, 2007, the applicant stated in its response to RAI B.2.21-1 that it

would update AMP B.2.21 and UFSAR Section A. 1.2.41 to include commitment No. 18 to

address the additional requirements that are specified in the March 1, 2006, SER. Hence,

RAI B.2.21-1 is resolved.

Exception. LRA B.2.21 characterized the SSES RPV surveillance program as consistent with

NUREG-1801, Section XI.M31, "Reactor Vessel Surveillance," with an exception from the

NUREG-1 801 guideline which requires that analyzed capsules be stored once the analysis is

complete. The staff does not accept this exception because analyzed specimens may be

reconstituted for future use during or beyond the current requested extended period of

operation. Hence, the staff issued RAI B.2.21-2, requesting the applicant remove this exception

to NUREG-1801. Further, since the BWRVIP-116 did not provide guidelines for storage of

deferred capsules, RAI B.2.21-2 also requested the applicant commit to the following:

If the SSES standby capsule is removed from the RPV without the intent to test

it, the capsule will be stored in manner which maintains it in a condition which

would permit its future use, including during the period of extended operation, if

necessary.

By letter dated October 16, 2007, the applicant made appropriate revisions to LRA AMP B.2.21,

LRA UFSAR Section A.1.2.41, and LRA Table A-i, Commitment No. 18, to reflect the

elimination of the NUREG-1801 exception and the inclusion of the commitment cited above.

Hence, RAI B.2.21-2 is resolved.

On the basis of its review, the staff finds that the applicant has demonstrated that the effects of

aging due to loss of fracture toughness of the RPV beltline region will be adequately managed

by the SSES Reactor Vessel Surveillance Program, so that the intended functions will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21(a)(3).

Operating Experience. LRA Section B.2.21 states that there have been capsule evaluations on

SSES Units 1 and 2 prior to the BWRVIP ISP. Measured decreases in upper shelf energy were

consistently less than RG 1.99 projections. Measured Unit 1 RTNDT increases were slightly

greater, within one standard deviation, than the RG 1.99 projections while measured Unit 2

RTNDT increases were less.

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The staff confirmed that the above description of the OE regarding SSES's evaluation of its

surveillance data from the Reactor Vessel Surveillance Program is correct. The fact that the

measured decreases in USE were consistently less than RG 1.99 projections and measured

RTNDT increases were within one standard deviation of the RG 1.99 projections indicated that

SSES's surveillance data testing results are consistent with industry OE.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program

element acceptable.

UFSAR Supplement. In LRA Section A.1.2.41, and Commitment No. 18 in Table A-i, the

applicant provided the UFSAR supplement for the Reactor Vessel Surveillance Program. The

staff reviewed this section and determines that the information in the revised UFSAR

supplement is an adequate summary description of the program, as required by

10 CFR 54.21(d).

Conclusion. On the basis of the audit and review of the applicant's Reactor Vessel Surveillance

Program, the staff determines that those program elements, for which the applicant claimed

consistency with the GALL Report are consistent. The staff concludes that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR supplement for this

AMP and concludes that it provides an adequate summary description of the program, as

required by 10 CFR 54.21(d).

3.0.3.2.13 Buried Piping and Tanks Inspection Program

Summary of Technical Information in the Application. LRA Section B.2.30 describes the new

Buried Piping and Tanks Inspection Program as consistent with GALL AMP XI.M34, "Buried

Piping and Tanks Inspection," with exceptions. This program is used to manage external

corrosion of buried piping and tanks by use of external coating where appropriate combined

with visual inspections of the external surfaces.

Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the

GALL Report. The staff also confirmed that the plant program contains all of the elements of

the referenced GALL Report program. Onsite interviews were also held to confirm these

results.

The staff reviewed the exceptions to determine whether the AMP, with the exceptions, will be

adequate to manage the aging effects for which the LRA credits it.

Exception 1. The applicant stated an exception to the "scope" program element, stating, in

addition to steel (which includes cast iron) piping components and steel tanks, the scope of

program includes stainless steel piping components. The GALL AMP only considers steel piping

and will be updated to include additional materials in the next revision of GALL. Recent LRA

reviews have shown that additional materials should be included in this AMP such as stainless

steel, AL6XN specialty steel, titanium alloys, aluminum alloys, and copper alloys. The staff

noted that based on the applicant's plant-specific operating experience that uncoated stainless

steel buried piping has not experienced degradation. However the applicant has conservatively

added the buried stainless steel piping within the scope of this program to ensure that

degradation has not occurred. The staff noted that a visual inspection will be performed by the

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applicant on the buried stainless steel piping within 10 years prior to entering the period of

extended operation. The inspection will be capable of detecting age-related degradation as a

result of loss of material, consistent with the GALL recommendations. The American Water

Works Association standard for stainless steel piping is AWWA C220, "Stainless Steel Piping."

On the basis of its review, the staff finds the applicant has conservatively included stainless

steel piping in the scope of this program to be inspected within 10 years prior to entering the

period of extended operation and that a visual inspection of the external surface will be capable

of detecting loss of material, and therefore this exception is acceptable.

The applicant stated an exception to the "preventive actions" program element, stating the

buried fire protection piping components and the buried stainless steel piping components in the

Condensate Transfer and Storage System are not provided with any special coatings or

wrappings in accordance with plant design specifications and consistent with plant operating

experience. The applicant stated in the LRA that buried piping in the Fire Protection System is

constructed using cast iron and ductile iron. It is not coated per the plant design specifications.

However the staff did not agree with the applicant for not coating this buried pipe, and issued

RAI B.2.30-1 in a letter dated June 13, 2008, to investigate this staff concern. The RAI B.2.30-1

stated that the GALL Report has certain requirements for coating buried piping and questioned

the applicant's decision not to coat the cast iron and ductile iron fire protection piping. By a letter

dated July 14, 2008, the applicant responded to this RAI stating that the NFPA guidance in

NFPA-24 only requires protective coatings of ductile iron or cast iron piping when the piping is

buried in aggressive soil. The applicant claimed that the soil at SSES is non-aggressive

(Chlorides less than 500 ppm, Sulfates less than 1500 ppm, and pH greater than 5.5). The staff

does not agree with this response because the definition for non-aggressive in the applicant's

response is for steel reinforcing bar in sub surface concrete and is not applicable to buried

ductile iron or cast iron piping. In a letter dated November 17, 2008, the applicant revised the

response to RAI B.2.30-1. In the revised response, the applicant agreed to conduct an

opportunistic inspection of the buried stainless steel and cast iron buried piping prior to entering

the period of extended operation. Because this will confirm that there is no loss of material for

stainless steel and carbon steel piping, or if loss of material is identified, the applicant will initiate

corrective action, the staff finds that this is acceptable.

Exception 2. LRA Section 3.3.4.1.13 states that the Fire Protection System piping will be

inspected as part of the Selective Leaching Inspection Program. However, the applicant's

Buried Piping and Tanks Inspection Program did not mention this. Therefore, the staff issued

RAI B.2.30-2 in a letter dated June 13, 2008, to follow up on this issue. In the applicant's

response to the RAI in the letter dated July 14, 2008, the applicant amended the Buried Piping

and Tanks Inspection Program to clarify that loss of material due to selective leaching for buried

cast iron components is managed by the Selective Leaching Inspection Program. This

amendment satisfactorily addresses the staff's concern, and this item is closed.

By letter dated June 13, 2008, in RAI B.2.30-3 the staff asked the applicant if there was any

uncoated carbon steel piping in the fire protection system. By letter dated July 14, 2008, the

applicant responded that there is no uncoated carbon steel piping in the fire protection system.

The staff finds that because there is no uncoated carbon steel piping in the fire protection

system, this issue is resolved.

The staff reviewed those portions of the applicant's Buried Piping and Tanks Inspection

Program that the applicant claimed consistency with GALL AMP XI.M34 and found they are

consistent with this GALL AMP. On the basis of the review, the staff concludes that the

applicant's Buried Piping and Tanks Inspection Program provides assurance that either the

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aging effect is indeed not occurring, or that the aging effect is occurring very slowly as not to

affect the intended function of the component or structure. The staff finds the applicant's Buried

Piping and Tanks Inspection Program acceptable because it conforms to the recommended

GALL AMP XI.M34, Buried Piping and Tanks Inspection Program is consistent with program

elements of GALL AMP XI.M34, with acceptable exceptions, and is therefore acceptable.

Operating Experience. The staff reviewed the applicant's OE described in LRA Section B.2.30.

Additionally, the staff reviewed a sample of condition reports, and interviewed the applicant's

technical staff to confirm that the plant-specific operating experience did not reveal any

degradation not bounded by industry experience. In the application, the applicant stated that

there is no operating experience with the effectiveness of the program because it is a new

program.

The applicant stated that the Buried Piping and Tanks Inspection is a new program for which

there is no operating experience and that inspection methods will be consistent with accepted

industry practices. For this program and for other new AMPs where the applicant provided no

current plant-specific operating experience, the staff issued RAI B.2.1 asking that the applicant

commit to provide documentation of plant-specific operating experience for staff review after the

program has been implemented, but prior to entering the period of extended operation.

In its letter dated July 8, 2008, the applicant stated that operating experience for new aging

management programs described in LRA Appendix B will be gained as these new programs are

implemented during the period of extended operation. The applicant stated that results of tests,

inspections, and other aging management activities conducted in accordance with these

programs will be subject to confirmation and corrective action elements of the SSES

10 CFR 50, Appendix B, Quality Assurance program and that results will be subject to NRC

review during regional inspections under existing NRC inspection modules. The applicant stated

that these new programs will be implemented prior to, and continue through, the period of

extended operation and that operating experience will be gained for these programs as they are

implemented. The applicant further stated that test and inspection results that do not meet

acceptance criteria for these new programs will be evaluated under the station's corrective

action program, which includes requirements for identification of appropriate corrective actions

and verification of the effectiveness of corrective actions.

The staff noted that the applicant'sý statement that inspection methods will be consistent with

industry practices is consistent with the "operating experience" program element for GALL

AMP XI.M34. The staff also noted that post-approval site inspections provide an opportunity for

staff review and assessment of the effectiveness of the applicant's Buried Piping and Tanks

Inspection Program after the applicant has developed operating experience with that program.

The staff concludes that the corrective action program, based on internal and external plant

operating experience, would capture operating experience in the future to support the

conclusion that the effects of aging are adequately managed. On this basis, the staff confirmed

that the "operating experience" program element satisfies the criterion defined in the GALL

Report and in SRP-LR Section A.1.2.3.10.

The staff finds this program element acceptable and concludes that a separate commitment is

not necessary.

The staff confirmed that the operating experience program element satisfies the criterion

defined in the GALL Report and in SRP LR Section A. 1.2.3.10. The staff finds this program

element acceptable.

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UFSAR Supplement. In LRA Section A. 1.2.3, and Commitment No. 26 in Table A-i, the

applicant provided the UFSAR Supplement for the Buried Piping and Tanks Inspection

Program. The staff reviewed this section and determined that the information in the UFSAR

Supplement does provide an adequate summary description of the program consistent with the

SRP-LR. The UFSAR Supplement does cite the commitment (Commitment No. 26) to

implement the program, and it does mention that the program must be implemented prior to the

period of extended operation.

By letter dated June 13, 2008, the staff issued RAIs on the need to coat ductile iron and cast

iron piping, the need to mention that ductile iron and cast iron piping are included in the

Selective Leaching Inspection Program, and whether or not there is any uncoated carbon steel

piping in the fire protection system. By letters dated July 14, 2008, and November 17, 2008, the

applicant provided responses to these RAIs that the staff finds to be acceptable.

The staff determines that the UFSAR supplement for this AMP provides an adequate summary

description of the program, as described by 10 CFR 54.21(d).

Conclusion. On the basis of the review of the applicant's Buried Piping and Tanks Inspection

Program the staff determines that those program elements for which the applicant claimed

consistency with the GALL Report are consistent. In addition, the staff reviewed the exceptions

and their justifications and determined that the AMP, with the exceptions, is adequate to

manage the aging effects for which the LRA credits it. The staff concludes that the applicant

has demonstrated that the effects of aging will be adequately managed, so that the intended

functions of these components will be maintained consistent with the CLB for the period of

extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR

supplement for this AMP and concludes that it provides an adequate summary description of

the program, as required by 10 CFR 54.21(d).

3.0.3.2.14 System Walkdown Program

Summary of Technical Information in the Application. LRA Section B.2.32 describes the existing

System Walkdown Program as consistent with GALL AMP XI.M36 "External Surfaces

Monitoring" with enhancements to the program elements, "scope of program" and "detection of

aging effects."

The applicant's program is a condition monitoring program that manages for aging effects of

external surfaces and in some cases, internal surfaces, by observations and surveillance

activities for mechanical components in the scope of license renewal. The applicant states that

the System Walkdown Program will manage loss of material for metals in indoor/outdoor air

and ventilation environments and cracking and/or change in material properties for elastomers

and polymers exposed to indoor air or ventilation environments.

By letters dated August 12, 2008, October 21, 2008, and November 11, 2008, the applicant

amended its LRA to include additional enhancements and exceptions to the AMP B.2.32,

Systems Walkdown Program.

Staff Evaluation. During the review, the staff confirmed the applicant's claim of consistency with

the GALL Report. The staff reviewed the exceptions and enhancements to determine whether

the AMP, with the exceptions and enhancements is adequate to manage the aging effects for

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which the LRA credits it. The staff's summary of its onsite review of AMP B.2.32, System

Walkdown Program, is documented in the staff's audit report.

In comparing the seven (7) program elements in the applicant's program to those in

GALL AMP XI.M36, the staff noted that the program elements in the applicant's AMP claimed to

be consistent with GALL were consistent with the corresponding program element criteria

recommended in the program elements of GALL AMP XI.M36 with the exception of three (3)

program elements: scope of program, detection of aging effects and OE, that the staff felt there

was a need for additional clarification and for which RAIs were issued. The "operating

experience" program element is discussed separately below.

The applicant states in LRA Section B.2.32 that this AMP will be credited to manage cracking

and/or change in material properties for elastomers and polymers that are exposed to indoor air

and ventilation. The staff noted that GALL AMP XI.M36 "External Surfaces Monitoring" is only

applicable for steel components for loss of material and leakage. Therefore, by letter dated

July 10, 2008, the staff issued RAI B.2.32-4 requesting the applicant to justify the basis for

crediting the System Walkdown Program to manage cracking and changes to material

properties for elastomer and polymer components. The applicant responded to RAI B.2.32-4 by

letter dated August 12, 2008. In its response, the applicant amended the LRA to include

exceptions and enhancements that were not previously identified in the LRA to address

RAI B.2.32-4. The staff determined that the applicant has addressed RAI B.2.32-4.

In AMP B.2.19 the applicant states that paints, coatings, sealants and caulking will be

monitored under the Systems Walkdown Program. Upon the staff's review of LRA section

B.2.32 and associated plant basis documents, the staff noted that these materials were not

included into the scope of program for B.2.32. Therefore by letter dated July 10, 2008, the staff

issued RAI B.2.32-3 requesting the applicant clarify whether paints, coatings, sealants and

caulking are within the scope of AMP B.2.32 and if so, to clarify the inspection techniques that

will be credited to monitor for applicable aging effects. The applicant responded to RAI B.2.32-

3, by letter dated August 12, 2008. In its response letter the applicant stated that paints,

coatings, sealants and caulking are not credited for preventing or mitigating the effects of aging

and do not perform an intended function as part of license renewal. The staff noted that since

the applicant does not credit these design features for aging management they are not required

to manage the aging effects that may affect paints, coating, sealants and caulking as part of

license renewal. However the applicant referred to its response to RAI B.2.19-1, which stated

that structural sealants and caulking are inspected as part of the Structural Monitoring Program.

The staff confirmed that sealants and caulking are inspected by the Structural Monitoring

Program for the Condensate and Refueling Water Storage Tanks. The staff noted that visual

inspections of the condition of paints and coatings on the external surfaces of the Condensate

and Refueling Water Storage Tanks will be a sign if degradation and corrosion maybe occurring

on the underlying material, but paints and coatings are not credited. Based on its review, the

staff finds the applicant's response acceptable because (1) the applicant has not credited paints

and coatings with preventing and mitigating aging of the underlying materials, and therefore

does not require aging management (2) the applicant will perform periodic visual inspections of

the external surfaces of the tanks, including paints and coatings, to determine the condition of

the underlying metallic material (3) the staff confirmed that sealants and caulking are inspected

and monitored by the Structures Monitoring Program.

Exception. The applicant responded to RAI B.2.32-4, by letter dated August 12, 2008. In its

response the applicant amended the LRA Section B.2.32 to include an exception to GALL AMP

XI.M36. This exception was in regard to the addition of elastomer and polymer components to

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the scope of the applicant's program. During its review the staff also noted that the applicant

had included stainless steel, copper alloy and aluminized steel into the scope of its program;

however, GALL AMP XI.M36 only recommends this program perform visual inspections on

carbon steel components. Therefore by letter dated October 17, 2008, the staff issued

RAI B.2.32-5 requesting the applicant to justify why the expansion in-scope of materials was not

considered an enhancement and to justify the basis for expanding the scope of materials. Also,

by letter dated October 17, 2008, the staff issued RAI B.2.32-4R requesting the applicant to

clarify why the exception above was not identified as an enhancement to the GALL

AMP XI.M36. By letter dated November 11, 2008, the applicant responded to RAI B.2.32-5 by

stating that the expansion in the scope of metallic materials will be considered an exception and

enhancement to GALL AMP XI.M36. The following exception was based on the applicant's

response to the staff's RAI B.2.32-4 and B.2.32-5:

Scope of Program, Parameters Monitored/Inspected, Detection of Aging Effects,

Monitoring and Trending

Elastomers and polymers are included within the scope of the Systems

Walkdown Program. The program is credited with managing cracking and

change in material properties for elastomers and polymers exposed to indoor air

or ventilation environments.

Copper alloy and stainless steel are included within the scope of the System

Walkdown Program. The program is credited with managing loss of material for

copper alloy and stainless steel exposed to indoor air, outdoor air or ventilation

environments.

The applicant responded to RAI B.2.32-4R and RAI B.2.32-5, by letter dated November 11,

2008. In its response to RAI B.2.32-4R the applicant stated that the expansion in the scope of

materials for this program is considered an exception and enhancement. The staff's evaluation

of this exception and enhancement were performed separately and are documented in this

section of the SER. The staff noted that the applicant has committed, by Commitment No. 28 as

amended by letter dated November 11, 2008, to enhance its program prior to the period of

extended operation to generate a routine activity to supplement the current existing plant

program to include a supplemental physical manipulation and/or prodding to inspect elastomer

and polymer components. The applicant stated in response to RAI B.2.32-4R that visual

inspections of elastomers and polymers will determine if such things as chalking, cracking,

crazing, discoloration and any physical distortion that may be occurring. The staff noted that for

the supplemental physical manipulation the applicant will identify hardening, lack of resiliency,

surface film or residue and unusual odors. The staff further noted that any signs of the

degradation identified by the visual inspection or physical manipulation will be evaluated. The

staff noted that the physical manipulation will aid the visual inspection in detecting age-related

degradation because changes in material properties and cracking can be detected during

manipulation of elastomeric and polymeric components by the relative inflexibility of the

component, or by the failure of the component to return to its previous shape or configuration.

On the basis of its review, the staff finds that the applicant will be capable of managing the

effects of aging for elastomers and polymers because the applicant (1) is crediting a visual

examination of elastomer and polymers and an inspection technique that includes physical

manipulation and/prodding of the components, which are capable of detecting the aging effects

of cracking and/or change in material properties and (2) any signs of degradation will be

evaluated by the applicant and addressed as part of their corrective actions program.

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In its response to RAI B.2.32-5 the applicant stated that for the aging effect and aging

mechanisms of concern, which include loss of material due to pitting, crevice and galvanic

corrosion, for copper alloy and stainless steel are similar to carbon steel, such that a visual

inspection will be effective in identifying loss of material. The applicant stated that aluminized

steel is considered to be equivalent to steel because the aluminum coating is not credited. The

staff determined that since the applicant does not credit the aluminum coating, aluminized steel

is equivalent to steel and does not need to be included in the expansion in the scope of

materials. The staff noted that metallic components, including copper alloy and stainless steel,

would exhibit indications of loss of material on the surface similar to steel and a visual inspection

will be capable of detecting age related degradation. The applicant further stated that the

parameters monitored by the visual inspection will include: corrosion, wastage of material,

leakage to and from external surfaces, worn/flaking/oxide-coated surfaces, corrosion stains and

coating degradation. Furthermore, any signs of degradation that is present will be evaluated to

determine if the components are acceptable for continued operation. On the basis of its review,

the staff finds the applicant's response acceptable because (1) the applicant will be performing

visual inspections that are capable of detecting loss of material in metallic components as they

display indications of degradation similar to steel, for which GALL AMP XI.M36 was intended

and (2) any signs of degradation will evaluated.

On the basis of its review of the LRA and the applicant's responses to RAI B.2.32-4,

RAI B.2.32-4R and RAI B.2.32-5, the staff finds the applicant's exception acceptable because

(1) the applicant will perform visual inspections during system walkdowns that will be effective in

identifying loss of material in other metallic components which exhibit indications of degradation

similar to steel, (2) the applicant will supplement the visual inspection with a physical

manipulation and/or prodding, which are adequate techniques to detect change in material

properties and cracking in elastomers and polymers (3) and any degradation will be evaluated to

ensure these metallic and non-metallic components are acceptable for continued operation.

Enhancement 1. In LRA Section B.2.32 the applicant states that the program element "scope of

program" for the System Walkdown Program must be enhanced in order to be consistent with

GALL XI.M36, "External Surfaces Monitoring." By letter dated November 11, 2008, the applicant

amended the LRA to include additional information to this enhancement. The applicant's

enhancement to the scope of program is as follows:

Scope of Program

The governing procedure for the System Walkdown Program must be revised to

add the listing of systems crediting the program for license renewal, and to

explicitly include other metals, copper alloy and stainless steel. A routine activity

to supplement the existing plant program must be generated to inspect

elastomers and polymers.

In the program element "scope of program" for GALL XI.M36 "External Surfaces Monitoring,"

it's states that external surfaces of in-scope components are to be visually inspected. The

additional information in this enhancement, in regards to the additional metallic components

and elastomers, is evaluated by the staff in Exception #1 and Enhancement #4 in this section of

the SER. The staff reviewed LRA Section B.2.32 and finds the applicant's enhancement

acceptable because the applicant's procedure will be updated to include all systems that have

credited this program for aging management based on the recommendations of GALL XI.M36.

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On the basis of its review, as described above, the staff concludes that this enhancement is

acceptable.

Enhancement 2. In LRA Section B.2.32 the applicant states that the program element

"detection of aging effects" for the System Walkdown Program must be enhanced in order to be

consistent with GALL XI.M36. By letter dated October 21, 2008, the applicant amended its LRA

based on a License Renewal Regional Inspection, and in this amendment the applicant

provided additional details to this enhancement. The applicant's enhancement to the detection

of aging effects is as follows:

Detection of Aging Effects

All of the systems to be added to the procedure contain mechanical components

whose external surfaces require aging management during the period of

extended operation. It may be determined by engineering evaluation that these

components do not require monitoring every two weeks, and the basis for a

different walkdown frequency may be documented on the appropriate procedure

form.

The governing procedure for the System Walkdown Program must be enhanced

to address the license renewal requirement for opportunistic inspections of

normally inaccessible components (e.g., those that are insulated), and those that

are accessible only during refueling outages.

For underground vaults, an initial sample of at least one vault/pit/manhole from

each grouping of components with identical material and environment

combinations will be inspected prior to entering the period of extended operation.

A representative sample of the entire population will be inspected within the first 6

years of the period of extended operation. Results of the inspection activities that

require further engineering evaluation/resolution (e.g., sample expansion and

inspection frequency changes if degradation is detected), if any, will be evaluated

using the corrective action process.

Based on its review, the staff determined additional information was needed to complete its

review that relates to the systems that will be added to the scope of the AMP B.2.32, the current

frequency of inspections, and the basis for changing the frequency. Therefore, by letter dated

July 10, 2008, the staff issued RAI B.2.32-2 requesting the applicant to identify the systems that

are within the scope of the AMP B.2.32 that are subject to the enhancements, to clarify the

current frequency of system walkdowns for different plant systems that are within the scope of

AMP B.2.32, and to provide the basis for changing the frequency of system walkdowns and

clarify the process used for changing these frequencies. The applicant responded to

RAI B.2.32-2, by letter dated August 12, 2008. The applicant provided a listing of the systems

that would be affected by this enhancement as requested by the staff. The applicant also

provided the frequency of walkdowns that are applicable to the scope of systems managed by

this program. The staff noted that the frequencies being utilized by the applicant are consistent

with those recommendations provided in GALL AMP XI.M36, which are walkdowns that exceed

once per refueling cycle for accessible locations, for locations inaccessible during normal plant

operation inspections are performed during the RFO, and for those locations that are

inaccessible during RFOs and normal plant operation inspections will be performed

opportunistically. As stated in the "detection of aging effects" program element in the GALL

Report, the inspection frequency may be adjusted as needed based on the plant-specific

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inspection results and industry experience. The applicant's proposal to adjust the inspection

frequency is consistent with the recommendations in the GALL Report, and is subject to an

engineering evaluation, approval by engineering supervision and is subject to a 10 CFR 50.59

review to determine if prior NRC approval is required for any frequency change. The applicant

amended the LRA by letter dated October 21, 2008, provided details on inspections that will be

performed before and after the period of extended operation on those normally inaccessible

components that require opportunistic inspections, specifically samples of underground vaults.

The staff noted for these normally inaccessible locations, the applicant has committed to

inspect an initial sample before the period of extended operation and again within 6 years after

the start of the period of extended operation. The staff further noted that the applicant's

approach is conservative because it requires the inspection within 6 years after entering the

period of extended operation compared to an opportunistic inspection that may potentially

exceed 6 years. Based on its review, the staff finds the applicant's response and enhancement

acceptable because (1) the applicant's inspection frequency is consistent with the

recommendations provided in GALL AMP XI.M36, (2) the applicant's ability to change the

inspection frequency of walkdowns is subject to a 10 CFR 50.59 review and (3) for underground

vaults the applicant's commitment to perform inspections in a specified time frame that is

conservative compared to a strictly opportunistic inspection.

On the basis of its review as described above, the staff concludes the applicant's enhancement

when implemented prior to the period of extended operation is acceptable.

Enhancement 3. By letter dated October 21, 2008, the applicant amended the LRA to provide

an additional enhancement. The applicant's enhancement to the detection of aging effects

program element is as follows:

Detection of Aging Effects

Also, within the 10 year period prior to the period of extended operation a visual

inspection and ultrasonic inspection of external surfaces of piping passing into

structures through penetrations (underground piping) will be performed, for those

penetrations with a history of leakage. These inspections will be focused on

penetrations that are leaking at the time and will include a representative sample

of each material, environment combination from those piping systems within the

scope of license renewal (which includes those for the RHRSW, ESW, and Fire

Protection systems) that enter structures below grade.

The staff noted that the applicant has committed to perform a visual inspection of external

surfaces of piping passing into structures through penetrations (underground piping) and in

addition the applicant will conservatively perform an ultrasonic inspection to identify degradation.

Furthermore, the applicant committed to perform these inspections prior to entering the period

of extended operation to ensure detection of degradation prior to component intended function

being lost. The staff noted the applicant's commitment, captured in Commitment No. 28, will

require inspections of these areas prior to the period of extended operation to ensure that

degradation, if any, is detected and corrected by the corrective actions program prior to entering

the period of extended operation.

On the basis of its review, as described above and the applicant's enhancements when

implemented prior to the period of extended operation will make the applicant's Systems

Walkdown Program consistent with the recommendations provided by GALL AMP XI.M36. On

the basis of its review, the staff finds the applicant's enhancement acceptable because (1) the

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applicant will be performing a visual inspection of the external surfaces of piping that enter

structures below grade, which is consistent with the recommendations in GALL AMP XI.M36

and (2) the applicant will conservatively perform an ultrasonic inspection in addition to the visual

inspection to assist in the detection of any degradation in those penetrations that are leaking

and with a history of leakage.

Enhancement 4. The applicant responded to RAI B.2.32-4, by letter dated August 12, 2008. In

its response the applicant amended the LRA Section B.2.32 to include the following

enhancement, and subsequently amended by letter dated November 11, 2008, to provide

additional details:

Parameters Monitored/Inspected

A routine activity must be generated, and based at least in part on EPRI

1007933, "Aging Assessment Field Guide", to inspect elastomers and polymers

for cracking and/or change in material properties. Evidence of surface

degradation, such as cracking, or discoloration, as well as physical manipulation

and/or prodding, will be used as measures of material condition.

The staff noted that the applicant has expanded the scope of its System Walkdown Program to

include elastomer and polymer components. The staff further noted that a visual inspection

alone would not have been capable of detecting aging effects such as cracking and/or change

in material properties for elastomers and polymers. Based on the applicant's amendment to

include this enhancement the staff noted that the applicant will not only utilize a visual

inspection for evidence of degradation, noticeable cracking or discoloration, but the applicant

will be supplementing the visual inspection with an appropriate physical manipulation and/or

prodding of the component. However, the staff felt that additional information was needed;

therefore, by letter dated October 17, 2008, the staff issued follow-up RAI B.2.32-4R Part B

requesting the applicant to clarify the acceptance criteria for the supplemental physical

manipulation and/or prodding of polymers and elastomers. By letter dated November 11, 2008,

the applicant responded to RAI B.2.32-4R by stating that the visual inspection of the elastomers

will determine if such things as chalking, cracking, crazing, discoloration and any physical

distortion is occurring. The staff noted that for the supplemental physical manipulation the

applicant will identify hardening, lack of resiliency, surface film or residue and unusual odors.

The staff further noted that any signs of the degradation identified by the visual inspection or

physical manipulation will be evaluated. The staff noted that the physical manipulation will aid

the visual inspection in detecting age-related degradation because changes in material

properties and cracking can be detected during manipulation of elastomeric and polymeric

components by the relative inflexibility of the component, or by the failure of the component to

return to its previous shape or configuration. On the basis of its review, the staff finds that the

applicant will be capable of managing the effects of aging for elastomers and polymers because

the applicant (1) is crediting a visual examination of elastomer and polymers and an inspection

technique that includes physical manipulation and/prodding of the components, which is

capable of detecting the aging effects of cracking and/or change in material properties and (2)

any signs of degradation will be evaluated by the applicant and addressed as part of its

corrective actions program.

On the basis of its review, the staff finds the applicant's enhancement acceptable because the

applicant will perform visual inspections and a physical manipulation during system walkdowns

that will be effective in identifying change in material properties and cracking for elastomer and

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polymer components and any degradation will be evaluated to ensure these components are

acceptable for continued operation.

Enhancement 5. The applicant responded to RAI B.2.32-4 by letter dated

August 12, 2008. In its response the applicant amended the LRA Section B.2.32 to

include the following enhancement, which was supplemented by a letter dated

November 11, 2008, to indicate the specific routine activity:

Detection of Aging Effects

The routine activity to inspect elastomers and polymers, to include physical

manipulation and/or prodding, will be based on inspection of a representative

sample of components. The sample will be determined by engineering

evaluation with a focus on components considered to be most susceptible to

aging, such as due to their time in service, the severity of conditions during

normal plant operation, and any pertinent design margins.

The staff noted that the applicant is selecting a representative sample of elastomer and polymer

components. The applicant stated that this representative sample will be based on an

engineering evaluation which takes into consideration which components may be more

susceptible to aging. The staff further noted that such conditions as the amount of time the

component has been in service, the severity of the conditions and environments that the

component is exposed to during normal plant operation and other relevant design margins that

may be applicable are factored in as part of the applicant's engineering evaluation to select

components for the routine activity to inspect elastomers and polymers.

On the basis of its review, the staff finds that the applicant's enhancement acceptable because

(1) the applicant's representative samples of elastomer and polymer components for inspection

will be based on selecting those components that are more susceptible and likely to experience

age-related degradation and (2) the applicant will supplement its visual inspection with a

physical manipulation and/or prodding which will be capable of detecting cracking and/or

change in material properties in elastomers and polymers as discussed in Enhancement No. 4.

Operatinq Experience. The staff also reviewed the applicant's OE described in the applicant's

license renewal basis document for the System Walkdown Program. The staff noted during its

review of the license renewal plant basis documents for this program, which the applicant

reviewed its plant OE action requests and condition reports for the most recent five-year period.

From the applicant's review of its database, it was revealed that leakage, damage, and

degradation are routinely identified by this program. The staff noted that subsequent to

identifying an issue with this program, corrective actions were taken in a timely manner, and a

loss of pressure boundary integrity did not occur due to aging effects that are within the scope

of this program. However, the staff felt that additional information was needed to complete its

review; therefore, by letter dated July 10, 2008, the staff issued RAI B.2.32-1 requesting the

applicant to identify the plant systems within the scope of this program that have had problems

with age-related degradation and to also identify the specific age-related degradation that was

occurring in each instance. The staff further asked the applicant to clarify if the age-related

degradation has had any impact on the program's ability to manage aging and if the program

will need to be augmented or enhanced to ensure adequate aging management of these

systems. Finally, the staff asked the applicant to identify the corrective actions that were taken

to correct these issues associated with the problems in the plant systems in the scope of this

program.

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The applicant responded to RAI B.2.32-1, by letter dated August 12, 2008. In this letter, the

applicant stated that as part of the preparation of the LRA, a plant-specific search of Action

Requests and Condition Reports was performed of the most recent 5-year period for OE. The

applicant provided several examples of OE and the corrective actions that were taken in

response to the action request or condition report. The staff noted that one of the examples

provided by the applicant indicated the Instrument Air piping had a crack downstream of an

isolation valve. The applicant took corrective actions and replaced the cracked section of pipe.

Another example provided by the applicant indicated that the enamel/wrap coating that normally

protects the piping for the Circulating Water System was severely degraded on the piping that

extends above the ground near the base of the cooling towers. The applicant noted that the

portions of the pipe that had been exposed due to the coating degradation were corroded. The

staff noted that based on this discovery of the degraded coating and corroded piping the

applicant initiated corrective actions to take UT measurements of the piping to ensure that there

was sufficient and proper wall thickness before the piping was re-coated. As an added

measure, the applicant excavated the buried portions of the corroded piping to ensure that the

coating was intact and that wall thinning and corrosion was not occurring in the buried portion of

this piping during the RFO that followed the initial discovery. Based on the staff's review of the

applicant's response and the OE that was provided, the staff finds the applicant's response

acceptable because the applicant's program was capable of detecting degradation bounded by

industry experience and then initiated corrective actions to resolve the discovered degradation.

The staff confirmed that the "operating" experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A. 1.2.3.10. The staff finds the program

element acceptable.

UFSAR Supplement. The staff reviewed the UFSAR Supplement summary description that was

provided in LRA Section A.1.2.47, and Commitment No. 28 in Table A-1, for the System

Walkdown Program. The staff verified that, in LRA Commitment No. 28 of UFSAR Supplement

Table A-I, the applicant committed to enhancing its program prior to the period of extended

operation. By letters dated August 12, 2008, October 21, 2008, and November 11, 2008, the

applicant amended the LRA to include additional enhancements to AMP B.2.32. The staff

confirmed the applicant amended LRA Section A.1.2.47 and Commitment No. 28 to include a

brief description of these enhancements and has committed to implement these enhancements

prior to the period of extended operation. The staff also verified that the applicant has placed

this commitment in UFSAR Supplement summary description A. 1.2.47 for the System

Walkdown Program.

Based on this review, the staff finds that UFSAR Supplement Section A.1.2.47 provides an

acceptable UFSAR Supplement summary description of the System Walkdown Program

because it is consistent with those UFSAR Supplement summary descriptions in the SRP-LR

and because the summary description includes the bases for determining that aging effects will

be managed. The staff determines that the UFSAR supplement for this AMP provides an

adequate summary description of the program, as described by 10 CFR 54.21 (d).

Conclusion. On the basis of the audit and review of the applicant's System Walkdown Program,

the staff determines that those program elements for which the applicant claimed consistency

with the GALL Report are consistent. In addition, the staff reviewed the exception and its

justification and determines that the AMP, with the exception, is adequate to manage the aging

effects for which the LRA credits it. Also, the staff reviewed the enhancements and confirmed

that they will be implemented through Commitment No. 28 prior to the period of extended

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operation. The staff concludes that the applicant has demonstrated that the effects of aging will

be adequately managed so that the intended function(s) will be maintained consistent with the

CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also

reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate

summary description of the program, as required by 10 CFR 54.21(d).

3.0.3.2.15 Lubricating Oil Analysis Program

Summary of Technical Information in the Application. LRA Section B.2.33 of the LRA describes

the existing program, "Lubricating Oil Analysis Program." as consistent with the GALL

AMP XI.M39, "Lubricating Oil Analysis Program" with enhancement and exceptions. The LRA

states this program is used to mitigate damage in components exposed to lubricating oil due to

loss of material and reduction of heat transfer due to fouling. The applicant stated that the

program manages the aging effects through monitoring that is consistent with manufacturer's

recommendations and standards for lubricating oil from the ASTM. In addition, this program is

supplemented with the Lubricating Oil Inspection, a one-time inspection program to verify its

effectiveness.

Staff Evaluation. The staff's summary of its onsite review of AMP B.2.33, Lubricating Oil

Analysis Program, is documented in staff's audit report. For its onsite review, the staff reviewed

and compared the program elements of B.2.33 Lubricating Oil Analysis Program with its

corresponding elements of GALL AMP XI.M39, "Lubricating Oil Analysis Program."

In comparing the seven (7) program elements in the applicant's program to those in

GALL AMP XI.M39, the staff noted that the program elements in the applicant's AMP claimed to

be consistent with the GALL Report were consistent with the corresponding program element

criteria recommended in the program elements of GALL AMP XI.M39 with the exception of

those enhancements and exceptions taken by the applicant that the staff determined there was

a need for additional clarification and for which RAIs were issued. The staff reviewed the

exceptions and enhancement, to determine whether the AMP with the exceptions and

enhancement, is adequate to manage the aging effects for which the LRA credits it. The

operating experience program element is discussed separately below.

Exception 1. The Lubricating Oil Analysis Program includes two exceptions to the parameters

monitored or inspection program element. The first exception is that the program does not

perform a particle count on the Emergency Diesel Generator or RHR System pump motor oil

samples. Instead, the applicant performs direct read ferrography as stated in LRA section

B.2.33. The staff noted that direct read ferrography only measures ferrous particles whereas

particle counters measures both ferrous and non-ferrous particles. Thus, aging effects due to

non-ferrous particles may not be accounted for by ferrography. By letter dated July 10, 2008,

the staff issued RAI B.2.33-1 in which the staff requested the applicant to justify why "direct

read-ferrography" is an acceptable alternative to performance of periodic particular content

counting. By letter dated August 12, 2008, the applicant responded to RAI B.2.33-1, in which

the applicant stated that it performs a direct read ferrography on the diesel lube oil rather than

particle counting because of the way in which particle counting performs the test. The applicant

explained that the particle counters utilize optical devices that pass light through the lube oil

sample in order to count the particles. The staff noted that diesel lube oil is dark in color, and

the use of a particle counter on dark lube oils is difficult unless the sample lube oil is diluted in

order to allow more light to pass through the sample oil. The applicant stated that dilution of the

sample lube oil would create concerns if the diluents contain any contamination that may skew

the results from the particle counting. The staff further noted that the method of direct read

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ferrography primarily measures the number of ferrous particles per milliliter of fluid, which is

normally due to mechanical wear of the system. The staff further noted that the applicant stated

it utilizes a spectrochemical testing which is capable of measuring up to twenty-one different

metals less than 10-microns in size. The staff noted that the intent of the recommendation of

the GALL AMP XI.M39 to perform particle counting was to reveal abnormal wear rates or

excessive corrosion. The staff finds that the applicant's use of direct read ferrography and

spectrochemical testing will be capable of revealing abnormal wear rates, excessive corrosion,

and detect changing trends in wear debris and contamination. On the basis of its review, the

staff finds the applicant's response acceptable as described above.

On the basis of its review, the staff finds the applicant's exception acceptable because with the

use of direct read ferrography and spectrochemical testing on dark diesel lubricating oil the

applicant will be capable of detecting abnormal wear rates, excessive corrosion and detect

changing trends in wear debris and contamination, which is consistent with the intent of the

particle counting test that is recommended by GALL AMP XI.M39.

Exception 2. The second exception to this program is it does not determine the flash point for

the HPCI, RCIC, or RHR motor oil samples. Instead, the applicant performs direct read

ferrography, viscosity, total acid number, water content and metals content as stated in LRA

section B.2.33. The staff reviewed this exception and onsite documents for this program. The

staff noted that the tests that will be performed in lieu of the flash point testing are acceptable

alternatives that would allow the applicant to track the level of contaminants in the oil systems.

The staff noted that the intent of the GALL AMP XI.M39 is to maintain the oil systems

contaminants within acceptable limits, which the applicant will be capable of doing by

performing a direct read ferrography, viscosity, total acid number, water content and metals

content test. The staff determined that the tests the applicant will be performing are consistent

with the intent of GALL AMP XI.M39 and on this basis; the staff finds this exception acceptable.

Enhancement. The Lubricating Oil Analysis Program includes an enhancement to the scope of

the program element. The applicant stated that the program will be enhanced to sample the

lubricating oil from the Control Structure Chiller when the oil is changed.

In addition, the applicant further stated that a particle count and a check for water will be

performed on the drained oil from the Control Structure Chiller.

As a result of the applicant's response to RAI B.2.25-1, in a letter dated August 12, 2008, the

applicant amended LRA Section B.2.33 and Commitment No. 48 so the program will be

enhanced to sample the lubricating oil from the Reactor Building Chiller when the oil is

changed. In addition, a particle count and a check for water will be performed on the drained oil

from the Reactor Building Chiller. The staff noted that the scope of program element of GALL

XI.M39 states that on a periodic basis, this program samples lubricating oil from plant

components subject to AMR. Upon review of the site documents and the LRA, the staff

determines the enhancement is consistent with scope of GALL XI.M39. On this basis, the staff

determines this enhancement is acceptable, for the Reactor Building Chiller and Control

Structure Chiller.

Operatingq Experience. The staff also reviewed the operating experience described in LRA

Section B.2.33. The applicant indicated that review of SSES operating experience did not reveal

a loss of component intended function for components exposed to lubricating oil from

inadequacy of the Lubricating Oil Analysis Program. In addition, the LRA stated that abnormal

lubricating oil conditions are promptly identified, evaluated, and corrected. The staff reviewed

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the operating experience identified in the GALL XI.M39 and noted that it states that no

instances of component failures from lubricating oil contamination have been identified as well.

In addition, the staff reviewed the onsite operating experience data and condition reports and

did not find any reports of component failures due to lubricating oil contamination. On this basis,

the staff finds the operating experience data acceptable.

The staff confirmed that the operating experience program element satisfies the criterion

defined in the GALL Report and in SRP LR Section A.1.2.3.10. The staff finds this program

element acceptable.

UFSAR Supplement. In LRA Section A.1.2.28, and Commitment No. 48 in Table A-i, the

applicant provided the UFSAR Supplement summarizing the Lubricating Oil Analysis Program.

The staff reviewed the section of the UFSAR Supplement and determines that it is an adequate

summary description of the program, as required byl10 CFR 54.21(d).

The staff reviewed the UFSAR Supplement summary description that was provided in LRA

Section A.1.2.28 for the Lubricating Oil Analysis Program. The staff noted that in its response to

RAI B.2.25-1 and the associated amendments, the applicant did not amend LRA

Section A. 1.2.28 to include the Reactor Building Chiller. The staff confirmed that by letter dated

September 26, 2008, the applicant amended LRA Section A.1.2.28 to include the Reactor

Building Chiller. The staff verified that, in LRA Commitment No. 48 of UFSAR Supplement

Table A-i, the applicant includes a brief description of the enhancement and committed to

enhancing the program to include sampling from the Reactor Building Chiller and the Control

Structure Chiller and have the lubricating oils tested for water and for particle count and

implementing these enhancements prior to the period of extended operation. The. staff also

verified that the applicant has placed this commitment on UFSAR Supplement summary

description A.1.2.28 for the Lubricating Oil Analysis Program.

Based on this review, the staff finds that UFSAR Supplement Section A.1.2.28 provides an

acceptable UFSAR Supplement summary description of the Lubricating Oil Analysis Program

because it is consistent with those UFSAR Supplement summary descriptions in the SRP-LR

and because the summary description includes the bases for determining that aging effects will

be managed. Therefore, the staff concludes that the UFSAR supplement for this AMP provides

an adequate summary description of the program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of its audit and review of the applicant's Lubricating Oil Analysis

Program, the staff determines that those program elements for which the applicant claimed

consistency with the GALL Report are consistent. In addition, the staff reviewed the exceptions

and their justifications and determines that the AMP, with the exceptions, is adequate to

manage the aging effects for which the LRA credits it. The staff reviewed the enhancement and

confirmed that its implementation through Commitment No. 48 prior to the period of extended

operation would make the existing AMP consistent with the GALL Report AMP to which it was

compared. In addition, the staff reviewed the applicant's responses to the staff's RAI and its

evaluation is documented above. The staff concludes that the applicant has demonstrated that

the effects of aging will be adequately managed so that the intended function(s) will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR supplement for this AMP and

concludes that it provides an adequate summary description of the program, as required by

10 CFR 54.21(d).

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3.0.3.2.16 Masonry Wall Program

Summary of Technical Information in the Application. LRA Section B.2.38 describes the existing

Masonry Wall Program as consistent, with an enhancement, with the GALL AMP XI.S5,

"Masonry Wall Program." This program will manage aging effects so that the evaluation basis

established for each masonry wall within the scope of license renewal remains valid through the

period of extended operations.

The applicant stated that the program includes all masonry walls identified as performing

intended functions in accordance with 10 CFR 54.4. Included components are the 10 CFR

50.48 required masonry walls, radiation shielding masonry walls, and masonry walls with the

potential to affect safety-related components.

The applicant further stated that the Masonry Wall Program is implemented as part of the

Structures Monitoring Program. Masonry walls are visually examined at a frequency selected to

ensure there is no loss of intended function between inspections.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. The staff reviewed the enhancement to determine whether

the AMP, with the enhancement, is adequate to manage the aging effects for which it is

credited in the LRA.

The staff interviewed the applicant's technical staff and reviewed the associated bases

documents for the AMP B.2.38 "Masonry Wall Program," which provides an assessment of the

AMP elements' consistency with GALL AMP XI.S5.

The staff noted that the Masonry Wall Program includes the guidance and lessons learned from

Office of Inspection and Enforcement Bulletin 80-11 (Masonry Wall Design, U.S. Nuclear

Regulatory Commission, May 8, 1980) and IN 87-67 (Lesson Learned from Regional

Inspections of Licensee Actions in Response to IE Bulletin 80-11, U.S. Nuclear Regulatory

Commission, December 31, 1987), During the audit and review, the staff asked the applicant

for the visual examination frequency for the program and its technical basis. In its response, the

applicant stated that the inspection is implemented by the Structures Monitoring Program and

consists of visual inspection for cracking in joints, deterioration of penetrations, missing or

broken blocks, missing mortar, and general mechanical soundness of steel supports. The

applicant also stated that visual inspections are conducted at least every five years to ensure no

loss of intended function between inspections. Based upon its review, the staff finds the

applicant's Masonry Wall Program, with the enhancement (Commitment No. 33) as described

below, consistent with the program elements of GALL AMP XI.S5, "Masonry Wall Program,"

and therefore acceptable.

The staff reviewed the enhancement to determine whether the AMP, with the enhancement, is

adequate to manage the aging effects for which it is credited in the LRA.

Enhancement. LRA Section B.2.38 states an enhancement to the "acceptance criteria" program

element of the Structures Monitoring Program procedure to specify that for each masonry wall,

the extent of observed masonry cracking and/or degradation of steel edge supports/bracing are

evaluated to ensure that the current evaluation basis is still valid.

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The staff reviewed the applicant's Masonry Wall Program, the Structures Monitoring Program,

and their AERMs under the acceptance criteria program element of the Structures Monitoring

Program. The staff noted that visual examination of masonry walls is performed to identify

indications of cracking resulting from overstress due to applied loads, shrinkage, temperature

effects, or differential movement. Potential design non-conforming conditions identified during

the course of an inspection are noted and a condition report is initiated. Corrective actions are

taken if the extent of cracking and steel degradation is sufficient to invalidate the evaluation

basis.

The responsible engineer identifies problems with structural performance, initiates structural

deficiency reports, and recommends corrective action. Acceptance criteria are established such

that corrective actions are initiated prior to loss of function. The staff found this enhancement

acceptable because when the enhancement is implemented, AMP B.2.38, "Masonry Wall

Program," will be consistent with the GALL AMP XI.S5 and provide additional assurance that

the effects of aging will be adequately managed.

Operating Experience. The staff reviewed the applicant's OE described in LRA Section B.2.38,

and "Operation Experience Review Report (Masonry Wall's section)," and interviewed the

applicant's technical staff to confirm that the plant-specific OE has been reviewed by the

applicant and was evaluated as intended in the GALL Report. During its audit, the staff found

some minor indications that did not affect the structural integrity of any of the structures

reviewed. Furthermore, the staff confirmed that the applicant had addressed OE identified after

the issuance of the GALL Report. The staff finds that the applicant's Masonry Wall Program,

with the corrective actions and enhancements discussed in the LRA, has been effective in

identifying, monitoring, and correcting the aging effects of masonry walls. The staff also

confirmed that plant-specific OE did not reveal any degradation not bounded by industry

experience.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program

element acceptable.

UFSAR Supplement. In LRA Section A.1.2.31 and Commitment No. 33 in Table A-i, "Masonry

Wall Program," the applicant provided the UFSAR supplement for the Masonry Wall Program.

The staff reviewed this section and determines that the information in the UFSAR supplement is

an adequate summary description of the program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of its audit and review of the applicant's Masonry Wall Program, the

staff determines that those program elements for which the applicant claimed consistency with

the GALL Report are consistent. In addition, the staff reviewed the enhancement and confirmed

that its implementation through Commitment No. 33 prior to the period of extended operation

would make the existing AMP consistent with the GALL Report AMP to which it was compared.

The staff concludes that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also

reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate

summary description of the program, as required by 10 CFR 54.21(d).

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3.0.3.2.17 Structures Monitoring Program

Summary of Technical Information in the Application. LRA Section B.2.39 describes the existing

Structures Monitoring Program as consistent, with enhancements, with GALL AMP XI.S6,

"Structures Monitoring Program." In the LRA, the applicant stated that the program will manage

aging effects such that loss of material, cracking, change of material properties, and loss of

form are detected by visual inspection prior to the loss of the structure's or component's

intended function(s). The applicant also stated that the program also implements the Masonry

Wall Program and the RG 1.127 Water Control Structures Inspection.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. The staff reviewed the enhancements (Commitment No. 34)

to determine whether the AMP, with the enhancements, is adequate to manage the aging

effects for which it is credited in the LRA.

During its audit, the staff reviewed the applicant's onsite documentation supporting the

applicant's conclusion that the program elements are consistent with the elements in the GALL

Report. The staff interviewed the applicant's technical staff and reviewed the documents related

to the Structures Monitoring Program, including the license renewal program evaluation report

in which the applicant assessed whether the program elements are consistent with GALL

AMP XI.S6.

Enhancement 1. LRA Section B.2.39 states an enhancement to the "scope of program"

program element in that the Structures Monitoring Program procedure will be enhanced to

include additional structures requiring aging management and "structural component" for

inspection includes each of the component types identified as requiring aging management.

The staff reviewed the applicant's Structures Monitoring Program, and its AERMs under the

scope of the Structures Monitoring Program. The staff noted that the Structures Monitoring

Program satisfies the monitoring requirements for plant structures that are within the scope of

the NRC Maintenance Rule (10 CFR 50.65). SSES structures and components that are within

the scope of license renewal monitored by the Structures Monitoring Program include the

following:

* Primary Containment

* Reactor Building

° Circulating Water Pumphouse and Water Treatment Building

* Control Structure

• Diesel Generator 'A, B, C & D' Building

* Diesel Generator 'E' Building

* Turbine Building

* Engineered Safeguards Service Water (ESSW) Pumphouse

* Spray Pond (includes Emergency Spillway and earthen embankment)

° Clarified Water Storage Tank Foundation

° Condensate Storage Tank Foundation and Retention Basin

* Diesel Generator Fuel Oil Storage Tanks 'A, B, C, D & E' Foundation and Vault

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* Refueling Water Storage Tank Foundation

* Station Blackout (SBO) component foundations and structures in the yard (Startup

Transformers T-10 and T-20 and associated disconnect switches, ESS Transformers)

* Cooling Tower Basins (Units 1 and 2)

* Duct banks, manholes, valve vaults (includes Spray Pond Valve Vault),

instrument pits, and piping trenches (structural component groups not identified as

structure/building)

T-1 0 230kV Switchyard SBO component foundations and structures

(located outside security fence)

230kV Switchyard SBO component foundations and structures

(located outside security fence)

500kV Switchyard SBO component foundations and structures

(located outside security fence)

The staff found this enhancement acceptable because when the enhancement is implemented,

AMP B.2.39, "Structures Monitoring Program," will be consistent with GALL AMP XI.S6 and

provide additional assurance that the effects of aging will be adequately managed.

Enhancement 2. LRA Section B.2.39 states an enhancement to the "parameters monitored or

inspected" program element in that the Structures Monitoring Program and excavation

procedure will be enhanced to specify that, if the below grade structural wall or component

become accessible through excavation, the responsible engineer will inspect the exposed

surfaces for age-related degradation. The Structures Monitoring Program procedure will also be

enhanced to specify that the responsible engineer shall review the site ground and raw water

chemistry data to validate that the below-grade environment remains non-aggressive during the

period of extended operations.

The staff reviewed the applicant's Structures Monitoring Program, and its AERMs under the

parameters monitored or inspected program element of the Structures Monitoring Program. The

staff noted that the chemical analysis of groundwater at WW-2 is non-aggressive, where pH >

5.5, Chloride < 500ppm, Sulfate < 1500ppm, as demonstrated in 2006: pH 6.11; Chloride 23.1

ppm; Sulfate 43.2 ppm and in 2007: pH 6.13; Chloride 40.4 ppm; Sulfate 54.6 ppm. The staff

also noted that the Structures Monitoring Program incorporates provisions for increased

monitoring described in RG 1.160. This includes clarifications for monitoring under

Paragraph (a)(1) of 10 CFR 50.65, including additional degradation-specific condition

monitoring and increased frequency of assessments until ongoing corrective actions are

complete and functional performance is assured. ACI 201.1 R-68, "Guide for Making a Condition

Survey of Concrete in Service" is used as a source by the applicant for observing concrete

deterioration and surface conditions. The staff further noted that the applicant's assessments

are performed in accordance with ANSI/ASCE 11-90, Guideline for Structural Condition

Assessments of Existing Buildings, and consider the following:

Function - Component design features, design basis, operational and maintenance

history.

* Existing degradation conditions - Locations, extent, rates.

* Degradation effects upon structural or component function - Structural safety,

containment, personnel safety, and protection of equipment. SSES does not employ a

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de-watering system in any of the site structures for control of settlement. If a below

grade structural wall or structural component becomes accessible through excavation, a

follow-up action is initiated for the responsible engineer to inspect the exposed.

The staff found this enhancement acceptable because when the enhancement is implemented,

AMP B.2.39, "Structures Monitoring Program," will be consistent with GALL AMP XI.S6 and

provide additional assurance that the effects of aging will be adequately managed.

Enhancement 3. LRA Section B.2.39 states an enhancement to the "parameters monitored or

inspected" and the "acceptance criteria" program elements of the Structures Monitoring

Program in that the procedure will be enhanced to include a degradation mechanism for

elastomers and an earthen embankment inspection.

The staff reviewed the applicant's Structures Monitoring Program, and its AERMs under the

parameters monitored or inspected, and acceptance criteria program elements of the

Structures Monitoring Program. The staff found that the additional structures that require

monitoring for license renewal are appropriately included in the Structural Monitoring program.

The staff also found the addition of inspection and acceptance criteria for elastomers and

earthen embankment inspection to the Structural Monitoring program acceptable because when

the enhancement is implemented, AMP B.2.39, "Structures Monitoring Program," will be

consistent with GALL AMP XI.S6 and provide additional assurance that the effects of aging will

be adequately managed.

Enhancement 4. LRA Section B.2.39 states an enhancement to the "scope of program" and

"parameters monitored or inspected" program elements of the Structures Monitoring Program in

that the procedure will be enhanced to include RG 1.127 inspection elements for water control

structures.

The staff reviewed the applicant's Structures Monitoring Program, and its AERMs under the

scope of program and the parameters monitored or inspected program elements of the

Structures Monitoring Program. The staff finds that the applicant omitted the acceptance criteria

program element enhancement for Water Control Structures, which should also have been

included as part of this enhancement. Therefore, RAI B.2.39-1 was issued. In the letter dated

July 8, 2008, the applicant indicated that the LRA Section B.2.39, Structures Monitoring

program, is amended to include the Acceptance Criteria for RG 1.127, Water Control Structures

Inspection. The staff reviewed the applicant's enhancement described above and its response

to the RAI and found them acceptable, because when the enhancement is implemented,

AMP B.2.39, "Structures Monitoring Program," will be consistent with GALL AMP XI.S6 and

provide additional assurance that the effects of aging will be adequately managed.

Enhancement 5. LRA Section B.2.39 states an enhancement to the "acceptance criteria"

program element of, the Structures Monitoring Program in that the procedure will be enhanced

to specify that the extent of observed masonry cracking and/or degradation of steel edge

supports/bracing are evaluated, and corrective action is required to ensure that the current

evaluation basis is still valid.

The staff reviewed the applicant's Structures Monitoring Program and its AERMs under the

acceptance criteria program element of the Structures Monitoring Program. The staff noted that

inspection criteria used to assess the condition of structures and structural components include

the following:

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Concrete is inspected for loss of material, cracking and change in material properties

aging effects.

* Masonry walls are inspected for cracking aging effect.

* Steel and other metals including threaded fasteners are inspected for loss of material

and cracking aging effects.

• Elastomers are inspected for cracking and change in material properties aging effects.

• Earthen structures are inspected for loss of form aging effect.

The staff also noted that the applicant's responsible engineer identifies problems with structural

performance, initiates structural deficiency reports and recommends corrective action.

Acceptance criteria are typically established such that corrective actions are initiated prior to

loss of function. The staff found this enhancement acceptable because when the enhancement

is implemented, AMP B.2.39, "Structures Monitoring Program," will be consistent with GALL

AMP XI.S6 and provide additional assurance that the effects of aging will be adequately

managed.

Enhancement 6. In the letter dated September 23, 2008, the applicant added an enhancement

to the "monitoring and trending," "acceptance," and "detection of aging effects" program

elements the Structures Monitoring Program to include direction for quantifying, monitoring and

trending of inspection results; guidance for inspection reporting, data collection and

documentation; acceptance criteria and critical parameters for monitoring degradation and for

triggering level of inspection and initiating of corrective action; and better alignment with

referenced industry codes, standards and guidelines. The applicant also stated that the

program will be enhanced to include specific qualification requirements for the inspector.

The staff reviewed the applicant's Structures Monitoring Program, the enhancement above, and

its AERMs under the monitoring and trending program element of the Structures Monitoring

Program. The staff found this enhancement acceptable because when the enhancement is

implemented, AMP B.2.39, "Structures Monitoring Program," will be consistent with GALL

AMP XI.S6 and provide additional assurance that the effects of aging will be adequately

managed.

Operating Experience. The staff also reviewed the applicant's OE described in LRA

Section B.2.39 and the applicant's Operation Experience Review Report, and interviewed the

applicant's technical staff to confirm that the plant-specific OE have been reviewed by the

applicant and is evaluated in the GALL Report. During its audit, the staff conducted a field walkdown with the applicant's technical staff in the general areas and those listed in the LRA, e.g.,

the ESSW pumphouse's roof membranes, expansion joints and penetration leakage in the

diesel generator building and the reactor building, and water leakage at penetrations located

below grade exterior walls, etc. In general, the staff noticed some degradation. However, all of

the observations are minor and acceptable per the applicant's inspection procedures and within

the guidance of the ACI 201.1 R (Guide for Making a Condition Survey of Concrete in Service)

and ACI 349-3R (Evaluation of Existing Nuclear Safety-Related Concrete Structures) as

recommended in the GALL Report.

The staff also confirmed that the applicant has addressed OE identified after the issuance of

the GALL Report. The staff finds that the applicant's Structures Monitoring Program, with the

corrective actions discussed in the LRA, has been effective in identifying, monitoring, and

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correcting the effects of aging on structures monitoring and the existing program OE revealed

no degradation not bounded by industry experience.

On the basis of its review of the OE and discussions with the applicant's technical staff, the staff

concluded that the applicant's Structures Monitoring Program will adequately manage the aging

effects that are identified in the LRA for which this AMP is credited. The staff confirmed that the

"operating experience" program element satisfies the criterion defined in the GALL Report and

in SRP-LR Section A. 1.2.3.10. The staff finds this program element acceptable.

UFSAR Supplement. In LRA Section A.1.2.45 and Commitment No. 34 in Table A-i, the

applicant provided the UFSAR supplement for the Structures Monitoring Program. The staff

reviewed this section and determines that the information in the UFSAR supplement is an

adequate summary description of the program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of the audit and review of the applicant's Structures Monitoring

Program, the staff determines that those program elements for which the applicant claimed

consistency with the GALL Report are consistent. In addition, the staff reviewed the

enhancements and confirmed that their implementation through Commitment No. 34 prior to the

period of extended operation would make the existing AMP consistent with the GALL Report

AMP to which it was compared. The staff concludes that the applicant has demonstrated that

the effects of aging will be adequately managed so that the intended function(s) will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and

concludes that it provides an adequate summary description of the program, as required by

10 CFR 54.21(d).

3.0.3.2.18 Regulatory Guide 1.127 Water-Control Structures Inspection

Summary of Technical Information in the Application. LRA Section B.2.40 describes the existing

RG 1.127 Water-Control Structures Inspection as consistent, with enhancements, with GALL

AMP XI.S7, "Inspection of Water-Control Structures Associated with Nuclear Power Plants."

The applicant stated that the program is implemented as part of the Spray Pond Inspection and

Structures Monitoring Program.

The applicant also stated that, RG 1.127 Water-Control Structures are visually examined at a

frequency selected to ensure there is no loss of intended function between inspections.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. The staff reviewed the enhancements (Commitment No. 35)

to determine whether the AMP, with the enhancements, is adequate to manage the aging

effects for which it is credited by the LRA.

The staff interviewed the applicant's technical staff and reviewed the associated bases

documents for the AMP B.2.40 "RG 1.127 Water-Control Structures Inspection," which provides

an assessment of the AMP elements' consistency with GALL AMP XI.S7.

The staff also reviewed those portions of the RG 1.127, Inspection of Water-Control Structures

Associated with Nuclear Power Plants Program for which the applicant claims consistency with

GALL AMP XI.S7.

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Enhancement 1. LRA Section B.2.40 states an enhancement to the "scope of program" and

"parameters monitored and inspected" program elements of the Structures Monitoring Program

in that the procedure will be enhanced to add the Spray Pond (including concrete liners,

emergency spillway, riser encasements and earthen embankments) to its scope for inspection.

The staff reviewed the applicant's RG 1.127 Water-Control Structures Inspection and its

AERMs under the scope of program element. The staff noted that the ultimate heat sink for

SSES consists of a concrete lined Spray Pond and an ESSW Pumphouse housing four

RHRSW pumps and four ESW pumps which pump the water from the Spray Pond through their

respective loops and back to the Spray Pond through a network of sprays located in the Spray

Pond. The staff further noted that the Spray Pond is designed in accordance with seismic

category I requirements. Earthen embankments are provided along the Spray Pond to ensure a

minimum freeboard of 3 feet and to direct flood water away from safety-related facilities in a

controlled manner. They are managed by both the Spray Pond Inspection and the Structures

Monitoring Program. The staff also noted that (1) there are no water-control structures that fall

under the regulatory jurisdiction of the Federal Energy Regulatory Commission (FERC) or the

U.S. Army Corps of Engineers; (2) the Spray Pond Inspection includes a visual inspection of the

Spray Pond and performance of groundwater level monitoring, and is credited for managing

loss of material and cracking aging effects for the concrete lined Spray Pond and its

appurtenances; and (3) the Structures Monitoring Program that includes a visual inspection of

the Spray Pond, ESSW Pump house, and earthen embankments, is credited for managing loss

of material, cracking, and spalling. The staff's review determined that this enhancement is

acceptable because when the enhancement is implemented, the AMP B.2.40, "RG 1.127

Water-Control Structures Inspection," will be consistent with the GALL AMP XI.S7 and provide

additional assurance that the effects of aging will be adequately managed.

Enhancement 2. LRA Section B.2.40 states an enhancement to the "parameters monitored or

inspected" program element of the Structures Monitoring Program in that the procedure will be

enhanced to include RG 1.127 Revision 1 Section C.2 inspection elements and degradation

mechanisms for water control structure inspection.

The staff reviewed the applicant's RG 1.127 Water-Control Structures Inspection, RG 1.127

Revision 1 Section C.2 requirements, the Structures Monitoring Program, and their AERMs

under the parameters monitored or inspected program elements of the Structures Monitoring

Program. The staff noted that the Spray Pond Inspection includes activities to inspect the

exposed and accessible external surfaces of the Spray Pond and its appurtenances to

determine material condition and to identify any signs of degradation that might affect its

structural integrity and operation adequacy. The staff also noted that the Structures Monitoring

Program monitors degradation mechanisms for the structure and structural components under

investigation and that a potential degradation mechanism matrix is contained in SSES design

standards which includes degradation mechanisms that require monitoring for license renewal.

The SMP will be enhanced to include parameters monitored and inspected for water-control

structures in accordance with inspection elements listed in Section C.2 of RG 1.127 Revision 1.

The staff found this enhancement acceptable because when the enhancement is implemented,

the AMP B.2.40, "RG 1.127 Water-Control Structures Inspection," will be consistent with GALL

AMP XI.S7 and provide additional assurance that the effects of aging will be adequately

managed.

Enhancement 3. LRA Section B.2.40 states an enhancement to the "acceptance criteria"

program element of the Structures Monitoring Program in that the procedure will be enhanced

to include acceptance criteria as delineated in GALL AMP XI.S7 for Water-Control Structures.

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The applicant stated that evaluation criteria provided in Chapter 5 of ACI 349.3R-96 provides

acceptance criteria (including quantitative criteria) for determining the adequacy of observed

aging effects and specifies criteria for further evaluation.

The staff reviewed the applicant's RG 1.127 Water-Control Structures Inspection, Chapter 5 of

ACI 349.3R-96, the Structures Monitoring Program, and their AERMs under the acceptance

criteria program element of the Structures Monitoring Program. The staff noted that the

acceptance criteria for the Spray Pond Inspection uses the six (6) permanent piezometer wells

(located in soil) along the perimeter of the Spray Pond; when the applicant determines that the

actual groundwater level has reached elevation 663 feet at any one of the six piezometer

locations, the following actions will be taken:

* NRC will be notified of the high (elevation 663') groundwater condition;

* Steps will be taken to identify the cause of the rise in the water level;

* An assessment of the safety impact of the occurrence will be performed;

* Appropriate actions will be taken based on the findings of the safety impact analysis.

The staff further notes that the applicant's responsible engineer identifies problems with

structural performance, initiates structural deficiency reports, and recommends corrective

action. Acceptance criteria are established such that corrective actions are initiated prior to loss

of function.

The acceptance criteria for the Structures Monitoring Program include the following:

0 Concrete is inspected for loss of material, cracking and change in material properties

aging effects.

0 Steel and other metals including threaded fasteners are inspected for loss of material

and cracking aging effects.

0 Elastomers are inspected for cracking and change in material properties aging effects.

* Earthen structures are inspected for loss of form aging effect.

The staff found this enhancement acceptable because when the enhancement is implemented,

AMP B.2.40, "RG 1.127 Water-Control Structures Inspection," will be consistent with the GALL

AMP XI.S7 and provide additional assurance that the effects of aging will be adequately

managed.

Operatinq Experience. The staff also reviewed the applicant's OE described in LRA

Section B.2.40, Operation Experience Review Report (RG 1.127 Water-Control Structures

Inspection's section), and interviewed the applicant's technical staff to confirm that the plantspecific OE have been reviewed by the applicant. The applicant indicated that it found some

minor indications that did not affect the structural integrity of any of the structures reviewed. The

staff found that visual examinations conducted by the Spray Pond Inspection as implemented

by the Structures Monitoring Program have not found any age-related problems or degraded

conditions that could affect their intended function. The SSES RG 1.127 Water-Control

Structures Inspection has demonstrated that it provides assurance that aging effects are being

managed. The staff also confirmed that the applicant has addressed OE identified after the

issuance of the GALL Report. The staff finds that the applicant's RG 1.127 Water-Control

Structures Inspection Program, has been effective in identifying, monitoring, and correcting the

aging effects on WCS and that existing program OE revealed no degradation not bounded by

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industry experience. The staff confirmed that the OE program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program

element acceptable.

UFSAR Supplement. In LRA Section A.1.2.42 and Commitment No. 35 in Table A-1, the

applicant provided the UFSAR supplement for the RG 1.127 Water-Control Structures

Inspection. The staff reviewed this section and determines that the information in the UFSAR

supplement is an adequate summary description of the program, as required by

10 CFR 54.21(d).

Conclusion. On the basis of the audit and review of the applicant's RG 1.127 Water-Control

Structures Inspection, the staff determines that those program elements for which the applicant

claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the

enhancements and confirmed that their implementation through Commitment No. 35 prior to the

period of extended operation would make the existing AMP consistent with the GALL Report

AMP to which it was compared. The staff concludes that the applicant has demonstrated that

the effects of aging will be adequately managed so that the intended function(s) will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and

concludes that it provides an adequate summary description of the program, as required by

10 CFR 54.21(d).

3.0.3.2.19 Fatigue Monitoring Program

Summary of Technical Information in the Application. Section B.3.1 of the LRA describes the

existing program, "Fatigue Monitoring Program (FMP)." The LRA describes this program as

consistent with the GALL AMP X.M1, "Metal Fatigue of Reactor Coolant Pressure Boundary"

with enhancements. The LRA states the purpose of the program is to manage the fatigue for all

Class 1 components. The FMP tracks the number and severity of critical thermal and pressure

transients for the selected reactor coolant system (RCS) components. The LRA indicates that

there is no exception for this program to the GALL AMP X.M1, however, enhancements will be

implemented prior to the period of extended operation in order for this program to be consistent

with the 10 elements described GALL AMP X.M1.

Staff Evaluation. The staff reviewed the technical information in the LRA to verify the

consistency of this program to the GALL AMP X.M1 and to assess the adequacy of this

program. The staff review identified several areas where it needed additional information to

complete the review of the SSES FMP. The staff transmitted RAIs to the applicant by letters

dated July 3, 2008, and October 22, 2008. The applicant responded to the staff RAIs by letters

dated August 1, 2008, and December 12, 2008.

The program description states that FMP monitors and tracks the number and severity of

critical thermal and pressure transients for the selected RCS components. In RAI B.3.1-1, the

staff requested the applicant to describe how this tracking and monitoring is accomplished.

The applicant's response indicated that the FMP is implemented by an approved engineering

procedure. The critical plant transients are monitored using two methods. Some of the

transients are automatically counted using computer software analysis of specific plant

operating data such as temperatures, pressures and flow rates. Those events that cannot be

automatically counted are manually counted by review of plant data and operating logs. The

applicant indicated that the SSES cycle counting procedure assumes that every event occurs at

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the full design value. The staff finds this procedure provides an acceptable method to track

design transient cycles for comparison to the number of cycles used in the fatigue evaluation of

ASME Class 1 components.

Section 4.3.1 of the LRA indicates that the design transients are monitored using the computer

software FatiguePro. In RAI B.3.1-2, the staff asked the applicant to confirm whether

FatiguePro is a part of the FMP and describe the role FatiguePro has in the FMP. In addition,

the staff asked the applicant to confirm whether FatiguePro is used for stress-based monitoring,

and if so, list the components that are stress-based monitored.

The applicant's response indicated that FatiguePro software is used for stress-based fatigue

(SBF) monitoring of the FW nozzle forgings, FW nozzle safe ends, and the CRD penetrations.

The applicant also indicated that FatiguePro is used to identify and count transient cycles from

the plant operating data. The transients that cannot be automatically counted are manually

entered into the FatiguePro database. FatiguePro is also used to calculate the fatigue CUF at

the limiting plant locations.

Previous LRA reviews determined that FatiguePro may use simplifying assumptions in the SBF

evaluation. The staff issued a draft regulatory information summary: "Fatigue Analysis of

Nuclear Power Plant Components," May 1, 2008, (73 FR 24094) which questioned the

conservatism of the simplifying assumptions used in the analysis methodology associated with

a Green's function that has been used for the detailed analysis of some components for license

renewal. The final reversion was issued on December 16, 2009 with no substantive changes

from the draft. In RAI B.3.1-7, the staff asked the applicant to provide the following information

regarding the fatigue evaluation, including environmental fatigue effects at the NUREG/CR6260 locations:

* Provide the details for the management of environmentally-assisted fatigue components

during the period of extended operation, including the elements to the AMP such as

scope, qualification, method and frequency.

* For all locations where 60-year environmental CUF is below 1.0, clarify whether any of

these values have been calculated using the Green's Function Methodology and if so

please describe the details of how Green's Function was used to calculate the CUF

values.

The applicant's response indicated that all eleven locations in LRA Table 4.3-3 will be managed

for environmentally-assisted fatigue by the SSES FMP. The applicant also indicated that the

environmental CUF at these locations would be updated once every fuel cycle and corrective

actions would be initiated prior to the CUF reaching the allowable limit at the monitored

locations. The staff finds this response acceptable because the applicant will monitor the

fatigue usage on a periodic basis and initiate appropriate corrective actions prior to the fatigue

CUF exceeding its allowable limit.

The applicant's response indicated that the Green's Function Methodology was used for the

SBF monitoring of the FW nozzle forging and nozzle safe end. In its response to RAI B3.1-1,

the applicant indicated that the SBF methodology had been benchmarked against the relevant

design basis stress report for each component. The staff requested that the applicant provide

additional information regarding the benchmarking of the methodology. In RAI 4.3-11, the staff

requested that the applicant provide the following additional information regarding the

benchmarking of the SBF methodology:

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a. Describe the procedure used to benchmark the SBF monitoring

locations against the relevant design reports. List the transients used

for the benchmarking and indicate the design fatigue usage associated

with each transient.

b. Discuss how the SSES SBF monitoring addresses the concern raised

in proposed Regulatory Information Summary (RIS), "Fatigue Analysis

of Nuclear Power Plant Components," May 1, 2008, (73 FR 24094).

Indicate whether any additional benchmarking of the SSES SBF

monitoring is planned.

The applicant's response described the procedure used to benchmark the SBF fatigue

monitoring locations for the FW nozzle safe and the CRD penetration locations. The applicant

indicated that key transient pairings from the design basis stress reports were used to adjust

the Green's functions so the stresses from the Green's function bounded the stresses from the

design report. The adjustment assures that the Green's function stresses bounded the stresses

from the design report for the key transient pairings.

The applicant also indicated that the benchmark calibrations were not performed for all possible

transient pairing scenarios. The applicant could not confirm that the benchmark calibration

procedure for the key transient pairings fully addressed all possible transient pairing scenarios.

Therefore, the applicant committed (Commitment No. 60) to either: (1) implement fatigue

monitoring software that satisfactorily addresses all issues raised in the proposed RIS, or (2)

perform a confirmatory ASME Code, Section III fatigue evaluation for the SBF monitored

locations to justify the existing FatiguePro methodology used at SSES Units 1 and 2. This

commitment will be completed prior to the period of extended operation. The staff finds the

applicant's commitment adequately addresses the technical concern indentified in the draft RIS

and is acceptable.

Enhancement 1. The FMP has an enhancement to the GALL Report program elements

"preventive actions, monitoring and trending." The LRA states that additional actions may be

taken when sufficient fatigue accumulation has occurred, if determined necessary to address

fatigue-related concerns. The staff found the above LRA statement does not provide sufficient

details to determine that FMP will prevent the design limit being reached. In RAI B.3.1-3, the

staff asked the applicant to explain what is meant by sufficient fatigue accumulation, describe

the criteria used to determine if further actions are required, and to provide the periodicity of the

updates for CUF values.

The applicant's response indicated that it had revised LRA Commitment No. 43 to include

specific action levels be determined for each monitored location. The revised commitment

requires the applicant to initiate actions at least 4 years prior to the projected CUF of any

monitored component reaching its allowable limit. In addition, the applicant committed to update

the fatigue calculation at least once every refueling cycle. The staff finds the applicant's revised

Commitment No. 43 provides adequate assurance that corrective actions will be initiated prior

to exceeding the allowable limit at any of the locations monitored by the SSES FMP.

The staff found this enhancement acceptable because when the enhancement is implemented,

the applicant's program will be consistent with the recommendations of GALL AMP X.M1.

Enhancement 2. The FMP has an enhancement to the GALL Report program elements

"preventive actions" and "acceptance criteria." This enhancement will address environmental

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effects on fatigue at specified locations in NUREG/CR-6260. The staff reviewed this

enhancement and found that it does not apply to the "preventive actions" and "acceptance

criteria" elements of GALL AMP X.M1. These two elements in the GALL AMP relate to

maintaining the fatigue usage factor below the design limit and monitoring the plant transients.

The enhancement therefore is not applicable to these program elements. In RAI B3.1-4, the

staff asked the applicant to explain how this enhancement to address environmental effects is

applicable to these two elements of GALL AMP X.M1.

The applicant's response provided a revision to the FMP described in LRA Appendix B,

Section B.3.1 and LRA Commitment No. 43 to clarify that the enhancements to address

environmental effects on fatigue at the NUREG/CR-6260 locations also include monitoring the

locations for environmental fatigue usage and acceptance criteria that the environmental fatigue

usage does not exceed the allowable limit. The staff finds the applicant's FMP revision

acceptable because it satisfies GALL AMP X.M1.

Consistent with the GALL Report X.M1, the FMP will provide for periodic updates of the fatigue

usage calculations. However, the LRA is not clear on the corrective actions that will be taken if

the updated CUF calculations are projected higher than the allowable limits. In RAI B.3.1-5, the

staff asked the applicant to state the exact actions that will be taken if FMP projects CUF values

higher than the allowable limit.

The applicant's response indicated that when an action level as defined in the response to

RAI B.3.1-3 is reached, an action request will be generated to require further engineering

evaluation of the monitored location. The engineering evaluation would attempt to demonstrate

that the CUF remains below the allowable limit through analysis refinements. If the analysis

cannot demonstrate that the CUF remains below the allowable limit, the applicant proposed the

following further options:

* Repair the component

* Replace the component

" Manage the component through inspection and flaw tolerance

The applicant's proposed actions to perform an engineering evaluation to demonstrate the CUF

remains within its allowable limit or repair/replacement of the component are consistent with

GALL AMP Xl.M1 and are acceptable. The applicant's proposal to manage the component

through inspection and flaw tolerance would require NRC review and approval as stated in LRA

Commitment No. 43.

Operatingq Experience. In the OE section of the FMP its states that industry OE has been

factored into the SSES FMP, however this section does not list or describe the applicable OE

that was reviewed by the applicant. The GALL Report X.M1 recommends that industry OE is

reviewed as part of the program and any applicable experience should be considered to be

incorporated into the FMP. In RAI B.3.1-6 the staff asked the applicant to list the documents

reviewed and provide the corresponding follow-up actions taken by SSES from any applicable

experience.

The applicant's response provided a list of documents reviewed as part of its FMP. These

documents included NRC bulletins and industry publications as well as other license renewal

applications relevant to fatigue of RCPB components. In addition, the applicant indicated that

SSES was an early participant in using fatigue monitoring of RCPB components and that SSES

maintains its participation in industry peer review groups. On the basis of the applicant's

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response to RAI B3.1-6, the staff finds that the applicant has considered the relevant industry

experience related to the fatigue of RCPB components.

The staff found this enhancement acceptable because when the enhancement is implemented,

the applicant's program will be consistent with the recommendations of GALL AMP X.M1.

UFSAR Supplement. 10 CFR 54.21(d) states that the UFSAR supplement for the facility must

contain a summary description of the programs and activities for managing the effects of aging.

The staff did not find a UFSAR Supplement for the Fatigue Monitoring Program, B.3.1. In

RAI B.3.1-8, dated July 3, 2008, the staff asked the applicant to provide the UFSAR

Supplement for AMP B.3.1.

In response to RAI B.3.1-8, dated August 1, 2008, the applicant provided an amendment to

LRA Appendix A to address the FMP. The amendment added a new Section A.1.2.49,

Commitment No. 43, which described the FMP, including the program enhancements that will

be implemented prior to the period of extended operation. In addition, the UFSAR Supplement

specifies corrective actions that will be implemented if the fatigue usage at any monitored

location is projected to exceed its design limit prior to the period of extended operation. The

staff reviewed the applicant's LRA amendment and finds that provides an adequate summary

description of the FMP.

The staff reviewed the UFSAR supplement and determines that it provides an adequate

summary description of the program as required by 10 CFR 54.21(d).

Conclusion. On the basis of its review of the applicant's FMP, the staff determines that those

program elements for which the applicant claimed consistency with the GALL Report are

consistent. The staff has reviewed the information provided in Section B.3.1 of the LRA and

additional information provided by the applicant by letters dated August 1, 2008, and

December 12, 2008. Also, the staff reviewed the enhancements and confirmed that they will be

implemented through Commitment No. 43 prior to the period of extended operation. On the

basis of its review as discussed above, the staff concludes that the applicant has demonstrated

that the effects of aging will be adequately managed so that the intended function(s) will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and

concludes that it provides an adequate summary description of the program, as required by

10 CFR 54.21(d).

3.0.3.2.20 Fuse Holders Program

Summary of Technical Information in the Application. LRA Section B.2.50 describes the new

Fuse Holders Program as consistent, with exception, with GALL AMP XI.E5, "Fuse Holders."

The applicant stated that this aging management program will manage increased connection

resistance due to fatigue of the fuse holder metallic clamp for fuse holders in the scope of the

program. This program will be used to ensure that the metallic clamps of the fuse holders are

not loosening due to removal and reinsertion of fuses.

In the LRA, Section 3.6.2.3.1, the applicant states that the fuse holders are located in metallic

electrical boxes (terminal boxes) which have covers that protect the interior of the box from the

environment. The applicant also states that the boxes are not exposed to weather (they are

located indoors at SSES); they are not exposed to chemical contamination or spills. Therefore,

the applicant concluded that chemical contamination, corrosion, and oxidation are not

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applicable aging effects for the metallic clamps of the fuse holders within the license renewal

scope at SSES. With respect to electrical transients and ohmic heating, the applicant states

that these fuses are not heavily loaded and do not experience frequent electrical and thermal

cycling. The power fuses with bolted connections used Belleville washers to maintain good

electrical contact in event of any differential thermal expansion. With respect to vibration, the

applicant states that the electrical boxes are mounted on walls; vibration is not an applicable

aging mechanism.

Furthermore, the applicant states that inspection of a sample of the 20 in-scope metal electric

boxes containing the fuse holders showed no corrosion or evidence of water intrusion or

collection and the metallic electrical boxes were clean and dry.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. The staff reviewed the exception to determine whether the

AMP, with the exception is adequate to manage the aging effects for which the LRA credits it.

The staff reviewed the applicant's claim of consistency with the GALL Report. The staff

reviewed and compared the "scope of program," "preventative actions," "parameters

monitored/detected," "detection of aging effects," "monitoring and trending," "acceptance

criteria," and "operating experience" program elements of the AMP to the corresponding

program element criteria in GALL AMP XI.E5, "Fuse Holders."

Exception. LRA Section B.2.50 states an exception to the "parameters monitored/inspected"

program element of GALL AMP XI.E5 such that it monitors only the mechanical fatigue of the

metallic clamp portion of the fuse holder caused by removal and insertion of the fuse. The

applicant stated that none of the other aging effects/mechanisms identified in this GALL Report

element are applicable. The staff noted that the in-scope fuse holders are installed in metal

terminal boxes, which are separate from sources of vibration. Therefore, vibration is not an

applicable aging mechanism. The terminal boxes are located inside the rooms that have a

controlled environment that protects the panels from the weather. They are not exposed to

potential system leakage or spills. With regard to internal moisture, the applicant inspected a

sample of terminal boxes and found the surface condition of the terminal boxes showed no

signs of corrosion or water intrusion. Therefore, corrosion is not an applicable aging

mechanism. With respect to thermal ohmic heating or thermal cycling, these fuse holders are

not used in heavy loading (control powers). In addition, these fuse holders are bolted

connections using Belleville washers to prevent thermal expansion of different material. Based

on this information, the staff determines that ohmic heating, thermal cycling or electrical

transients, vibration, chemical contamination, corrosion and oxidation are not applicable aging

mechanisms/effects for the metallic clamps of the fuse holders within the scope of license

renewal at SSES. Therefore, the staff finds that the exception to the "parameters

monitored/inspected" element acceptable.

The staff compared the programs elements in the applicant's program to those in GALL

AMP XI.E5 and verified that the program elements were consistent. The staff found the

applicant's AMP acceptable because it conforms to the recommended GALL Report AMP with

the exception described above.

Operating Experience. The staff reviewed the applicant's OE described in LRA Section B.2.50.

The applicant stated that the Fuse Holders Program is a new program for which there is no

SSES-specific OE. The applicant also stated that during routine preventive maintenance

activities in 2005, a fuse holder in a Unit 1 FW control panel was identified as being slightly

warmer than other fuse holders in the same location due to loosening of the fuse holder metallic

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clamps. The fuse holder was replaced, and post-maintenance testing, using thermography,

confirmed the condition was corrected. In addition, the applicant stated that in 2004, a fuse

holder in a Unit 2 reactor building chiller control panel was identified as being slightly warmer

than other fuse holders in the same location due to loosening of the fuse holder metallic

clamps. The fuse holder was replaced, and post-maintenance testing, using thermography,

confirmed the condition was corrected. The condition was detected prior to loss of intended

function in both of these cases.

The staff finds that the OE identified above demonstrates that the applicant's identification of

early problems with fuse holders and correction of them prior to loss of intended functions

provide assurance that the program will remain effective in assuring that equipment is

maintained during the period of extended operation.

The staff finds that the "operating experience" program element satisfies the criterion defined in

the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program element

acceptable.

UFSAR Supplement. In LRA Section A.1.2.51 and Commitment No. 59 in Table A-1, the

applicant provides its UFSAR Supplement for the Fuse Holders Program. The staff reviewed

the UFSAR supplement and determines that it provides an adequate summary description of

the program as required by 10 CFR 54.21(d). The applicant has committed to implement this

AMP prior to the period of extended operation.

Conclusion. On the basis of its review of the applicant's Fuse Holders Program, the staff

determines that those program elements for which the applicant claimed consistency with the

GALL Report are consistent. In addition, the staff reviewed the exception and its justification

and determines that the AMP, with the exception, is adequate to manage the aging effects for

which it is credited. The staff concludes that the applicant has demonstrated that effects of

aging will be adequately managed so that the intended function(s) will be maintained consistent

with the CLB for the period of extended operation as required by 10 CFR 54.21(a)(3). The staff

also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate

summary description of the program, as required by 10 CFR 54.21(d).

3.0.3.3 AMPs Not Consistent with or Not Addressed in the GALL Report

In LRA Appendix B, the applicant identified the following AMPs as plant-specific:

* Area-Based Nonsafety-affecting Safety Inspection

* Leak Chase Channel Monitoring Activities

* Preventive Maintenance Activities - RCIC/HPCI Turbine Casings

* Preventive Maintenance Activities -'Main Turbine Casings

For AMPs not consistent with or not addressed in the GALL Report the staff performed a

complete review to determine their adequacy to monitor or manage aging. The staff's review of

these plant-specific AMPs is documented in the following sections.

3.0.3.3.1 Area-Based Nonsafety-Affecting Safety (NSAS) Inspection

Summary of Technical Information in the Application. LRA Section B.2.46 describes the AreaBased NSAS Inspection Program as plant-specific. This program involves a one-time inspection

of the internal surfaces of nonsafety-related components that are exposed to non-radioactive

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drainage water or potable water environments. Also inspected are the internal surfaces of

copper alloys exposed to raw water from the spray pond/cooling tower. The applicant stated

that the one-time inspection will ensure that the structural integrity of nonsafety-related

components is maintained such that spatial interactions such as leakage will not result in the

loss of intended function of safety-related components during the period of extended operation.

Staff Evaluation. The staff reviewed the Area-Based NSAS Inspection against the

AMP elements found in the GALL Report, in the SRP-LR Section A.1.2.3, and in the SRP-LR

Table A. 1-1, focusing on how the program manages aging effects through the effective

incorporation of 10 program elements (i.e., "scope of program," "preventive actions,"

"parameters monitored or inspected," "detection of aging effects," "monitoring and trending,"

"acceptance criteria," "corrective actions," "confirmation process," "administrative controls," and

"operating experience").

The applicant indicated that the "corrective actions," "confirmation process," and "administrative

controls" program elements are part of the LRA Section B. 1.3, Quality Assurance Program and

Administrative Controls. The staffs evaluation of LRA Section B.1.3 program is discussed in

SER Section 3.0.4. The remaining seven elements are discussed below.

Scope of Program. LRA Section B.2.46, states that the scope of this program includes

confirming the environmental and/or internal surface conditions of nonsafety-related carbon

steel, cast iron, copper alloy, and stainless steel components in systems that contain nonradioactive equipment/area drainage water or potable water, as well as for copper alloy

components in systems that contain raw water. The applicant further stated that for systems

containing non-radioactive equipment/area drainage water or potable water, as well as for

copper alloy components in systems that contain raw water, a sample of copper alloy

components will be examined for evidence of SCC.

The original LRA limited the inspection of copper alloy components to systems where ammonia

or ammonium compounds were detected. By letter dated September 30, 2008, the applicant

deleted the requirement that limited the inspection of copper alloy components to systems

where ammonia or ammonium compounds were detected.

The staff reviewed the applicant's "scope of the program" program element against the criteria

in SRP-LR Section A. 1.2.3.1 which states that "The specific program necessary for license

renewal should be identified. The scope of the program should include the specific structures

and components of which the program manages the aging."

The staff finds that the applicant identified the program necessary for license renewal and

specified the specific structures and components consistent with SRP-LR Section A.1.2.3.1.

The staff confirmed that the "scope of program" program element satisfies the criterion defined

in the GALL Report and in SRP-LR Section A.1.2.3.1. The staff finds this program element

acceptable

Preventive Actions. LRA Section B.2.46 states that no actions are taken as part of the AreaBased NSAS Inspection to prevent aging effects or to mitigate aging degradation.

The staff reviewed the applicant's "preventive actions" program element against the criteria in

SRP-LR Section A. 1.2.3.2.2, which states that condition monitoring or performance monitoring

programs do not rely on preventive actions.

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Since this is a condition monitoring program, the staff concludes that this program does not rely

on preventive actions. The staff confirmed that the "preventive actions" program element

satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.2. The staff

finds this program element acceptable.

Parameters Monitored or Inspected. LRA Section B.2.46 states that parameters inspected will

include wall thickness and/or visual evidence of internal surface degradation. The internal

surfaces of copper alloy components will be inspected using visual or volumetric inspection to

detect SCC.

The original LRA limited the inspection of copper alloy components to systems where ammonia

or ammonium compounds were detected. By letter dated September 30, 2009, the applicant

deleted the requirement that limited the inspection of copper alloy components to systems

where ammonia or ammonium compounds were detected.

The staff reviewed the applicant's "parameters monitored or inspected" program element

against the criterion in SRP-LR Section A. 1.2.3.3.1, which states that, "The parameters to be

monitored or inspected should be identified and linked to the degradation of the particular

structure and component intended function(s)."

The applicant describes what kind of inspections will be conducted. The applicant also

discusses that degradation of these nonsafety-related systems and components (while not

expected) are conducted to ensure that spatial interactions do not occur that could impair or

prevent a safety-related function. The applicant also states that a focused characterization of

conditions is warranted to provide confirmation of a lack of degradation or to serve as the basis

for recurring actions during the period of extended operation, if required.

The staff confirmed that the "parameters monitored or inspected" program element satisfies the

criterion defined in the GALL Report and SRP-LR Section A.1.2.3.3. The staff finds this

program element acceptable.

Detection of Aqing Effects. LRA Section B.3.46 states: "The Area-Based NSAS Inspection will

use a combination of established volumetric and visual examination techniques performed by

qualified personnel on a sample population of subject nonsafety-related components exposed

to non-radioactive

equipment/area drainage water or potable water to identify evidence of a loss of material or to

confirm a lack thereof. The results of the inspection will be applied to all of the components

within the scope of the inspection activity."

The LRA also states: "If needed, based on engineering evaluation, the Area-Based NSAS

Inspection, will use a combination of established volumetric and visual examination techniques

performed by qualified personnel on a sample population of select nonsafety-related systems,

structures, and components. This program will use a combination of volumetric and visual

examination techniques on a sample population to identify evidence of loss of material or to

confirm lack of it. This program will also use a combination of volumetric and visual examination

techniques on a sample population to identify evidence of SCC or a lack of SCC."

The staff reviewed the applicant's "detection of aging effects" program element against the

criteria in SRP-LR Section A.1.2.3.4 which states that the inspections should be the proper

inspections to detect the anticipated aging effects. In addition, this program element should tell

when the inspections will be conducted and, if sampling is used, how the sample size will be

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determined. Finally, the inspections should be concentrated in areas thought to be the most

susceptible to degradation.

The applicant stated that it will use industry accepted inspections using qualified inspectors.

The inspections will be conducted within 10 years of entering the period of extended operation.

The locations to be inspected will be selected based on engineering evaluation and will be

concentrated in areas thought to be the most susceptible to degradation.

The staff review finds that the applicant's program uses the proper types of inspections to

detect the kinds of aging anticipated. The selection of locations for inspection based on

engineering evaluation is also acceptable. Finally, selection of areas anticipated to have the

most degradation is also acceptable.

The staff confirmed that the "detection of aging effects" program element satisfies the criterion

as defined in GALL Report and in SRP-LR Section A. 1.2.3.4. The staff finds this program

element acceptable.

Monitorinq and Trendinq. LRA Section B.2.46 states: "No actions are taken as part of the AreaBased NSAS Inspection to monitor and/or trend inspection results. This is a one-time inspection

used to determine if, and to what extent, further actions such as monitoring and trending may

be required. Results of inspections, including follow-up inspections, are routinely evaluated

through the site corrective action process, if necessary."

The staff reviewed the "monitoring and trending" program element and found that the SRP-LR

Section A.1.2.3.5 is not applicable because this is a one-time inspection and there is no

monitoring and trending unless unanticipated degradation is detected.

The staff confirmed that the "monitoring and trending" program element does not satisfy the

criterion defined in SRP-LR Section A.1.2.3.5 because this is a one-time inspection so

monitoring and trending does not apply. The staff finds this program element acceptable.

Acceptance Criteria. LRA Section B.2.46 states that there will be no unacceptable loss of

material, wall thinning, or SCC that could result in spatial interaction with safety-related

components during the period of extended operation, as determined by engineering evaluation.

The staff reviewed the applicant's "acceptance criteria" program element against the criteria in

SRP-LR Section A.1.2.3.6 which states that the acceptance criteria, against which the need for

corrective actions will be evaluated, should ensure that the structure and component intended

function(s) are maintained under all CLB design conditions during the period of extended

operation and the program should include a methodology for analyzing the results against

applicable acceptance criteria.

The structures and components inspected as part of the NSAS Inspection Program are

nonsafety-related structures and components and this is a new program., However, the

applicant has identified appropriate acceptance criteria and how the age related degradation will

be evaluated. On the basis of its review, the staff finds this program element acceptable.

The staff confirmed that the "acceptance criteria" program element satisfies the criterion

defined in the GALL Report and SRP-LR Section A.1.2.3.6. The staff finds this program

element acceptable.

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Operating Experience. The staff reviewed the applicant's OE described in LRA Section B.2.26.

The applicant stated that the Area-Based NSAS Inspection is a new one-time inspection for

which there is no OE indicating the need for an aging management program.

In a letter dated June 10, 2008, the staff issued RAI B.2-1 that is consistent with the statement

in the SRP-LR Section A. 1.2.3.10, that the applicant make a commitment to provide OE in the

future to the staff for new AMPs to confirm their effectiveness for the period of extended

operation. In its letter dated July 8, 2008, the applicant responded to RAI B.2-1 and stated that

OE for new aging management programs described in LRA Appendix B will be gained as these

new programs are implemented during the period of extended operation. The applicant stated

that results of tests, inspections, and other aging management activities conducted in

accordance with these programs will be subject to confirmation and corrective action elements

of the Susquehanna 10 CFR Part 50, Appendix B, quality assurance program and that results

will be subject to NRC review during regional inspections under existing NRC inspection

modules. The applicant further stated that one-time inspections will be performed prior to entry

to the period of extended operation to confirm the effectiveness of these aging management

programs, and that these programs are subject to review under NRC Inspection Procedure

71003, Post-Approval Site Inspection for License Renewal.

The staff noted that post-approval site inspections provide an opportunity for staff review and

assessment of the effectiveness of the applicant's Area-Based NSAS Inspection Program after

the applicant has developed OE with that program. The staff concludes that the corrective

action program, based on internal and external plant OE, would capture OE in the future to

support the conclusion that the effects of aging are adequately managed. On this basis, the

staff finds the response acceptable.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds that this program

element acceptable.

UFSAR Supplement. In LRA Section A.1.2.1 and Commitment No. 40 in Table A-1, the

applicant provided the UFSAR supplement for Area Based Nonsafety Affecting Safety

Inspection Program. The applicant has committed to implementing the Area Based Nonsafety

Affecting Safety Inspection Program within the 10 year period prior to the period of extended

operation.

The staff determines that the information in the UFSAR Supplement provides an adequate

summary description of the program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of the review of the applicant's Area Based Nonsafety Affecting

Safety Inspection Program including the applicant's response to the staff RAI, the staff

concludes that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended functions of these components will be maintained consistent with

the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also

reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate

summary description of the program, as required by 10 CFR 54.21(d).

3.0.3.3.2 Leak Chase Channel Monitoring Activities

Summary of Technical Information in the Application. LRA Section B.2.47 describes the existing

Leak Chase Channel Monitoring Activities as plant-specific. In the LRA, the applicant stated

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that AMP B.2.47 is an existing plant-specific condition monitoring program consisting of

observation and surveillance activities to detect leakage from the spent fuel pool and the fuel

shipping cast storage pool liners due to age-related degradation within the scope of license

renewal.

Staff Evaluation. The staff reviewed the Leak Chase Channel Monitoring Activities against the

AMP elements found in the GALL Report, in SRP-LR Section A. 1.2.3, and in SRP-LR

Table A.1-1, focusing on how the program manages aging effects through the effective

incorporation of 10 program elements. The staff's evaluations on seven of these elements

follow.

Scope of the Pro-gram. LRA Section B.2.47 states that the program includes periodic monitoring

of the spent fuel pool and fuel shipping cask storage pool leak chase system. The applicant

also stated that the program is credited for detecting loss of material aging effects for the spent

fuel pool and fuel shipping cask storage pool liners.

The staff reviewed the applicant's "scope of the program" program element against the criteria

in SRP-LR Section A.1.2.3.1, which states that the scope of the program should include the

specific structures and components of which the program manages the aging. The staff found

the applicant has identified the specific structures and components of which the aging effects

are managed. On this basis, the staff finds the applicant's scope of the program acceptable.

The staff confirmed that the "scope of the program" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A. 1.2.3.1. The staff finds this program

element acceptable.

Preventive Actions. LRA Section B.2.47 states that no actions are taken as part of the program

to prevent aging effects or mitigate age-related degradation.

The staff reviewed the "preventive actions" program element criterion in SRP-LR

Section A.1.2.3.2 which states that condition monitoring programs do not rely on preventive

actions, and thus, preventive actions need not be provided. Therefore, this program element is

acceptable because this is a condition monitoring program and there is no need for preventive

actions.

Parameters Monitored or Inspected. LRA Section B.2.47 states that the spent fuel pool and fuel

shipping cask storage pool liner leak detection drain valves are periodically opened and the leak

rate estimated by the volumetric method. The applicant also stated that this ensures evidence

of leakage from the spent fuel pool and fuel shipping cask storage pool liner is promptly

identified and corrected if necessary.

The applicant further stated that the program includes activities to cycle open and close spent

fuel pool and fuel shipping cask storage pool liner drain valves and measure and report any

Water collected to shift supervision.

The staff reviewed the "parameters monitored or inspected" program element against the

criteria in SRP-LR Section A. 1.2.3.3 which states that the parameters to be monitored or

inspected should be identified and linked to the degradation of the particular structure and

component intended function(s).The staff found the program identifies the parameters to be

monitored or inspected and linked them to the degradation of the particular structures and

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components intended functions by collecting, measuring and reporting any water collected to

the shift supervision for further action.

This staff confirmed that the "parameters monitored or inspected" program element satisfies the

criterion defined in the GALL Report and SRP-LR Section A. 1.2.3.3. The staff finds this

program element acceptable.

Detection of Aging Effects. LRA Section B.2.47 states that the spent fuel pool and fuel shipping

cask storage pool drain valves are cycled and the volume of any water collected is measured.

The applicant also stated that estimating the time from start of opening valve until flow slows to

a slow drip is also performed for known leakage.

The staff reviewed the "detection of aging effects" program element against the criteria in

SRP-LR Section A. 1.2.3.4, which states that the parameters to be monitored or inspected

should be appropriate to ensure that the structure and component intended function(s) will be

adequately maintained for license renewal under all CLB design conditions. The staff found the

applicant has identified the drain valves for the spent fuel pool and fuel shipping cask storage

are cycled and the volume of any water collected is measured as required under their CLB

design conditions.

This staff confirmed that the "detection of aging effects" program element satisfies the criterion

defined in the GALL Report and SRP-LR Section A. 1.2.3.4. The staff finds this program

element acceptable.

Monitorinq and Trending. LRA Section B.2.47 states that leak chase channel monitoring

activities are performed at least once quarterly. The applicant also stated that the routine task

requires that any water collected in excess of one pint is reported to shift supervision. Shift

supervision will then notify Nuclear System Engineering by an appropriate mechanism. The

applicant further stated that data are entered into the Shift Operations Management System log

for trending purposes even if no leakage was identified.

The staff reviewed the applicant's "monitoring and trending" program element against the

criteria in SRP-LR Section A. 1.2.3.5 which states that the program element describes "how" the

data collected are evaluated and may also include trending for a forward look. This includes an

evaluation of the results against the acceptance criteria and a prediction regarding the rate of

degradation in order to confirm that timing of the next scheduled inspection will occur before a

loss of SC intended function.

The staff found that the "monitoring and trending" program element satisfies the criterion

defined in SRP-LR Section A. 1.2.3.5 because the applicant provides predictability of the extent

of degradation and thus effects timely corrective or mitigative actions e.g., monitoring activities

are performed at least once quarterly and evaluation of the results against the acceptance

criteria, and a prediction regarding the rate of degradation before a loss of structures

component intended function. The staff confirmed that the "monitoring and trending" program

element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.5.

The staff finds this program element acceptable.

Acceptance Criteria. LRA Section B.2.47 states the acceptance criterion is less than one pint of

measured leakage from each liner leak chase drain valve. The applicant also stated that the

one pint criterion is based on SSES plant-specific historical accumulation of water at Unit 2

spent fuel pool drain points.

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The staff reviewed the "acceptance criteria" program element against the criteria in SRP-LR

Section A.1.2.3.6 which states that the acceptance criteria of the program and its basis should

be described. The staff found that the "acceptance criteria" program element satisfies the

criterion defined in SRP-LR Section A. 1.2.3.6 since; the applicant has provided the

predetermined criteria as quantitative inspections by personnel in accordance with the approved

site-specific programs. On this basis, the staff finds this program element acceptable.

Operatingq Experience. The staff also reviewed the applicant's OE described in LRA

Section B.2.47, "Operation Experience Review Report (Leak Chase Channel Monitoring

Activities' section)", and to confirm that the plant-specific OE have been reviewed by the

applicant. The staff found that the Leak Chase Channel Monitoring Activities have indicated

small leakage in the Unit 2 spent fuel pool. The Unit 1 spent fuel pool and the common fuel

shipping cask storage pool liners have shown no leakage. The staff reviewed CR 94-251

(April 4, 1994) Reported leakage from Fuel Pool drain valves 253082A thru valves 253082E

and found: for the first time in three months, valves 253082A has 40 gallons, and all of other

valves (valves 253082B - valves 253082E were dry. However, on December 5, 2006, OPS PM

S5477 (CR 830720) identified no leakage at valve 253082A, and therefore, the tracking and

trending was closed. The applicant noted in the LRA that, based on the expected leakage from

this small leak as well as minor drainage previously noted at liner drain valves "B" and "E," the

inspection frequency has been accelerated to monthly for the Unit 2 spent fuel pool. For the

past five years, the Unit 2 spent fuel pool liner leakage measurements have all been within the

acceptance criteria.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program

element acceptable.

UFSAR Supplement. In LRA Section A. 1.2.27 and Commitment No. 41 in Table A-1, the

applicant provided the UFSAR supplement for the leak Chase Channel Monitoring Activities.

The staff reviewed this section and determines that the information in the UFSAR supplement is

an adequate summary description of the program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of its technical review of the applicant's Leak Chase Channel

Monitoring Activities, the staff concludes that the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended function(s) will be maintained consistent

with the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff

also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate

summary description of the program, as required by 10 CFR 54.21(d).

3.0,3.3.3 Preventive Maintenance Activities - RCIC/HPCI Turbine Casings

Summary of Technical Information in the Application. LRA Section B.2.48 describes the existing

Preventive Maintenance Activities - RCIC/HPCI Turbine Casings as a plant-specific AMP. The

applicant stated that this program manages loss of material due to general corrosion on internal

surfaces of RCIC and HPCI pump turbine casings, and on piping and piping components such

as rupture disks and valve bodies made of carbon steel or cast iron.

Staff Evaluation. The staff reviewed the Preventive Maintenance Activities - RCIC/HPCI

Turbine Casings as an existing program that is plant-specific. There is no corresponding

AMP in the GALL Report.

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The staff reviewed the Preventive Maintenance Activities - RCIC/HPCI Turbine Casings

Program against the AMP elements found in SRP-LR Section A.1.2.3 and SRP-LR Table A.1-1,

focusing on how the program manages aging effects through the effective incorporation of

10 elements (i.e., "scope of program," "preventive actions," "parameters monitored or

inspected," "detection of aging effects," "monitoring and trending," "acceptance criteria," "corrective actions," "confirmation process," "administrative controls," and "operating

experience").

The applicant indicated that the "corrective actions," "confirmation process," and "administrative

controls" program elements are part of the LRA Section B.1.3, Quality Assurance Program and

Administrative Controls. The staffs evaluation of LRA Section B. 1.3 program is discussed in

SER Section 3.0.4. The remaining seven elements are discussed below.

Scope of Program. LRA Section B.2.48 states that this program will manage loss of material

due to general corrosion of the internal carbon steel and cast iron surfaces in the RCIC and

HPCI pump turbine casings and in-scope piping and piping components in steam lines

downstream from the steam admission valves that are exposed to ambient air during normal

plant operation. The applicant stated that this ambient air internal environment is untreated and

will be moist as a result of steam that has condensed and drained to the barometric condensers

or vented to the drywell.

The staff reviewed the applicant's "scope of the program" program element against the criteria

in SRP-LR Section A.1.2.3.1 which states that, "The specific program necessary for license

renewal should be identified. The scope of the program should include the specific structures

and components of which the program manages the aging."

In its letter dated October 21, 2008, in response to the NRC regional inspection of the LRA, the

applicant included an enhancement in the "scope of program" program element to include a

specific step to perform a visual inspection of the RCIC turbine casing. The cast iron

components are subject to a visual inspection and a hardness test to determine if selective

leaching has occurred. The staff's review of the "Selective Leaching Program" can be found in

section 3.0.3.1.17. The staff finds the enhancement acceptable because the enhancement

provides details that makes the "scope of program" program element satisfy the criterion

defined in SRP-LR Section A.1.2.3.1.

The staff finds this program element acceptable because it adequately describes the scope of

the program.

The staff confirmed that the "scope of the program" (called the "scope of activity" in the LRA)

program element satisfies the criterion defined in SRP-LR Section A. 1.2.3.1. The staff finds this

program element acceptable.

Preventive Actions. LRA Section B.2.48 states that no actions are taken as part of the

Preventive Maintenance Activities - RClC/HPCI Turbine Casings Program to prevent aging

effects or to mitigate age-related degradation.

The staff reviewed the applicant's "preventive actions" program element against the criteria in

SRP-LR Section A.1.2.3.2-2., which states that condition monitoring or performance monitoring

programs do not rely on preventive actions.

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Since this is a condition monitoring program, the staff concludes that this program does not rely

on preventive actions.

The staff confirmed that the "preventive actions" program element satisfies the criterion defined

in SRP-LR Section A.1.2.3.2-2. The staff finds this program element acceptable.

Parameters Monitored or Inspected. LRA Section B.2.48 states that this program inspects the

internal carbon steel surfaces of RCIC and HPCI pump turbine casings and the cast iron

surfaces of the associated gland cases for signs of degradation for evidence of loss of material.

The staff reviewed the applicant's "parameters monitored or inspected" program element

against the criteria in SRP-LR Section A.1.2.3.3, which states that for a condition monitoring

program, the parameter monitored or inspected should detect the presence and extent of aging

effects.

By letter dated July 9, 2008, the staff issued RAI B.2.48-1 asking the applicant to provide more

details of the types of inspections that will be conducted. Specifically, the staff asked the

applicant to provide the method used to inspect, the frequency of inspections, and the type of

data collected. By letter dated August 8, 2008, the applicant responded that the inspection of

RCIC and HPCI pump turbine internals, including the casings, is a skill-based visual inspection

performed by Mechanical Maintenance personnel. The inspection follows SSES procedures

and includes inspections for loose parts, mechanical damage, corrosion, erosion, pitting, scale

deposits, and other abnormal wear. The procedure for the HPCI turbine includes visual

inspection for the turbine casing which was not included for the RCIC turbine. A commitment

(Commitment No. 42) has been added to the LRA committing to an enhancement to add the

visual inspection for the RCIC turbine casing. The applicant also stated that the frequency of

inspections will be a 10-year frequency and any deficiencies noted will be entered into the

corrective action program for evaluation.

The staff finds this program element acceptable, because in response to RAI B.2.48-1 the

applicant has appropriately identified the inspection methods, frequency of testing and the type

of data collected.

The staff confirmed that the "parameters monitored or inspected" program element satisfies the

criterion defined in SRP-LR Section A. 1.2.3.3. The staff finds this program element acceptable.

Detection of Aqing Effects. LRA Section B.2.48 states that this program will detect loss of

material prior to any loss of component intended functions.

The staff reviewed the applicant's "detection of aging effects" program element against the

criteria in SRP LR Section A.1.2.3.4, which states that the parameters to be monitored or

inspected should be appropriate to ensure that the structure and component intended

function(s) will be adequately maintained for license renewal under all CLB design conditions.

This includes aspects such as method or technique (e.g., visual, volumetric, surface

inspection), frequency, and data collection.

The staff concluded that there was insufficient information in the LRA for this program element.

By letter dated July 9, 2008, the staff issued RAI B.2.48-1 asking the applicant to provide more

details of the types of inspections that will be conducted. Specifically, the staff asked the

applicant to provide the method used to inspect, the frequency of inspections, and the type of

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data collected. By letter dated August 8, 2008, the applicant responded to RAI B.2.48-1 and it is

discussed under the "parameters monitored or inspected" program element.

The staff finds this program element acceptable because it is a condition monitoring program

that uses inspection techniques to identify loss of material and the response to the RAI gives

adequate details of the inspection techniques.

In its letter dated October 21, 2008, in response to the NRC regional inspection of the LRA, the

applicant included an enhancement in the "detection of aging effects" program element to add

requirements to have inspections performed by qualified personnel using VT-3 or equivalent

inspection methods, and to document and trend inspection results.

The staff finds the enhancement acceptable because the applicant has provided qualifications

of personnel performing the visual inspections.

The staff confirmed that the "detection of aging effects" program element satisfies the criterion

defined in SRP-LR Section A.1.2.3.4. The staff finds this program element acceptable.

Monitoring and Trending. LRA Section B.2.48 states that "this is a condition monitoring program

that uses visual inspections to identify internal degradation of turbine casings. The observation

of significant, unusual, or unexpected casing degradation is noted and is followed up by writing

a condition report. The condition report may result in a condition assessment or further

inspection. The disposition of the condition may result in a change in the frequency of

inspection."

The SRP-LR Section A. 1 2 3.5 states that: "Monitoring and trending activities should be

described, and they should provide predictability of the extent of degradation and thus effect

timely corrective or mitigative actions. Plant-specific and/or industry-wide OE may be

considered in evaluating the appropriateness of the technique and frequency."

The staff finds that the "monitoring and trending" program element is acceptable because, in

response to RAI B.2.48-1, the applicant has supplied sufficient detail for the staff to find that

monitoring and trending activities have been described and any significant degradation will

result in a condition assessment that will determine if more frequent inspections are required.

In its letter dated October 21, 2008, in response to the NRC regional inspection of the LRA, the

applicant included an enhancement in the "monitoring and trending" program element to add

requirements to have inspections performed by qualified personnel using VT-3 or equivalent

inspection methods, and to document and trend inspection results.

The staff finds the enhancement acceptable because the applicant has indicated that qualified

personnel will document and trend inspection results, which make the "monitoring and trending"

program element, satisfy the criterion defined in SRP-LR Section A. 1.2.3.5

The staff confirmed that the "monitoring and trending" program element satisfies the criterion

defined in SRP-LR Section A. 1.2.3.5. The staff finds this program element acceptable.

Acceptance Criteria. LRA Section B.2.48 states that the acceptance criteria for this program are

no unacceptable visual indications of wall-thinning or loss of material. The applicant further

stated that unacceptable in this program involves a determination by engineering evaluation

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that the components are degraded to the point that they may not be capable of performing their

intended function until the next scheduled inspection.

The staff reviewed the applicant's "acceptance criteria" program element against the criteria in

SRP-LR Section A. 1.2.3.6 which states that the acceptance criteria, against which the need for

corrective actions will be evaluated, should ensure that the structure and component intended

function(s) are maintained under all CLB design conditions during the period of extended

operation and the program should include a methodology for analyzing the results against

applicable acceptance criteria.

In its letter dated October 21, 2008, in response to the NRC regional inspection of the LRA, the

applicant included an enhancement in the "acceptance criteria" program element to establish

specific acceptance criteria for inspection results, similar to those of ASME Section Xl, IWB

3519.1, used for pump casing inspection.

The staff finds the enhancement acceptable because specific acceptance criteria are identified

in addition to the engineering evaluation for determining the extent of age related degradation.

The staff finds the "acceptance criteria" program element acceptable because the applicant has

identified the acceptance criteria and will use engineering evaluation to determine the extent of

degradation and the need for corrective action.

The staff finds that the "acceptance criteria" program element is acceptable because it satisfies

the recommendations in the SRP-LR Section A. 1.2.3.6-1.

Operatinq Experience. The applicant stated in LRA Section B.2.48 that a search of plantspecific OE for the most recent five-year period, no loss of pressure boundary integrity was

identified that could be attributed to the applicable aging effects in the scope of this program.

The staff reviewed the applicant's "operating experience" program element against the criteria

in SRP LR Section A.1.2.3.10, which states that OE with existing programs should be

discussed. The OE of AMPs, including past corrective actions resulting in program

enhancements or additional programs, should be considered.

The staff reviewed the applicant's OE described in LRA Section B.2.48. The applicant stated

that this program is consistent with industry practice and has proven effective in maintaining the

material condition of the RCIC and HPCI pump turbine casings.

By letter dated July 9, 2008, the staff issued RAI B.2.48-2 asking the applicant to provide more

information concerning the statement in the LRA that stated, "The elements that comprise the

Preventive Maintenance Activities - RCIC/HPCI Turbine Casings program are consistent with

industry practice and have proven effective in maintaining the material condition of the RCIC

and HPCI pump turbines, including casings." The staff asked for details on the industry

practice. The staff also asked for a justification explaining how a monitoring program can

maintain the material condition of the RCIC and HPCI pump turbines and whether visual

inspections can be used to stop loss of material.

By letter dated August 8, 2008, the applicant responded stating that industry practice is to

perform periodic disassembly and inspection of the turbines in accordance with vendor

recommendations contained in the vender instruction manual. The applicant went on to state

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that visual inspection provides an indication of the material condition and is not intended to

prevent the effects of aging.

The applicant amended the "detection of aging effects" program element to include the

following:

The program relies on visual inspection to identify surface degradation.

Inspections are performed on a nominal 10-year frequency based on past

inspections and on industry experience.

The applicant amended the "operating experience" program element to say:

The elements that comprise the Preventive Maintenance Activities - RCIC/HPCI

Turbine Casings are based on manufacturing recommendations and with

industry guidance and have proven effective in managing the material condition

of the RCIC and HPCI pump turbines, including the casings.

The staff reviewed the response and finds that it satisfactorily addresses the RAI.

The staff confirmed that the "operation experience" program element satisfies the criterion

defined in SPR-LR Section A.1.2.3.10. The staff finds this program element acceptable.

UFSAR Supplement. In LRA Section A.1.2.39 and Commitment No. 42 in Table A-i, the

applicant provided the UFSAR supplement for the Preventive Maintenance Activities -

RCIC/HPCI Turbine Casings Program. The staff reviewed this section and determined that the

information in the UFSAR Supplement does not provide an adequate summary description of

the program consistent with the SRP-LR.

By letter dated July 9, 2008, the staff issued RAI B.2.48-1 asking the applicant to provide more

details of the types of inspections that will be conducted. Specifically, the staff asked the

applicant to provide the method used to inspect, the frequency of inspections, and the type of

data collected. By letter dated August 8, 2008, in response to RAI B.2.48-1, the applicant

responded that the inspection of RCIC and HPCI pump turbine internals, including the casings,

is a skill-based visual inspection performed by Mechanical Maintenance personnel. The

inspection follows SSES procedures and includes inspections for loose parts, mechanical

damage, corrosion, erosion, pitting, scare deposits, and other abnormal wear. In its letter dated

October 21, 2008, in response to the NRC regional inspection of the LRA, the applicant revised

the UFSAR supplement to include the following three enhancements:

" A specific step to perform a visual inspection of the RCIC turbine casing

* Performance of inspections by qualified personnel using VT-3 or equivalent inspection

methods, and to document and trend inspection results

* Specific acceptance criteria for inspections

The applicant has revised Commitment No. 42 to include these commitments.

Based on acceptable responses to the RAI and on the amendment to the UFSAR supplement

in terms of the revision to the commitment list, the staff finds the UFSAR supplement is

acceptable.

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The staff determines that the information in the UFSAR Supplement provides an adequate

summary description of the program, as required by 10 CFR 54.21(d).

Conclusion. The staff finds the applicant's Preventive Maintenance Activities - RCIC/HPCI

Turbine Casings Program acceptable on the basis of its review as discussed above. The staff

finds that the program will adequately manage the aging effects so that the intended functions

will be maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and finds that

it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).

3.0.3.3.4 Preventive Maintenance Activities - Main Turbine Casing

Summary of Technical Information in the Application. In its letter dated June 30, 2008, and

September 26, 2008, the applicant added a plant-specific existing program, Section B.2.49,

"Preventive Maintenance Activities - Main Turbine Casing," with an enhancement.

The applicant stated that the Preventive Maintenance Activities - Main Turbine Casing will

manage loss of material due to FAC on the internal surfaces of the high pressure casing for the

main turbine.

Staff Evaluation. The staff reviewed the Preventive Maintenance Activities - Main Turbine

Casing Program against the AMP elements found in the GALL Report, SRP-LR Section A.1.2.3,

and SRP-LR Table A.1-1, focusing its review on how the program manages aging effects

through the effective incorporation of 10 elements (i.e., "scope of program," "preventive

actions," "parameters monitored or inspected," "detection of aging effects," "monitoring and

trending," "acceptance criteria," "corrective actions," "confirmation process," "administrative

controls," and "operating experience").

The applicant indicated that the "corrective actions," "confirmation process," and "administrative

controls" program elements are part of the LRA Section B. 1.3, Quality Assurance Program and

Administrative Controls. The staffs evaluation of LRA Section B. 1.3 program is discussed in

SER Section 3.0.4. The remaining seven elements are discussed below.

Enhancement. In LRA Section B.2.49, the applicant identified an enhancement to the program

to specify that the inspection of the high pressure turbine shell will consist of a visual inspection

(VT-3 or equivalent) and an ultrasonic examination for wall thickness.

The staff reviewed the enhancement and determined that implementation of the enhancement

will add the inspection techniques necessary to adequately manage the aging effects of loss of

material due to FAC during the period of extended operation. As stated in "detection of aging

effects" program element below, visual inspection will be performed to detect any age related

degradation and if detected, ultrasonic inspection will be performed to determine the extent of

the degradation. Based on the review, the staff finds the enhancement acceptable.

Scope of Program. In LRA Section B.2.49, the applicant stated that this program is credited for

managing loss of material due to FAC on the internal carbon steel surfaces of the high pressure

casing for the main turbine that is exposed to steam during normal plant operation.

The staff reviewed the applicant's "scope of program" program element against the criteria in

SRP-LR Section A.1.2.3.1, which states that the specific program necessary for license renewal

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should be identified. The scope of the program should include the specific structures and

components of which the program manages the aging.

The staff concludes that since the applicant has identified the components for which this

program manages aging. The staff confirmed that the "scope of program" program element

satisfies the criterion defined in the GALL Report and in SRP-LR Section A. 1.2.3.1. The staff

finds this program element acceptable.

Preventive Actions. In LRA Section B.2.49, the applicant stated that no actions are taken to

prevent aging effects or to mitigate age-related degradation.

The staff reviewed the applicant's "preventive actions" program element against the criteria in

SRP-LR Section A.1.2.3.2, which states that for condition or performance monitoring programs,

they do not rely on preventive actions and thus, this information need not be provided.

Since this is a condition monitoring program, the staff concludes that this program does not rely

on preventive actions. The staff confirmed that the "preventive actions" program element

satisfies the criterion defined in the GALL Report and in SRP-LR Section A. 1.2.3.2.The staff

finds this program element acceptable.

Parameters Monitored or Inspected. In LRA Section B.2.49, the applicant stated that the

program inspects the internal carbon steel surfaces of the high pressure turbine casing for

signs of degradation that might be indicative of wall-thinning or loss of material. Inspections will

consist of a combination of visual examination and non-destructive testing.

The staff reviewed the applicant's "parameters monitored or inspected" program element

against the criteria in SRP-LR Section A.1.2.3.3, which states that for a condition monitoring

program, the parameter monitored or inspected should detect the presence and extent of aging

effects.

Since this is a condition monitoring program, the applicant has appropriately identified the

parameter to be inspected and the method of inspection. The staff confirmed that the

"parameters monitored or inspected" program element satisfies the criterion defined in the

GALL Report and SRP-LR Section A.1.2.3.3. The staff finds this program element acceptable.

Detection of AqinQ Effects. In LRA section B.2.49, the applicant stated that the program will rely

on established NDE techniques, including visual (VT-3 or equivalent) inspection of accessible

surfaces and ultrasonic inspections of selected locations by qualified personnel to identify

surface degradation and wall thickness. Inspections are performed on a nominal 10-year (12-

year maximum) frequency based on manufacturer recommendation.

The staff reviewed the applicant's "detection of aging effects" program element against the

criteria in SRP-LR Section A. 1.2.3.4, which states that the parameters to be monitored or

inspected should be appropriate to ensure that the structure and component intended

function(s) will be adequately maintained for license renewal under all CLB design conditions.

This includes aspects such as method or technique (e.g., visual, volumetric, surface

inspection), frequency, sample size, data collection and timing of new/one-time inspections to

ensure timely detection of aging effects.

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The staff reviewed the operating experience provided by the applicant and noted that based on

significant modification work performed on the high pressure turbines during the last five years,

no indication of pressure boundary wear was found on the high pressure turbine outer casing.

The staff finds that based on plant operating experience, the frequency of once every ten years

based on manufacturer's recommendation is acceptable. If visual inspection identifies aging

degradation, ultrasonic inspection will be performed to determine the extent of the degradation.

The staff confirmed that the "detection of aging effects" program element satisfies the criterion

defined in the GALL Report and SRP-LR Section A. 1.2.3.4. The staff finds this program

element acceptable.

Monitoring and Trending. In LRA Section B.2.49, the applicant stated that this program is a

condition monitoring program that is performed by qualified individuals at established intervals

through a combination of visual inspection and ultrasonic testing. The applicant further stated

that if during the inspection, significant or unusual or unexpected casing deterioration is

observed, it will be documented on a CR; and based on analysis, the CR may result in further

inspection or change in frequency.

The staff reviewed the applicant's "monitoring and trending" program element against the

criteria in SRP-LR Section A.1.2.3.5, which states that monitoring and trending activities should

be described, and they should provide predictability of the extent of degradation and thus effect

timely corrective or mitigative actions. Plant-specific and/or industry-wide operating experience

may be considered in evaluating the appropriateness of the technique and frequency.

During the review process, the staff determined that monitoring and trending is not described in

enough detail to allow an assessment of the predictability of the extent of degradation. As a

result, the staff issued RAI B.2.49-1, by letter dated July 23, 2008, requesting the applicant to

provide details describing the methods to assess remaining component life for loss of material

using inspection results such that timely mitigative action can be made.

In its letter dated August 22, 2008, in response to RAI B.2.49-1 the applicant stated that the

inspection is conducted to evaluate the condition of the internal surfaces of the turbine casing

and looks for indications of erosion, and should erosion be detected the condition would be

evaluated under the corrective action program, which would determine the margin to minimum

wall thickness, acceptability of current condition and future actions including further monitoring

and trending. The applicant also stated that the inspection and evaluation of the results are

performed in conjunction with the equipment vendor representative who is present during the

inspections. Furthermore, the results of the latest inspections conducted in 2003 and 2004,

after 20 years of service, found no signs of erosion and the casings were in excellent condition.

The staff reviewed the applicant's response and noted that enough information is provided to

conclude that the applicant would appropriately identify the degraded condition, and if found, it

would be evaluated along with the need for further monitoring and trending. On this basis, the

staff finds the response acceptable.

The staff confirmed that the "monitoring and trending" program element satisfies the criterion

defined in the GALL Report and SRP-LR Section A. 1.2.3.5. The staff finds this program

element acceptable.

Acceptance Criteria. In LRA Section B.2.49, the applicant stated that any indications or relevant

conditions of degradation will be evaluated. The inspection observations will be compared to

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predetermined acceptance criteria. Inspection results that do not meet the acceptance criteria

will be entered into the corrective action program for evaluation.

The staff reviewed the applicant's "acceptance criteria" program element against the criteria in

SRP-LR Section A.1.2.3.6, which states that the acceptance criteria of the program and its

basis should be described. The acceptance criteria, against which the need for corrective

actions will be evaluated, should ensure that the structure and component intended function(s)

are maintained under all CLB design conditions during the period of extended operation. The

program should include a methodology for analyzing the results against applicable acceptance

criteria.

The applicant did not provide specific acceptance criteria or its basis such as comparison to

design minimum wall or manufacturer suggested minimum wall in order to provide the basis for

evaluation. The staff issued RAI B.2.49-2 by letter dated July 23, 2008, requesting the applicant

to provide more details on how acceptance criteria will be established.

In its letter dated August 22, 2008, in response to RAI B.2.49-2, the applicant stated that the

inspection is conducted to evaluate the condition of the internal surfaces of the turbine casing

and looks for indications of erosion; and should erosion be detected the condition would be

evaluated under the corrective action program, which would determine the margin to minimum

wall thickness, acceptability of current condition and future actions including further monitoring

and trending. The applicant also stated that the inspection and evaluation of the results rely on

industry experience with the turbine equipment and are performed in conjunction with the

equipment vendor representative who is present during the inspections. Furthermore, the

results of the latest inspections conducted in 2003 and 2004, after 20 years of service, found no

signs of erosion and the casings were in excellent condition.

The staff reviewed the applicant's response and noted that enough information is provided to

conclude that the applicant would appropriately identify the degraded condition, and if found, it

would evaluate the need for further corrective action. Since the inspections are conducted in the

presence of the equipment vendor representative, an appropriate technical review will be

performed on the inspection results. On this basis, the staff finds the response acceptable.

The staff confirmed that the "acceptance criteria" program element satisfies the criterion

defined in the GALL Report and SRP-LR Section A.1.2.3.6. The staff finds this program

element acceptable.

Operating Experience. In LRA Section B.2.49, the applicant stated that a review of plant OE for

the most recent five-year period did not reveal any age-related degradation for the main turbine

casing. The applicant further stated that both high pressure turbines have been the object of

significant modifications and the work associated with these modifications revealed no

indication of pressure boundary wear on the high pressure turbine outer casing.

The staff reviewed the applicant's "operating experience" program element against the criteria

in SRP-LR Section A.1.2.3.10, which states that OE with existing programs should be

discussed. The OE of AMPs, including past corrective actions resulting in program

enhancements or additional programs, should be considered.

The staff reviewed the OE provided by the applicant to confirm that the plant-specific OE did

not reveal any degradation not bounded by industry experience.

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The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and SRP-LR Section A.1.2.3.10. The staff finds this program

element acceptable.

UFSAR Supplement. In its letter dated September 26, 2008, the applicant provided the UFSAR

supplement Section A.2.1.50, for the Preventive Maintenance Activities - Main Turbine Casing

Program. The applicant added Commitment No. 57 to enhance the program to add the

inspection techniques. The staff reviewed this section and determines that the information in

the UFSAR supplement provides an adequate summary description of the program, as required

by 10 CFR 54.21(d).

Conclusion. On the basis of its technical review of the applicant's Preventive Maintenance

Activities - Main Turbine Casing Program, including the applicant's responses to the RAIs and

the enhancement, the staff concludes that the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended function(s) will be maintained consistent

with the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff

also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate

summary description of the program, as required by 10 CFR 54.21(d).

3.0.4 Quality Assurance Program Attributes Integral to Aging Management Programs

3.0.4.1 Summary of Technical Information in the Application

In Sections A. 1.2, "Aging Management Program and Activities," and B.1.3, "Quality Assurance

Program and Administrative Controls," of the license'renewal application (LRA), the applicant

described the elements of corrective action, confirmation process, and administrative controls

that are applied to the AMPs for both safety-related (SR) and nonsafety-related components.

The SSES Operational Quality Assurance (OQA) Program is used which includes the elements

of corrective action, confirmation process, and administrative controls. Corrective actions,

confirmation, and administrative controls are applied in accordance with the OQA Program

regardless of the safety classification of the components. Specifically, in Section A.1.2 and

Section B.1.3, respectively, the applicant stated that the QA Program implements the

requirements of 10 CFR Part 50, Appendix B, and is consistent with NUREG-1800, "Standard

Review Plan for Review of license Renewal Applications for Nuclear Power Plants."

3.0.4.2 Staff Evaluation

Pursuant to.10 CFR 54.21(a)(3), an applicant is required to demonstrate that the effects of

aging on SCs subject to an AMR will be adequately managed so that their intended functions

will be maintained consistent with the CLB for the period of extended operation. NUREG-1 800,

Branch Technical Position RLSB-1, "Aging Management Review - Generic," describes

10 attributes of an acceptable AMP. Three of these ten attributes are associated with the QA

activities of corrective action, confirmation process, and administrative control. Table A.1-1,

"Elements of an Aging Management Program for license Renewal," of Branch Technical

Position RLSB-1 provides the following description of these quality attributes:

Corrective actions, including root cause determination and prevention of recurrence,

should be timely;

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The confirmation process should ensure that preventive actions are adequate and that

appropriate corrective actions have been completed and are effective; and,

Administrative controls should provide a formal review and approval process.

NUREG-1800, Branch Technical Position IQMB-1 noted that those aspects of the AMP that

affect quality of safety-related SSCs are subject to the QA requirements of Appendix B to

10 CFR Part 50. Additionally, for nonsafety-related SCs subject to an AMR, the applicant's

existing Appendix B to 10 CFR Part 50 QA program may be used to address the elements of

corrective action, confirmation process, and administrative control. Branch Technical Position

IQMB-1 provides the following guidance with regard to the QA attributes of AMPs:

Safety-related SCs are subject to Appendix B to 10 CFR Part 50 requirements

which are adequate to address all quality related aspects of an AMP consistent

with the CLB of the facility for the period of extended operation. For nonsafetyrelated SCs that are subject to an AMR for license renewal, an applicant has an

option to expand the scope of its Appendix B to 10 CFR Part 50 program to

include these SCs to address corrective action, confirmation process, and

administrative control for aging management during the period of extended

operation. In this case, the applicant should document such a commitment in the

Final Safety Analysis Report supplement in accordance with 10 CFR 54.21(d).

The NRC staff reviewed the applicant's AMPs described in Appendix A, "Final Safety Analysis

Report Supplement," and Appendix B, "Aging Management Programs," of the LRA, and the

associated implementing documents. The purpose of this review was to ensure that the quality

assurance attributes (corrective action, confirmation process, and administrative controls) were

consistent with the staff's guidance described in NUREG-1800, Section A.2, "Quality Assurance

for Aging Management Programs (Branch Technical Position IQMB-1 )." Based on the NRC

staff's evaluation, the descriptions of the AMPs and their associated quality attributes provided

in Appendix A, Section A. 1.2, and Appendix B, Section B. 1.3, of the LRA are consistent with the

staff's position regarding quality assurance for aging management.

3.0.4.3 Conclusion

On the basis of the NRC staff's evaluation, the staff concludes that the descriptions and

applicability of the plant-specific AMPs and their associated quality attributes provided in

Appendix A, Section A.1.2, and Appendix B, Section B.1.3 and Section B.2, of the LRA, are

consistent with the staff's position regarding QA for aging management. The staff concludes

that the QA attributes (corrective action, confirmation process, and administrative control) of the

applicant's AMPs are consistent with 10 CFR 54.21 (a)(3).

3.1 Aging Management of Reactor Vessel, Internals, and Reactor Coolant System

This section of the SER documents the staff's review of the applicant's AMR results for the RV,

RV internals, and reactor coolant system components and component groups of:

* Reactor Pressure Vessel

* Reactor Vessel Internals

* Reactor Coolant System Pressure Boundary

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3.1.1 Summary of Technical Information in the Application

LRA Section 3.1 provides AMR results for the RV, RV internals, and reactor coolant system

components and component groups. LRA Table 3.1.1, "Summary of Aging Management

Programs for Reactor Vessel, Reactor Vessel Internals, and Reactor Coolant System Evaluated

in Chapter IV of the GALL Report," is a summary comparison of the applicant's AMRs with

those evaluated in the GALL Report for the RV, RV internals, and reactor coolant system

components and component groups.

The applicant's AMRs evaluated and incorporated applicable plant-specific and industry OE in

the determination of AERMs. The plant-specific evaluation included condition reports and

discussions with appropriate site personnel to identify AERMs. The applicant's review of

industry OE included a review of the GALL Report and OE issues identified since the issuance

of the GALL Report.

3.1.2 Staff Evaluation

The staff reviewed LRA Section 3.1 to determine whether the applicant provided sufficient

information to demonstrate that the effects of aging for the RV, RV internals, and reactor

coolant system components within the scope of license renewal and subject to an AMR, will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

The staff conducted an onsite audit of AMRs to ensure the applicant's claim that certain AMRs

were consistent with the GALL Report. The staff did not repeat its review of the matters

described in the GALL Report; however, the staff did verify that the material presented in the

LRA was applicable and that the applicant identified the appropriate GALL Report AMRs. The

staff's evaluations of the AMPs are documented in SER Section 3.0.3. Details of the staff's

audit evaluation are documented in SER Section 3.1.2.1.

In the onsite audit, the staff also selected AMRs consistent with the GALL Report and for which

further evaluation is recommended. The staff confirmed that the applicant's further evaluations

were consistent with the SRP-LR Section 3.1.2.2 acceptance criteria. The staff's audit

evaluations are documented in SER Section 3.1.2.2.

The staff also conducted a technical review of the remaining AMRs not consistent with or not

addressed in the GALL Report. The technical review evaluated whether all plausible aging

effects have been identified and whether the aging effects listed were appropriate for the

material-environment combinations specified. The staff's evaluations are documented in SER

Section 3.1.2.3.

For SSCs which the applicant claimed were not applicable or required no aging management,

the staff reviewed the AMR line items and the plant's OE to verify the applicant's claims.

Table 3.1-1 summarizes the staff's evaluation of components, aging effects or mechanisms,

and AMPs listed in LRA Section 3.1 and addressed in the GALL Report.

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Table 3.1-1 Staff Evaluation for Reactor Vessel, Reactor Vessel Internals, and Reactor

Coolant System Components in the GALL Report

Component Group Aging Effect/ AMP'in GALL Further AMP in LRA, Staff Evaluation,-

(GALL Report'. Mechanism Report EvalUation Supplements,'

Item No.) in GALL dOr

_______________ •• r;"•• _Report : 4;4' k'al4'" " Amendments

Steel pressure Cumulative TLAA, evaluated in Yes TLAA Fatigue is a TLAA

vessel support skirt fatigue damage accordance with (See SER Section

and attachment 10 CFR 54.21 (c) 3.1.2.2.1)

welds

(3.1.1-1)

Steel; stainless steel; Cumulative TLAA, evaluated in Yes TLAA Fatigue is a TLAA

steel with nickel alloy fatigue damage accordance with (See SER Section

or stainless steel 10 CFR 54.21(c) and 3.1.2.2.1)

cladding; nickel alloy environmental

RV components: effects are to be

flanges; nozzles; addressed -for

penetrations; safe Class 1 components

ends; thermal

sleeves; vessel

shells, heads and

welds

(3.1.1-2) _ _ _ _ __-._.

Steel; stainless steel; Cumulative TLAA, evaluated in Yes TLAA Fatigue, is a TLAA

steel with nickel alloy fatigue damage accordance with (See-, SER Section

or stainless steel 10 CFR 54.21(c) and 3.1.2.2.1),

cladding; nickel alloy environmental

RCPB piping, piping effects are to be

components, and addressed for

piping elements Class 1 components

exposed to reactor

coolant

(3.1.1-3)

Steel pump and Cumulative TLAA, evaluated in Yes Not applicable Not applicable to

valve closure bolting fatigue damage accordance with SSES. (See SER

(3.1.1-4) 10 CFR 54.21(c) Section 3.1.2.2.1)

check Code limits for

allowable cycles

(less than

7000 cycles) of

thermal stress range

Stainless steel and Cumulative TLAA, evaluated in Yes TLAA Fatigue is a TLAA

nickel alloy RV fatigue damage accordance with (See SER Section

internals 10 CFR 54.21(c) 3.1.2.2.1)

components

(3.1.1-5)

Nickel Alloy tubes Cumulative TLAA, evaluated in Yes Not applicable Not applicable to

and sleeves in a fatigue damage accordance with BWRs (See SER

reactor coolant and 10 CFR 54.21 (c) Section 3.1.2.2.1)

secondary

FW/steam

environment

(3.1.1-6)

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Component Group, Aging Effect/ AMP in GALL Further 'AMP in LRA, Staff Evaluation

(GALL Report Mechanism Report Evaluation Supplements,

Itrem No.) - in GALL or

___ •__ __ . ___ Report, Amendments

Steel and stainless Cumulative TLAA, evaluated in Yes Not applicable Not applicable to

steel RCPB closure fatigue damage accordance with BWRs (See SER

bolting, head closure 10 CFR 54.21(c) Section 3.1.2.2.1)

studs, support skirts

and attachment

welds, pressurizer

relief tank

components, steam

generator

components, piping

and components

external surfaces

and bolting

(3.1.1-7)

Steel; stainless steel; Cumulative TLAA, evaluated in Yes Not applicable Not applicable to

and nickel alloy fatigue damage accordance with BWRs (See SER

RCPB piping, piping 10 CFR 54.21(c) and Section 3.1.2.2.1)

components, piping environmental

elements; flanges; effects are to be

nozzles and safe addressed for

ends; pressurizer Class 1 components

vessel shell heads

and welds; heater

sheaths and sleeves;

penetrations; and

thermal sleeves

(3.1.1-8)

Steel; stainless steel; Cumulative TLAA, evaluated in Yes Not applicable Not applicable to

steel with nickel alloy fatigue damage accordance with BWRs (See SER

or stainless steel 10 CFR 54.21(c) and Section 3.1.2.2.1)

cladding; nickel alloy environmental

RV components: effects are to be

flanges; nozzles; addressed for

penetrations; Class 1 components

pressure housings;

safe ends; thermal

sleeves; vessel

shells, heads and

welds

(3.1.1-9)'

Steel; stainless steel; Cumulative TLAA, evaluated in Yes Not applicable Not applicable to

steel with nickel alloy fatigue damage accordance with BWRs (See SER

or stainless steel 10 CFR 54.21(c) and Section 3.1.2.2.1)

cladding; nickel alloy environmental

steam generator effects are to be

components addressed for,

(flanges; Class 1 components

penetrations;

nozzles; safe ends,

lower heads and

welds)

(3.1.1-10) 1

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Component Groupý Aging Effect/l AMP, in GALL. Further, AMP in LRA, Staff Evaluation

(GALL Report Mechanism:, Report Evaluation Supplements,

Item.No.)- in GALL or

: •Report Amendments

Steel top head Loss of material Water Chemistry and Yes BWR Water Consistent with

enclosure (without due to general, One-Time Inspection Chemistry GALL Report

cladding) top head pitting and Program (B.2.2)

nozzles (vent, top crevice and Chemistry (See SER Section

head spray or RCIC, corrosion Program 3.1.2.2.2.1)

and spare) exposed Effectiveness

to reactor coolant Inspection

(3.1.1-11) (B.2.22), or

BWR Water

Chemistry

Program (B.2.2)

and ISI Program

(B.2.1)

Steel steam Loss of material Water Chemistry and Yes Not applicable Not applicable to

generator shell due to general, One-Time Inspection BWRs (See SER

assembly exposed to pitting and Section 3.1.2.2.2.1)

secondary FW and crevice

steam corrosion (3.1.1-12)

Steel and stainless Loss of material Water Chemistry and Yes Not applicable Not applicable to

steel isolation due to general One-Time Inspection BWRs (See SER

condenser (steel only), Section 3.1.2.2.2.2)

components pitting and

exposed toreactor crevice

coolant corrosion

(3.1.1-13)

Stainless steel, Loss of material Water Chemistry and Yes BWR Water Consistent with

nickel alloy, and due to pitting One-Time Inspection Chemistry GALL Report

steel with nickel alloy and crevice Program (B.2.2)

or stainless steel corrosion and Chemistry (See SER Section

cladding RV flanges, Program 3.1.2.2.2.3)

nozzles, Effectiveness

penetrations, safe Inspection

ends, vessel shells, (B.2.22), or

heads and welds BWR Water

(3.1.1-14) Chemistry

Program (B.2.2)

and ISI Program

(B.2.1), or

BWR Water

Chemistry

Program (B.2.2)

and BWR

Vessel Internals

Program (B.2.9)

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Component Group Aging Effect/ AMP in GALL Further AMP in LRA, Staff Evaluation

(GALL Report Mechanism- Report Evaluation Supplements,

Item No.) in GALL or

SReport Amendments

Stainless steel; steel Loss of material Water Chemistry and Yes BWR Water Consistent with

with nickel alloy or due to pitting One-Time Inspection Chemistry GALL Report

stainless steel and crevice Program (B.2.2)

cladding; and nickel corrosion and Chemistry (See SER Section

alloy RCPB Program 3.1.2.2.2.3)

components Effectiveness

exposed to reactor Inspection

coolant (B.2.22), or

(3.1.1-15)BWWae

BWR Water

Chemistry

Program (B.2.2)

and ISI Program

(B.2.1)

Steel steam Loss of material Inservice Yes Not applicable Not applicable~to

generator upper and due to general, Inspection (IWB, BWRs (See SER

lower shell and pitting and IWC, and IWD), and Section 3.1.2.2.2.4)

transition cone crevice Water Chemistry

exposed to corrosion and, for

secondary FW and Westinghouse

steam Model 44 and

(3.1.1-16) 51 S/G, if general

and pitting corrosion

of the shell is known

to exist, additional

inspection

procedures are to be

developed.

Steel, (with or without Loss of fracture TLAA, evaluated in Yes TLAA Loss of fracture

stainless steel toughness due accordance with toughness is a TLAA

cladding) RV beltline to neutron 10 CFR Part 50, (See SER Section

shell, nozzles, and irradiation Appendix G, and 3.1.2.2.3.1)

welds embrittlement RG 1.99. The

(3.1.1-1 7) applicant may

choose to

demonstrate that the

materials of the

nozzles are not

controlling for the

TLAA evaluations.

Steel (with or without Loss of fracture Reactor Vessel Yes Reactor Vessel Consistent with

stainless steel toughness due Surveillance Surveillance GALL Report (See

cladding) RV beltline to neutron Program SER Section

shell, nozzles, and irradiation (B.2.21) 3.1.2.2.3.2)

welds; safety embrittlement

injection nozzles

(3.1.1-18)

Stainless steel and

nickel alloy top head

enclosure vessel

flange leak detection

line

(3.1.1-19)

Cracking due to

SCC and IGSCC

A plant-specific

aging management

program is to be

evaluated.

Yes BWR Water

Chemistry

Program (B.2.2)

and Small Bore

Class 1 Piping

Inspection

(B.2.31)

Consistent with

GALL Report

(See SER Section

3.1.2.2.4.1)

3-203
Component Group Aging Effect!. AMP in GALL Further AMP in LRA, Staff Evaluation

(GALL Report Mechanism Report, Evaluation Supplements,

I'.temn No.) iAnGALL or: - RepOort Aendmeints,ý

Stainless steel Cracking due to Inservice Yes Not applicable See SER Section

isolation condenser SCC and IGSCC Inspection (IWB, 3.1.2.2.4.2

components IWC, and IWD),

exposed to reactor Water Chemistry,

coolant and plant-specific

(3.1.1-20) verification program

Reactor vessel shell Crack growth TLAA Yes Not applicable Not applicable to

fabricated of SA508- due to cyclic BWRs (See SER

Cl 2 forgings clad loading Section 3.1.2.2.5)

with stainless steel

using a high-heatinput welding

process

(3.1.1-21)

Stainless steel and Loss of fracture UFSAR supplement No Not applicable Not applicable to

nickel alloy RV toughness due commitment to BWRs (See SER

internals to neutron (1) participate in Section 3.1.2.2.6)

components irradiation industry RVI aging

exposed to reactor embrittlement, programs

coolant and neutron void swelling (2) implement

flux applicable results (3)

(3.1.1-22) submit for NRC

approval > 24

months before the

extended period an

RVI inspection plan

based on industry

recommendation.

Stainless steel RV Cracking due to A plant-specific Yes Not applicable Not applicable to

closure head flange SCC aging management BWRs (See SER

leak detection line program is to be Section 3.1.2.2.7.1)

and bottom-mounted evaluated.

instrument guide

tubes

(3.1.1-23)

Class 1 CASS Cracking due to Water Chemistry Yes Not applicable Not applicable to

piping, piping SCC and, for CASS BWRs (See SER

components, and components that do Section 3.1.2.2.7.2)

piping elements not meet the

exposed to reactor NUREG-0313

coolant guidelines, a plant-

(3.1.1-24) specific AMP

Stainless steel jet Cracking due to A plant-specific Yes BWR Water Consistent with

pump sensing line cyclic loading aging management Chemistry GALL Report

(3.1.1-25) program is to be Program (B.2.2)

evaluated. and Small Bore (See SER Section

Class 1 Piping 3.1.2.2.8.1)

Inspection

I_ _(B.2.31)

3-204
Component Group Aging Effect/ AMP in GALL Further AMP in LRA, Staff Evaluation

(GALL Report. Mechanism Report Evaluation Supplements,

Item No.) in GALL or

_ _ _ _ Report Amendments

Steel and stainless Cracking due to Inservice Yes Not applicable See SER Section

steel isolation cyclic loading Inspection (IWB, 3.1.2.2.8.2

condenser IWC, and IWD) and

components plant-specific

exposed to reactor verification program

coolant

(3.1.1-26)

Stainless steel and Loss of preload UFSAR supplement No Not applicable Not applicable to

nickel alloy RV due to stress commitment to BWRs (See SER

internals screws, relaxation (1) participate in Section 3.1.2.2.9)

bolts, tie rods, and industry RVI aging

hold-down springs programs

(3.1.1-27) (2) implement

applicable results (3)

submit for NRC

approval > 24

months before the

extended period an

RVI inspection plan

based on industry

recommendation.

Steel steam Loss of material A plant-specific Yes Not applicable Not applicable to

generator FW due to erosion aging management BWRs (See SER

impingement plate program is to be Section 3.1.2.2.10)

and support exposed evaluated.

to secondary FW

(3.1.1-28)

Stainless steel Cracking due to A plant-specific Yes BWR Vessels Consistent with

steam dryers flow-induced aging management Internals GALL Report

exposed to reactor vibration program is to be (B.2.9), (See SER Section

coolant evaluated. 3:1.2.2.11)

(3.1.1-29) 1 _

3-205
Compnt Group Aging Effect .AMP in GALL Further AMP in LRA, Staff Evaluation

(GLLRport Mecha.nismn Report, Ev'aluation Supplemrents;

ItemnNo.) r ALo

omnntGru .AginEffAmendments:

Stainless steel RV Cracking due to Water Chemistry and No Not applicable Not applicable to

intemals SCC, IASCO UFSAR supplement BWRs (See SER

components commitment to Section 3.1.2.2.12)

(e.g., Upper internals (1) participate in

assembly, RCCA industry RVI aging

guide tube programs

assemblies, (2) implement

Baffle/former applicable results

assembly, Lower (3) submit for NRC

internal assembly, approval > 24

shroud assemblies, months before the

Plenum cover and extended period an

plenum cylinder, RVI inspection plan

Upper grid assembly, based on industry

Control rod guide recommendation.

tube (CRGT)

assembly, Core

support shield

assembly, Core

barrel assembly,

Lower grid assembly,

Flow distributor

assembly, Thermal

shield,

Instrumentation

support structures)

(3.1.1-30)

Nickel alloy and steel Cracking due to Inservice No Not applicable Not.applicable to

with nickel alloy primary water Inspection (IWB, BWRs (See SER

cladding piping, SCC IWC, and IWD) and Section 3.1.2.2.13)

piping component, Water Chemistry and

piping, elements, UFSAR supplement

penetrations, commitment to

nozzles, safe ends, implement applicable

and welds (other plant commitments

than RV head)"; to (1) NRC Orders,

pressurizer heater Bulletins, and

sheaths, sleeves, Generic Letters

diaphragm plate, associated with

manways and nickel alloys and

flanges; core support (2) staff-accepted

pads/core guide lugs industry guidelines.

(3.1.1-31)

Steel steam Wall thinning A plant-specific Yes Not applicable Not applicable to

generator FW inlet due to FAC aging management BWRs (See SER

ring and supports program is to be Section 3.1.2.2.14)

(3.1.1-32) evaluated.

3-206
Component Group Aging Effect/ AMP inGALL Further AMP in LRA, Staff Evaluation

(GALL Report. Mechanism .Report," Evaluation Supplements,

ItemNo.) . . in GALL or,

-• Report Amendments. "

Stainless steel and Changes in UFSAR supplement No Not applicable Not applicable to

nickel alloy RV dimensions due commitment to BWRs (See SER

internals to void swelling (1) participate in Section 3.1.2.2.15)

components industry RVI aging

(3.1.1-33) programs

(2) implement

applicable results

(3) submit for NRC

approval > 24

months before the

extended period an

RVI inspection plan

based on industry

recommendation.

Stainless steel and Cracking due to Inservice No Not applicable Not applicable to

nickel alloy reactor SCC and Inspection (!WB, BWRs (See SER

CRD head primary water IWC, and IWD) and Section 3.1.2.2.16.1)

penetration pressure SCC Water Chemistry and

housings for nickel alloy,

(3.1.1-34) comply with

applicable NRC

Orders and provide a

commitment in the

UFSAR supplement

to implement

applicable

(1) Bulletins and

Generic Letters and

(2) staff-accepted

industry guidelines.

Steel with stainless Cracking due to Inservice No Not applicable Not applicable to

steel or nickel alloy SCC and Inspection.(IWB, BWRs (See SER

cladding primary side primary water IWC, and IWD) and Section 3.1.2.2.16.1)

components; steam SCC Water Chemistryand

generator upper and for nickel alloy,

lower heads, comply with

tubesheets and tube- applicable NRC

to-tube sheet welds Orders and provide a

(3.1.11-35) commitment in the

UFSAR supplement

to implement

applicable

(1) Bulletins and

*Generic Letters and

(2) staff-accepted Sindustry guidelines.

3-207
Compmonet Group Aging Effect' MPinGALL* h• " Further:. AMPin; LRA,:., Staff Evaluation

(GALL•k•port M•e•'chfanism Rep'•trt• Evaluati6nm Supplements-,

Item No.)~ In GALL' o

'4.~ ~ eort ~AmendmentsNickel alloy, Cracking due to Water Chemistry and No Not applicable Not applicable to

stainless steel SCC and One-Time Inspection BWRs (See SER

pressurizer spray primary water and, for nickel alloy Section 3.1.2.2.16.2)

head SCC welded spray heads,

(3.1.1-36) comply with

applicable NRC

Orders and provide a

commitment in the

UFSAR supplement

to implement

applicable

(1) Bulletins and

Generic Letters and

(2) staff-accepted

industry guidelines.

Stainless steel and Cracking due to Water Chemistry and No Not applicable Not applicable to

nickel alloy RV SCC, primary UFSAR supplement BWRs (See SER

internals water SCC, commitment to Section 3.1.2.2.17)

components IASCC (1) participate in

(e.g., Upper internals industry RVI aging

assembly, RCCA programs

guide tube (2) implement

assemblies, Lower applicable results

internal assembly, (3) submit for NRC

CEA shroud approval > 24

assemblies, Core months before the

shroud assembly, extended period an

Core support shield RVI inspection plan

assembly, Core based on industry

barrel assembly, recommendation.

Lower grid assembly,

Flow distributor

assembly)

(3.1.1-37)

Steel (with or without Cracking due to BWR Control Rod No BWR CRD Consistent with

stainless steel cyclic loading Drive Return Line Return Line GALL Report

cladding) CRD return Nozzle Nozzle

line nozzles exposed (B.2.6)

to reactor coolant

(3.1.1-38)

Steel (with or without Cracking due to BWR Feedwater No BWR Feedwater Consistent with

stainless steel cyclic loading Nozzle Nozzle GALL Report

cladding) FW (B.2.5)

nozzles exposed to

reactor coolant

(3.1.1-39)

3-208
Component Giroup Aging Effect/ AMP in GALL Further AMP in LRA, Staff Evaluation

(GALL Reportr Mechanism Report Evaluation Supplements,

Item No.) in GALL or

_________... ___ Report Amendments

Stainless steel and Cracking due to BWR Penetrations No BWR Consistent with

nickel alloy SCC, IGSCC, and Water Chemistry Penetrations GALL Report

penetrations for CRD cyclic loading (B.2.8),

stub tubes BWR Water

instrumentation, jet Chemistry

pump (B.2.2)

instrumentation,

SLC, flux monitor,

and drain line

exposed to reactor

coolant

(3.1.1-40)

Stainless steel and Cracking due to BWR Stress No BWR Stress Consistent with

nickel alloy piping, SCC and IGSCC Corrosion Cracking Corrosion GALL Report

piping components, and Water Chemistry Cracking

and piping elements (B.2.7),

greater than or equal BWR Water

to 4 NPS; nozzle Chemistry

safe ends and (8.2.2)

associated welds

(3.1.1-41)

Stainless steel and Cracking due to BWR Vessel ID No BWR Vessel ID Consistent with

nickel alloy vessel SCC and IGSCC Attachment Welds Attachment GALL Report

shell attachment and Water Chemistry Welds

welds exposed to (B.2.9),

reactor coolant BWR Water

(3.1.1-42) Chemistry

(B.2.2)

Stainless steel fuel Cracking due to BWR Vessel No BWR Vessel Consistent with

supports and CRD SCC and IGSCC Internals and Water Internals GALL Report

assemblies CRD Chemistry (B.2.9),

housing exposed to BWR Water

reactor coolant Chemistry

(3.1.1-43) (B.2.2),

Inservice

Inspection

(B.2.1)

Stainless steel and Cracking due to BWR Vessel No BWR Vessel Consistent with

nickel alloy core SCC, IGSCC, Internals and Water Internals GALL Report

shroud, core plate, IASCC Chemistry (B.2.9),

core plate bolts, BWR Water

support structure, top Chemistry

guide, core spray (B.2.2)

lines, spargers, jet

pump assemblies,

CRD housing,

nuclear

instrumentation

guide tubes

(3.1.1-44)

3-209
Component Group Aging Effect/. -•AMPOin GALL Further AMP in LRA, Staff Evaluation

,(GALL Report . Mechanismi Report Evaluation Supplements,,

Ite•mNo) inGALL. or

Report .-Amendments.

Steel piping, piping Wall thinning Flow-Accelerated No Flow- Consistent with

components, and due to FAC Corrosion Accelerated GALL Report

piping elements Corrosion

exposed to reactor Program

coolant (B.2.1 1)

(3.1.1-45)

Nickel alloy core Cracking due to Inservice No Not applicable Not applicable to

shroud and core SCC, IGSCC, Inspection (IWB, SSES (See SER

plate access hole IASCC IWC, and IWO), and Section 3.1.2.1.1)

cover (mechanical Water Chemistry

covers)

(3.1.1-46)

Stainless steel and Loss of material Inservice No Not Applicable Addressed under

nickel alloy RV due to pitting Inspection (IWB, item 3.1.1-14 (See

internals exposed to and crevice IWC, and IWO), and SER Section

reactor coolant corrosion Water Chemistry 3.1.2.1.1)

(3.1.1-47)

Steel and stainless Cracking due to Inservice No Inservice Consistent with

steel Class 1 piping, SCC, IGSCC Inspection (IWB, Inspection (ISI) GALL Report

fittings and branch (for stainless IWC, and IWO), Program (B.2.1),

connections < NPS 4 steel only), and Water chemistry, BWR Water (See SER Section

exposed to reactor thermal and and One-Time Chemistry 3.1.2.1.2.)

coolant mechanical Inspection of ASME Program (B.2.2),

(3.1.1-48) loading Code Class 1 Small- and Small Bore

bore Piping Class 1 Piping

Inspection

(B.2.31), or

Inservice

Inspection (ISI)

Program (B.2.1)

and Small Bore

Class 1 Piping

Inspection

(B.2.31)

Nickel alloy core Cracking due to Inservice No Inservice Consistent with

shroud and core SCC, IGSCC, Inspection (IWB, Inspection GALL Report

plate access hole IASCC IWC, and IWO), (B.2.1),

cover (welded Water Chemistry, BWR Water Access hole covers

covers) and, for BWRs with a Chemistry do not have a

(3.1.1-49) crevice in the access (B.2.2) crevice

hole covers,

augmented

inspection using UT

or other

demonstrated

acceptable

inspection of the

access hole cover

welds

3-210
Component Group Aging Effect/ AMP in GALL Further AMP in LRA, Staff Evaluation

(GALL Report. Mechanism Report Evaluation Supplements,

Item No.)" inGALL or

Reportr Amendments

High-strength low Cracking due to Reactor Head No Reactor Head Consistent with

alloy steel top head SCC and IGSCC Closure Studs Closure Studs GALL Report

closure studs and Program (B.2.3)

nuts exposed to air

with reactor coolant

leakage

(3.1.1-50)

Cast austenitic Loss of fracture Thermal Aging and No Thermal Aging Consistent with

stainless steel jet toughness due Neutron Irradiation and Neutron GALL Report

pump assembly to thermal aging Embrittlement of Irradiation

castings; orificed fuel and neutron CASS Embrittlement of

support irradiation CASS

(3.1.1-51) embrittlement (B.2.10)

Steel and stainless Cracking due to Bolting Integrity No Bolting Integrity Consistent with

steel RCPB (RCPB) SCC, loss of Program GALL Report

pump and valve material due to (B.2.12)

closure bolting, wear, loss of

manway and holding preload due to

bolting, flange thermal effects,

bolting, and closure gasket creep,

bolting in high- and selfpressure and high- loosening

temperature systems

(3.1.1-52)

Steel piping, piping Loss of material Closed-Cycle No Not applicable Not applicable to

components, and due to general, Cooling Water SSES (See SER

piping elements pitting and System Section 3.1.2.1.1)

exposed to closed crevice

cycle cooling water corrosion

(3.1.1-53)

Copper alloy piping, Loss of material Closed-Cycle No Not applicable Not applicable to

piping components, due to pitting, Cooling Water SSES (See SER

and piping elements crevice, and System Section 3.1.2.1.1)

exposed• to closed galvanic

cycle cooling water corrosion

(3.1.1-54)

Cast austenitic Loss of fracture- Inservice No Inservice Consistent with

stainless steel toughness due Inspection (IWB, Inspection (ISI) GALL Report

Class 1 pump to thermal aging IWC, and IWD). Program (B.2.1)

casings, and valve embrittlement Thermal aging (See SER Section

bodies and bonnets susceptibility Small Bore 3.1.2.1.3.)

exposed to reactor screening is not Class 1 Piping

coolant > 250'C necessary, ISI Inspection

(> 482F) requirements are (B.2.31)

(3.1.1-55) sufficient for

managing these

aging effects. ASME

Code Case N-481

also provides an

alternative for pump

casings.

3-211
Component;Group Aging EffeCtl i AMP inGALL Further AMP in LRA, Staff Evaluation

(G-ALL Report Mechanisma , Report Evaluation Supplements, Item No) . in GALL or

Report Amendments

Copper alloy Loss of material Selective Leaching No Not applicable Not applicable to

> 15% Zn piping, due to selective of Materials SSES (See SER

piping. components, leaching Section 3.1.2.1.1)

and piping elements

exposed to closed

cycle cooling water

(3.1.1-56)

Cast austenitic Loss of fracture Thermal Aging No Not Applicable Not Applicable (See

stainless steel toughness due Embrittlement of SER Section

Class 1 piping, to thermal aging CASS 3.1.2.1.1)

piping component, embrittlement

and piping elements

and CRD pressure

housings exposed to

reactor coolant

> 2500C (> 482`F)

(3.1.1-57)

Steel RCPB external Loss of material Boric Acid Corrosion No Not applicable Not applicable to

surfaces exposed to due to boric acid BWRs

air with borated corrosion

water leakage

(3.1.1-58)

Steel steam Wall thinning Flow-Accelerated No Not applicable Not applicable to

generator steam due to FAC Corrosion BWRs

nozzle and safe end,

FW nozzle and safe

end, AFW nozzles

and safe ends

exposed to

secondary

FW/steam

(3.1.1-59)

Stainless steel flux Loss of material Flux Thimble Tube No Not applicable Not applicable to

thimble tubes (with due to wear Inspection BWRs

or without chrome

plating)

(3.1.1-60)

Stainless steel, steel Cracking due.to Inservice No Not applicable Not applicable to

pressurizer integral cyclic loading Inspection (IWB, BWRs

support exposed to IWC, and IWD)

air with metal

temperature up to

280C (550=) .

(3.1.1-61)

3-212
ComponentGroup Aging Effect! AMP-in GALL Further AMP in LRA, Staff Eiialuation

(GALL Report Mechanism , Report: Evaluation Supplements,

Item No.): in GALL or

_...__..___ Report Amendments

Stainless steel, steel Cracking due to Inservice No Not applicable Not applicable to

with stainless steel cyclic loading Inspection (IWB, BWRs

cladding reactor IWC, and IWD)

coolant system cold

leg, hot leg, surge

line, and spray line

piping and fittings

exposed to reactor

coolant

(3.1.1-62)

Steel RV flange, Loss of material Inservice No Not applicable Not applicable to

stainless steel and due to wear Inspection(IWB, BWRs

nickel alloy RV IWC, and IWD)

internals exposed to

reactor coolant

(e.g., upper and

lower internals

assembly, CEA

shroud assembly,

core support barrel,

upper grid assembly,

core support shield

assembly, lower grid

assembly)

(3.1.1-63)

Stainless steel and Cracking due to Inservice No Not applicable Not applicable to

steel with stainless SCC, primary Inspection (IWB, BWRs

steel or nickel alloy, water SCC IWC, and IWD) and

cladding pressurizer Water Chemistry

components

(3.1.1-64)

Nickel alloy RV Cracking due to Inservice No Not applicable Not applicable to

upper head and CRD primary water Inspection (IWB, BWRs

penetration nozzles, SCC IWC, and IWD) and

instrument tubes, Water Chemistry and

head vent pipe (top nickel alloy

head), and welds Penetration Nozzles

(3.1.1-65) Welded to the Upper Reactor Vessel

Closure Heads of

PWRs

Steel steam Loss of material Inservice No Not applicable Not applicable to

generator secondary due to erosion Inspection (IWB, BWRs

manways and IWC, and IWD) for

handholds Class 2 components

(cover only) exposed

to air with leaking

secondary-side

water and/or steam

(3 .1.1-66 ) __ _ _ _ _ __II_ I_

3-213
Component Group Aging Effect/ AMP in GALL Further AMP in LRA, Staff Evaluation

(GALL Report Mechanism Report Evaluation Supplements,

Item No.) in GALL or

Report Amendments

Steel with stainless Cracking due to Inservice No Not applicable Not applicable to

steel or nickel alloy cyclic loading Inspection (IWB, BWRs

cladding; or stainless IWC, and IWD), and

steel pressurizer Water Chemistry

components

exposed to reactor

coolant

(3.1.1-67)

Stainless steel, steel Cracking due to Inservice No Not applicable Not applicable to

with stainless steel SCC Inspection (IWB, BWRs

cladding Class 1 IWC, and IWD), and

piping, fittings, pump Water Chemistry

casings, valve

bodies, nozzles, safe

ends, manways,

flanges, CRD

housing; pressurizer

heater sheaths,

sleeves, diaphragm

plate; pressurizer

relief tank

components, reactor

coolant system cold

leg, hot leg, surge

line, and spray line

piping and fittings

(3.1.1-68)

Stainless steel, Cracking due to Inservice No Not applicable Not applicable to

nickel alloy safety SCC, primary Inspection (IWB, BWRs

injection nozzles, water SCC IWC, and IWD), and

safe ends, and Water Chemistry

associated welds

and buttering

exposed to reactor

coolant

(3.1.1-69)

Stainless steel; steel Cracking due to Inservice No Not applicable Not applicable to

with stainless steel SCC, thermal Inspection (IWB, BWRs

cladding Class 1 and mechanical IWC, and IWD),

piping, fittings and loading Water chemistry,

branch connections and One-Time

< NPS 4 exposed to Inspection of ASME

reactor coolant Code Class 1 Small-

(3.1.1-70) bore Piping

High-strength low Cracking due to Reactor Head No Not applicable Not applicable to

alloy steel closure SCC; loss of Closure Studs BWRs

head stud assembly material due to

exposed to air with wear

reactor coolant

leakage

(3.1.1-71)

3-214
Component Group Aging Effect/ AMP in GALL' Further AMP in LRA, Staff Evaluation

(GALL Report. Mechanism Report. Evaluation Supplements,

Item No.), in GALL or ____________. _ . _____ ____ - Report Amendments

Nickel alloy steam Cracking due to Steam Generator No Not applicable Not applicable to

generator tubes and OD SCC and Tube Integrity and BWRs

sleeves exposed to intergranular Water Chemistry

secondary attack, loss of

FW/steam material due to

(3.1.1-72) fretting and wear_

Nickel alloy steam Cracking due to Steam Generator No Not applicable Not applicable to

generator tubes, primary water Tube Integrity and BWRs

repair sleeves, and SCC. Water Chemistry

tube plugs exposed

to reactor coolant

(3.1.1-73)

Chrome plated steel, Cracking due to Steam Generator No Not applicable Not applicable to

stainless steel, nickel SCC, loss of Tube Integrity and BWRs

alloy steam material due to Water Chemistry

generator anti- crevice

vibration bars corrosion and

exposed to fretting

secondary

FW/steam

(3.1.1-74)

Nickel alloy once- Denting due to Steam Generator No Not applicable Not applicable to

through steam corrosion of Tube Integrity and BWRs

generator tubes carbon steel Water Chemistry

exposed to tube support

secondary plate

FW/steam

(3.1.1-75)

Steel steam Loss of material Steam Generator No Not applicable Not applicable to

generator tube due to erosion, Tube Integrity and BWRs

support plate, tube general, pitting, Water Chemistry

bundle wrapper and crevice

exposed to corrosion,

secondary ligament

FW/steam cracking due to

(3.1.1-76) corrosion

Nickel alloy steam Loss of material Steam Generator No Not applicable Not applicable to

generator tubes and due to wastage Tube Integrity and BWRs

sleeves exposed to and pitting Water Chemistry

phosphate chemistry corrosion

in secondary

FW/steam

(3.1.1-77)

Steel steam Wall thinning Steam Generator No Not applicable Not applicable to

generator tube due to FAC Tube Integrity and BWRs

support lattice bars Water Chemistry

exposed to

secondary

FW/steam

(3.1.1-78)

3-215
Component Group. Aging Effect/ AMP in GALL Further. AMP in LRA, Staff Evaluation

(GALL Report Mechanism, Report Evaluation. Supplements,.

Item, No.) in GALL! or"

______________ .. . .____ _ Report, Amendments

Nickel alloy steam Denting due to Steam Generator No Not applicable Not applicable to

generator tubes corrosion of Tube Integrity; Water BWRs

exposed to steel tube Chemistry and, for

secondary support plate plants that could

FW/steam experience denting (3.1.1-79) at the upper support

plates, evaluate

potential for rapidly

propagating cracks

and then develop

and take corrective

actions consistent

with NRC

Bulletin 88-02.

Cast austenitic Loss of fracture Thermal Aging and No Not applicable Not applicable to

stainless steel RV toughness due Neutron Irradiation BWRs

internals (e.g., upper to thermal aging Embrittlement of

internals assembly, and neutron CASS

lower internal irradiation

assembly, CEA embrittlement

shroud assemblies,

control rod guide

tube assembly, core

support shield

assembly, lower grid

assembly)

(3.1.1-80)

Nickel alloy or nickel Cracking due to Water Chemistry No Not applicable Not applicable to

alloy clad steam primary water BWRs

generator divider SCC

plate exposed to

reactor coolant (3.1.1-81) ________

Stainless steel Cracking due to Water Chemistry No Not applicable Not applicable to

steam generator SCC BWRs

primary side divider

plate exposed to

reactor coolant

(3.1.1-82)

'Stainless steel; steel Loss of material Water Chemistry No Not applicable Not applicable to

with nickel alloy or due to pitting BWRs

stainless steel and crevice

cladding; and nickel corrosion

alloy RV internals

and RCPB

components

exposed to reactor

coolant (3.1.1-83)__ _ _ _ _ __ _ _ _ _ _ _ _ _ _ _

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ComponentGiroup, Aging.Effect! AMPin GALL Further AMPinh LRA, StaffEvaluation,.

(GALLReport". Mechanism Report` Evaluation supplements,

Item No.) , in GALL or,

Rpo~rt, -Amendments'

Nickel alloy steam Cracking due to Water Chemistry and No Not applicable Not applicable to

generator SCC One-Time Inspection BWRs

components such or Inservice

as, secondary side Inspection (IWB,

nozzles IWC, and IWD).

(vent, drain, and

instrumentation)

exposed to

secondary

FW/steam

(3.1.1-84)

Nickel alloy piping, None None No None Consistent with

piping components, GALL Report

and piping elements

exposed to air -

indoor uncontrolled

(external)

(3.1.1-85)

Stainless steel None None No None Consistent with

piping, piping GALL Report

components, and

piping elements

exposed to air -

indoor uncontrolled

(External); air with

borated water

leakage; concrete;

gas

(3.1.1-86) _ "_

Steel piping, piping None None No Not applicable Not applicable to

components, and SSES (See SER

piping elements in Section 3.1.2.1.1)

concrete

(3.1.1-87)

The staff's review of the RV, RV internals, and reactor coolant system component groups

followed any one of several approaches. One approach, documented in SER Section 3.1.2.1,

reviewed AMR results for components that the applicant indicated are consistent with the GALL

Report and require no further evaluation. Another approach, documented in SER

Section 3.1.2.2, reviewed AMR results for components that the applicant indicated are

consistent with the GALL Report and for which further evaluation is recommended. A third

approach, documented in SER Section 3.1.2.3, reviewed AMR results for components that the

applicant indicated are not consistent with, or not addressed in, the GALL Report. The staff's

review of AMPs credited to manage or monitor aging effects of the RV, RV internals, and

reactor coolant system components is documented in SER Section 3.0.3.

3.1.2.1 AMR Results Consistent with the GALL Report

LRA Section 3.1.2.1 identifies the materials, environments, AERMs, and the following programs

that manage aging effects for the RV, RV internals, and reactor coolant system components:

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• Inservice Inspection (ISI) Program

" BWR Water Chemistry Program

* Reactor Head Closure Studs Program

* BWR Vessel ID Attachment Welds Program

* BWR Feedwater Nozzle Program

* BWR CRD Return Line Nozzle Program

" BWR Stress Corrosion Cracking (SCC) Program

* BWR Penetrations Program

* BWR Vessel Internals Program

* Thermal Aging and Neutron Embrittlement of Cast Austenitic Stainless Steel (CASS)

Program

* Flow-Accelerated Corrosion (FAC) Program

* Bolting Integrity Program

* Closed Cooling Water Chemistry Program

• Reactor Vessel Surveillance Program

" Small Bore Class 1 Piping Inspection

* System Walkdown Program

* Inservice Inspection (ISI) Program - IWF

LRA Tables 3.1.2-1 through 3.1.2-3 summarize AMRs for the RV, RV internals, and reactor

coolant system components and indicate AMRs claimed to be consistent with the GALL Report.

For component groups evaluated in the GALL Report for which the applicant claimed

consistency with the report and for which it does not recommend further evaluation, the staff's

audit and review determined whether the plant-specific components of these GALL Report

component groups were bounded by the GALL Report evaluation.

The applicant noted for each AMR line item how the information in the tables aligns with the

information in the GALL Report. The staff audited those AMRs with notes A through E

indicating how the AMR is consistent with the GALL Report.

Note A indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP is consistent with the GALL

Report AMP. The staff audited these line items to verify consistency with the GALL Report and

validity of the AMR for the site-specific conditions.

Note B indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP takes some exceptions to the

GALL Report AMP. The staff audited these line items to verify consistency with the GALL

Report and verified that the identified exceptions to the GALL Report AMPs have been

reviewed and accepted. The staff also determined whether the applicant's AMP was consistent

with the GALL Report AMP and whether the AMR was valid for the site-specific conditions.

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Note C indicates that the component for the AMR line item, although different from, is

consistent with the GALL Report for material, environment, and aging effect. In addition, the

AMP is consistent with the GALL Report AMP. This note indicates that the applicant was unable

to find a listing of some system components in the GALL Report; however, the applicant

identified in the GALL Report a different component with the same material, environment, aging

effect, and AMP as the component under review. The staff audited these line items to verify

consistency with the GALL Report. The staff also determined whether the AMR line item of the

different component was applicable to the component under review and whether the AMR was

valid for the site-specific conditions.

Note D indicates that the component for the AMR line item, although different from, is

consistent with the GALL Report for material, environment, and aging effect. In addition, the

AMP takes some exceptions to the GALL Report AMP. The staff audited these line items to

verify consistency with the GALL Report. The staff verified whether the AMR line item of the

different component was applicable to the component under review and whether the identified

exceptions to the GALL Report AMPs have been reviewed and accepted. The staff also

determined whether the applicant's AMP was consistent with the GALL Report AMP and

whether the AMR was valid for the site-specific conditions.

Note E indicates that the AMR line item is consistent with the GALL Report for material,

environment, and aging effect, but credits a different AMP. The staff audited these line items to

verify consistency with the GALL Report. The staff also determined whether the credited

AMP would manage the aging effect consistently with the GALL Report AMP and whether the

AMR was valid for the site-specific conditions.

The staff audited and reviewed the information in the LRA. The staff did not repeat its review of

the matters described in the GALL Report; however, the staff did verify that the material

presented in the LRA was applicable and that the applicant identified the appropriate GALL

Report AMRs.

The staff reviewed the LRA to confirm that the applicant: (a) provided a brief description of the

system, components, materials, and environments; (b) stated that the applicable aging effects

were reviewed and evaluated in the GALL Report; and (c) identified those aging effects for the

reactor vessel, reactor vessel internals, and RCS components that are subject to an AMR. On

the basis of its audit and review, the staff determines that, for AMRs not requiring further

evaluation, as identified in LRA Table 3.1.1, the applicant's references to the GALL Report are

acceptable and no further staff review is required, with the exception of the following AMRs that

the applicant had identified were consistent with the AMRs of the GALL Report and for which

the staff felt were in need of additional clarification and assessment. The staff's evaluations of

these AMRs are provided in the subsection that follows.

3.1.2.1.1 AMR Results Identified as Not Applicable

In LRA Table 3.1.1, items 46, the applicant states that the corresponding AMR result line in the

GALL Report is not applicable because access hole covers are a welded design. The staff

noted that the nickel alloy core shroud and core plate access hole cover is a mechanical design

for item 46. The staff reviewed the documentation supporting the applicant's AMR evaluation

and confirmed the applicant's claim that SSES does not have a mechanical access hole cover.

Therefore, the staff agrees with the applicant's determination that the corresponding AMR result

line in the GALL Report is not applicable to SSES.

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In LRA Table 3.1.1, item 47, the applicant states that the corresponding AMR result line in the

GALL Report is addressesed under item 3.1.1-14. The staff reviewed the documentation

supporting the applicant's AMR evaluation in items 3.1.1-14, and no AMR line items roll up to

3.1.1-47. Therefore, the staff agrees with the applicant's determination that the corresponding

AMR result line in the GALL Report is not applicable to SSES.

In LRA Table 3.1.1, items 53, 54, 56 and 87, the applicant indicates that the corresponding

AMR result line in the GALL Report is not applicable because SSES does not have the

components for these items. The staff reviewed the documentation supporting the applicant's

AMR evaluation and confirmed the applicant's claim that SSES does not have these

components. Therefore, the staff agrees with the applicant's determination that the

corresponding AMR result line in the GALL Report is not applicable to SSES.

In LRA Table 3.1-1 line item 3.1.1-57, the applicant stated that loss of fracture toughness due

to thermal aging embrittlement for cast austenitic stainless steel Class 1 piping, piping

component, and piping elements and control rod drive pressure housings exposed to reactor

coolant > 250'C (> 4820 F) is not applicable because these components are included in LRA

Table 3.1-1 line items 3.3.1-51 and 3.1.1-55.

The staff confirmed that the components listed under line item 3.1.1-57 are included in line

items 51 and 55. The applicant has proposed using the Thermal Aging and Neutron Irradiation

Embrittlement of CASS Program to manage the aging effects in line 3.1.1-51; and the Inservice

Inspection, and Small Bore Class 1 Piping Inspection Programs to manage the aging effects in

line 3.1.1-55. Based on this review, the staff finds that Table 3.3.1, line item 3.1.1-57 is not

applicable.

3.1.2.1.2 Cracking due to Stress Corrosion Cracking, Intergranular Stress Corrosion Cracking

In LRA Table 3.1.2-3, for stainless steel tubing in a treated water (reactor coolant) environment,

the applicant specified use of the BWR Water Chemistry Program for managing the aging

effect of cracking due to SCC or IGSCC. For this AMR result line, the applicant referred to LRA

Table 3.1.1, item 3.1.1-48 and cited generic note E, indicating that the result is consistent with

the GALL Report for component, material, environment and aging effect but a different AMP is

used. The staff noted that for the same component, material and environment combination, the

GALL report recommends use of the Inservice Inspection (IWB, IWC and IWD) Program, the

Water Chemistry Program, and the One-Time Inspection of ASME Code Class 1 Small Bore

Piping for managing the aging effect of cracking due to SCC or IGSCC. The staff issued

RAI 3.1-4 by letter dated July 15, 2008, asking the applicant to provide technical justification

that the AMP specified in the LRA provides adequate management of the aging effect during

the period of extended operation.

In a letter dated August 15, 2008, the applicant responded to RAI 3.1-4 by providing the

following response:

An inspection program is needed to confirm the effectiveness of the BWR Water

Chemistry Program. LRA Table 3.1.2-3 is revised to credit the ISI Program and

the Small Bore Class 1 Piping Inspection in addition to the BWR Water

Chemistry Program to manage cracking for stainless steel tubing in treated

water. This is consistent with the combination of aging management programs

identified in GALL Report Item IV.C1-1. Note A is applicable.

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In LRA Table 3.1.2-3, for stainless steel condensing chambers, piping and fittings, valve bodies,

and flow orifices in a treated water environment, the applicant specified use of the BWR Water

Chemistry Program and the Small Bore Class 1 Piping Inspection for managing the aging effect

of cracking due to SCC or IGSCC. For these AMR result lines, the applicant referred to LRA

Table 3.1.1, item 3.1.1-48 and cited generic note A, indicating that the result is consistent with

the GALL Report for component, material, environment, aging effect, and the AMP is consistent

with the GALL Report. The staff noted that for the same or similar components and the same

material and environment combination, the GALL report recommends use of the Inservice

Inspection (IWB, IWC and IWD) Program, the Water Chemistry Program, and the One-Time

Inspection of ASME Code Class 1 Small Bore Piping for managing the aging effect of cracking

due to SCC or IGSCC. The staff issued RAI 3.1-6 by letter dated July 15, 2008, asking the

applicant to provide technical justification that the applicant's recommended AMPs provide

adequate management of the aging effect during the period of extended operation and justify

why Note A is appropriate for these AMR results lines.

In a letter dated August 15, 2008, the applicant responded to RAI 3.1-6 by providing the

following response:

The LRA Table 3.1.2-3 AMR result lines where the components are small bore

piping components made of stainless steel, the environment is "treated water

(internal)," the aging effect is cracking, and the AMPs are BWR Water Chemistry

Program and Small Bore Class 1 Piping Inspection are revised to also credit the

ISI Program. Also, the line entry for stainless steel tubing in LRA Table 3.1-2-3 is

revised to credit both the Inservice Inspection Program and the Small Bore

Class 1 Piping Inspection.

In total, there are 6 AMR line entries, covering stainless steel condensing

chambers, flow orifices, piping and fittings <4 inch, tubing and valves exposed to

treated water subject to cracking and compared to GALL Report line item IV.C1-

1. By crediting ISI for these entries and ISI and small bore inspection for the

tubing, the credited programs are consistent with GALL Report line item IV.C1-1.

Note A is applicable.

The LRA is amended to make the necessary changes.

The staff reviewed all of the LRA changes that the applicant made in response to RAIs 3.1-4

and 3.1-6. The staff confirmed that the changes brought the applicant's AMR result lines into

consistency with the corresponding AMR results in the GALL Report. Because the applicant's

AMR results are consistent with the GALL Report, the staff finds the LRA changes and the

applicant's AMR results for LRA Table 3.1.1, Item 3.1.1-48 to be acceptable.

LRA Table 3.1.2-3 includes AMR result lines for carbon steel piping and fittings <4" nominal

pipe size (NPS) and for carbon steel valves <4" NPS in an environment of treated water and

with an aging effect of cracking. The applicant specified the Small Bore Class 1 Piping

Inspection, only, as the AMP to manage the aging effect of cracking for these components and

cites generic note H, indicating that the aging effect is not in the GALL Report for this

component, material and environment combination. The staff noted that the components,

material, environment and aging effect all appear to be consistent with GALL Report

Item IV.C1-1, where the recommended AMPs are the ISI Program, the Water Chemistry

Program, and the One-Time Inspection of ASME Class 1 Small Bore Piping. The staff issued

RAI 3.1-7 by letter dated July 15, 2008, asking the applicant to explain why Note H was used

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for these AMR results and to justify that the AMP specified by the applicant for these

components provides satisfactory aging management during the period of extended operation,

comparable to the AMPs recommended in GALL Report line IV.C1-1.

In a letter dated August 15, 2008, the applicant responded to RAI 3.1-7 by providing the

following response:

GALL Report item IV.C1 -1 is appropriate for comparison in the AMR result lines

in the LRA Table 3.1.2-3 for piping and fittings <4 inch and for valve bodies <4

inch, for which the material is carbon steel, the environment is "treated water

(internal)," and the aging effect is cracking (due to thermal and mechanical

loading).

The AMR results are consistent with GALL Report item IV.C1-1 for the material

(steel), environment (reactor coolant) and aging effect (cracking). The LRA is

revised to credit the ISI Program, in addition to the Small Bore Class 1 Piping

Inspection, to manage cracking for the components. While GALL Report item

IV.C1-1 also credits Water Chemistry, it is not applicable here, since cracking

due to stress corrosion is not an aging effect for steel components. Therefore,

crediting ISI and Small Bore Class 1 Piping Inspection to manage cracking due

to thermal and mechanical loading is considered to be consistent with the

recommendations of GALL Report item IV.C1-1. However, since PPL is crediting

only two of the three programs that are listed in the GALL Report item, a note E,

instead of note A, is used for the comparison to the GALL Report.

The staff reviewed the applicant's response and the associated LRA changes. The staff noted

that the mechanism associated with the aging effect of cracking in these components is thermal

and mechanical loading, which is not strongly influenced by the water chemistry environment of

the components. Because there is no mitigating effect provided by the BWR Water Chemistry

Program for the aging mechanism of thermal and mechanical loading, the staff finds it

acceptable for the applicant not to credit the BWR Water Chemistry Program for these

components. Because the Small Bore Class 1 Piping Inspection provides for one-time

volumetric inspections that are capable of finding cracking due to thermal and mechanical

loading, and for piping <4 inch diameter the ISI program provides for periodic surface

examinations and for VT-2 examinations for leakage at every RFO. The staff finds the

applicant's LRA changes and the revised AMR results for carbon steel piping and fittings

<4 inch and for carbon steel valve bodies <4 inch in an environment of treated water with the

aging effect is cracking due to thermal and mechanical loading to be acceptable.

Based on the changes that the applicant made to the LRA in response to RAIs 3.1-4 and 3.1-6,

the explanation provided in response to RAI 3.1-7, and the programs identified for managing

the subject aging effects, the staff determines that the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended function(s) will be maintained

consistent with the CLB during the period of extended operation as required by

10 CFR 54.21(a)(3).

3.1.2.1.3 Loss of Fracture Toughness due to Thermal Aging Embrittlement

In the discussion in LRA Table 3.1.1, item 3.1.1-55, the applicant stated that for CASS valve

bodies less than 4 inch NPS, the Small Bore Class 1 Piping Inspection is credited to manage

loss of fracture toughness. In a letter dated July 15, 2008, the staff issued RAI 3.1-5 asking the

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applicant to justify use of the Small Bore Class 1 Piping Inspection for managing the loss of

fracture toughness in CASS valve bodies less than 4 inch NPS, rather than using the Inservice

Inspection Program as recommended in the GALL Report. In the applicant's response to RAI

B.2.31-1, in letter dated July 25, 2008, which is discussed in Section 3.0.3.1.18 and the

applicant's response to RAI 3.1-5 in a letter dated August 15, 2008, the applicant revised the

discussion in item 3.1.1-55 to delete the statement that for CASS valve bodies less than 4 inch

NPS, the Small Bore Class 1 Piping Inspection is credited to manage loss of fracture

toughness. Based on this change, the applicant's Inservice Inspection Program is credited to

manage loss of fracture toughness due to thermal aging embrittlement for all CASS pump

casings, pump covers, thermal barriers and valve bodies exposed to reactor coolant >250 0C

(>4821F), including CASS valve bodies less than 4 inch NPS. This combination of components,

material, environment, aging effect and aging management program is consistent with the

recommendations in the GALL Report for item 3.1.1-55. On this basis, the staff finds the

applicant's change in the LRA discussion for item 3.1.1-55 and the applicant's associated AMR

results to be acceptable.

SER Section 3.1.2.1 Conclusion: The staff evaluated the applicant's claim of consistency with

the GALL Report. The staff also reviewed information pertaining to the applicant's consideration

of recent OE and proposals for managing aging effects. On the basis of its review, the staff

concludes that the AMR results, which the applicant claimed to be consistent with the GALL

Report, are indeed consistent with its AMRs. Therefore, the staff concludes that the applicant

has demonstrated that the effects of aging for these components will be adequately managed

so that their intended function(s) will be maintained consistent with the CLB during the period of

extended operation, as required by 10 CFR 54.21(a)(3).

3.1.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation is

Recommended

In LRA Section 3.1.2.2, the applicant further evaluates aging management, as recommended

by the GALL Report, for the RV, RV internals, and reactor coolant system components and

provides information concerning how it will manage the following aging effects:

* cumulative fatigue damage

* loss of material due to general, pitting, and crevice corrosion

* loss of fracture toughness due to neutron irradiation embrittlement

* cracking due to stress corrosion cracking (SCC) and intergranular stress corrosion

cracking (IGSCC)

* crack growth due to cyclic loading

* loss of fracture toughness due to neutron irradiation embrittlement and void swelling

• cracking due to SCC

* cracking due to cyclic loading

* loss of preload due to stress relaxation

• loss of material due to erosion

* cracking due to flow-induced vibration

* cracking due to SCC and irradiation-assisted SCC

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* cracking due to primary water SCC

* wall thinning due to FAC

" changes in dimensions due to void swelling

* cracking due to SCC and primary water SCC

* cracking due to SCC, primary water SCC, and irradiation-assisted SCC

* QA for aging management of nonsafety-related components

For component groups evaluated in the GALL Report, for which the applicant claimed

consistency with the report and for which the report recommends further evaluation, the staff

audited and reviewed the applicant's evaluation to determine whether it adequately addressed

the issues further evaluated. In addition, the staff reviewed the applicant's further evaluations

against the criteria contained in SRP-LR Section 3.1.2.2. The staff's review of the applicant's

further evaluation follows.

3.1.2.2.1 Cumulative Fatigue Damage

LRA Section 3.1.2.2.1 states that fatigue is a TLAA, as defined in 10 CFR 54.3. Applicants must

evaluate TLAAs in accordance with 10 CFR 54.21(c)(1). SER Section 4.3 documents the staff's

review of the applicant's evaluation of this TLAA.

3.1.2.2.2 Loss of Material Due to General, Pitting, and Crevice Corrosion

The staff reviewed LRA Section 3.1.2.2.2 against the following criteria in SRP-LR

Section 3.1.2.2.2:

(1) LRA Section 3.1.2.2.2 addresses loss of material due to general, pitting, and crevice

corrosion in BWR top head and top head nozzles and PWR steam generator shell

assembly. The applicant stated that the BWR Water Chemistry Program is

supplemented by the ISI Program for managing loss of material due to general, pitting,

and crevice corrosion for the steel RV upper head and the top head nozzles exposed to

reactor coolant. A one-time inspection is not credited. The BWR Water Chemistry

Program in association with the Small Bore Class 1 Piping Inspection manages loss of

material due to general, pitting, and crevice corrosion for steel piping and valves less

than 4 inches exposed to reactor coolant. The Small Bore Class 1 Piping Inspection is a

one-time inspection. Loss of material for a steam generator shell assembly is only

applicable to PWRs.

SRP-LR Section 3.1.2.2.2 states that loss of material due to general, pitting, and crevice

corrosion may occur in the steel PWR steam generator shell assembly exposed to

secondary FW and steam. Loss of material due to general, pitting, and crevice corrosion

also may occur in the steel top head enclosure (without cladding) top head nozzles

(vent, top head spray or reactor core isolation cooling (RCIC), and spare) exposed to

reactor coolant. The existing program controls reactor water chemistry to mitigate

corrosion. However, control of water chemistry does not preclude loss of material due to

pitting and crevice corrosion at locations with stagnant flow conditions; therefore, the

effectiveness of water chemistry control programs should be verified to ensure that

corrosion does not occur. The GALL Report recommends further evaluation of programs

to verify the effectiveness of water chemistry control programs. A one-time inspection of

selected components at susceptible locations is an acceptable method to determine

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whether an aging effect is occurring or is slowly progressing such that the component's

intended functions will be maintained during the period of extended operation.

The staff reviewed all AMR result lines referring to LRA Table 3.1.1, item 3.1.1 -11, and

to LRA Section 3.1.2.2.2.1. The staff noted that the AMR results can be divided into

three categories based upon the AMP proposed by the applicant: 1) AMR results where

loss of material is managed by the BWR Water Chemistry Program, alone; 2) AMR

results where loss of material is managed by a combination of the BWR Water

Chemistry Program and the ASME Code Section XI Inservice Inspection (IWB, IWC,

and IWD) program; and 3) AMR results where loss of material is managed by a

combination of the BWR Water Chemistry Program and the Small Bore Class 1 Piping

Inspection. For the first and second category of these AMR results, the applicant cited

generic Note E indicating that the material, environment and aging effect are consistent

with the GALL Report but a different aging management program is credited. For AMR

results in the third category, BWR Water Chemistry Program and Small Bore Class 1

Piping Inspection, the applicant cited generic Note C indicating that the component is

different, but the material, environment, aging effect, and AMP are all consistent with the

GALL Report.

As a result of its review of the applicant's AMP B.2.31, Small Bore Class 1 Piping

Inspection, and the applicant's AMR results, the staff issued requests for additional

information in letters dated June 23, 2008, and July 15, 2008.

RAI B.2.31-1 asked the applicant to reconcile inconsistencies related to the applicant's

claim that the Small Bore Class 1 Piping Inspection is consistent with GALL AMP

XI.M35, "One-Time Inspection of ASME Code Class 1 Small Bore Piping."

RAI 3.1-1 asked the applicant to justify how the BWR Water Chemistry Program, alone,

would provide adequate aging management for loss of material for those AMR results

where no inspection was specified to confirm effectiveness of the water chemistry

program.

RAI 3.1-2 asked the applicant to explain why confirmation of effectiveness of the BWR

Water Chemistry Program is not needed with regard to managing the aging effect of

loss of material in carbon steel MS flow elements/restrictors exposed to treated water.

RAI 3.1-3 asked the applicant to explain why generic Note A or Note C, indicating that

the AMP used is consistent with the AMP recommended in the GALL Report, was used

for multiple AMR result lines in Table 3.1.2-3 where the applicant proposed using the

BWR Water Chemistry Program in combination with the Small Bore Class 1 Piping

Inspection, but the GALL Report recommends GALL AMP XI.M2, "Water Chemistry," in

combination with GALL AMP XI.M32, "One-Time Inspection," for managing loss of

material.

The applicant responded to RAI B.2.31-1 in a letter dated July 25, 2008, and to RAIs

3.1-1, 3.1-2, and 3.1-3 in a letter dated August 15, 2008. In those responses, the

applicant revised all of the AMR results that referred to LRA Table 3.1.1, item 3.1.1-11,

where the aging effect was managed either by the BWR Water Chemistry Program,

alone, or by the BWR Water Chemistry Program in combination with the Small Bore

Class 1 Piping Inspection. In the revised AMR results, the applicant proposes to manage

loss of material for carbon steel components exposed to treated water with a

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combination of the BWR Water Chemistry Program and the Chemistry Program

Effectiveness Inspection. The staff finds that use of the BWR Water Chemistry Program

and the CPEI is consistent with recommendations in the GALL Report, and issues

raised in RAIs B.2.31-1, 3.1-1, 3.1-2, and 3.1-3 were resolved by the applicant's

changes to the LRA made in response to these RAIs.

The staff reviewed the applicant's BWR Water Chemistry Program. The staffs

evaluation of this program, which is documented in SER Section 3.0.3.1.1, found that

the applicant's BWR Water Chemistry Program provides mitigation for the aging effect

of loss of material due to general, pitting, and crevice corrosion. The staff reviewed the

applicant's Chemistry Program Effectiveness Inspection. The staff's evaluation of this

program, which is documented in SER Section 3.0.3.1.10, found that the applicant's

CPEI is a one-time inspection that is consistent with the GALL Report's

recommendations for AMP XI.M32, "One-Time Inspection." The applicant's CPEI

includes provisions for inspecting selected components in areas of low or stagnant flow

and is capable of detecting loss of material due to general, pitting, and crevice

corrosion, if it should occur in the selected components. Because the BWR Water

Chemistry Program provides mitigation and the CPEI provides detection for loss of

material due to general, pitting, and crevice corrosion, the staff finds the applicant's LRA

changes and the applicant's use of the BWR Water Chemistry Program and the CPEI

for managing loss of material due to general, pitting, and crevice corrosion in steel

components exposed to treated water in the reactor vessel top head enclosure and in

the reactor coolant system pressure boundary to be acceptable.

For some components referring to LRA Table 3.1.1, item 3.1.1-11, the applicant credited

the ISI Program in lieu of a one-time inspection program to confirm that the BWR Water

Chemistry Program is effective in preventing loss of material due to corrosion. The

components where the ISI Program is credited are carbon steel or unclad low alloy steel

upper head components (dome, closure flange, and nozzles), and certain reactor

coolant pressure boundary piping and fittings, and valve bodies greater than 4 inches

nominal pipe size. For all of these components, the applicant's ISI Program requires

volumetric and visual examinations. The staff reviewed the applicant's ISI Program, and

the staff's evaluation of that program is documented in SER Section 3.0.3.2.1. The staff

found that the ISI Program is capable of detecting loss of material for components of the

reactor coolant pressure boundary, including piping, valves, and the reactor pressure

vessel. On the basis that the ISI Program's examination methodology is capable of

detecting loss of material in the subject components, the staff finds it acceptable for the

applicant to credit the ISI Program in lieu of a one-time inspection program for

confirming that the BWR Water Chemistry Program is effective in preventing loss of

material due to corrosion in those components.

The staff confirmed that SRP-LR Table 3.1-1, Item 12, is only applicable to PWR plants

and is not applicable to SSES, because SSES is a BWR.

(2) LRA Section 3.1.2.2.2.2 addresses loss of material due to general, pitting, and crevice

corrosion in isolation condenser components. The applicant stated that this aging effect

is not applicable because SSES design does not include an isolation condenser.

SRP-LR Section 3.1.2.2.2 states that loss of material due to pitting and crevice

corrosion may occur in stainless steel BWR isolation condenser components exposed to

reactor coolant. Loss of material due to general, pitting, and crevice corrosion may occur

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in steel BWR isolation condenser components. The existing program controls reactor

water chemistry to mitigate corrosion. However, control of water chemistry does not

preclude loss of material due to pitting and crevice corrosion at locations with stagnant

flow conditions; therefore, the effectiveness of water chemistry control programs should

be verified to ensure that corrosion does not occur. The GALL Report recommends

further evaluation of programs to verify the effectiveness of water chemistry control

programs. A one-time inspection of selected components at susceptible locations is an

acceptable method to determine whether an aging effect is occurring or is slowly

progressing such that the component's intended functions will be maintained during the

period of extended operation.

The staff verified in the UFSAR, Rev. 63 that SSES is a BWR that does not have an

isolation condenser.

On the basis of its review, the staff concluded that because SSES is a BWR without an

isolation condenser, SRP-LR Section 3.1.2.2.2.2 is not applicable to SSES.

(3) LRA Section 3.1.2.2.2 addresses loss of material due to general, pitting, and crevice

corrosion in flanges, nozzles, penetrations, pressure housings, safe ends, and vessel

shells, heads, and welds. The applicant stated that the BWR Water Chemistry Program

is supplemented by the ISI Program for managing loss of material due to crevice and

pitting corrosion for the steel RV upper head closure flange and shell closure flange with

stainless steel cladding exposed to reactor coolant. A one-time inspection is not

credited. The BWR Water Chemistry Program alone is credited for managing loss of

material due to crevice and pitting corrosion of the steel RV shell rings, ID attachments

and welds, bottom head, nozzles, safe ends, and CRD stub tubes and housings with

stainless steel cladding exposed to reactor coolant. A one-time inspection is not

credited. The BWR Water Chemistry Program in association with the Small Bore

Class 1 Piping Inspection or the ISI Program manages loss of material due to pitting and

crevice corrosion for stainless steel components of the reactor coolant system (RCS)

pressure boundary exposed to reactor coolant. The Small Bore Class 1 Piping

Inspection is a one-time inspection.

SRP-LR Section 3.1.2.2.2 states that loss of material due to pitting and crevice

corrosion may occur in stainless steel, nickel alloy, and steel with stainless steel or

nickel alloy cladding flanges, nozzles, penetrations, pressure housings, safe ends, and

vessel shells, heads, and welds exposed to reactor coolant. The existing program

controls reactor water chemistry to mitigate corrosion. However, control of water

chemistry does not preclude loss of material due to pitting and crevice corrosion at

locations with stagnant flow conditions; therefore, the effectiveness of water chemistry

control programs should be verified to ensure that corrosion does not occur. The GALL

Report recommends further evaluation of programs to verify the effectiveness of water

chemistry control programs. A one-time inspection of selected components at

susceptible locations is an acceptable method to determine whether an aging effect is

occurring or is slowly progressing such that the component's intended functions will be

maintained during the period of extended operation.

The staff reviewed all AMR results lines referring to LRA Table 3.1.1, items 3.1.1-14 or

3.1.1-15, and to LRA Section 3.1.2.2.2.3. The staff noted that the AMR results can be

divided into four categories based upon the AMPs proposed by the applicant: 1) AMR

results where loss of material is managed by the BWR Water Chemistry Program,

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alone; 2) AMR results where loss of material is managed by a combination of the BWR

Water Chemistry Program and the Small Bore Class 1 Piping Inspection; 3) AMR results

where loss of material is managed by a combination of the BWR Water Chemistry

Program and the ASME Code Section XI Inservice Inspection (IWB, IWC, and IWD)

program; and 4) AMR results where loss of material is managed by a combination of the

BWR Water Chemistry Program and the BWR Vessel Internals Program. For AMR

results in the first, third and fourth category, the applicant cited generic Note E indicating

that the material, environment and aging effect are consistent with the GALL Report but

a different aging management program is credited. For AMR results in the second

category, BWR Water Chemistry Program and Small Bore Class 1 Piping Inspection,

the applicant cited generic Note A indicating that the component, material, environment,

aging effect, and AMP are all consistent with the GALL Report.

As a result of its review of the applicant AMP B.2.31, Small Bore Class 1 Piping

Inspection, and the applicant's AMR results, the staff issued requests for additional

information in letters dated June 23, 2008, and July 15, 2008:

RAI B.2.31-1 asked the applicant to reconcile inconsistencies related to the

applicant's claim that the Small Bore Class 1 Piping Inspection is consistent with

GALL AMP XI.M35, "One-Time Inspection of ASME Code Class 1 Small Bore

Piping."

RAI 3.1-1 asked the applicant to justify how the BWR Water Chemistry Program,

alone, would provide adequate aging management for loss of material for those

AMR results where no inspection was specified to confirm effectiveness of the

water chemistry program.

The applicant responded to RAI B.2.31-1 in a letter dated July 25, 2008, and to RAI 3.1-

1 in a letter dated August 15, 2008. In those responses, the applicant revised all of the

AMR results that referred to LRA Table 3.1.1, items 3.1.1-14 or 3.1.1-15, where the

aging effect was managed either by the BWR Water Chemistry Program or by the BWR

Water Chemistry Program in combination with the Small Bore Class 1 Piping Inspection.

In the revised AMR results, the applicant proposes to manage loss of material for

stainless steel, nickel alloy, and steel with stainless steel or nickel alloy clad components

exposed to treated water with a combination of the BWR Water Chemistry Program and

the Chemistry Program Effectiveness Inspection. The staff finds that use of the BWR

Water Chemistry Program and the CPEI is consistent with recommendations in the

GALL Report.

The staff also noted that the applicant had aligned its AMR on loss of material in the

external surfaces of the reactor recirculation pump thermal barrier to GALL AMR IV.C1-

14. In this AMR, the staff noted that the applicant credited both its Water Chemistry

Program and Inservice Inspection Program to manage loss of material in the external

surfaces that are exposed to the treated water environment of the reactor coolant.

Consistent with other AMRs on loss of material due to pitting and crevice corrosion on

AMSE Code Class 1 components, the staff determined that the crediting of the Water

Chemistry Program for mitigation of pitting and crevice corrosion was acceptable

because the AMP is designed to prevent or mitigate loss or material that may be

induced by corrosive aging mechanisms (e.g., such as pitting or crevice corrosion).

However, the staff was concerned that it might not be appropriate to credit the Inservice

Inspection Program for aging management of loss of material in the external thermal

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barrier surfaces because they may be located in areas that are inaccessible for

examination. In RAI 3.1.2.2.2.3-3 dated July 23, 2008, the staff asked the applicant to

clarify which type of ISI examinations and requirements will be used to monitor for and

detect loss of material in the external surfaces of the recirculation pump thermal barriers

and whether the external surfaces of the reactor recirculation pump thermal barriers are

accessible for ISI examination method that is credited for aging management.

The applicant responded to RAI 3.1.2.2.2.3-3 by letter dated August 27, 2008. In its

response, the applicant stated that the external surfaces of the reactor recirculation

pump thermal barriers are inaccessible for examination when the pump is assembled.

The applicant further stated that since the pumps are not disassembled on any periodic

or planned frequency, the ISI Program is not an appropriate aging management

program for loss of material.

The applicant further stated that an appropriate aging management approach is to credit

the CPEI to supplement the BWR Water Chemistry Program. The applicant also stated

that although the external surfaces of the reactor recirculation pump thermal barrier are

inaccessible for inspection, the CPEI will inspect other components of like material

exposed to treated water to confirm that loss of material has been effectively mitigated

or to detect any degradation that is occurring. The inspection of an alternative location is

acceptable because the alternative location has a material and an environment

equivalent to the reactor recirculation pump thermal barriers.

The applicant revised the line entry in Table 3.1.2-3 to credit the CPEl in place of the ISI

Program. The applicant also indicated that this line item is consistent with GALL Item

IV.C1-14, which recommends water chemistry program augmented by a one-time

inspection program to manage loss of material for stainless steel components exposed,,

to treated water.

The staff reviewed the applicant's BWR Water Chemistry Program. The staff's

evaluation of this program, which is documented in SER Section 3.0.3.1.1, found that

the applicant's BWR Water Chemistry Program provides mitigation for the aging effect

of loss of material due to pitting and crevice corrosion. The staff reviewed the applicant's

Chemistry Program Effectiveness Inspection. The staff's evaluation of this program,

which is documented in SER Section 3.0.3.1.10, found that the applicant's CPEI is a

one-time inspection that is consistent with the GALL Report's recommendations for AMP

XI.M32, "One-Time Inspection." The applicant's CPEI includes provisions for inspecting

selected components in areas of low or stagnant flow and is capable of detecting loss of

material due to pitting and crevice corrosion, if it should occur in the selected

components. Because the BWR Water Chemistry Program provides mitigation and the

CPEI provides detection for loss of material due to pitting, and crevice corrosion, the

staff finds the applicant's LRA changes and the applicant's use of the BWR Water

Chemistry Program and the CPEI for managing loss of material due to pitting, and

crevice corrosion for stainless steel, nickel alloy, and steel with stainless steel or nickel

alloy clad components exposed to treated water in the reactor pressure vessel and in

the reactor coolant system pressure boundary to be acceptable.

For some components referring to LRA Table 3.1.1, items 3.1.1-14 and 3.1.1-15, the

applicant credited the ISI Program in lieu of a one-time inspection program to confirm

that the BWR Water Chemistry Program is effective in preventing loss of material due to

pitting or crevice corrosion. The components where the ISI Program is credited are

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stainless steel clad reactor vessel and upper head closure flanges, stainless steel pump

casings and covers, piping and valve bodies greater than 4 inch nominal pipe size and

tubing, and steam line flow restrictors. For all of these components, the applicant's ISI

Program requires volumetric and visual examinations (except tubing where only visual

examination is required). The staff reviewed the applicant's ISI Program, and the staff's

evaluation of that program is documented in SER Section 3.0.3.2.1. The staff found that

the ISI Program is capable of detecting loss of material for components of the reactor

coolant pressure boundary, including piping, tubing, pump casings, valves, flow

restrictors, and the reactor pressure vessel. On the basis that the ISI Program's

examination methodology is capable of detecting loss of material in the subject

components, the staff finds it acceptable for the applicant to credit the ISI Program in

lieu of a one-time inspection program for confirming that the BWR Water Chemistry

Program is effective in preventing loss of material due to corrosion in those

components.

For vessel internal components referring to LRA Table 3.1.1, item 3.3.1-14, the

applicant credited the BWR Vessel Internals Program in lieu of a one-time inspection

program to confirm that the BWR Water Chemistry Program is effective in preventing

loss of material due to pitting and crevice corrosion. The staff reviewed the applicant's

BWR Vessel Internals Program, and the staff's evaluation is documented in SER

Section 3.0.3.2.4. The staff found that the BWR Vessel Internals Program is capable of

detecting loss of material due to pitting and crevice corrosion for stainless steel or nickel

alloy components that are within its scope. On the basis that the BWR Vessel Internals

Program is capable of detecting loss of material in the subject components, the staff

finds it acceptable for the applicant to credit the BWR Vessel Internals Program in lieu of

a one-time inspection program for confirming that the BWR Water Chemistry Program is

effective in preventing loss of material due to pitting and crevice corrosion in stainless

steel or nickel alloy reactor vessel internals.

(4) LRA Section 3.1.2.2.2 addresses loss of material due to general, pitting, and crevice

corrosion in PWR steam generator upper and lower shell and transition cone. The

applicant stated that this aging effect is not applicable because SSES is a BWR.

SRP-LR Section 3.1.2.2.2 states that loss of material due to general, pitting, and crevice

corrosion may occur in the steel PWR steam generator upper and lower shell and

transition cone exposed to secondary feedwater and steam.

The staff confirmed that SRP-LR Table 3.1-1, Item 16, is only applicable to PWR plants.

On the basis of its review, the staff concluded that because SSES is a BWR, SRP-LR

Section 3.1.2.2.2.4 is not applicable to SSES.

Based on the programs identified above, the staff concludes that the applicant's programs meet

SRP-LR Section 3.1.2.2.2 criteria. For those line items that apply to LRA Section 3.1.2.2.2, the

staff determines that the LRA, as amended in response to associated RAIs, is consistent with

the GALL Report and that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

during the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.1.2.2.3 Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement

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The staff reviewed LRA Section 3.1.2.2.3 against the following criteria in SRP-LR

Section 3.1.2.2.3:

(1) LRA Section 3.1.2.2.3 states that neutron irradiation embrittlement is a TLAA, as defined

in 10 CFR 54.3. Applicants must evaluate TLAAs in accordance with

10 CFR 54.21(c)(1). SER Section 4.2 documents the staff's review of the applicant's

evaluation of this TLAA.

(2) LRA Section 3.1.2.2.3 addresses loss of fracture toughness due to neutron irradiation

embrittlement in RV beltline shell, nozzle, and welds. The applicant stated that reduction

in fracture toughness due to radiation embrittlement could occur for RV beltline region

materials exposed to reactor coolant and neutron flux. A RV materials surveillance

program monitors radiation embrittlement of the steel RV beltline materials with

stainless steel cladding. The Reactor Vessel Surveillance Program, and the results of its

evaluation for license renewal, are presented in Appendix B of the LRA.

SRP-LR Section 3.1.2.2.3 states that loss of fracture toughness due to neutron irradiation

embrittlement may occur in BWR and PWR RV beltline shell, nozzle, and welds exposed to

reactor coolant and neutron flux. A RV materials surveillance program monitors neutron

irradiation embrittlement of the RV. Reactor vessel surveillance programs are 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 is required to submit its proposed withdrawal schedule for approval prior to

implementation. Untested capsules placed in storage must be maintained for future insertion.

Thus, further staff evaluation is required for license renewal. Specific recommendations for an

acceptable AMP are provided in GALL Report Chapter XI, Section M31.

LRA Section 3.1.2.2.3.1 provides the applicant's discussion on management of neutron

irradiation embrittlement TLAA. The applicant states that, "Certain aspects of neutron

irradiation embrittlement are time-limited aging analyses (TLAAs) as defined in 10 CFR 54.3.

TLAAs are required to be evaluated in accordance with 10 CFR 54.21(c)(1). The staff's

acceptance of this TLAA is documented separately in Section 4.2 of this SER.

LRA Section 3.1.2.2.3.2 provides the applicant's discussion on management of neutron

irradiation embrittlement using Reactor Vessel Surveillance Program. The applicant has

implemented the BWRVIP Integrated Surveillance Program (ISP) based on the BWRVIP-78

report and the BWRVIP-86-A report. The NRC approved the two BWRVIP reports in an SE

dated February 1, 2002. BWRVIP-1 16 incorporates the technical criteria specified in BWRVIP78 and BWRVIP-86 and extends the ISP to cover the BWR fleet through the period of extended

operation. The applicant committed to address any NRC imposed requirements of BWRVIP116 (Commitment No. 18), when approved. The staff's acceptance of Reactor Vessel

Surveillance Program with Commitment No. 18 is documented in Section 3.0.3.2.12 of

this SER.

Based on the programs identified above, the staff concludes that the applicant's programs meet

SRP-LR Section 3.1.2.2.3 criteria. For those line items that apply to LRA Section 3.1.2.2.3, the

staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21(a)(3).

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3.1.2.2.4 Cracking Due to Stress Corrosion Cracking and Intergranular Stress Corrosion

Cracking

The staff reviewed LRA Section 3.1.2.2.4 against the following criteria in SRP-LR

Section 3.1.2.2.4:

(1) LRA Section 3.1.2.2.4 addresses cracking due to SCC and IGSCC in BWR top head

enclosure vessel flange leak detection lines. The applicant stated that the RV flange

leak detection line at SSES is a Class 1 line that is normally dry. The stainless steel line

is evaluated for a treated water environment and is therefore susceptible to cracking due

to SCC. This aging effect is managed with a combination of the BWR Water Chemistry

Program and the Small Bore Class 1 Piping Inspection.

SRP-LR Section 3.1.2.2.4 states that cracking due to SCC and IGSCC may occur in the

stainless steel and nickel alloy BWR top head enclosure vessel flange leak detection

lines. The GALL Report recommends that a plant-specific AMP be evaluated because

existing programs may not be capable of mitigating or detecting cracking due to SCC

and IGSCC.

The staff reviewed the applicant's BWR Water Chemistry Program. The staff's

evaluation of this program, which is documented in SER Section 3.0.3.1.1, found that

the applicant's BWR Water Chemistry Program provides mitigation for the aging effect

of cracking caused by SSC or IGSCC in stainless steel piping exposed to treated water.

The staff reviewed the applicant's Small Bore Class 1 Piping Inspection program. The

staff's evaluation of this program, which is documented in SER Section 3.0.3.1.18, found

that the applicant's Small Bore Class 1 Piping Inspection program provides for a onetime examination of ASME Code Class 1 small bore piping using volumetric examination

techniques that are capable of detecting piping cracks caused by SCC or IGSCC. Based

on the staff's determination that the BWR Water Chemistry Program provides mitigation

for the aging effect of cracking due to SCC or IGSCC, and the Small Bore Class 1

Piping Inspection program provides detection of potential cracking due to SCC or

IGSCC, the staff finds the applicant's proposed AMPs for managing the aging effect of

cracking in the stainless steel flange leak detection lines to be acceptable.

(2) LRA Section 3.1.2.2.4 addresses cracking due to SCC and IGSCC in isolation

condenser components. The applicant stated that this aging effect is not applicable

because SSES design does not include an isolation condenser.

SRP-LR Section 3.1.2.2.4 states that cracking due to SCC and IGSCC may occur in

stainless steel BWR isolation condenser components exposed to reactor coolant. The

existing program controls reactor water chemistry to mitigate SCC and relies on ASME

Code Section XI ISI; however, the existing program should be augmented to detect

cracking due to SCC and IGSCC. The GALL Report recommends an augmented

program to include temperature and radioactivity monitoring of the shell-side water and

eddy current testing of tubes to ensure that component intended functions will be

maintained during the period of extended operation.

SRP-LR Section 3.1.2.2.4.2 invokes the AMR Item 20 in Table 1 of the GALL Report,

Volume 1 and AMR Item IV.C1-4 of the GALL Report, Volume 2 on management of

cracking due to SCC and IGSCC in stainless steel BWR isolation condenser

components that are exposed to the treated water environment of the reactor coolant.

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The staff reviewed the UFSAR for SSES. The staff verified that the units do not include

isolation condensers. Based on this review, the staff concludes that the

recommendations in SRP-LR Section 3.1.2.2.4.2 and in GALL AMR IV.C1-4 are not

applicable to the SSES LRA, because the SSES plant designs does not include isolation

condenser systems.

Based on the programs identified above, the staff concludes that the applicant's programs meet

SRP-LR Section 3.1.2.2.4 criteria. For those line items that apply to LRA Section 3.1.2.2.4, the

staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21(a)(3).

3.1.2.2.5 Crack Growth Due to Cyclic Loading

LRA Section 3.1.2.2.5 addresses crack growth due to cyclic loading. The applicant stated that

this aging effect is not applicable because SSES is a BWR.

The staff reviewed LRA Section 3.1.2.2.5 against the criteria in SRP-LR Section 3.1.2.2.5 which

states that crack growth due to cyclic loading can occur in the reactor vessel shell forgings clad

with stainless steel using a high-heat-input welding process.

The staff confirmed in SRP-LR Table 3.1-1, Item 21, is only applicable to PWR plants.

On the basis of its review, the staff concluded that because SSES is a BWR, SRP-LR Section

3.1.2.2.5 is not applicable to SSES.

3.1.2.2.6 Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement and Void

Swelling

The staff reviewed LRA Section 3.1.2.2.6 against the criteria in SRP-LR Section 3.1.2.2.6.

LRA Section 3.1.2.2.6 addresses loss of fracture toughness due to neutron irradiation

embrittlement and void swelling. The applicant stated that this aging effect is not applicable

because SSES is a BWR.

Based on the above, the staff concludes that SRP-LR Section 3.1.2.2.6 criteria is not

applicable.

3.1.2.2.7 Cracking Due to Stress Corrosion Cracking

The staff reviewed LRA Section 3.1.2.2.7 against the following criteria in SRP-LR

Section 3.1.2.2.7:

(1) LRA Section 3.1.2.2.7 addresses cracking due to SCC in PWR stainless steel RV flange

leak detection lines and bottom-mounted instrument guide tubes exposed to reactor

coolant. The applicant stated that this aging effect is not applicable because SSES is a

BWR.

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SRP-LR Section 3.1.2.2.7 states that cracking due to SCC may occur in the PWR

stainless steel RV flange leak detection lines and bottom-mounted instrument guide

tubes exposed to reactor coolant.

The staff reviewed the UFSAR for SSES. The staff determined that the UFSAR Chapter

1 indicates that the SSES reactors are General Electrical (GE) Model 4 BWRs with Mark

II containment structures. Based on this review, the staff concludes that the

recommendations in SRP-LR Section 3.1.2.2.7.1 are not applicable to the SSES LRA,

because the SSES plants are not PWR designed reactors.

The staff confirmed in SRP-LR Table 3.1-1, Item 23, is only applicable to PWR plants.

Because SSES is a BWR, the staff finds that this item in SRP-LR Section 3.1.2.2.7.1

does not apply to SSES.

(2) LRA Section 3.1.2.2.7 addresses cracking due to SCC in Class 1 PWR cast austenitic

stainless steel (CASS) reactor coolant system piping, piping components, and piping

elements exposed to reactor coolant. The applicant stated that this aging effect is not

applicable because SSES is a BWR.

SRP-LR Section 3.1.2.2.7 states that cracking due to SCC may occur in Class 1 PWR

cast austenitic stainless steel (CASS) reactor coolant system piping, piping components,

and piping elements exposed to reactor coolant.

The staff reviewed the UFSAR for SSES. The staff determined that the UFSAR Chapter

1 indicates that the SSES reactors are General Electrical (GE) Model 4 BWRs with Mark

II containment structures. Based on this review, the staff concludes that the

recommendations in SRP-LR Section 3.1.2.2.7.2 are not applicable to the SSES LRA,

because the SSES plants are not PWR designed reactors.

The staff confirmed in SRP-LR Table 3.1-1, Item 24, is only applicable to PWR plants.

Because SSES is a BWR, the staff finds that this item in SRP-LR Section 3.1.2.2.7.2

does not apply to SSES.

Based on the above, the staff concludes that SRP-LR Section 3.1.2.2.7 criteria is not

applicable.

3.1.2.2.8 Cracking Due to Cyclic Loading

The staff reviewed LRA Section 3.1.2.2.8 against the following criteria in SRP-LR

Section 3.1.2.2.8:

(1) LRA Section 3.1.2.2.8 addresses cracking due to cyclic loading in stainless steel BWR

jet pump sensing lines. The applicant stated that for SSES, the jet pump instrumentation

lines inside the vessel are not subject to AMR, as they do not perform an intended

function. The lines outside of the vessel are part of the RCS pressure boundary and are

subject to AMR for a reactor coolant environment. Cracking of the stainless steel lines

external to the vessel is managed with a combination of the BWR Water Chemistry

Program and the Small Bore Class 1 Piping Inspection.

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SRP-LR Section 3.1.2.2.8 states that cracking due to cyclic loading may occur in the

stainless steel BWR jet pump sensing lines. The GALL Report recommends that a

plant-specific AMP be evaluated to ensure that this aging effect is adequately managed.

The staff reviewed the applicant's statement that the jet pump sensing lines inside the

reactor vessel are not subject to AMR. The staff noted that the jet pump sensing lines

inside the vessel are not part of the reactor coolant pressure boundary and that the

function of the jet pump sensing lines is to provide indication of jet pump flow, which is

not a license renewal intended function. Since the jet pump sensing lines inside the

reactor vessel are not part of the reactor coolant pressure boundary and are not

required to support a license renewal intended function, the staff finds the applicant's

statement that jet pump sensing lines inside the reactor vessel are not subject to AMR

to be acceptable.

The staff reviewed the applicant's BWR Water Chemistry Program. The staff's

evaluation of this program, which is documented in SER Section 3.0.3.1.1, found that

the applicant's BWR Water Chemistry Program provides mitigation for the aging effect

of cracking caused by SSC in stainless steel piping exposed to treated water. The staff

reviewed the applicant's Small Bore Class 1 Piping Inspection program. The staff's

evaluation of this program, which is documented in SER Section 3.0.3.1.18, found that

the applicant's Small Bore Class 1 Piping Inspection program provides for a one-time

examination of ASME Code Class 1 small bore piping using volumetric examination

techniques that are capable of detecting piping cracks caused by SCC, IGSCC or cyclic

loading. Based on the staff's determination that the BWR Water Chemistry Program

provides mitigation for potential cracking and the Small Bore Class 1 Piping Inspection

program provides detection of cracks due to SCC, IGSCC or cyclic loading, should they

occur, the staff finds the applicant's proposed AMPs for managing the potential aging

effect of cracking in the stainless steel jet pump sensing lines outside the reactor vessel

to be acceptable.

(2) LRA Section 3.1.2.2.8 addresses cracking due to cyclic loading in isolation condenser

components. The applicant stated that this aging effect is not applicable because SSES

design does not include an isolation condenser.

SRP-LR Section 3.1.2.2.8 states that cracking due to cyclic loading may occur in steel

and stainless steel BWR isolation condenser components exposed to reactor coolant.

The existing program relies on ASME Code Section XI ISI; however, the existing

program should be augmented to detect cracking due to cyclic loading. The GALL

Report recommends an augmented program to include temperature and radioactivity

monitoring of the shell-side water and-eddy current testing of tubes to ensure that

component intended functions will be maintained during the period of extended

operation.

SRP-LR Section 3.1.2.2.8.2 invokes the AMR Item 26 in Table 1 of the GALL Report,

Volume 1 and AMR Item IV.C1-5 of the GALL Report, Volume 2 on management of

cracking due to cyclical loading in steel and stainless steel BWR isolation condenser

components that are exposed to the treated water environment of the reactor coolant.

The staff reviewed the UFSAR for SSES. The staff verified that the units do not include

isolation condensers. Based on this review, the staff concludes that the

recommendations in SRP-LR Section 3.1.2.2.8.2 and in GALL AMR IV.C1-5 are not

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applicable to the SSES LRA because the SSES plant designs do not include isolation

condenser systems.

Based on the programs identified above, the staff concludes that the applicant's programs meet

SRP-LR Section 3.1.2.2.8 criteria. For those line items that apply to LRA Section 3.1.2.2.8, the

staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21(a)(3).

3.1.2.2.9 Loss of Preload Due to Stress Relaxation

The staff reviewed LRA Section 3.1.2.2.9 against the criteria in SRP-LR Section 3.1.2.2.9.

LRA Section 3.1.2.2.9 addresses loss of preload due to stress relaxation. The applicant stated

that this aging effect is not applicable because SSES is a BWR.

The staff reviewed the UFSAR for SSES. The staff determined that the UFSAR Chapter 1

indicates that the SSES reactors are General Electrical (GE) Model 4 BWRs with Mark II

containment structures. Based on this review, the staff concludes that the recommendations in

SRP-LR Section 3.1.2.2.9 are not applicable to the SSES LRA because the SSES plants are

not PWR designed reactors.

Based on the above, the staff concludes that SRP-LR Section 3.1.2.2.9 criteria is not

applicable.

3.1.2.2.10 Loss of Material Due to Erosion

The staff reviewed LRA Section 3.1.2.2.10 against the criteria in SRP-LR Section 3.1.2.2.10.

LRA Section 3.1.2.2.10 addresses loss of material due to erosion in steam generators. The

applicant stated that this aging effect is not applicable because SSES is a BWR.

Because SSES is a BWR, the staff finds that this item in SRP-LR Section 3.1.2.2.10 does not

apply to SSES.

Based on the above, the staff concludes that the applicant meets SRP-LR Section 3.1.2.2.10

criteria is not applicable.

3.1.2.2.11 Cracking Due to Flow-Induced Vibration

The staff reviewed LRA Section 3.1.2.2.11 against the criteria in SRP-LR Section 3.1.2.2.11.

LRA Section 3.1.2.2.11 addresses cracking due to flow-induced vibration. The applicant stated

that cracking due to flow-induced vibration for SSES stainless steel steam dryers exposed to

reactor coolant is managed by a combination of the BWR Vessel Internals Program and the

BWR Water Chemistry Program.

SRP-LR Section 3.1.2.2.11 states that cracking due to flow-induced vibration could occur for

the BWR stainless steel steam dryers exposed to reactor coolant. The GALL Report

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recommends further evaluation of a plant-specific AMP to ensure that this aging effect is

adequately managed.

SRP-LR Section 3.1.2.2.11 invokes the AMR Item 29 in Table 1 of the GALL Report, Volume 1

and AMR IV.B1-16 in the GALL Report, Volume 2 on management of cracking due to flowinduced vibration stainless steel BWR steam dryers.

The staff reviewed the information in LRA Section 3.1.2.2.11 and in LRA Table 3.1.2-2 against

the staff's recommended AMR guidance in SRP-LR Section 3.1.2.2.11 and in GALL AMR

IV.B1-16. The staff verified that in LRA Table 3.1.2-2, the applicant has included an AMR that

aligns to GALL AMR IV.B1-16, and that in the AMR, the applicant credits a combination Water

Chemistry Program and BWR Vessel Internals Program to manage cracking of the steam

dryers that is induced by flow-induced vibration.

The staff noted that the aging mechanism of concern is a high cycle fatigue mechanism and

that this mechanism is not dependent on the concentrations of chemical impurities that could

lead to corrosive type of cracking, such stress corrosion cracking (SCC, including intergranular

stress corrosion cracking [IGSCC], primary water stress corrosion cracking [PWSCC]) and

intergranular attack (IGA).

Thus, the staff noted that the applicant's crediting of the Water Chemistry Program did not

create a valid basis for aging management of cracking due to flow-induced vibrations because

flow-induced vibrations are a high-cycle fatigue phenomenon and are not dependent on the

control of water chemistry impurity concentrations.

The staff also noted that the applicant credited its BWR Vessel Internals Program (LRA AMP

B.2.9) for aging management and that the applicant's program is identified as a program that is

consistent with the recommended program elements of GALL AMP XI.M9, "BWR Vessel

Internals," with an enhancement to perform augmented inspections of the SSES top guide grid

beam and beam-to-beam crevice slots. The staff reviewed GALL AMP XI.M9 and confirmed

that, although the BWRVIP has submitted a number of BWRVIP topical reports on evaluation of

flow-induced vibrations in BWR steam dryers and on inspection of BWR steam dyers and

management of cracking that may result in BWR steam dryers as a result of flow-induced

vibrations, none of the BWRVIP reports on BWR steam dryer flow induced vibrations and

cracking have been approved to date or endorsed in GALL AMP XI.M9, "BWR Vessel

Internals." Thus the staff was of the opinion that the applicant's BWR Vessel Internals

Program, in its current form, did not provide a valid basis for managing cracking due to flowinduced vibrations in the steam dryers because the applicant's program does not currently

include any enhancements and commitments to: (1) of perform flow-induced vibration high

cycle fatigue flaw growth calculations of the steam dryers, (2) establish the flaw evaluation and

corrective action recommendations on postulated steam dryer cracking, and (3) establish the

augmented inspection recommendations for the steam dryers (including the inspection methods

and frequency for the examinations to be performed).

In RAI 3.1.2.2.11-1 by letter dated July 23, 2008, the staff asked the applicant to justify its

selection of the Water Chemistry Program and the BWR Vessel Internals Program for aging

management of cracking due to flow-induced vibrations of the steam dryers.

In its letter dated August 27, 2008, in response to RAI 3.1.2.2.11-1, the applicant stated that the

BWR Water Chemistry Program does not manage cracking due to flow-induced vibration. The

applicant revised the LRA to delete the BWR Water Chemistry Program from the line entry for

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cracking of the steam dryers in LRA Table 3.1.2-2. The applicant stated the following for

crediting the BWR Vessel Internals Program to manage cracking of the steam dryers:

The technical basis for crediting the BWR Vessel Internals Program (BWRVIP) for

management of cracking due to flow-induced vibration in the steam dryers is that the

BWRVIP incorporates the best industry guidance that is currently available from

BWRVIP reports BWRVIP- 139, BWRVIP- 181, and BWRVIP- 182.

PPL will follow Section 6 of BWRVIP-139 when evaluating cracking in the steam dryer.

PPL has instrumented the newly designed steam dryer in Unit 1 to obtain data on the

actual stresses in the dryer during current licensed power at extended power uprate

(EPU) conditions. Based on the measured stresses, PPL will perform a flow-induced

vibrational analysis. If any fatigue flaws are identified during the BWRVIP-required

inspections, PPL can accurately calculate flaw growth and establish re-inspection

intervals.

Currently, there is no regulatory basis for management of cracking due to flow-induced

vibration in the steam dryers. GALL line item IV.B 1-16 recommends a plant-specific

program, which, in effect, acknowledges that there is no generically accepted or

approved program for management of flow-induced vibration of the steam dryers.

However, since the BWRVIP includes provisions to incorporate all approved BWRVIP

documents, or to file notice of exception, the program requires its own modification if the

NRC requires changes to BWRVIP- 139, BWRVIP- 181, and BWRVIP- 182 prior to their

approval. Consequently, there is no need to enhance AMP B.2.9, the BWR Vessel

Internals Program, at this time.

The staff reviewed the applicant response and noted that the applicant proposes to use

BWRVIP-139, Steam Dryer Inspection and Flaw Evaluation Guidelines, to manage the aging

effect of cracking in the steam dryers. The staff issued its safety evaluation on BWRVIP-139 in

a letter to the BWRVIP dated July 30, 2008. For re-inspection, the staff stated that the

guidelines below should be followed:

* Each BWR licensee will determine the appropriate re-inspection approach according to

GE SIL-644 or BWRVIP-139 in consideration of the steam dryer performance at its

plant.

* License conditions associated with steam dryer monitoring programs in power uprate

license amendments take precedence over the steam dryer re-inspection provisions in

GE SIL-644 or BWRVIP-139.

, The licensee will justify any adjustments to its steam dryer re-inspection program where

commitments exist to implement the re-inspection provisions in GE SIL-644 to support a

power uprate license amendment or other activities.

* The licensee is expected to inform the NRC staff of significant changes to its steam

dryer re-inspection program where the staff relied on the program in a regulatory

decision.

The staff finds the deletion of the Water Chemistry Program to be acceptable because flowinduced vibrations are a high-cycle fatigue phenomenon and are not dependent on the control

of water chemistry impurity concentrations.

The staff noted that the applicant has instrumented the dryer to obtain data on actual stresses

during extended power uprate conditions. Based on this data, the applicant plans to perform a

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flow-induced vibrational analysis. The staff concludes that the applicant is implementing the

guidelines of BWRVIP-139 as accepted by the staff in its SE and on the basis that the

applicant's BWR Vessel Internals Program includes provisions to incorporate all approved

BWRVIP documents, and the BWR Vessel Internals Program has incorporated the guidelines

of BWRVIP-139, the staff finds the applicant response acceptable.

Based on the programs identified above, the staff concludes that the applicant's programs meet

SRP-LR Section 3.1.2.2.11 criteria. For those line items that apply to LRA Section 3.1.2.2.11,

the staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21(a)(3).

3.1.2.2.12 Cracking Due to Stress Corrosion Cracking and Irradiation-Assisted Stress

Corrosion Cracking

The staff reviewed LRA Section 3.1.2.2.12 against the criteria in SRP-LR Section 3.1.2.2.12.

LRA Section 3.1.2.2.12 addresses cracking due to SCC and IASCC. The applicant stated that

this aging effect is not applicable because SSES is a BWR.

SRP-LR Section 3.1.2.2.12 states that cracking due to SCC and IASCC may occur in PWR

stainless steel reactor internals exposed to reactor coolant.

The staff confirmed in SRP-LR Table 3.1-1, Item 20, is only applicable to PWR plants.

Because SSES is a BWR, the staff finds that this item in SRP-LR Section 3.1.2.2.12 does not

apply to SSES.

Based on the above, the staff concludes that SRP-LR Section 3.1.2.2.12 criteria is not

applicable.

3.1.2.2.13 Cracking Due to Primary Water Stress Corrosion Cracking

The staff reviewed LRA Section 3.1.2.2.13 against the criteria in SRP-LR Section 3.1.2.2.13.

LRA Section 3.1.2.2.13 addresses cracking due to primary water SCC (PWSCC). The applicant

stated that this aging effect is not applicable because SSES is a BWR.

SRP-LR Section 3.1.2.2.13 states that cracking due to primary water SCC (PWSCC) may occur

in PWR components made of nickel alloy and steel with nickel alloy cladding, including RCPB

components and penetrations inside the reactor coolant system such as pressurizer heater

sheathes and sleeves, nozzles, and other internal components.

The staff confirmed in SRP-LR Table 3.1-1, Item 31, is only applicable to PWR plants.

Because SSES is a BWR, the staff finds that this item in SRP-LR Section 3.1.2.2.13 does not

apply to SSES.

Based on the above, the staff concludes that SRP-LR Section 3.1.2.2.13 criteria is not

applicable.

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3.1.2.2.14 Wall Thinning Due to Flow-Accelerated Corrosion

The staff reviewed LRA Section 3.1.2.2.14 against the criteria in SRP-LR Section 3.1.2.2.14.

LRA Section 3.1.2.2.14 addresses wall thinning due to FAC in steam generators. The applicant

stated that this aging effect is not applicable because SSES is a BWR.

SRP-LR Section 3.1.2.2.14 states that wall thinning due to FAC may occur in steel FW inlet

rings and supports.

The staff confirmed in SRP-LR Table 3.1-1, Item 32, is only applicable to PWR plants.

Because SSES is a BWR, the staff finds that this item in SRP-LR Section 3.1.2.2.14 does not

apply to SSES.

Based on the above, the staff concludes that SRP-LR Section 3.1.2.2.14 criteria is not

applicable.

3.1.2.2.15 Changes in Dimensions Due to Void Swelling

The staff reviewed LRA Section 3.1.2.2.15 against the criteria in SRP-LR Section 3.1.2.2.15.

LRA Section 3.1.2.2.15 addresses changes in dimension due to void swelling. The applicant

stated that this aging effect is not applicable because SSES is a BWR.

SRP-LR Section 3.1.2.2.15 states that changes in dimensions due to void swelling may occur in

stainless steel and nickel alloy PWR internal components exposed to reactor coolant.

The staff confirmed in SRP-LR Table 3.1-1, Item 33, is only applicable to PWR plants.

Because SSES is a BWR, the staff finds that this item in SRP-LR Section 3.1.2.2.15 does not

apply to SSES.

Based on the above, the staff concludes that SRP-LR Section 3.1.2.2.15 criteria is not

applicable.

3.1.2.2.16 Cracking Due to Stress Corrosion Cracking and Primary Water Stress Corrosion

Cracking

The staff reviewed LRA Section 3.1.2.2.16 against the following criteria in SRP-LR

Section 3.1.2.2.16:

(1) LRA Section 3.1.2.2.16 addresses cracking due to SCC and primary water SCC on the

primary coolant side of PWR steel steam generator upper and lower heads, tubesheets,

and tube-to-tube sheet welds made or clad with stainless steel. The applicant stated that

this aging effect is not applicable because SSES is a BWR.

SRP-LR Section 3.1.2.2.16 states that cracking due to SCC may occur on the primary

coolant side of PWR steel steam generator upper and lower heads, tubesheets, and

tube-to-tube sheet welds made or clad with stainless steel. Cracking due to PWSCC

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may occur on the primary coolant side of PWR steel steam generator upper and lower

heads, tubesheets, and tube-to-tube sheet welds made or clad with nickel alloy.

The staff reviewed the UFSAR for SSES. The staff determined that the UFSAR Chapter

1 indicates that the SSES reactors are General Electrical (GE) Model 4 BWRs with Mark

II containment structures. Based on this review, the staff concludes that the

recommendations in SRP-LR Section 3.1.2.2.16.1 are not applicable to the SSES LRA

because the SSES plants are not PWR designed reactors.

The staff confirmed in SRP-LR Table 3.1-1, Item 34 and Item 35, is only applicable to

PWR plants. Because SSES is a BWR, the staff finds that this item in SRP-LR Section

3.1.2.2.16.1 does not apply to SSES.

(2) LRA Section 3.1.2.2.16 addresses cracking due to SCC and primary water SCC on

stainless steel pressurizer spray heads. The applicant stated that this aging effect is not

applicable because SSES is a BWR.

SRP-LR Section 3.1.2.2.16 states that cracking due to SCC may occur on stainless

steel pressurizer spray heads. Cracking due to PWSCC may occur on nickel alloy

pressurizer spray heads.

The staff reviewed the UFSAR for SSES. The staff determined that the UFSAR Chapter

1 indicates that the SSES reactors are General Electrical (GE) Model 4 BWRs with Mark

II containment structures. Based on this review, the staff concludes that the

recommendations in SRP-LR Section 3.1.2.2.16.2 are not applicable to the SSES LRA

because the SSES plants are not PWR designed reactors.

The staff confirmed in SRP-LR Table 3.1-1, Item 36, is only applicable to PWR plants.

Because SSES is a BWR, the staff finds that this item in SRP-LR Section 3.1.2.2.16.2

does not apply to SSES.

Based on the above, the staff concludes that SRP-LR Section 3.1.2.2.16 criteria are not

applicable.

3.1.2.2.17 Cracking Due to Stress Corrosion Cracking, Primary Water Stress Corrosion

Cracking, and Irradiation-Assisted Stress Corrosion Cracking

The staff reviewed LRA Section 3.1.2.2.17 against the criteria in SRP-LR Section 3.1.2.2.17.

LRA Section 3.1.2.2.17 addresses cracking due to SCC, primary water SCC, and irradiationassisted SCC. The applicant stated that this aging effect is not applicable because SSES is a

BWR.

SRP-LR Section 3.1.2.2.17 states that cracking due to SCC, PWSCC, and IASCC may occur in

PWR stainless steel and nickel alloy RV internals components.

The staff confirmed in SRP-LR Table 3.1-1, Item 37, is only applicable to PWR plants.

Because SSES is a BWR, the staff finds that this item in SRP-LR Section 3.1.2.2.17 does not

apply to SSES.

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Based on the above, the staff concludes that SRP-LR Section 3.1.2.2.17 criteria are not

applicable.

3.1.2.2.18 Quality Assurance for Aging Management of Nonsafety-Related Components

SER Section 3.0.4 documents the staff's evaluation of the applicant's QA program.

3.1.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report

In LRA Tables 3.1.2-1 through 3.1.2-3, the staff reviewed additional details of the AMR results

for material, environment, AERM, and AMP combinations not consistent with or not addressed

in the GALL Report.

In LRA Tables 3.1.2-1 through 3.1.2-3, the applicant indicated, via notes F through J, which the

combination of component type, material, environment, and AERM does not correspond to a

line item in the GALL Report. The applicant provided further information about how it will

manage the aging effects. Specifically, note F indicates that the material for the AMR line item

component is not evaluated in the GALL Report. Note G indicates that the environment for the

AMR line item component and material is not evaluated in the GALL Report. Note H indicates

that the aging effect for the AMR line item component, material, and environment combination

is not evaluated in the GALL Report. Note I indicates that the aging effect identified in the GALL

Report for the line item component, material, and environment combination is not applicable.

Note J indicates that neither the component nor the material and environment combination for

the line item is evaluated in the GALL Report.

For component type, material, and environment combinations not evaluated in the GALL

Report, the staff reviewed the applicant's evaluation to determine whether the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB for the period of extended operation. The

staff's evaluation is documented in the following sections.

3.1.2.3.1 Aging Management Review Results - Reactor Pressure Vessel - LRA Table 3.1.2-1

The staff reviewed LRA Table 3.1.2-1, which summarizes the results of AMR evaluations for the

reactor pressure vessel component groups.

LRA Table 3.1.2-1 summarizes the results of AMRs for the Reactor Pressure Vessel low alloy

steel, nickel based alloy, and low alloy steel clad with stainless steel, exposed to indoor air

(external) for the reactor vessel upper head closure flange, safe ends, nozzles, reactor vessel

bottom head flanges, reactor vessel shell rings, reactor vessel closure flange, and reactor

vessel upper head (dome). The applicant proposed no aging effect for this

material/environment combination and stated that no AMR is required.

The applicant assigned Note G for this material/environment combination. Note G states,

"Environment not in NUREG-1801 for this component and environment combination."

During the staff's review, the staff pointed out that the low alloy steel is at high temperature

during operation preventing the accumulation of moisture and therefore, insignificant corrosion

will occur during this time period. The staff also pointed out that the only time that corrosion

could occur is during outages, and these would not be of sufficient duration to result in

significant corrosion.

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During the staff's review, the staff pointed out that Stainless steels and nickel alloys are highly

resistant to corrosion in dry atmospheres in the absence of corrosive species (which would be

reflective of indoor uncontrolled air), as cited in Metals Handbook, Volumes 3 (p. 65) and 13

(p.555) (Ninth Edition, American Society for Metals International, 1980 and 1987). Components

are not subject to moisture in a dry air environment (and indoor uncontrolled air would have

limited humidity and condensation). Therefore, stainless steel in an indoor, uncontrolled air

environment exhibits no aging effect, and the component or structure will remain capable of

performing intended functions consistent with the CLB for the period of extended operation.

The staff concludes that there are no aging effects requiring management for these

components because of the dry environment for low alloy steel and no aging effect for the

nickel alloys or stainless steel cladding and stainless steel components in the Reactor Vessel,

Reactor Vessel Internals and Reactor Coolant System components within the scope of license

renewal

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

In LRA Table 3.1.2-1, the applicant proposed to manage cracking due to stress corrosion

cracking (SCC) in stainless steel cladding for low alloy steel in an environment of treated water

using the BWR Water Chemistry Program, alone. The applicant cited generic Note H for these

AMR results, indicating that the aging effect is not in the GALL Report for this component,

material and environment combination. The staff noted that the BWR Water Chemistry

Program does not include an inspection activity to confirm effectiveness of the program to

mitigate the aging effect and issued RAI 3.1-8 by letter dated July 15, 2008, asking the

applicant why a confirmatory AMP, such as the Water Chemistry Effectiveness Inspection, is

not needed for these components.

In a letter dated August 15, 2008, the applicant responded to RAI 3.1-8 by providing the

following response:

The LRA Table 3.1.2-1 is revised to credit the Chemistry Program Effectiveness

Inspection in addition to the BWR Water Chemistry Program for AMR result lines

addressing stainless steel cladding in treated water with an aging effect of "cracking - SCC (cladding)."

The staff reviewed the applicant's response and the associated LRA changes. The staff

reviewed the applicant's BWR Water Chemistry Program. The staff's evaluation of this

program, which is documented in SER Section 3.0.3.1.1, found that the BWR Water Chemistry

Program provides mitigation for the aging effect of cracking caused by SSC in stainless steel

clad components exposed to treated water. The staff reviewed the applicant's Chemistry

Program Effectiveness Inspection. The staff's evaluation of this program, which is documented

in SER Section 3.0.3.1.10, found that the CPEI is a one-time inspection that is consistent with

the GALL Report's recommendations for AMP XI.M32, "One-Time Inspection." The CPEI

includes examination methods that are capable of detecting cracking due to SCC. Because the

BWR Water Chemistry Program provides mitigation and the CPEI provides detection for

cracking due to SCC, the staff finds the applicant's LRA changes and the applicant's use of the

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BWR Water Chemistry Program and the CPEI for managing cracking due to SCC in the

cladding of stainless steel clad components exposed to treated water in the reactor pressure

vessel to be acceptable.

In LRA Table 3.1.2-1, the applicant includes its plant-specific AMRs on management of

cracking - flaw growth in steel (carbon steel or alloy steel) reactor vessel (RV) components that

are unclad or have internal stainless steel or nickel alloy cladding under internal exposure to the

treated water environment of the reactor coolant:

* RV upper heads, closure flanges, shells, and bottom heads

" RV recirculation inlet nozzles, recirculation outlet nozzles, core spray nozzles, jet pump

instrumentation nozzles,

" RV main steam line nozzles and their safe ends,

• RV head spray and spare nozzles, RV head vent nozzles, and their flanges

* RV feedwater nozzle safe ends, and RV Nll, N12, and N16 instrumentation nozzle safe

ends

In these AMRs, the applicant identifies that cracking/flaw growth is an applicable aging effect

requiring management (AERM) for the internal component surfaces that are exposed to the

reactor coolant. In these AMRs, the applicant credits its Inservice Inspection Program with

management of cracking/flaw growth in the components.

The staff determined that the applicant conservatively identified cracking/flaw growth as an

applicable AERM for the internal component surfaces that are exposed to the treated water

environment of the reactor coolant. The staff noted that the applicant's aging effect

cracking/flaw growth corresponds to the phrase "crack initiation and growth" in the definition for

cracking that is provided in GALL Table IX.E. Based on this determination, the staff finds that

the applicant has conformed to the guidance for cracking in GALL Table IX.E.

The staff also determined that the applicant has credited AMP B.2.1, Inservice Inspection

Program as the basis for managing cracking/flaw growth in the internal component surfaces

that are exposed to the treated water environment of the reactor coolant. The staff verified for

the RV components assessed in this section that the Inservice Inspection Program requires the

applicant to perform volumetric examinations of these components in accordance with the

applicable volumetric and surface examination requirements in the ASME Code Section XI

Examination Categories B-A, B-D, or B-F, as invoked by 10 CFR 50.55a. The required

volumetric examinations use techniques (such as ultrasonic testing or radiography) that are

capable of detecting cracks or imperfections throughout the thickness of the components. Thus,

the inspections required by these examination categories are sufficient to detect and monitor for

crack initiation and growth that may be occurring in these RV components. On this basis, the

staff finds that the applicant has provided an acceptable basis for crediting the Inservice

Inspection Program for aging management of cracking/flaw growth in these components as a

result of exposure to the treated water environment of the reactor coolant.

Based on this review, the staff also concludes the applicant has provided an acceptable basis

that demonstrates that the volumetric examinations performed under the Inservice Inspection

Program will be capable of detecting and monitoring for cracking/flaw growth in these RV

components. The staff's evaluation of the ability of the Inservice Inspection Program to manage

cracking in AMSE Code Class components is given in SER Section 3.0.3.2.1.

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In LRA Table 3.1.2-1, the applicant includes its plant-specific AMR on management of cracking

- flaw growth in the alloy steel reactor vessel stabilizer brackets that are exposed externally to

an indoor air environment. In this AMR, the applicant identifies that cracking/flaw growth is an

applicable AERM for the external component surfaces that are exposed to the indoor air

environment. In this AMR, the applicant credits its Inservice Inspection Program with

management of cracking/flaw growth in the external component surfaces.

The staff determined that the applicant conservatively identified cracking/flaw growth as an

applicable AERM for the external RV stabilizer bracket surfaces that are exposed to indoor air.

The staff noted that the applicant's aging effect cracking/flaw growth corresponds to the phrase "crack initiation and growth" in the definition for cracking that is provided in GALL Table IX.E.

Based on this determination, the staff finds that the applicant has conformed to the guidance for

cracking in GALL Table IX.E.

The staff also determined that the applicant has credited AMP B.2.1, Inservice Inspection

Program as the basis for managing cracking/flaw growth in the RV stabilizer bracket surfaces

that are exposed externally to indoor air. The staff verified that, for the RV stabilizer brackets

assessed in this section, the Inservice Inspection Program requires that the applicant to

perform surface examinations of these components in accordance with the applicable

volumetric and surface examination requirements in the ASME Code Section XI Examination

Category B-K, as invoked by 10 CFR 50.55a. The required volumetric examinations use

techniques (penetrant testing [PT] or magnetic particle test [MT]) that are capable of detecting

potential cracks that penetrate the external surfaces of the stabilizer bracket welds. Thus, the

inspections required by this ASME Code Section XI examination category are sufficient to

detect and monitor for crack initiation and growth that may be occurring in the externals

surfaces of the RV stabilizer brackets. On this basis, the staff finds that the applicant has

provided an acceptable basis for crediting the Inservice Inspection Program for aging

management of cracking/flaw growth in these components as a result of exposure to indoor air.

Based on this review, the staff also concludes that the Inservice Inspection Program is

acceptable for management of the applicable AERMs because the applicant has provided an

acceptable basis that demonstrates that the surface examinations performed under the

Inservice Inspection Program will be capable of detecting and monitoring for cracking/flaw

growth in the external RV stabilizer bracket surfaces that are exposed to indoor air. The staff's

evaluation of the ability of the Inservice Inspection Program to manage cracking in AMSE Code

Class components is given in SER Section 3.0.3.2.1.

In LRA Table 3.1.2-1, the applicant includes its plant-specific AMR on management of cracking

- flaw growth in the nickel alloy N9 CRD nozzle cap that is exposed internally to the treated

water environment of the reactor coolant. In this AMR, the applicant identifies that cracking/flaw

growth is an applicable AERM for the internal component surfaces that are exposed to the

reactor coolant. In this AMR, the applicant credits its BWR CRD Return Line Program with

management of cracking/flaw growth in the internal component surfaces.

The staff determined that the applicant conservatively identified cracking/flaw growth as an

applicable AERM for the internal CRD return line nozzle cap surfaces that are exposed to the

reactor coolant. The staff noted that the applicant's aging effect cracking/flaw growth

corresponds to the phrase "crack initiation and growth" in the definition for cracking that is

provided in GALL Table IX.E. Based on this determination, the staff finds that the applicant met

the guidance in SRP-LR 3.1.3.3 for identifying the applicable aging effects for these nozzle cap

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surfaces because the applicant has conformed to the guidance for cracking in GALL Table

IX.E.

The staff also determined that the applicant has credited AMP B.2.6, BWR CRD Return Line

Nozzle Program as the basis for managing cracking/flaw growth in the internal surfaces of the

CRD return line nozzle caps and their associated cap-to-nozzle circumferential welds that are

exposed to the reactor coolant. The staff verified that, for these nozzle caps, the applicant's

BWR CRD Return Line Nozzle Program is a program that is designed to manage cracking in

the CRD return lines nozzles and that the AMP is consistent with the staff's recommended

program elements for CRD return line nozzles in GALL AMP XI.M6, "CRD Return Line Nozzle,"

with an exception to perform weld overlay methods for repairs of existing cracks in the nozzles.

The staff also verified that the scope of the AMP includes potential capping of the nozzles and

their associated cap-to-nozzle circumferential welds. The staff evaluates the ability of the BWR

CRD Return Line Nozzle Program to manage cracking in these components in SER Section

3.0.3.2.2. The staff evaluation includes an evaluation on the ability of the BWR CRD Return

Line Nozzle Program to manage cracking in the CRD return line nozzle cap cap-to-nozzle

circumferential welds and the exception to use weld overlay methods for repairs of cracking in

these welds. On this basis, the staff finds that the applicant has provided an acceptable basis

for crediting the BWR CRD Return Line Nozzle Program for aging management of

cracking/flaw growth in these components as a result of exposure to the reactor coolant.

In LRA Table 3.1.2-1 the applicant includes its plant-specific AMR items for managing cracking

and loss of material in the carbon steel reactor pressure vessel support skirt ring girders and

cracking in the high strength alloy steel reactor pressure vessel support skirt bolts that are

exposed to a indoor air environment. In these AMRs, the applicant credits its Inservice

Inspection Program - IWF for aging management of these aging effects. The staff noted that

the applicant's Inservice Inspection Program - IWF is a condition monitoring program that is

based on compliance with the requirements of 10 CFR 50.55a and the ASME Code Section XI,

Subsection IWF for ASME Code Class components supports and that the applicant program is

based on conformance with the staff's recommended program elements in GALL AMP XI.S3,

"ASME Section XI, Subsection IWF." Based on this review, the staff finds that the applicant has

provided an acceptable basis for crediting its Inservice Inspection Program -IWF to manage

cracking and loss of material in the reactor pressure vessel support skirt ring girders and

cracking of the reactor pressure vessel support skirt bolts because these components are

ASME Code Class 1 component supports. The staff evaluates the ability of the Inservice

Inspection Program - IWF to manage aging in ASME Code Class 1 components in SER Section

3.0.3.1.21

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.1.2.3.2 Aging Management Review Results - Reactor Vessel Internals - LRA Table 3.1.2-2

The staff reviewed LRA Table 3.1.2-2, which summarizes the results of AMR evaluations for the

RV internals component groups.

In LRA Table 3.1.2-2, the applicant includes its plant-specific AMRs on management of

reduction in fracture toughness for the following stainless steel (including CASS) reactor vessel

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(RV) internal components that are exposed to the treated water environment of the reactor

coolant and an integrated neutron flux:

* Core shroud (including upper, intermediate, and lower shroud shells and welds)

" Core plate (including plate, beams, rim hold-down bolts and nuts, alignment assembly

bolts and nuts and alignment pins)

* Top guide components (including beams and rim, alignment pins, bolts, nuts, and hold

down clamps)

" Orificed and peripheral fuel support pieces

* Control Rod Drive tubes

" Jet pump assemblies and their subcomponents

* Incore dry tubes from the source range and intermediate range monitors

In these AMRs, the applicant states that it credits its BWR Vessel Internals Program to manage

reduction of fracture toughness in the components.

The staff noted that in Table IV.B1 of GALL Volume 2, the staff identifies that the following cast

austenitic stainless steel (CASS) BWR RV internal components may be subject to reduction of

fracture toughness as a result of thermal aging embrittlement and neutron irradiation

embrittlement:

* Fuel supports and CRD drive assemblies - fuel orifice supports (GALL AMR IV.B1 -9)

" Jet pump assembly castings (GALL AMR IV.B1-1 1)

The staff noted that the applicant's plant-specific AMRs for these RV internal components

accounts for the fact that, even though the components were not fabricated from a stainless

steel casting method (i.e. the stainless steel components are made by forged or wrought

fabrication methods, and thus the components not subject to the phenomenon of thermal aging

embrittlement), the components are located in areas of high neutron flux and that the

components may be subject to reduction of fracture toughness as a result of exposure to a high

integrated neutron flux. Thus, the staff finds that the applicant has taken a conservative

approach relative to the information on management of fracture toughness in GALL Table IV.B1

for BWR RV internal components.

The staff also noted that the applicant's AMRs did identify reduction (loss) of fracture toughness

as an applicable AERM for these RV internal components (as listed in the bullets above),

implying that these RV internal components are exposed to a high integrated neutron flux. The

staff finds that the applicant's identification that reduction of fracture toughness is an applicable

AERM for these components to be acceptable because it is in conformance with the aging

effect discussion for loss of fracture toughness in GALL Table IX.E and the neutron irradiation

embrittlement aging mechanism discussion in GALL Table IX.F.

The staff noted, however, that the applicant had credited its BWR Vessel Internals Program to

manage reduction in fracture toughness in these RV internal components. The staff verified that

the applicant's BWR Vessel Internals Program is given in LRA Section B.2.9 and that the

program is identified as an AMP that is consistent with the program elements in GALL AMP

XI.M9, "BWR Vessel Internals, with an exception. The staff noted that this AMP credits the

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augmented inspection and flaw evaluation criteria in NRC-approved BWRVIP topical reports as

the basis for managing the aging effects that are applicable to BWR RV and RV internal

components. The staff noted that reduction in fracture toughness is not an aging effect "per se"

but instead refers to a change that may occur in the fracture toughness material property over

time. In its review of the applicant's BWR Vessel Internals Program, the staff noted that the

applicant credits the program with limited aging management of reduction of fracture toughness

in RV internal components. However, the staff determined that some additional information

would be needed to clarify how the recommended BWRVIP report guidelines within the scope

of AMP B.2.9, BWR Vessel Internals Program, would accomplish adequate management of

reduction of fracture toughness in these RV internal components. In RAI 3.1.2.3.2.1-1/8.2.9-4

by letter dated July 23, 2008, the staff asked the applicant to justify why the applicable BWRVIP

inspection and flaw evaluation guidelines are considered to be capable of managing reduction

of fracture toughness in these RV internals and to clarify the methodology or methodologies in

these reports that are credited for management of this aging effect.

In its response to RAI 3.1.2.3.2.1-1/B.2.9-4 dated August 27, 2008, the applicant stated that

"applicable BWRVIP inspection and flaw evaluation guidelines for RV internal components are

considered to be capable of managing reduction of fracture toughnss (ROFT) because the

inspections are designed to detect cracking, and, if cracking is detected, the inspection intervals

will be adjusted based on crack growth rates that are determined by evaluations that include the

effects of ROFT. The examination methods in the BWRVIP reports include ultrasonic

examination and visual examination of the RV internal components, when accessible, for the

detection of cracks. These same methods are credited for managing ROFT, since ROFT is

managed as cracking is identified, evaluated, and monitored in components with fluence values

exceeding the threshold for ROFT."

Because the BWRVIP guidelines provide examination methods and evaluation techniques to

detect cracking, and inspection intervals are adjusted based on the results of the inspection, the

staff finds that the guidelines will also manage ROFT, since fluence is one of the key factors

affecting the crack growth rate, which increases as fluence increases the yield strength of the

material (i.e., reduces fracture toughness). The staff reviewed the applicant's BWR Vessel

Internals Program and its evaluation is documented in SER Section 3.0.3.2.4. On this basis, the

staff finds the applicant response acceptable, and considers the issue closed.

On this basis, the staff finds that the applicant has provided an acceptable basis for crediting

the BWR Vessel Internals Program for aging management of reduction of fracture toughness in

these components as a result of exposure to treated water environment of the reactor coolant

and an integrated neutron flux.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.1.2.3.3 Aging Management Review Results - Reactor Coolant System Pressure Boundary -

LRA Table 3.1.2-3

The staff reviewed LRA Table 3.1.2-3, which summarizes the results of AMR evaluations for the

reactor coolant system pressure boundary component groups.

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In LRA Table 3.1.2-3, the applicant proposed to manage loss of material for steel material for

driver mount, piping and fitting components exposed to an external environment of indoor air

using the AMP B.2.32 "System Walkdown Program." In addition, the applicant also proposed to

manage the loss of material for carbon steel valve bodies (> 4 and < 4 in.) components

exposed to external environment of indoor air using the AMP B.2.32 "System Walkdown

Program."

The AMR line item credits the AMP B.2.32 "System Walkdown Program" to manage loss of

material for these components. The AMR line item cites Generic Note H, which indicates that

the aging effect is not addressed in GALL Report for this component, environment and material

combination. The staff's evaluation of the AMP B.2.32 "System Walkdown Program" is

documented in SER Section 3.0.3.2.14. The staff determined that this program is a condition

monitoring program that will detect the aging effect of loss of material for metals, including

steel, by periodic surveillance activities and observations of components' external surfaces to

detect aging degradation that are within the scope of license renewal. On the basis that the

applicant will be performing periodic visual inspections of these components, the staff finds the

AMR results for this line item acceptable.

In LRA Table 3.1.2-3, the applicant includes its plant-specific AMR on management of loss of

material in the internal reactor recirculation pump thermal barrier surfaces that are exposed to

the treated, closed-cycle cooling water environment. In this AMR, the staff noted that the

applicant credited both its Closed Cooling Water Program and Inservice Inspection Program to

manage loss of material in the internal surfaces that are exposed to the treated water

environment of the reactor coolant. The staff determined that the crediting of the Water

Chemistry Program for mitigation of pitting and crevice corrosion was acceptable because the

AMP is designed to prevent or mitigate loss or material that may be induced by corrosive aging

mechanisms (e.g., such as pitting or crevice corrosion). However, the staff was concerned that

it might not be appropriate to credit the Inservice Inspection Program for aging management of

loss of material in the internal thermal barrier surfaces because they may be located in areas

that are inaccessible for examination. In RAI 3.1.2.3.3.2-1 dated July 23, 2008, the staff asked

the applicant to clarify whether the internal surfaces of the reactor recirculation pump thermal

barriers are accessible for ISI examination method that is credited for aging management; and

which alternative aging management approach (if any) will be credited in addition to the Water

Chemistry Program if it is determined that the internal surfaces of the reactor recirculation pump

thermal barrier are inaccessible for inspection.

The applicant responded to RAI 3.1.2.3.3.2-1 by letter dated August 27, 2008. In its response,

the applicant stated that the internal surfaces of the reactor recirculation pump thermal barrier

consist of the bored channels that provide the flowpath for the Reactor Building Closed Cooling

Water (RBCCW). The applicant also stated that these internal surfaces are inaccessible for

inspection, and, as such, the ISI Program is not an appropriate aging management program for

loss of material.

The applicant stated that an appropriate aging management approach is to credit the Closed

Cooling Water (CCW) Chemistry Program supplemented by the CPEI. The applicant further

stated that as described in LRA Section B.2.14, the combination of these two programs will

manage loss of material for stainless steel components exposed to closed cooling water. The

applicant also stated that although the internal surfaces of the reactor recirculation pump

thermal barrier are inaccessible for inspection, the CPEI will inspect other components of like

material exposed to CCW to confirm that loss of material has been effectively mitigated or to

detect any degradation that is occurring. The applicant indicated that this is consistent with

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GALL Item VII.C2- 10, which is for stainless steel components exposed to closed cycle cooling

water and recommends the closed cooling water program for management of loss of material.

The applicant revised the line entry in Table 3.1.2-3 to credit the CPEI in place of the ISI

Program. The applicant also revised the footnote from H to E. Since the applicant has changed

the footnote from H to E, the discussion in LRA Section 3.1.2.2.2.3 is also revised to note the

use of CPEI with the CCW Chemistry Program.

The staff reviewed the applicant's Closed Cooling Water Chemistry Program. The staff's

evaluation of this program, which is documented in SER Section 3.0.3.2.7, found that the

applicant's Closed Cooling Water Chemistry Program provides mitigation for the aging effect of

loss of material due to pitting and crevice corrosion. The staff reviewed the applicant's

Chemistry Program Effectiveness Inspection. The staff's evaluation of this program, which is

documented in SER Section 3.0.3.1.10, found that the applicant's CPEI is a one-time inspection

that is consistent with the GALL Report's recommendations for AMP Xl.M32, "One-Time

Inspection." The applicant's CPEI includes provisions for inspecting selected components in

areas of low or stagnant flow and is capable of detecting loss of material due to pitting and

crevice corrosion, if it should occur in the selected components. Because the Closed Cooling

Water Chemistry Program provides mitigation and the CPEI provides detection for loss of

material due to pitting, and crevice corrosion, the staff finds the applicant's LRA changes and

the applicant's use of the Closed Cooling Water Chemistry Program and the CPEI for

managing loss of material due to pitting, and crevice corrosion for stainless steel reactor

recirculation pump thermal barrier surfaces that are exposed to the treated, closed-cycle

cooling water environment in the reactor pressure vessel and in the reactor coolant system

pressure boundary to be acceptable. The inspection of an alternative location is acceptable

because the alternative location has a material and an environment equivalent to the reactor

recirculation pump thermal barriers.

In LRA Table 3.1.2-3, the applicant includes its plant-specific AMR on management of cracking

and flaw growth in the internal reactor recirculation pump thermal barrier surfaces that are

exposed to the treated, closed-cycle cooling water environment. In these AMRs, the applicant

identifies that cracking and flaw growth is an applicable AERM for the internal component

surfaces that are exposed to the treated, closed-cycle cooling water environment. In these

AMRs, the applicant credits a combination of the Closed Cooling Water Chemistry Program and

BWR Stress Corrosion Cracking Program to manage cracking and flaw growth in the internal

thermal barrier surfaces that are exposed to the treated, closed-cycle cooling water

environment.

The staff verified that the applicant had included a plant-specific AMR on cracking and flaw

growth in the internal surfaces of the reactor recirculation pump thermal barriers that are

exposed to the treated, closed-cycle cooling water environment, and that, in this AMR, the

applicant credited both its Closed Cooling Water Chemistry Program and BWR Stress

Corrosion Cracking Program to manage cracking and flaw growth in the internal component

surfaces that are exposed to closed-cycle cooling water.

The staff was initially of the opinion that it might not be appropriate to credit the BWR Stress

Corrosion Cracking Program for aging management of cracking and flaw growth in the internal

surfaces of the reactor recirculation pump thermal barriers because they may be located in

areas that are inaccessible for examination.

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In RAI 3.1.2.3.3.3-1, Part A dated July 23, 2008, the staff asked the applicant to identify the

type of examinations that will be used under the BWR Stress Corrosion Cracking Program to

monitor for and detect cracking and flaw growth in the internal surfaces of the recirculation

pump thermal barriers that are exposed to closed-cycle cooling water, and to clarify whether the

internal surfaces of the reactor recirculation pump thermal barriers are accessible for the

examination method that is credited for aging management.

The staff also noted that the applicant has credited the Closed Cooling Water Chemistry

Program to manage cracking and flaw growth in internal surfaces of these components. The

staff noted, however, that these components are made of alloy steel without internal stainless

steel or nickel alloy cladding. The staff noted that Closed Cooling Water Chemistry Program

would only be a valid program to credit for management of cracking/flaw growth if the

mechanisms inducing cracking and flaw growth were chemistry-related or corrosion-related

cracking/flaw growth mechanisms, such as stress corrosion cracking (SCC and its forms such

as PWSCC or IGSCC) or IGA. Thus, the staff was of the opinion that the Closed Cooling Water

Chemistry Program would only be a valid program to credit if the cracking/flaw growth was

induced by either SCC, PWSCC, IGSCC or IGA. In Part B, the staff asked the applicant to

clarify the aging mechanisms that could induce cracking and flaw growth in the internal

surfaces of the reactor recirculation pump thermal barriers, and based on these mechanisms, to

provide its basis why the Closed Cooling Water Chemistry is considered to be a valid AMP for

managing cracking and flaw growth in these components.

In its response to RAI 3.1.2.3.3.3-1, Part A dated August 27, 2008, the applicant stated that the

internal surfaces of the reactor recirculation pump thermal barrier consist of the bored channels

that provide the flowpath for the Reactor Building Closed Cooling Water (RBCCW). The

applicant also stated that these internal surfaces are inaccessible for inspection; as such, the

BWR Stress Corrosion Cracking (SCC) Program is not an appropriate aging management

program for cracking.

The applicant further stated that "an appropriate aging management approach is to credit the

Closed Cooling Water (CCW) Chemistry Program supplemented by the CPEI. As described in

LRA Section B.2.14, these programs will manage cracking for stainless steel components

exposed to closed cooling water. Although the internal surfaces of the reactor recirculation

pump thermal barrier are inaccessible for inspection, the CPEI will inspect other components of

like material exposed to CCW to confirm that cracking has been effectively mitigated or to

detect any degradation that is occurring."

In response to RAI 3.1.2.3.3.3-1, Part B dated August 27, 2008, the applicant stated that "the

aging mechanism capable of inducing cracking and flaw growth in the internal surfaces of the

reactor recirculation pump thermal barriers is stress corrosion cracking (SCC). The pump

thermal barrier is susceptible to SCC because it is made of stainless steel and is subjected to a

closed cycle cooling water environment. Cracking due to SCC on the internal surfaces of the

thermal barrier is mitigated by water chemistry control via the Closed Cooling Water Chemistry

Program. This is consistent with GALL Item VII.C2-1 1, which is for stainless steel components

exposed to closed cycle cooling water. The GALL item recommends the closed cooling water

program for management of cracking due to SCC. It is noted that there is no direct comparison

in GALL Section IV for the internal surfaces of the thermal barrier because GALL Section IV

does not address a closed cooling water environment.

The applicant revised Table 3.1.2-3 for CASS pump thermal barrier to delete BWRSCC

Program as the verification program for Closed Cycle Cooling Water Chemistry and instead

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credits the CPEI as the verification program. The applicant also revised the footnote H to

footnote E.

The staff reviewed the applicant response and the changes to the LRA. The GALL Report Item

VII.C2-11 addresses stainless components in an environment of closed cycle cooling water >

140QF with an aging effect of cracking due to SCC. For this line, the GALL Report recommends

GALL AMP XI.M21, "Closed Cycle Cooling Water System," to manage the aging effects. The

applicant is crediting its Closed Cycle Cooling Water System program, which is consistent with

the GALL Report recommendation, and, in addition, is crediting the Chemistry Program

Effectiveness Inspection. The staff evaluates the ability of the Closed Cycle Cooling Water

System Program and CPEI to manage cracking in these components in SER Sections 3.0.3.2.7

and 3.0.3.1.10 respectively. On the basis that the applicant is consistent with the GALL Report,

the staff finds that applicant response acceptable and concludes that the Closed Cycle Cooling

Water System Program and CPEI will adequately manage the aging effect of cracking due to

SCC in CASS reactor recirculation pump thermal barrier in an environment of closed cycle

cooling water > 140°F during the period of extended operation.

In LRA Table 3.1.2-3, the applicant includes its plant-specific AMR on management of

cracking/flaw growth in the unclad steel N15 reactor vessel (RV) drain nozzles that are exposed

internally to the treated water environment of the reactor coolant. In these AMRs, the applicant

identifies that cracking/flaw growth is an applicable AERM for the internal component surfaces

that are exposed to the treated water environment of the reactor coolant. In these AMRs, the

applicant credits a combination of BWR Water Chemistry Program and the BWR Penetrations

Program for management of cracking/flaw growth in the internal component surfaces that are

exposed to the treated water environment of the reactor coolant.

The staff verified that, in its AMR for managing cracking and flaw growth in the N15 RV drain

nozzles, the applicant credits a combination of its BWR Water Chemistry Program and the

BWR Penetrations Program to manage this aging effect.

The staff verified that in AMP B.2.8 the applicant identifies that the BWR Penetrations Program

is credited for managing cracking that is projected to occur in the SSES RV penetration nozzles

and that the program is designated as an AMP that is consistent with the program elements in

GALL AMP XI.M8, "BWR Penetrations," with an exception to include additional RV penetrations

(including the N15 RV drain nozzles) within the scope of the program. In RAI B.2.8-1 by letter

dated July 23, 2008, the staff asked the applicant to provide its basis for extending the scope of

the BWR Penetrations Program to the RV drain nozzles. The scope of RAI B.2.8-1 is also

applicable to the staff's assessment of the applicant's AMR item on cracking and flaw growth of

the N15 RV drain nozzles and their associated nozzle-to-vessel welds.

The staff noted that the applicant has also credited the BWR Water Chemistry Program to

manage cracking and flaw growth in these components. The staff noted, however, that these

components are made of alloy steel without internal stainless steel or nickel alloy cladding. The

staff noted that BWR Water Chemistry Program would only be a valid program to credit for

management of cracking/flaw growth if the mechanisms inducing cracking and flaw growth

were chemistry-related or corrosion-related cracking/flaw growth mechanisms, such as stress

corrosion cracking (SCC and its forms such as PWSCC or IGSCC) or IGA. To date, SCC or

IGA have not been identified as aging mechanisms of concern for steel materials (including

carbon steels and alloy steels).

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The staff noted that the N1 5 RV drain nozzles are designated as alloy steel nozzles without

stainless steel or nickel alloy cladding. Thus, the staff was of the opinion that the BWR Water

Chemistry Program would only be a valid program to credit if the cracking/flaw growth was

induced by SCC, PWSCC, IGSCC or IGA. In RAI 3.1.2.3.3.4-1, Part A by letter dated July 23,

2008, the staff asked the applicant to clarify the weld material that was used to fabricate the

N15 RV drain nozzle-to-vessel welds. In RAI 3.1.2.3.3.4-1, Part B, the staff asked the applicant

to clarify the aging mechanisms that could induced cracking and flaw growth in the N15 RV

drain nozzles and their associated nozzle-to-vessel welds, and based on these mechanisms, to

provide its basis why the BWR Water Chemistry is considered to be a valid AMP for managing

cracking and flaw growth in these components.

In its response to RAI 3.1.2.3.3.4-1 dated August 27, 2008, the applicant stated:

Part A. The N15 RV drain nozzles were constructed by boring a hole through the

bottom head of the reactor vessel and then welding a short length of a forged

pipe (nozzle) to the outside surface of the bottom head. The weld material

between the low alloy nozzle (SA-508 Class 1) and the low alloy vessel (SA-533

Grade B) is low alloy steel, compatible with the vessel and nozzle materials. The

weld consists of two parts; the weld buildup on the outside diameter of the

bottom head of the vessel, and the weld between the nozzle and the weld

buildup. The weld buildup material is E8018-G, trade name Atom Arc 8018NM,

conforming to the current specification for E8018-NM1. The material for the weld

between the nozzle and the weld buildup is equivalent to E8018-NM, trade name

Adcom 1NMM.

The line entry for drain nozzle N15 in LRA Table 3.1.2-1 (LRA page 3.1-45)

identifies the drain nozzle as low alloy steel with partial stainless steel (SS) clad.

The SS cladding is only on the inside diameter of the bottom head of the vessel,

extending just slightly into the bore from the inside diameter of the vessel. There

is no cladding on the inside diameter of the vessel bore hole, the weld, or the

drain nozzle.

Part B. The aging mechanism that is capable of inducing cracking and flaw

growth in the N15 RV drain nozzle and associated weld is crack initiation and

flaw growth due to thermal and mechanical loading. The BWR Water Chemistry

Program does not mitigate cracking caused by this mechanism. LRA Table

3.1.2-1 and line item 3.1.1-40 in Table 3.1.1 are revised to remove the BWR

Water Chemistry Program from this entry.

The staff reviewed the applicant's response and finds, that because the material of the drain

nozzle is alloy steel, cracking is caused by thermal and mechanical loading, and BWR water

chemistry does not mitigate cracking caused by this mechanism. Therefore, the staff finds it

acceptable to delete the Water Chemistry Program from this line item. The BWR Penetration

Program includes inspection and flaw evaluation in conformance with the guidelines of NRCapproved BWRVIP reports BWRVIP-49 and BWRVIP-27, and is-consistent with the GALL AMP

XI.M8. Therefore, based on the review of the BWR Penetrations Program as documented in

SER Section 3.0.3.2.3, the staff finds that the BWR Penetrations Program will adequately

manage the aging effect of cracking in the N15 penetration nozzle.

In LRA Table 3.1.2-3, the applicant proposed to manage cracking in carbon steel piping and

fittings (< 4 inch) and in carbon steel valves (<4 inch) in an environment of treated water using

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the Small Bore Class 1 Piping Inspection, alone. The applicant cited generic Note H for these

AMR results, indicating that the aging effect is not in the GALL Report for this component,

material and environment combination. The staff noted that the component, material,

environment and aging effect combination for these lines appears to be the same as in the

GALL Report line IV.C1 -1 (where the material is stainless steel or steel). In a letter dated July

15, 2008, the staff issued RAI 3.1-7 asking the applicant to explain why Note H was used for

these lines and to justify why the AMP proposed by the applicant provides acceptable aging

management for these components.

The applicant responded to RAI 3.1-7 in a letter dated August 15, 2008. In their response, the

applicant revised the results for these two AMR result lines in LRA Table 3.1.2-3. In the

revision, the applicant changed the GALL Report reference for these two lines from "N/A" to

"IV.C1-1" and changed the Table 1 item reference from "N/A" to "3.1.1-48." The applicant also

changed from citing Note H to citing Note E for these components and added the ISI Program

as an additional AMP to manage the aging effect of cracking in these components. The staff's

evaluation of the applicant's response to RAI 3.1-7 and the related LRA changes is documented

in SER Section 3.1.2.1.2.

In LRA Table 3.1.2-3 the applicant includes its plant-specific AMR items for managing cracking

in carbon steel piping, piping components, and piping elements, and valve bodies that are

greater or equal to than 4 inches in diameter and that are exposed to a treated water

environment. In these AMRs, the applicant credits its Inservice Inspection Program for aging

management of cracking in the surfaces that are exposed to treated water. The staff noted that

the applicant's Inservice Inspection Program is a condition monitoring program that is based on

compliance with the requirements of 10 CFR 50.55a and the ASME Code Section XI and that

the applicant's program is based on conformance with the staff's recommended program

elements in GALL AMP XI.M1, "ASME Section Xl Inservice Inspection, Subsections IWB, IWC,

and IWD." Based on this review the staff finds that the applicant has provided an acceptable

basis for crediting its Inservice Inspection Program to manage cracking in these components

because these components are ASME Code Class components. The staff evaluates the ability

of the Inservice Inspection Program to manage aging in ASME Code Class components in SER

Section 3.0.3.2.1

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.1.3 Conclusion

The staff concludes that the applicant has provided sufficient information to demonstrate that

the effects of aging for the RV, RV internals, and reactor coolant system components within the

scope of license renewal and subject to an AMR will be adequately managed so that the

intended function(s) will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21(a)(3).

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3.2 Aging Management of Engineered Safety Features

This section of the SER documents the staff's review of the applicant's AMR results for the

engineered safety features components and component groups of:

• Residual Heat Removal (RHR) System

* Reactor Core Isolation Cooling (RCIC) System

* Core Spray System

* High Pressure Coolant Injection (HPCI) System

• Containment and Suppression System

• Containment Atmosphere Control System

* Standby Gas Treatment System (SGTS)

3.2.1 Summary of Technical Information in the Application

LRA Section 3.2 provides AMR results for the engineered safety features components and

component groups. LRA Table 3.2.1, "Summary of Aging Management Programs for

Engineered Safety Features Evaluated in Chapter V of the GALL Report," is a summary

comparison of the applicant's AMRs with those evaluated in the GALL Report for the

engineered safety features components and component groups.

The applicant's AMRs evaluated and incorporated applicable plant-specific and industry OE in

the determination of AERMs. The plant-specific evaluation included condition reports and

discussions with appropriate site personnel to identify AERMs. The applicant's review of,

industry OE included a review of the GALL Report and OE issues identified since the issuance

of the GALL Report.

3.2.2 Staff Evaluation

The staff reviewed LRA Section 3.2 to determine whether the applicant provided sufficient

information to demonstrate that the effects of aging for the engineered safety features

components within the scope of license renewal and subject to an AMR, will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21(a)(3).

The staff conducted an onsite audit of AMRs to ensure the applicant's claim that certain AMRs

were consistent with the GALL Report. The staff did not repeat its review of the matters

described in the GALL Report; however, the staff did verify that the material presented in the

LRA was applicable and that the applicant identified the appropriate GALL Report AMRs. The

staff's evaluations of the AMPs are documented in SER Section 3.0.3. Details of the staff's

audit evaluation are documented in SER Section 3.2.2.1.

In the onsite audit, the staff also selected AMRs consistent with the GALL Report and for which

further evaluation is recommended. The staff confirmed that the applicant's further evaluations

were consistent with the SRP-LR Section 3.2.2.2 acceptance criteria. The staff's audit

evaluations are documented in SER Section 3.2.2.2.

The staff also conducted a technical review of the remaining AMRs not consistent with or not

addressed in the GALL Report. The technical review evaluated whether all plausible aging

3-255
effects have been identified and whether the aging effects listed were appropriate for the

material-environment combinations specified. The staffs evaluations are documented in SER

Section 3.2.2.3.

For SSCs which the applicant claimed were not applicable or required no aging management,

the staff reviewed the AMR line items and the plant's OE to verify the applicant's claims.

Table 3.2-1 summarizes the staff's evaluation of components, aging effects or mechanisms,

and AMPs listed in LRA Section 3.2 and addressed in the GALL Report.

Table 3.2-1 Staff Evaluation for Engineered Safety Features Components in the GALL

Report

Component Group Aging Effectl AMP in GALL." Further AMP in LRA, Staff Evaluation

(GALL Report Mechanism Report Evaluation Supplements,

Item No.) in% GALL or

Report Amendments.

Steel and stainless Cumulative TLAA, evaluated in Yes TLAA Consistent with

steel piping, piping fatigue damage accordance with GALL Report (See

components, and 10 CFR 54.21(c) SER Section

piping elements in 3.2.2.2.1)

emergency core

cooling system

(3.2.1-1)

Steel with stainless Loss of material A plant-specific Yes Not applicable Not applicable to'

steel cladding pump due to cladding aging management BWRs (See SER

casing exposed to breach program is to be Section 3.2.2.2.2)

treated borated evaluated.

water

(3.2.1-2) Reference NRC

Information

Notice 94-63,

"Boric Acid Corrosion

of Charging Pump.

Casings Caused by

_ Cladding Cracks"

Stainless steel Loss of material Water Chemistry and Yes Not applicable Not applicable. The

containment isolation due to pitting One-Time Inspection applicant addressed

piping and and crevice these components

components internal corrosion under GALL Report

surfaces exposed to Item number 3.2.1-5.

treated water

(3.2.1-3) (See SER Section

3.2.2.2.3.1)

Stainless steel Loss of material A plant-specific Yes Not applicable Not applicable to

piping, piping due to pitting aging management SSES (See SER

components, and and crevice program is to be Section 3.2.2.2.3.2)

piping elements corrosion evaluated.

exposed to soil

(3.2.1-4)

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ComponentGroup •AgiingEffect!.. AMP in GALL.'. Further. :AMPin:LRA, Staff Evaluation

.(GALL Reportt :Me'chnism': ."Report 'Evaluation- Supplements,

Item Nod.) in GALL or

_..____"" ' __-___ _____Report ."_. , Amendments

Stainless steel and Loss of material Water Chemistry and Yes BWR Water Consistent with

aluminum piping, due to pitting One-Time Inspection Chemistry GALL Report

piping components, and crevice Program (B.2.2)

and piping elements corrosion and Chemistry (See SER Section

exposed to treated Program 3.22.2.3.3)

water Effectiveness

(3.2.1-5) Inspection

(B.2.22)

Stainless steel and Loss of material Lubricating Oil Yes Lubricating Oil Consistent with

copper alloy piping, due to pitting Analysis and- Analysis GALL Report

piping components, and crevice One-Time Inspection Program

and piping elements corrosion (6.2.33) and (See SER Section

exposed to Lubricating Oil 3.2.2.2.3.4)

lubricating oil Inspection

(3.2.1-6) Program

-__(B.2.25)

Partially encased Loss of material A plant-specific Yes Not applicable Not applicable

stainless steel tanks due to pitting aging management

with breached and crevice program is to be (See SER Section

moisture barrier corrosion evaluated for pitting 3.2.2.2.3.5)

exposed to raw water and crevice

(3.2.1-7) corrosion of tank

bottoms because

moisture and water

can egress under the

tank due to cracking

of the perimeter seal

from weathering.

Stainless steel Loss of material A plant-specific Yes Not applicable See SER Section

piping, piping due to pitting aging management 3.2.2.2.3.6

components, piping and crevice program is to be

elements, and tank corrosion evaluated.

internal surfaces

exposed to

condensation

(internal)

(3.2.1-8)

Steel, stainless steel, Reduction of Lubricating Oil Yes Piping Corrosion Consistent with

and copper alloy heat transfer Analysis and Program GALL Report

heat exchanger due to fouling One-Time Inspection (B.2.13)

tubes exposed to (See SER Section

lubricating oil 3.2.2.2.4.1)

(3.2.1-9)

Stainless steel heat Reduction of Water Chemistry and Yes Heat Exchanger Consistent with

exchanger tubes heat transfer One-Time Inspection Inspection GALL Report

exposed to treated due to fouling (B.2.24)

water (See SER Section

(3.2.1-10) 3.2.2.2.4.2)

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PComponent Group Aging Effect/ "'AMP in GALL Further AMP in LRA,

(GALL Report Mechanism Report Evaluation Supplements,

Item No.) I in GALL or

-Rprt: Amedmenridrts.

Elastomer seals and

components in

standby gas

treatment system

exposed to air -

indoor uncontrolled

(3.2.1-11)

Hardening and

loss of strength

due to elastomer

degradation

A plant-specific

aging management

program is to be

evaluated.

Yes System

Walkdown

(8.2.32)

Consistent with

GALL Report

(See SER Section

3.2.2.2.5)

Stainless steel high- Loss of material A plant-specific Yes Not applicable Not applicable to

pressure safety due to erosion aging management BWRs (See SER

injection (charging) program is to be Section 3.2.2.2.6)

pump miniflow orifice evaluated for erosion

exposed to treated of the orifice due to

borated water extended use of the

(3.2.1-12) centrifugal HPSI

pump for normal

charging.

Steel drywell and Loss of material A plant-specific Yes Not applicable See SER Section

suppression due to general aging management 3.2.2.2.7

chamber spray corrosion and program is to be

system nozzle and fouling evaluated.

flow orifice internal

surfaces exposed to

air - indoor

uncontrolled

(internal)

(3.2.1-13)

Steel piping, piping Loss of material Water Chemistry and Yes BWR Water Consistent with

components, and due to general, One-Time Inspection Chemistry GALL Report

piping elements pitting, and Program (B.2.2)

exposed to treated crevice and Chemistry (See SER Section

water corrosion Program 3.2.2.2.8.1)

(3.2.1-14) Effectiveness

Inspection

(B.2.22)

Steel containment Loss of material Water Chemistry and Yes Not applicable Not applicable. The

isolation piping, due to general, One-Time Inspection applicant addressed

piping components, pitting, and these components

and piping elements crevice under GALL Report

internal surfaces corrosion Item number

exposed to treated 3.2.1-14.

water

(3.2.1-15) (See SER Section

3.2.2.2.8.2.)

Steel piping, piping Loss of material Lubricating Oil Yes Lubricating Oil Consistent with

components, and due to general, Analysis and Analysis GALL Report

piping elements pitting, and One-Time Inspection P~ogram

exposed to crevice (B.2.33) and (See SER Section

lubricating oil corrosion Lubricating Oil 3.2.2.2.8.3)

(3.2.1-16) Inspection

Program

(B.2.25)

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i'Component, ,Grou'p,: A:•i•.ging EffecitilW" .ý..'AMPJinWGALL .Further. AMPin LRA, Staff Evaluation

M(GALa.Report Mehaism, Report Evaluation Supp!ements,

Item No.) in GALL or

______________ Report Amendments

Steel (with orwithout Loss of material Buried Piping and No Not applicable Not applicable to

coating or wrapping) due to general, Tanks Surveillance SSES (3.2.2.2.9)

piping, piping pitting, crevice,

components, and and MIC or

piping elements

buried in soil Buried Piping and Yes

(3.2.1-17) Tanks Inspection

Stainless steel Cracking due to BWR Stress No BWR Water Consistent with

piping, piping SCC and IGSCC Corrosion Cracking Chemistry GALL Report

components, and and Water Chemistry Program (B.2.2)

piping elements and Chemistry (See SER Section

exposed to treated Program 3.2.2.1.4)

water > 60'C Effectiveness

(> 140F) Inspection

(3.2.1-18) (B.2.22)

Steel piping, piping Wall thinning Flow-Accelerated No Flow- Consistent with

components, and due to FAC Corrosion Accelerated GALL Report

piping elements Corrosion

exposed to steam or (B.2.11)

treated water

(3.2.1-19)

Cast austenitic Loss of fracture Thermal Aging No Not applicable Not applicable. (See

stainless steel toughness due Embrittlement of SER Section

piping, piping to thermal aging CASS 3.2.2.1.1)

components, and embrittlement

piping elements

exposed to treated

water (borated or

unborated) > 25013

(> 4829F)

(3.2.1-20)

High-strength steel Cracking due to Bolting Integrity No Bolting Integrity Consistent with

closure bolting cyclic loading, Program GALL Report

exposed to air with SCC (B.2.12)

steam or water

leakage

(3.2.1-21)

Steel closure bolting Loss of material Bolting Integrity No Bolting Integrity Consistent with

exposed to air with due to general Program GALL Report

steam or water corrosion (B.2.12)

leakage

(3.2.1-22)

Steel bolting and Loss of material Bolting Integrity No Bolting Integrity Consistent with

closure bolting due to general, Program GALL Report

exposed to air - pitting, and (B.2.12)

outdoor (external), or crevice

air - indoor corrosion

uncontrolled

(external)

(3.2.1-23)

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ComponentGrouP Aging Effect! AMP in GALL. Further AMP in LRA, Staff Evaluation

(GALL Report Mechanism Report Evaluation Supplements,

Item No.),: in GALL or

"_______"____...Report Amendments

Steel closure bolting Loss of preload Bolting Integrity No Not applicable Consistent with

exposed to air - due to thermal GALL Report (See

indoor uncontrolled effects, gasket SER Section

(external) creep, and self- 3.0.3.2.5)

(3.2.1-24) loosening

Stainless steel Cracking due to Closed-Cycle No Not applicable Not applicable to

piping, piping SCC Cooling Water SSES (See SER

components, and System Section 3.2.2.1.1)

piping elements

exposed to closed

cycle cooling water

> 60C (> 1400F)

(3.2.1-25)

Steel piping, piping Loss of material Closed-Cycle No Not applicable Not applicable to

components, and due to general, Cooling Water SSES (See SER

piping elements pitting, and System Section 3.2.2.1.1)

exposed to closed crevice

cycle cooling water corrosion

(3.2.1-26)

Steel heat exchanger Loss of material Closed-Cycle No BWR Water Consistent with

components due to general, Cooling Water Chemistry GALL Report

exposed to closed pitting, crevice, System Program (B.2.2)

cycle cooling water and galvanic and Chemistry (See SER Section

(3.2.1-27) corrosion Program 3.2.2.1.5.)

Effectiveness

Inspection

(B.2.22)

Stainless steel Loss of material Closed-Cycle No BWR Water Consistent with

piping, piping due to pitting Cooling Water Chemistry GALL Report

components, piping and crevice System Program (B.2.2)

elements, and heat corrosion and Chemistry (See SER Section

exchanger Program 3.2.2.1.5.)

components Effectiveness

exposed to closed- Inspection

cycle cooling water (B.2.22)

(3.2.1-28)

Copper alloy piping, Loss of material Closed-Cycle No BWR Water Consistent with

piping components, due to pitting, Cooling Water Chemistry GALL Report

piping elements, and crevice, and System Program (B.2.2)

heat exchanger galvanic and Chemistry (See SER Section

components corrosion Program 3.2.2.1.5.)

exposed to closed Effectiveness

cycle cooling water Inspection

(3.2.1-29) (B.2.22)

Stainless steel and Reduction of Closed-Cycle No Piping Corrosion Consistent with

copper alloy heat heat transfer Cooling Water (B.2.13), and GALL Report

exchanger tubes due to fouling System Heat Exchanger

exposed to closed Inspection (See SER Section

cycle cooling water (B.2.24) 3.2.2.1.2)

(3.2.1-30)

3-260
Component.Group Aging Effect! AMP in GALL Further. AMP in LRA, Staff Evaluation

(GALL Report. Mechanism Report Evaluation Supplements,,

Item No'.)~ :in GALL o or".

_________Report, Amendments

External surfaces of Loss of material External Surfaces No System Consistent with

steel components due to general Monitoring Walkdown GALL Report

including ducting, corrosion (B.2.32), and

piping, ducting Supplementary (See SER Section

closure bolting, and Piping/Tank 3.2.2.1.3)

containment isolation Inspection

piping external (B.2.28)

surfaces exposed to

air - indoor

uncontrolled

(external);

condensation

(external) and air -

outdoor (external)

(3.2.1-31)

Steel piping and Loss of material Inspection of Internal No Preventive Consistent with

ducting components due to general Surfaces in Maintenance GALL Report

and internal surfaces corrosion Miscellaneous Piping Activities -

exposed to air - and Ducting HPCI/RCIC (See SER Section

indoor uncontrolled Components Turbine Casings 3.2.2.1.3)

(Internal) (B.2.48),

(3.2.1-32) System

Walkdown

(B.2.32), and

Supplementary

Piping/Tank

Inspection

(B.2.28)

Steel encapsu!ation Loss of material. Inspection of Internal No Not applicable Not applicable to

components due to general; Surfaces in SSES (See SER

exposed to air - pitting, and Miscellaneous Piping Section 3.2.2.1.1)

indoor uncontrolled crevice and Ducting

(internal) corrosion Components

(3.2.1-33)

Steel piping, piping Loss of material Inspection of Internal No Not applicable Addressed under

components, and due to general, Surfaces in 3.2.1-32 (See SER

piping elements pitting, and Miscellaneous Piping Section 3.2.2.1.1)

exposed to crevice and Ducting

condensation corrosion Components

(internal)

(3.2.1-34)

Steel containment Loss of material Open-Cycle Cooling No Not applicable Not applicable to

isolation piping and due to general, Water System SSES (See SER

components internal pitting, crevice, Section 3.2.2.1.1)

surfaces exposed to and MIC, and

raw water fouling

(3.2.1-35)

Steel heat exchanger Loss of material Open-Cycle Cooling No Piping Corrosion Consistent with

components due to general, Water System Program GALL Report

exposed to raw water pitting, crevice, (B.2.13)

(3.2.1-36) galvanic, and

MIC, and fouling

3-261
Component Group, Aging Effect/ AMP in GALL- Further AMP in LRA, Staff Evaluation

(GALL Report Mechanism Report Evaluation Supplements, Item-No.) inGALL or

Report Amendments

Stainless steel Loss of material Open-Cycle Cooling No Not applicable Not applicable to

piping, piping due to pitting, Water System SSES (See SER

components, and crevice, and MIC Section 3.2.2.1.1)

piping elements

exposed to raw water

(3.2.1-37)

Stainless steel Loss of material Open-Cycle Cooling No Not applicable Not applicable to

containment isolation due to pitting, Water System SSES (See SER

piping and crevice, and Section 3.2.2.1.1)

components internal MIC, and fouling

surfaces exposed to

raw water

(3.2.1-38)

Stainless steel heat Loss of material Open-Cycle Cooling No Piping Corrosion Consistent with

exchanger due to pitting, Water System Program GALL Report

components crevice, and (B.2.13)

exposed to raw water MIC, and fouling

(3.2.1-39)

Steel and stainless Reduction of Open-Cycle Cooling No Piping Corrosion Consistent with

steel heat exchanger heat transfer Water System Program GALL Report

tubes (serviced by due to fouling (8.2.13)

open-cycle cooling

water) exposed to

raw water

(3.2.1-40)

Copper alloy Loss of material Selective Leaching No Selective Consistent with

> 15% Zn piping, dueto selective of Materials Leaching GALL Report

piping components, leaching Inspection

piping elements, and Program

heat exchanger (B.2.29)

components

exposed to closed

cycle cooling water

(3.2.1-41)

Gray cast iron piping, Loss of material Selective Leaching No Selective Consistent with

piping components, due to selective of Materials Leaching GALL Report

piping elements leaching Inspection

exposed to closed- Program

cycle cooling water (B.2.29)

(3.2.1-42)

Gray cast iron piping, Loss of material Selective Leaching No Not applicable Not applicable to

piping components, due to selective of Materials SSES (See SER

and piping elements leaching Section 3.2.2.1.1)

exposed to soil

(3.2.1-43)

Gray cast iron motor Loss of material Selective Leaching No Not applicable Not applicable to

cooler exposed to due to selective of Materials SSES (See SER

treated water leaching Section 3.2.2.1.1)

(3.2.1-44)

3-262
Component Group AAging Effect/ AMP in GALL Further 'AMP in LRA, Staff Evaluation

(GALL Report. Mechanism, Report Evaluation Supplements,

ItemN in GALL or

Report.. Amendments

Aluminum, copper Loss of material Boric Acid Corrosion No Not applicable Not applicable to

alloy > 15% Zn, and due to Boric acid BWRs

steel external corrosion

surfaces, bolting,

and piping, piping

components, and

piping elements

exposed to air with

borated water

leakage

(3.2.1-45)

Steel encapsulation Loss of material Inspection of Internal No Not applicable Not applicable to

components due to general, Surfaces in BWRs

exposed to air with pitting, crevice Miscellaneous Piping

borated water and boric acid and Ducting

leakage (internal) corrosion Components

(3.2.1-46)

Cast austenitic Loss of fracture Thermal Aging No Not applicable Not applicable to

stainless steel toughness due Embrittlement of BWRs

piping, piping to thermal aging CASS

components, and embrittlement

piping elements

exposed to treated

borated water

> 250AC (> 4829F)

(3.2.1-47)

Stainless steel or Cracking due to Water Chemistry No Not applicable Not applicable to

stainless-steel-clad SCC BWRs

steel piping, piping

components, piping.

elements, and tanks

(including safety

injection

tanks/accumulators)

exposed to treated

borated water > 60C3

(> 140'F)

(3.2.1-48)

Stainless steel Loss of material Water Chemistry No Not applicable Not applicable to

piping, piping due to pitting BWRs

components, piping and crevice

elements, and tanks corrosion

exposed to treated

borated water

(3.2.1-49)

Aluminum piping, None None No None Consistent with

piping components, GALL Report

and piping elements

exposed to air -

indoor uncontrolled

(internal/external)

(3.2.1-50)

3-263
Component: Group Aging Effect! AMP in GALL Further AMP in LRA, Staff Evaluation,

(GALL Report Mechanism Report Evaluation Supplements,

Item No.) in GALL., or

________________ eport.: .Amendments,,

Galvanized steel None None No None Consistent with

ducting exposed to GALL Report

air - indoor controlled

(external)

(3.2.1-51)

Glass piping None None No None Consistent with

elements exposed to GALL Report

air - indoor

uncontrolled

(external), lubricating

oil, raw water,

treated water, or

treated borated

water

(3.2.1-52)

Stainless steel, None None No None Consistent with

copper alloy, and GALL Report

nickel alloy piping,

piping components,

and piping elements

exposed to air -

indoor uncontrolled

(external)

(3.2.1-53)

Steel piping, piping None None No Not applicable Not applicable to

components, and SSES (See SER

piping elements Section 3.2.2.1.1)

exposed to air -

indoor controlled

(external)

(3.2.1-54)

Steel and stainless None None No Not applicable Not applicable to

steel piping, piping SSES (See SER

components, and Section 3.2.2.1.1)

piping elements in

concrete

(3.2.1-55)

Steel, stainless steel, None None No Not applicable Not applicable to

and copper alloy SSES (See SER

piping, piping Section 3.2.2.1.1)

components, and

piping elements

exposed to gas

(3.2.1-56)

3-264
Component Group Aging Effect/ AMP in GALL Further AMP in LRA, Staff Evaluation

(GALL Report Mechanism Report Evaluation Supplements,

Item No.) in GALL or

Report Amendments

Stainless steel and None None No Not applicable Not applicable to

copper alloy BWRs

< 15% Zn piping,

piping components,

and piping elements

exposed to air with

borated water

leakage

(3.2.1-57)

The staff's review of the engineered safety features component groups followed any one of

several approaches. One approach, documented in SER Section 3.2.2.1, reviewed AMR results

for components that the applicant indicated are consistent with the GALL Report and require no

further evaluation. Another approach, documented in SER Section 3.2.2.2, reviewed AMR

results for components that the applicant indicated are consistent with the GALL Report and for

which further evaluation is recommended. A third approach, documented in SER

Section 3.2.2.3, reviewed AMR results for components that the applicant indicated are not

consistent with, or not addressed in, the GALL Report. The staff's review of AMPs credited to

manage or monitor aging effects of the engineered safety features components is documented

in SER Section 3.0.3.

3.2.2.1 AMR Results Consistent with the GALL Report

LRA Section 3.2.2.1 identifies the materials, environments, AERMs, and the following programs

that manage aging effects for the engineered safety features components:

* BWR Water Chemistry Program

* Flow-Accelerated Corrosion (FAC) Program

* Bolting Integrity Program

" Piping Corrosion Program

" Fire Water System Program

* Chemistry Program Effectiveness Inspection

* Heat Exchanger Inspection

* Lubricating Oil Inspection

* Supplemental Piping/Tank Inspection

* Selective Leaching Inspection

* System Walkdown Program

* Lubricating Oil Analysis Program

* Preventive Maintenance Activities - RCIC/HPCI Turbine Casings

LRA Tables 3.2.2-1 through 3.2.2-7 summarize AMRs for the engineered safety features

components and indicate AMRs claimed to be consistent with the GALL Report.

For component groups evaluated in the GALL Report for which the applicant claimed

consistency with the report and for which it does not recommend further evaluation, the staff's

audit and review determined whether the plant-specific components of these GALL Report

component groups were bounded by the GALL Report evaluation.

3-265
The applicant noted for each AMR line item how the information in the tables aligns with the

information in the GALL Report. The staff audited those AMRs with notes A through E

indicating how the AMR is consistent with the GALL Report.

Note A indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP is consistent with the GALL

Report AMP. The staff audited these line items to verify consistency with the GALL Report and

validity of the AMR for the site-specific conditions.

Note B indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP takes some exceptions to the

GALL Report AMP. The staff audited these line items to verify consistency with the GALL

Report and verified that the identified exceptions to the GALL Report AMPs have been

reviewed and accepted. The staff also determined whether the applicant's AMP was consistent

with the GALL Report AMP and whether the AMR was valid for the site-specific conditions.

Note C indicates that the component for the AMR line item, although different from, is

consistent with the GALL Report for material, environment, and aging effect. In addition, the

AMP is consistent with the GALL Report AMP. This note indicates that the applicant was unable

to find a listing of some system components in the GALL Report; however, the applicant

identified in the GALL Report a different component with the same material, environment, aging

effect, and AMP as the component under review. The staff audited these line items to verify

consistency with the GALL Report. The staff also determined whether the AMR line item of the

different component was applicable to the component under review and whether the AMR was

valid for the site-specific conditions.

Note D indicates that the component for the AMR line item, although different from, is

consistent with the GALL Report for material, environment, and aging effect. In addition, the

AMP takes some exceptions to the GALL Report AMP. The staff audited these line items to

verify consistency with the GALL Report. The staff verified whether the AMR line item of the

different component was applicable to the component under review and whether the identified

exceptions to the GALL Report AMPs have been reviewed and accepted. The staff also

determined whether the applicant's AMP was consistent with the GALL Report AMP and

whether the AMR was valid for the site-specific conditions.

Note E indicates that the AMR line item is consistent with the GALL Report for material,

environment, and aging effect, but credits a different AMP. The staff audited these line items to

verify consistency with the GALL Report. The staff also determined whether the credited

AMP would manage the aging effect consistently with the GALL Report AMP and whether the

AMR was valid for the site-specific conditions.

The staff audited and reviewed the information in the LRA. The staff did not repeat its review of

the matters described in the GALL Report; however, the staff did verify that the material

presented in the LRA was applicable and that the applicant identified the appropriate GALL

Report AMRs.

The staff reviewed the LRA to confirm that the applicant: (a) provided a brief description of the

system, components, materials, and environments; (b) stated that the applicable aging effects

were reviewed and evaluated in the GALL Report; and (c) identified those aging effects for the

engineered safety features ESF components that are subject to an AMR. On the basis of its

audit and review, the staff determines that, for AMRs not requiring further evaluation, as

3-266
identified in LRA Table 3.2.1, the applicant's references to the GALL Report are acceptable and

no further staff review is required, with the exception of the following AMRs that the applicant

had identified were consistent with the AMRs of the GALL Report and for which the staff felt

were in need of additional clarification and assessment. The staff's evaluations of these AMRs

are provided in the subsections that follow.

3.2.2.1.1 AMR Results Identified as Not Applicable

In LRA Table 3.2.1, item 20, the applicant indicates that the corresponding AMR result line in

the GALL Report is not applicable because there are no CASS components in the ESF systems

for SSES that are exposed to treated water > 250 0C (>4820F). The staff reviewed the

documentation supporting the applicant's AMR evaluation and confirmed the applicant's claim

that SSES do not have ESF CASS components in the environment stated above. Therefore,

the staff finds the corresponding AMR result line in the GALL Report is not applicable to SSES.

In LRA Table 3.2.1, item 22, the applicant states that the corresponding AMR result line are

addressed under item 3.2.1-23. The staff reviewed the documentation supporting the

applicant's AMR evaluation in items 3.1.1-23, and no SSES AMR line items roll up to 3.1.1-22.

Therefore, the staff agrees with the applicant's determination that the corresponding AMR result

line in the GALL Report is not applicable to SSES.

In LRA Table 3.2.1, item 25, the applicant states that the corresponding AMR result line in the

GALL Report is not applicable because there are no stainless steel piping and piping

components in the ESF systems for SSES that are exposed to closed-cycle cooling water >

600C (>1400 F). The staff reviewed the documentation supporting the applicant's AMR

evaluation and confirmed the applicant's claim that SSES does not have this commodity group

in the ESF System. Therefore, the staff finds the corresponding AMR result line in the GALL

Report is not applicable to SSES.

In LRA Table 3.2.1, item 26, the applicant states that the corresponding AMR result line in the

GALL Report is not applicable because there are no steel piping and piping components in the

ESF systems for SSES that are exposed to closed-cycle cooling water. The staff reviewed the

documentation supporting the applicant's AMR evaluation and confirmed the applicant's claim

that this line item is not applicable to SSES. Therefore, the staff agrees with the applicant's

determination that the corresponding AMR result line in the GALL Report is not applicable to

SSES.

In LRA Table 3.2.1, item 33, the applicant states that the corresponding AMR result line in the

GALL Report is not applicable because the ESF systems include no steel encapsulation

components. The staff reviewed the documentation supporting the applicant's AMR evaluation

and confirmed the applicant's claim. Therefore, the staff agrees with the applicant's

determination that the corresponding AMR result line in the GALL Report is not applicable to

SSES.

In LRA Table 3.2.1, item 34, the applicant states that the corresponding AMR result line are

addressed under item 3.2.1-32. The staff reviewed the documentation supporting the

applicant's AMR evaluation in items 3.1.1-32, and no SSES AMR line items roll up to 3.1.1-34.

Therefore, the staff agrees with the applicant's determination that the corresponding AMR result

line in the GALL Report is not applicable to SSES.

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In LRA Table 3.2.1, item 35, the applicant indicates for that the corresponding AMR result line,

there are no steel containment isolation piping or components exposed to raw water in the ESF

systems for SSES. In addition, the applicant indicated that this item is applied to loop seal

valves exposed to raw water in the SGTS. The staff reviewed the documentation supporting

the applicant's AMR evaluation and confirmed the applicant's claim that SSES has no steel

containment isolation piping or components exposed to raw water in the ESF System. In

addition, the staff reviewed the Table 2 items which correspond to loop seal valves exposed to

raw water in the SGTS, and finds the applicant's management of these line item components

consistent with the GALL Report. Therefore, the staff agrees with the applicant's treatment of

line item 3.2.1-35.

In LRA Table 3.2.1, items 37 and 38, the applicant states that the corresponding AMR result

line in the GALL Report is not applicable because there are no stainless steel piping, piping

components, or piping elements exposed to raw water in the ESF Systems, and no stainless

steel containment isolation piping or components exposed to raw water in the ESF Systems

respectively. The staff reviewed the documentation supporting the applicant's AMR evaluation

and confirmed the applicant's claim that SSES has no in-scope stainless steel piping, piping

components, piping elements, containment isolation piping or components in the ESF Systems.

Therefore, the staff agrees with the applicant's determination that the corresponding AMR result

lines in the GALL Report is not applicable to SS ES.

In LRA Table 3.2.1, item 43, the applicant indicates for this corresponding AMR result line in the

GALL Report, there are no gray cast iron piping, piping components, or piping elements

exposed to soil in the ESF systems. The staff reviewed the documentation supporting the

applicant's AMR evaluation and confirmed the applicant's claim that no SSES components in

the ESF systems align to this item. Therefore, the staff agrees with the applicant's

determination that the corresponding AMR result line in the GALL Report, and finds this line

item as not applicable to SSES.

In LRA Table 3.2.1, item 44, the applicant states that the corresponding AMR result line in the

GALL Report is not applicable because there are no gray cast iron motor coolers exposed to

treated water in the ESF systems. The staff reviewed the documentation supporting the

applicant's AMR evaluation and confirmed the applicant's claim that SSES has no in-scope gray

cast iron motor coolers exposed to treat water in the ESF Systems. Therefore, the staff agrees

with the applicant's determination that the corresponding AMR result line in the GALL Report is

not applicable to SSES.

In LRA Table 3.2.1, item 54, the applicant states that the corresponding AMR result line in the

GALL Report is not applicable because there are no steel components exposed to indoor air

(controlled) environments in ESF systems. The staff reviewed the documentation supporting

the applicant's AMR evaluation and confirmed that no components under this commodity group

exist in the ESF. Therefore, the staff agrees with the applicant's determination that the

corresponding AMR result line in the GALL Report is not applicable to SSES.

In LRA Table 3.2.1, item 55, the applicant states that the corresponding AMR result line in the

GALL Report is not applicable because there are no steel or stainless steel components

embedded in concrete in the ESF Systems. The staff reviewed the documentation supporting

the applicant's AMR evaluation and confirmed the applicant's claim. Therefore, the staff agrees

with the applicant's determination that the corresponding AMR result line in the GALL Report is

not applicable to SSES.

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In LRA Table 3.2.1, item 56 the applicant states that the corresponding AMR result line in the

GALL Report is not applicable because there are no steel, stainless steel, or cooper alloy

components in the ESF systems for SSES that are exposed to gas. The staff reviewed the

documentation supporting the applicant's AMR evaluation and confirmed the applicant's claim

that SSES has no in-scope steel, stainless steel, or cooper alloy components in the ESF that

are exposed to gas. Therefore, the staff agrees with the applicant's determination that the

corresponding AMR result line in the GALL Report is not applicable to SSES.

3.2.2.1.2 Reduction of Heat Transfer due to Fouling

In LRA Table 3.2.2.-1, the applicant stated that reduction of heat transfer of RHR heat

exchanger copper alloy tubes in an external environment of treated water is managed by the

Piping Corrosion Program.

The staff noted that the applicant applied Note E to this item. The applicant referenced Table

3.2-1, item 3.2.1-30 and GALL Report Volume 2, item V.A-1 1. The staff reviewed the AMR

results lines that reference Note E and determines that the component type, material,

environment, and aging effect are consistent with the GALL Report. However, the staff noted

that where the GALL Report recommends AMP XI.M21, "Closed-Cycle Cooling Water System,"

the applicant proposed using the Piping Corrosion Program. The staff also noted that the

internal environment of the tubes is raw water and the heat exchanger is part of the GL 89-13

Program.

The GALL recommended AMP XI.M21, Closed-Cycle Cooling Water System, recommends

preventive measures to minimize corrosion and testing and inspection to monitor the effects of

corrosion. The staff reviewed the Piping Corrosion Program, which includes preventive

measures such as chemical treatment and cleaning, and testing and inspection on a periodic

basis as per the commitments in response to NRC GL 89-13. Based on this review, the staff

finds that the Piping Corrosion program will adequately manage the aging effect of reduction of

heat transfer of copper alloy heat exchanger tubes in an external environment of treated water

for the period of extended operation.

In LRA Tables 3.2.2.-2 and 3.2.2-4, the applicant states that reduction of heat transfer of RCIC

and HPCI heat exchanger copper alloy tubes in an internal environment of treated water is

managed by the Heat Exchanger Inspection Program.

The staff noted that the applicant applied Note E to this item. The applicant referenced Table

3.2-1, item 3.2.1-30 and GALL Report Volume 2, item V.A-11. The staff reviewed the AMR

results lines that reference Note E and determines that the component type, material,

environment, and aging effect are consistent with the GALL Report. However, the staff noted

that where the GALL Report recommends AMP XI.M21, "Closed-Cycle Cooling Water System,"

the applicant proposed using the Heat Exchanger Inspection Program.

The GALL recommended AMP XI.M21, Closed-Cycle Cooling Water System, recommends

preventive measures to minimize corrosion and testing and inspection to monitor the effects of

corrosion, whereas the applicant is proposing only a one-time inspection activity. The staff

issued RAI 3.2.2.1-1 dated July 23, 2008, requesting the applicant to justify how the one-time

heat exchanger inspection activity by itself will manage the aging effect of reduction in heat

transfer, without preventive measures to minimize corrosion, such as maintaining treated water

chemistry control.

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In its response to RAI 3.2.2.1-1 dated August 22, 2008, the applicant stated that as indicated in

Tables 3.2.2-2 and 3.2.2-4, the BWR Water Chemistry Program is credited for managing loss

of material for copper alloy heat exchanger tubes exposed to treated water. The applicant also

stated that since the BWR Water Chemistry Program does not contain measures for detection

of aging effects through inspection, it is not credited for managing reduction in heat transfer;

however, it is recognized that the same preventive actions by which the water chemistry

program manages loss of material also mitigates the conditions that could result in reduction in

heat transfer. The applicant further stated that due to the BWR water chemistry control, fouling

of heat exchanger tubes is not expected to occur. Therefore, the applicant concluded that as

stated in LRA Section B.2.24, the Heat Exchanger Inspection will provide direct evidence as to

whether, and to what extent, reduction in heat transfer has occurred, or is likely to occur, that

could result in a loss of intended function.

The staff noted that in LRA Tables 3.2.2-2 and 3.2.2-4, the BWR Water-Chemistry Program is

credited for managing loss of material of RCIC turbine oil coolers and HPCI lube oil coolers. For

these same coolers, the applicant has credited Heat Exchanger Inspection Program for

reduction of heat transfer. On the basis that water chemistry is maintained to minimize

corrosion and fouling, the staff finds the use of Heat Exchanger Inspection Program acceptable

for managing the aging effects of reduction of heat transfer for copper alloy heat exchanger

tubes exposed to treated water and finds the applicant response acceptable. The evaluation of

the Heat Exchanger Program is documented in SER Section 3.0.3.1.12.

3.2.2.1.3 Loss of material due to general corrosion

In LRA Table 3.2.1, Item 3.2.1-32, addresses loss of material due to general corrosion for steel

piping and ducting components and internal surfaces exposed to air (indoor uncontrolled

[internal]) in the Standby Gas Treatment System. The GALL Report recommends GALL AMP

XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components" to

manage this aging effect. The AMR line items in LRA Table 2 that reference this line item in

GALL Report Table 1 cite Generic Note E, indicating that the AMR line items are consistent with

GALL Report material, environment, and aging effect, but a different aging management

program is credited. The staff reviewed the AMR results lines that reference Note E and

determines that the material, environment, and aging effect are consistent with the GALL

Report.

The staff reviewed the applicant's AMP B.2.32 "System Walkdown Program" and its evaluation

is documented in SER Sections 3.0.3.2.14. The staff determined that this aging management

program which include surveillance activities and observations that are adequate to manage

loss of material due to general corrosion for steel components exposed to ventilation (internal)

addressed by this AMR are consistent with those activities recommend by GALL AMP XI.M38,

"Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components." However

the applicant is crediting the AMP B.2.32, which performs visual inspections of the external

surfaces only, for the internal surfaces of fan and filter housings, piping, valve bodies, plenums,

and SGTS filter unit enclosures. The staff felt that additional information was needed and

therefore, by letter dated July 23, 2008, the staff issued RAI 3.x.2.1-1 requesting the applicant

to justify the basis for crediting AMP B.2.32, which performs visual inspections of external

surfaces only, for the internal surfaces of steel ventilation system enclosures and for piping

components in ventilation environments.

In its response to RAI 3.x.2.1-1 dated August 22, 2008, the applicant stated that the internal

ventilation environment of that these components are exposed to is the same as the

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environment the external surfaces are exposed to because this system is normally in a standby

mode in which the relevant temperature and humidity is the same on the external and internal

surface. The staff noted that crediting an external visual inspection for managing aging of the

internal surface if the environments are the same is consistent with the recommendations given

in the program element, "scope of program", of GALL AMP XI.M36 "External Surfaces

Monitoring", in which a visual inspection of the external surfaces may be representative of the

internal surfaces if the environment is the same for the external and internal surfaces. The staff

noted that internal surfaces of the SGTSfilter unit enclosure and piping may experience a

different environment at the air/water interface of the mist eliminator loop seal, so the applicant

is supplementing the AMP B.2.32 "System Walkdown Program" with the AMP B.2.28

"Supplemental Piping/Tank Inspection" and the staff confirmed that the AMP B.2.28 will provide

verification if degradation has occurred on the internal surfaces of these components and the

effectiveness of the AMP B.2.32 "System Walkdown Program" for managing loss of material.

On the basis of its review, the staff finds the applicable portion of the applicant's response that

references GALL Item V.B-1 to be acceptable because (1) the environments of the external

surface and internal surface is the same and consistent with the recommendations provided in

GALL that an visual inspection of the external surface can be credited for managing aging of

the internal surfaces if the environments are the same and (2) the applicant has credited a onetime inspection to verify if degradation has occurred and the effectiveness of the Systems

Walkdown Program when the environment of the external surface may be different than the

environment of the internal surface. On this basis, the staff finds the AMR results for this line

item acceptable.

In LRA Tables 3.2.2-1 and 3.2.2-2, the applicant states that loss of material of RHR and RCIC

steel piping in an internal environment of ventilation and external environment of indoor air is

managed by the Supplementary Piping/Tank Inspection Program.

The staff noted that the applicant applied Note E to this item. The applicant referenced Table

3.2-1, items 3.2.1-31 and 3.2.1-32 and GALL Report Volume 2, items VD2-16 and VD2-2. The

staff reviewed the AMR results lines that reference Note E and determines that the component

type, material, environment, and aging effect are consistent with the GALL Report. However,

the staff noted that where the GALL Report recommends AMP XI.M39, "Inspection of Internal

Surfaces in Miscellaneous Piping and Ducting Components," and AMP XI.M36, "External

Surface Monitoring", the applicant proposed using the Supplementary Piping/Tank Inspection

Program.

The LRA also references footnote 0203, which states that the environment is an aggressive

air/water interface in the suppression pool. The staff determined that in this environment, loss of

material is due to general, crevice and pitting corrosion. The Supplementary Piping/Tank

Inspection Program uses a combination of volumetric and visual examination techniques to

identify evidence of loss of material or lack thereof. The staff's evaluation of the Supplementary

Piping/Tank Inspection Program is documented in SER Section 3.0.3.1.16. Because the

Supplementary Piping/Tank Inspection is performed at very specific locations of air/water

interface, and employs more conservative inspection techniques than the visual inspection of

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components and the

External Surfaces Monitoring Program, the staff finds that the Supplementary Piping/Tank

Inspection Program will adequately manage the aging effects of loss of material in this

aggressive environment.

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In Table 3.2.2-5, the LRA states that loss of material of containment and suppression system

steel downcomers in an external environment of indoor air is managed by the Supplementary

Piping/Tank Inspection Program.

The staff noted that the applicant applied Note E to this item. The applicant referenced

Table 3.2-1, item 3.2.1-31 and GALL Report Volume 2, item VB-3. The staff reviewed the AMR

results lines that reference Note E and determines that the component type, material,

environment, and aging effect are consistent with the GALL Report. However, the staff noted

that where the GALL Report recommends AMP AMP XI.M36, "External Surface Monitoring", the

applicant proposed using the Supplementary Piping/Tank Inspection Program.

The LRA also references footnote 0212, which states that the environment is an aggressive

air/water interface in the suppression pool. The staff determined that in this environment, loss of

material is due to general, crevice and pitting corrosion. The Supplementary Piping/Tank

Inspection Program uses a combination of volumetric and visual examination techniques to

identify evidence of loss of material or lack thereof. The staff's evaluation of the Supplementary

Piping/Tank Inspection Program is documented in SER Section 3.0.3.1.16. Because the

Supplementary Piping/Tank Inspection is performed at very specific locations, and employs

more conservative inspection techniques than the visual inspection of External Surfaces

Monitoring Program, the staff finds that the Supplementary Piping/Tank Inspection Program will

adequately manage the aging effects of loss of material in this aggressive environment.

In Table 3.2.2-7, the LRA states that loss of material of SGTSsteel filter unit enclosure and

skimmer surge tanks in an internal environment of ventilation is managed by the Supplementary

Piping/Tank Inspection Program.

The staff noted that the applicant applied Note E to this item. The applicant referenced Table

3.2-1, item 3.2.1-32 and GALL Report Volume 2, item V.B-1. The staff reviewed the AMR

results lines that reference Note E and determines that the component type, material,

environment, and aging effect are consistent with the GALL Report. However, the staff noted

that where the GALL Report recommends AMP XI.M39, "Inspection of Internal Surfaces in

Miscellaneous Piping and Ducting Components," the applicant proposed using the

Supplementary Piping/Tank Inspection Program.

The LRA also references footnote 0215, which states that the environment is an aggressive

air/water interface in the suppression pool. The staff determined that in this environment, loss of

material is due to crevice and/or pitting corrosion and MIC (at the airwater interface in the mist

eliminator loop seals), and galvanic corrosion (at contact points with the mist eliminator

housing. The Supplementary Piping/Tank Inspection Program uses a combination of volumetric

and visual examination techniques to identify evidence of loss of material or lack thereof. The

staff's evaluation of the Supplementary Piping/Tank Inspection Program is documented in SER

Section 3.0.3.1.16. Because the Supplementary Piping/Tank Inspection is performed at very

specific locations, and employs more conservative inspection techniques than the visual

inspection of Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components

Program, the staff finds that the Supplementary Piping/Tank Inspection Program will adequately

manage the aging effects of loss of material in this aggressive environment.

LRA Table 3.3.1, line items 3.2.1-32 addresses the results of an AMR for Steel piping and

ducting components exposed internal air - indoor uncontrolled. The applicant addresses cast

iron and carbon steel piping, pump casings, rupture disks and valve bodies in the Reactor Core

Isolation Cooling System and High Pressure Coolant Injection System. The applicant states

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that the aging effect requiring management is loss of material and proposes to use the

Preventive Maintenance Activities - RCIC/HPCI Turbine Casings to manage the effects of

aging.

The applicant has indicated generic Note E for this line item which is consistent with the GALL

report for material, environment, and aging effect, but a different aging management program.

The staff noted that the GALL Report recommends GALL AMP XI.M38, "Inspection of Internal

Surfaces in Miscellaneous Piping and Ducting Components" for GALL AMR Item V.D2-16. The

staff noted that the GALL AMP XI.M38 recommends periodic visual inspections during

maintenance and surveillance activities to detect age-related degradation, such as loss of

material due to general corrosion.

The staff's evaluation of the AMP B.2.48 is documented in SER Section 3.0.3.3.3. The staff

noted that this program is a plant-specific program that performs a periodic visual inspection of

the carbon steel and cast iron internal surfaces of the RCIC and HPCI pump turbine casings

(and gland cases) and the in-scope piping and piping components in steam lines downstream

from the steam admission valves, by qualified personnel. The staff noted that the visual

inspections being performed will detect rust, discoloration and other signs of degradation that

may be indicative of wall-thinning and loss of material. The staff further noted that if

unacceptable visual indications of wall-thinning or loss of material the applicant will initiate

appropriate corrective actions. The staff determined that a visual inspection will be capable of

detecting loss of material, which is consistent with the inspection techniques recommended by

GALL AMP XI.M38. On the basis that the applicant will be performing periodic visual

inspections on the components within the scope of this program and will initiate appropriate

corrective actions if unacceptable loss of material or wall-thinning has occurred, the staff finds

the AMR results for this line item acceptable.

3.2.2.1.4 Cracking due to Stress Corrosion Cracking (SCC) and Intergranular Stress Corrosion

Cracking (IGSCC)

LRA Tables 3.2.2-2 and 3.2.2-4 address stainless steel tubing in an environment of treated

water greater than 60 0C (>1400 F) in the reactor core isolation cooling (RCIC) system and in the

HPCI system. The applicant specified the BWR Water Chemistry Program, alone, to manage

the aging effect of cracking due to SCC or IGSCC. For these AMR result lines, the applicant

referred to LRA Table 3.2.1, item 3.2.1-18, and cited generic note A, indicating that the results

are consistent with the GALL Report. The applicant also included a plant-specific note stating

that these results apply only to stainless steel tubing in the steam supply to RCIC and HPCI

pump turbines up to the steam admission valves that are maintained at temperature >140 IF.

The staff noted that for the corresponding line in SRP-LR Table 3.2-1 and in GALL Report,

Volume 1, Table 2, the recommended AMPs are the BWR Stress Corrosion Cracking program

and the Water Chemistry program. The staff also noted that the BWR Stress Corrosion

Cracking program applies only to stainless steel piping components that are greater than 4 inch

nominal pipe size; and therefore, it is not applicable for stainless steel tubing. Because the

applicant did not recommend an inspection activity to confirm effectiveness of the BWR Water

Chemistry program in mitigating cracking in the stainless steel tubing exposed to treated water,

the staff issued RAI 3.2-1, in a letter dated July 15, 2008, asking the applicant to provide a

technical justification that confirmation of BWR Water Chemistry Program effectiveness is not

needed for these components, and to justify the use of generic note A for these AMR results.

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In its response to RAI 3.2-1 dated August 15, 2008, the applicant provided the following

response:

For the AMR results listed in LRA Tables 3.2.2-2 and 3.2.2-4 for stainless steel

tubing in a treated water environment and with an aging effect of cracking,

verification of the effectiveness of the BWR Water Chemistry Program is

needed. The Chemistry Program Effectiveness Inspection provides confirmation

of the effectiveness of the BWR Water Chemistry Program in managing the

effects of aging, including cracking of susceptible materials. Also, as discussed

below, the use of note A is not appropriate.

These AMR results are compared to GALL Report, item V.D2-29, for which the

AMP is identified as GALL AMP XI.M7, "BWR Stress Corrosion Cracking," and

GALL AMP XI.M2, "Water Chemistry." As described in plant-specific note 0207,

the BWR Stress Corrosion Cracking program is applicable only to stainless steel

piping (>4 inch), pump casings, valve bodies, and reactor vessel attachments

containing reactor coolant at >2000F. Therefore, the BWR Stress Corrosion

Cracking program is not credited with managing cracking of stainless steel

tubing exposed to treated water in the RCIC and HPCI systems. Instead, the

BWR Water Chemistry Program and the Chemistry Program Effectiveness

Inspection are credited, and note E is used instead of note A.

LRA Tables 3.2.1, 3.2.2-2, and 3.2.2-4, and the plant-specific note 0207 for the

tables in LRA Section 3.2 are revised to reflect these results.

The staff reviewed the applicant's response and the associated LRA changes. The staff

reviewed the applicant's BWR Water Chemistry Program. The staff's evaluation of this

program, which is documented in SER Section 3.0.3.1.1, found that the BWR Water Chemistry

Program provided mitigation for the aging effect of cracking due to SCC and IGSCC. The staff

reviewed the applicant's Chemistry Program Effectiveness Inspection. The staff's evaluation of

this program, which is documented in SER Section 3.0.3.1.10, found that the CPEI is a onetime inspection that is consistent with the GALL Report's recommendations for AMP XI.M32,

"One-Time Inspection." The CPEI includes provisions for inspecting selected components in

areas of low or stagnant flow and includes methodology that is capable of detecting cracking

due to SCC and IGSCC, if it should occur in the selected components. Because the BWR

Water Chemistry Program provides mitigation and the CPEI provides detection for cracking due

to SCC or IGSCC, the staff finds the applicant's proposed AMPs for managing the aging effect

of cracking due to SCC or IGSCC in stainless steel tubing exposed to treated water >60 0C

(>1400 F) in the RCIC system and in the HPCI system to be acceptable. On this basis, the staff

finds that the issue raised in RAI 3.2-1 is resolved by the applicant's changes in the LRA.

3.2.2.1.5 Loss of Material due to General, Pitting, Crevice, and Galvanic Corrosion

LRA Table 3.2.2-1 addresses carbon steel RHR heat exchanger shells, shell covers and tube

sheets in a treated water environment. The applicant specified use of the BWR Water

Chemistry Program, alone, for managing the aging effect of loss of material due to general,

pitting, crevice, and galvanic corrosion. For these AMR results the applicant referred to LRA

Table 3.2.1, Item 3.2.1-27, and cited generic Note E, indicating that the result is consistent with

the corresponding GALL Report item for material, environment and aging effect, but a different

AMP is credited. The staff noted that for the corresponding line in SRP-LR Table 3.2-1 and in

GALL Report, Volume 1, Table 2, the recommended AMP is GALL AMP XI.M21, "Closed-Cycle

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Cooling Water System," which includes both preventive measures, such as control of water

chemistry to minimize corrosion and SSC, and testing and inspection to monitor the effect of

corrosion and SSC on the intended function of the components.

LRA Table 3.2.2-2 addresses stainless steel reactor core isolation cooling (RCIC) turbine lube

oil cooler tubes, tube sheets and channels in a treated water environment. The applicant

specified use of the BWR Water Chemistry Program, alone, for managing the aging effect of

loss of material due to pitting, and crevice corrosion. For these AMR results the applicant

referred to LRA Table 3.2.1, Item 3.2.1-28, and cited generic Note E, indicating that the result is

consistent with the corresponding GALL Report item for material, environment and aging effect,

but a different AMP is credited. The staff noted that for the corresponding line in SRP-LR

Table 3.2-1 and in GALL Report, Volume 1, Table 2, the recommended AMP is GALL AMP

XI.M21, "Closed-Cycle Cooling Water System," which includes both preventive measures, such

as control of water chemistry to minimize corrosion and SSC, and testing and inspection to

monitor the effect of corrosion and SSC on the intended function of the components.

LRA Tables 3.2.2-1, 3.2.2-2, 3.2.2-3 and 3.2.2-4 address copper alloy piping and piping

components and heat exchanger tubes in the RHR system, turbine lube oil heat exchanger

tubes, tube sheets and channels in the RCIC system, piping and piping components in the core

spray system, and lube oil heat exchanger tubes, tube sheets and channels in the HPCI

system; all of these components are in a treated water environment. The applicant specified

use of the BWR Water Chemistry Program, alone, for managing the aging effect of loss of

material due to pitting, crevice and galvanic corrosion. For these AMR result lines, the applicant

referred to LRA Table 3.2.1, item 3.2.1-29 and cited generic Note E, indicating that the result is

consistent with the corresponding GALL Report item for material, environment and aging effect,

but a different AMP is credited. The staff noted that for the corresponding line in SRP-LR

Table 3.2-1 and in GALL Report, Volume 1, Table 2, the recommended AMP is GALL

AMP XI.M21, "Closed-Cycle Cooling Water System," which includes both preventive measures,

such as control of water chemistry, to minimize corrosion and SSC, and testing and inspection

to monitor the effect of corrosion and SSC on the intended function of the components.

For the AMR results described in the preceding paragraphs, because the applicant proposed

use of the BWR Water Chemistry Program, alone, and no inspection activity was credited to

monitor effectiveness of the water chemistry program, the staff issued RAI 3.2-2, in a letter

dated July 15, 2008, addressing these AMR results and asking the applicant to justify why an

inspection is not performed to verify the effectiveness of the water chemistry program and

confirm that loss of material is not occurring in these components.

In a letter dated August 15, 2008, the applicant responded to RAI 3.2-2 by providing the

following response:

For the AMR results listed in LRA Tables 3.2.2-1, 3.2.2-2, 3.2.2-3 and 3.2.2-4 that

reference the LRA Table 1 items 3.2.1-27, 3.2.1-28 or 3.2.1-29, verification of the

effectiveness of the BWR Water Chemistry Program is needed. The Chemistry Program

Effectiveness Inspection will provide confirmation of the effectiveness of the BWR Water

Chemistry Program in managing the effects of aging, including loss of material.

LRA Tables 3.2.1, 3.2.2-1, 3.2.2-2, 3.2.2-3, and 3.2.2-4 are revised to reflect these

results.

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The staff reviewed the applicant's response and the associated LRA changes. The staff

reviewed the applicant's BWR Water Chemistry Program. The staff's evaluation of this

program, which is documented in SER Section 3.0.3.1.1, found that the BWR Water Chemistry

Program provides mitigation for the aging effect of loss of material due to general, pitting,

crevice, and galvanic corrosion. The staff reviewed the applicant's Chemistry Program

Effectiveness Inspection. The staff's evaluation of this program, which is documented in SER

Section 3.0.3.1.10, found that the CPEI is a one-time inspection that is consistent with the

GALL Report's recommendations for AMP XI.M32, "One-Time Inspection." The CPEI includes

provisions for inspecting selected components in areas of low or stagnant flow and is capable of

detecting loss of material due to general, pitting, crevice, and galvanic corrosion, if it should

occur in the selected components. Because the BWR Water Chemistry Program provides

mitigation and the CPEI provides detection for loss of material due to general, pitting, crevice,

and galvanic corrosion, the staff finds the applicant's LRA changes and the applicant's

proposed AMPs for managing the aging effect of aging effect of loss of material due to general,

pitting, crevice, and galvanic corrosion in steel, stainless steel, and copper alloy components

exposed to closed-cycle cooling water in the RHR system, the reactor core isolation cooling

system, the core spray system, and the high pressure coolant injection system to be

acceptable. On this basis, the staff finds that the issue raised in RAI 3.2-2 is resolved by the

applicant's changes in the LRA.

SER Section 3.2.2.1 Conclusion. The staff evaluated the applicant's claim of consistency with

the GALL Report. The staff also reviewed information pertaining to the applicant's consideration

of recent OE and proposals for managing aging effects. On the basis of its review, the staff

concludes that the AMR results, which the applicant claimed to be consistent with the GALL

Report, are indeed consistent with its AMRs. Therefore, the staff concludes that the applicant

has demonstrated that the effects of aging for these components will be adequately managed

so that their intended function(s) will be maintained consistent with the CLB during the period of

extended operation, as required by 10 CFR 54.21(a)(3).

3.2.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation is

Recommended

In LRA Section 3.2.2.2, the applicant further evaluates aging management, as recommended

by the GALL Report, for the engineered safety features components and provides information

concerning how it will manage the following aging effects:

* cumulative fatigue damage

* loss of material due to cladding

* loss of material due to pitting and crevice corrosion

* reduction of heat transfer due to fouling

* hardening and loss of strength due to elastomer degradation

* loss of material due to erosion

* loss of material due to general corrosion and fouling

* loss of material due to general, pitting, and crevice corrosion

* loss of material due to general, pitting, crevice, and MIC

* QA for aging management of nonsafety-related components

For component groups evaluated in the GALL Report, for which the applicant claimed

consistency with the report and for which the report recommends further evaluation, the staff

audited and reviewed the applicant's evaluation to determine whether it adequately addressed

the issues further evaluated. In addition, the staff reviewed the applicant's further evaluations

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against the criteria contained in SRP-LR Section 3.2.2.2. The staff's review of the applicant's

further evaluation follows.

3.2.2.2.1 Cumulative Fatigue Damage

LRA Section 3.2.2.2.1 states that fatigue is a TLAA, as defined in 10 CFR 54.3. Applicants must

evaluate TLAAs in accordance with 10 CFR 54.21 (c)(1). SER Section 4.3 documents the staff's

review of the applicant's evaluation of this TLAA.

3.2.2.2.2 Loss of Material Due to Cladding Breach

The staff reviewed LRA Section 3.2.2.2.2 against the criteria in SRP-LR Section 3.2.2.2.2.

LRA Section 3.2.2.2.2 addresses loss of material and cladding breach. The applicant stated

that this aging effect is not applicable because SSES is a BWR.

SRP-LR Section 3.2.2.2.2 states that loss of material due to cladding breach may occur in PWR

steel pump casings with stainless steel cladding exposed to treated borated water.

The staff confirmed in SRP-LR Table 3.2-1, Item 2, is only applicable to PWR plants.

Because SSES is a BWR, the staff finds that this item in SRP-LR Section 3.2.2.2.2 does not

apply to SSES.

Based on the above, the staff concludes SRP-LR Section 3.2.2.2.2 criteria are not applicable.

3.2.2.2.3 Loss of Material Due to Pitting and Crevice Corrosion

The staff reviewed LRA Section 3.2.2.2.3 against the following criteria in SRP-LR

Section 3.2.2.2.3:

(1) LRA Section 3.2.2.2.3 addresses loss of material due to pitting and crevice corrosion in

containment isolation piping, piping components, and piping elements at locations with

stagnant flow conditions. The applicant stated that containment isolation piping and

components were grouped with similar piping having the same material, environment,

aging effects, and aging management program(s). As stated in Table 3.2.1, the SSES

components matching the description of LRA item number 3.2.1-03 were included in the

evaluation of components for LRA item number 3.2.1-05. Refer to Section 3.2.2.2.3.3 for

the details of the evaluation of aging management for these components.

SRP-LR Section 3.2.2.2.3 states that loss of material due to pitting and crevice

corrosion may occur on internal surfaces of stainless steel containment isolation piping,

piping components, and piping elements exposed to treated water. The existing

AMP monitors and controls water chemistry to mitigate degradation. However, control of

water chemistry does not preclude loss of material due to pitting and crevice corrosion

at locations with stagnant flow conditions; therefore, the effectiveness of water chemistry

control programs should be verified to ensure that corrosion does not occur. The GALL

Report recommends further evaluation of programs to verify the effectiveness of water

chemistry control programs. A one-time inspection of selected components at

susceptible locations is an acceptable method to determine whether an aging effect is

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occurring or is slowly progressing such that the component's intended functions will be

maintained during the period of extended operation.

Because the grouped components have identical material, environment, aging effect

and aging management program(s) recommended in the GALL Report, the staff finds

the applicant's grouping of components from LRA Table 3.2.1, item 3.2.1-3, with

components in LRA Table 3.2.1, item 3.2.1-5, for the purpose of AMR evaluation to be

acceptable. On this basis, the staff finds it acceptable for the applicant to designate LRA

Table 3.2.1, item 3.2.1-3 as not applicable.

(2) LRA Section 3.2.2.2.3 addresses loss of material due to pitting and crevice corrosion in

piping, piping components, and piping elements exposed to soil. The applicant stated

that this aging effect is not applicable because there are no stainless steel piping, piping

components, or piping elements exposed to soil in the ESF systems for SSES.

SRP-LR Section 3.2.2.2.3 states that loss of material due to pitting and crevice

corrosion may occur in stainless steel piping, piping components, and piping elements

exposed to soil. The GALL Report recommends further evaluation of a plant-specific

AMP to ensure that the aging effect is adequately managed.

LRA Table 3.2.1 states that there are no SSES components comparable to LRA item

number 3.2.1-04. The applicant stated that there is no buried stainless steel piping or

piping components in the ESF Systems and the staff verified the applicant's statement

by a review of plant boundary drawings. The staff reviewed LRA Section 2.3.2 and

verified that SSES does not have ESF systems with-in the scope of license renewal that

contain the piping, piping components and piping elements fabricated from stainless

steel exposed to soil. The applicant stated that no further evaluation is necessary and

the staff agrees with that because there is no buried stainless steel piping or piping

components in the ESF Systems.

Based on the staff's review as described above and of LRA Section 3.2 and found that

there were no stainless steel piping, piping components and piping elements exposed to

soil. On the basis of this review, the staff finds that SRP-LR Section 3.2.2.2.3.2 is not

applicable to SSES.

(3) LRA Section 3.2.2.2.3 addresses loss of material due to pitting and crevice corrosion in

BWR piping, piping components, and piping elements exposed to treated water. The

applicant stated that loss of material due to pitting and crevice corrosion for stainless

steel piping components exposed to treated water in ESF Systems is managed by the

BWR Water Chemistry Program and the Chemistry Program Effectiveness Inspection.

There are no aluminum piping components subject to AMR in ESF Systems. The BWR

Water Chemistry Program manages aging effects through periodic monitoring and

control of contaminants. The CPEI will provide a verification of the effectiveness of the

BWR Water Chemistry Program to manage loss of material due to pitting and crevice

corrosion through examination of stainless steel ESF components.

SRP-LR Section 3.2.2.2.3 states that loss of material due to pitting and crevice

corrosion may occur in BWR stainless steel and aluminum piping, piping components,

and piping elements exposed to treated water. The existing AMP monitors and controls

water chemistry for BWRs to mitigate degradation. However, control of water chemistry

does not preclude loss of material due to pitting and crevice corrosion at locations with

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stagnant flow conditions; therefore, the effectiveness of water chemistry control

programs should be verified to ensure that corrosion does not occur. The GALL Report

recommends further evaluation of programs to verify the effectiveness of water

chemistry control programs. A one-time inspection of selected components at

susceptible locations is an acceptable method to determine whether an aging effect is

occurring or is slowly progressing such that the component's intended functions will be

maintained during the period of extended operation.

The staff reviewed the applicant's BWR Water Chemistry Program. The staff's

evaluation of this program, which is documented in SER Section 3.0.3.1.1, found that

the BWR Water Chemistry Program provides mitigation for the aging effect of loss of

material due to general, pitting, and crevice corrosion. The staff reviewed the applicant's

Chemistry Program Effectiveness Inspection. The staff's evaluation of this program,

which is documented in SER Section 3.0.3.1.10, found that the CPEI is a one-time

inspection that is consistent with the GALL Report's recommendations for AMP XI.M32,

"One-Time Inspection." The CPEI includes provisions for inspecting selected

components in areas of low or stagnant flow and is capable of detecting loss of material

due to pitting and crevice corrosion, if it should occur in the selected components.

Based on the applicant's use of a one-time inspection consistent with the

recommendations of the GALL Report, the staff finds the applicant's proposed AMPs for

managing the potential aging effect of loss of material due to pitting and crevice

corrosion in stainless steel piping components exposed to treated water in the ESF

systems to be acceptable.

(4) LRA Section 3.2.2.2.3 addresses loss of material due to pitting and crevice

corrosion in piping, piping components, and piping elements exposed to lubricating oil.

The applicant stated that loss of material for stainless steel or copper alloy piping

components exposed to lubricating oil is managed by the Lubricating Oil Analysis

Program. The Lubricating Oil Analysis Program manages aging effects through periodic

monitoring and control of contaminants, including water. The Lubricating Oil Inspection

will provide a verification of the effectiveness of the Lubricating Oil Analysis Program to

manage loss of material due to crevice and pitting corrosion through examination of

stainless steel or copper alloy piping components. In its letter dated July 28, 2009, the

applicant revised its response to RAI 3.2.2.3-1 and the LRA Table 3.2.2-4 to state that

flex connections exposed to an internal environment of lubricating oil were fabricated

from stainless steel material and not synthetic rubber as stated in the LRA. The

applicant further stated that stainless steel flex hoses in a lubricating oil environment will

have an aging effect of loss of material and credited the Lubricated Oil Analysis and the

Lubricating Oil Inspection Programs.

SRP-LR Section 3.2.2.2.3 states that loss of material due to pitting and crevice

corrosion may occur in stainless steel and copper alloy piping, piping components, and

piping elements exposed to lubricating oil. The existing program periodically samples

and analyzes lubricating oil to maintain contaminants within acceptable limits, thereby

preserving an environment that is not conducive to corrosion. However, control of lube

oil contaminants may not always be fully effective in precluding corrosion; therefore, the

effectiveness of lubricating oil control should be verified to ensure that corrosion does

not occur. The GALL Report recommends further evaluation to verify the effectiveness

of the lubricating oil programs. A one-time inspection of selected components at

susceptible locations is an acceptable method to ensure that corrosion does not occur

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and that component intended functions will be maintained during the period of extended

operation.

The staff evaluated the Lubricating Oil Analysis Program and the Lubricating Oil

Inspection Program, and the evaluations are documented in SER Sections 3.0.3.2.15

and 3.0.3.1.13, respectively. The staff reviewed the applicant's Lubricating Oil Analysis

Program and determined that this program includes periodic sampling and analysis of

lubricating oil to maintain contaminants within acceptable limits. The staff finds that

these activities are consistent with the recommendations in the GALL Report and are

adequate to manage loss of material due to pitting and crevice corrosion in copper alloy

and stainless steel piping, piping components, piping elements and stainless steel flex

hoses exposed to lubricating oil. The staff verified that the applicant has credited its

Lubricating Oil Inspection Program to verify the effectiveness of the Lubricating Oil

Analysis Program to manage this aging effect for ECCS system. The applicant's AMPS

are consistent with those recommended for aging management in SRP-LR Section

3.2.2.2.3, Item #4 and in GALL AMR Items V.D1-24 and V.D2-22.

(5) LRA Section 3.2.2.2.3 addresses loss of material due to pitting and crevice corrosion in

partially encased tanks exposed to raw water. The applicant stated that this aging effect

is not applicable because there are no outdoor stainless steel tanks in the ESF systems

for SSES.

SRP-LR Section 3.2.2.2.3 states that loss of material due to pitting and crevice

corrosion may occur in partially encased stainless steel tanks exposed to raw water due

to cracking of the perimeter seal from weathering. The GALL Report recommends

further evaluation to ensure that the aging effect is adequately managed. The GALL

Report recommends that a plant-specific AMP be evaluated because moisture and

water can egress under the tank if the perimeter seal is degraded.

The staff reviewed the applicant's Updated Final Safety Analysis Report (UFSAR)

Rev.63 updated in September 2007, to determine the tanks that are relied upon as part

of the ESF Systems. Based on the staff's review, the Condensate Storage Tanks are

the primary source of water and then transferred to the suppression pool for the ESF

Systems. The staff noted from its review that the condensate storage tanks for both

Unit 1 and 2 are located outdoors but are not made of stainless steel. The staff verified

that both tanks are made of carbon steel.

Based on the staff's review of the applicant's UFSAR, the staff agrees with the

applicant's determination that item 5 of SRP-LR Section 3.2.2.2.3 does not apply to

SSES ESF systems because there are no stainless steel tanks located outdoors that

are relied upon by the ESF systems.

(6) LRA Section 3.2.2.2.3 addresses loss of material due to pitting and crevice corrosion in

piping, piping components, piping elements, and tanks exposed to internal

condensation. The applicant stated that this aging effect is not applicable because there

are no stainless steel piping, piping components, piping elements, and tank internal

surfaces exposed to condensation in the ESF systems for SSES.

SRP-LR Section 3.2.2.2.3 states that loss of material due to pitting and crevice

corrosion may occur in stainless steel piping, piping components, piping elements, and

tanks exposed to internal condensation. The GALL Report recommends further

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evaluation of a plant-specific AMP to ensure that the aging effect is adequately

managed.

SRP-LR Section 3.2.2.2.3.6 invokes AMR Item 8 in Table 2 of the GALL Report, Volume

1, and AMR Items V.D-2 in the GALL Report, Volume 2, as applicable to stainless steel

piping, piping components, piping elements, and tanks exposed to internal condensation

in BWR emergency core cooling systems.

The staff reviewed the LRA Table 2s AMR Results for ESF systems and noted that

there are no stainless steel piping, piping components, piping elements, and tank

internal surfaces exposed to condensation in the ESF systems for SSES. Therefore, the

staff concludes that this item is not applicable.

Based on the programs identified above, the staff concludes that the applicant's programs meet

SRP-LR Section 3.2.2.2.3 criteria. For those line items that apply to LRA Section 3.2.2.2.3, the

staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21(a)(3).

3.2.2.2.4 Reduction of Heat Transfer Due to Fouling

The staff reviewed LRA Section 3.2.2.2.4 against the following criteria in SRP-LR

Section 3.2.2.2.4:

(1) LRA Section 3.2.2.2.4 addresses reduction of heat transfer due to fouling in heat

exchanger tubes exposed to lubricating oil. The applicant stated that For those heat

exchangers within the scope of GL 89-13 for SSES, the Piping Corrosion Program is

credited with managing fouling of heat exchanger tubes exposed to lubricating oil. For

heat exchangers not within the scope of GL 89-13, the Lubricating Oil Analysis Program

will manage reduction in heat transfer of heat exchanger tubes exposed to lubricating

oil.

SRP-LR Section 3.2.2.2.4 states that reduction of heat transfer due to fouling may occur

in steel, stainless steel, and copper alloy heat exchanger tubes exposed to lubricating

oil. The existing AMP monitors and controls lube oil chemistry to mitigate reduction of

heat transfer due to fouling. However, control of lube oil chemistry may not always be

fully effective in precluding fouling; therefore, the effectiveness of lube oil chemistry

control should be verified to ensure that fouling does not occur. The GALL Report

recommends further evaluation of programs to verify the effectiveness of lube oil

chemistry control. A one-time inspection of selected components at susceptible

locations is an acceptable method to determine whether an aging effect is occurring or

is slowly progressing such that the component's intended functions will be maintained

during the period of extended operation.

The Piping Corrosion Program is credited for RHR system motor oil cooler tubes in

Table 3.2.2-1. The corresponding GALL Report Volume 2 line item is V.D2-1 1. For this

line item, the GALL Report recommends GALL AMP XI.M39, "Lubricating Oil Analysis",

and an effectiveness verification program such as one-time inspection.

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Although the external surface of the motor oil cooler tubes is lubricating oil, the internal

environment is raw water and this cooler is part of the GL 89-13 program. Therefore, the

applicant credits the Piping Corrosion Program. The staff noted that the Piping

Corrosion Program is a combination of condition monitoring program (consisting of

inspections, surveillances, and testing to detect the presence of, and to assess the

extent of, fouling and loss of material) and a mitigation program (consisting of chemical

treatments and cleaning activities to minimize fouling and loss of material). The staff's

evaluation of the Piping Corrosion program is documented in SER Section 3.0.3.2.6.

Because the Piping Corrosion Program includes both the chemistry treatment and

cleaning for mitigation and inspection for verification, the staff finds that the Piping

Corrosion Program will adequately manage the aging effects of reduction of heat

transfer through the period of extended operation.

The Lubricating Oil Analysis Program and Lubricating Oil Inspection Program is credited

for RCIC turbine lube oil cooler tubes in Table 3.2.2-2, lube oil cooler tubers in Table

3.2.2-4 and heat exchanger tubes in Table 3.3.2-9. The corresponding GALL Report

Volume 2 line item is V.D2-1 1. For these line items, the GALL Report recommends

GALL AMP XI.M39, "Lubricating Oil Analysis", and an effectiveness verification program

such as one-time inspection.

The staff evaluated the Lubricating Oil Analysis Program and the Lubricating Oil

Inspection Program, and the evaluations are documented in SER Sections 3.0.3.2.15

and 3.0.3.1.13, respectively. The staff reviewed the applicant's Lubricating Oil Analysis

Program and determined that this program includes periodic sampling and analysis of

lubricating oil to maintain contaminants within acceptable limits. The staff finds that

these activities are consistent with the recommendations in the GALL Report and are

adequate to manage reduction in heat transfer due to fouling in copper alloy and

stainless steel heat exchanger tubes exposed to lubricating oil. The staff verified that

the applicant has credited its Lubricating Oil Inspection Program to verify the

effectiveness of the Lubricating Oil Analysis Program to manage this aging effect. The

applicant's AMPs are consistent with those recommended for aging management in

SRP-LR Section 3.2.2.2.4, Item #1 and in GALL AMR Items V.D1-9 and V.D2-11.

(2) LRA Section 3.2.2.2.4 addresses reduction of heat transfer due to fouling in heat

exchanger tubes exposed to treated water. The applicant stated that the Heat

Exchanger Inspection activity is a one-time inspection that will detect and characterize

reduction in heat transfer of stainless steel heat exchanger tubes exposed to treated

water.

SRP-LR Section 3.2.2.2.4 states that reduction of heat transfer due to fouling may occur

in stainless steel heat exchanger tubes exposed to treated water. The existing program

controls water chemistry to manage reduction of heat transfer due to fouling. However,

control of water chemistry may be inadequate; therefore, the GALL Report recommends

that the effectiveness of water chemistry control programs should be verified to ensure

that reduction of heat transfer due to fouling does not occur. A one-time inspection is an

acceptable method to ensure that reduction of heat transfer does not occur and that

component intended functions will be maintained during the period of extended

operation.

The LRA references this section to RCIC turbine lube oil cooler tubes in the reactor core

isolation cooling system and the corresponding GALL Report Volume 2 line item is

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V.D2-13. For this line item, the GALL Report recommends GALL AMP XI.M21, ClosedCycle Cooling Water System Program. The GALL AMP XI.M21, Closed-Cycle Cooling

Water System, recommends preventive measures to minimize corrosion and testing and

inspection to monitor the effects of corrosion, whereas the applicant is proposing only a

one-time inspection activity. The staff issued RAI 3.2.2.2.4.2-1 by letter dated July 23,

2008, requesting the applicant to justify how the one-time heat exchanger inspection

activity by itself will manage the aging effect of reduction in heat transfer, without

preventive measures to minimize corrosion, such as maintaining treated water chemistry

control.

In its response to RAI 3.2.2.2.4.2-1 dated August 22, 2008, the applicant stated that the

BWR Water Chemistry Program is credited for managing loss of material for stainless

steel heat exchanger tubes exposed to treated water. The applicant also stated that

since the BWR Water Chemistry Program does not contain measures for detection of

aging effects through inspection, it is not credited for managing reduction in heat

transfer; however, it is recognized that the same preventive actions by which the water

chemistry program manages loss of material also mitigates the conditions that could

result in reduction in heat transfer. The applicant further stated that due to the BWR

water chemistry control, fouling of heat exchanger tubes is not expected to occur.

Therefore, the applicant concluded that as stated in LRA Section B.2.24, the Heat

Exchanger Inspection will provide direct evidence as to whether, and to what extent,

reduction in heat transfer has occurred, or is likely to occur, that could result in a loss of

intended function.

The staff confirmed that in LRA Table 3.2.2-2, BWR Water Chemistry Program is

credited for managing loss of material of RCIC turbine oil coolers. For these same

coolers, the applicant has credited the Heat Exchanger Inspection Program for reduction

of heat transfer. The staff's evaluation of the Heat Exchanger Program is documented in

SER Section 3.0.3.1.12. The Heat Exchanger Inspection Program uses visual (VT-3 or

equivalent) or remote visual inspection techniques to verify the absence of, or to identify

the extent of fouling on the tube surfaces. On the basis that water chemistry is

maintained to minimize corrosion and fouling, the staff finds the use of the Heat

Exchanger Inspection Program acceptable for managing the aging effects of reduction

of heat transfer for stainless steel heat exchanger tubes exposed to treated water and

finds the applicant response acceptable.

Based on the programs identified above, the staff concludes that the applicant's programs meet

SRP-LR Section 3.2.2.2.4 criteria. For those line items that apply to LRA Section 3.2.2.2.4, the

staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

3.2.2.2.5 Hardening and Loss of Strength Due to Elastomer Degradation

The staff reviewed LRA Section 3.2.2.2.5 against the criteria in SRP-LR Section 3.2.2.2.5.

LRA Section 3.2.2.2.5 addresses hardening and loss of strength due to elastomer degradation.

The applicant stated that the System Walkdown Program is credited with managing

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degradation due to aging of the visible external surfaces, and in some cases the internal

surfaces, of these components.

SRP-LR Section 3.2.2.2.5 states that hardening and loss of strength due to elastomer

degradation may occur in elastomer seals and components of the BWR standby gas treatment

system ductwork and filters exposed to air - indoor uncontrolled. The GALL Report

recommends further evaluation of a plant-specific AMP to ensure that these aging effects are

adequately managed.

SRP-LR Section 3.2.2.2.5 invokes AMR Item 11 in Table 2 of the GALL Report, Volume 1, and

AMR Items V.B-4 in the GALL Report, Volume 2, as applicable to elastomeric seals and

components in SGTS. In these AMRs, the staff identifies that hardening and loss of strength

due to elastomer degradation may occur in elastomeric seal or component surfaces that are

exposed either internally or externally to uncontrolled indoor air. In these AMRs, the GALL

Report recommends that a plant-specific aging management program is to be evaluated and

credited to manage hardening and loss of strength in the elastomer seal surfaces that are

exposed either internally or externally to indoor air.

The staff noted that in the applicant's AMR for these components, as given in LRA Table 3.2.2-

7, the applicant identified that the flexible connections in the SGTS ductwork are the applicable

SGTS components falling within the scope of this assessment and that neoprene is the

applicable elastomeric material (rubber). The applicant also identified that the neoprene flexible

connections are exposed internally to a ventilation environment and externally to uncontrolled

indoor air. The applicant stated that is crediting its Systems Walkdown Program to manage

hardening and loss of strength in these materials.

The staff noted that, in AMP B.2.32, the applicant stated that the purpose of the System

Walkdown Program is, in part, to manage cracking and/or change in material properties for

elastomers (neoprene and rubber) and polymers (Teflon) that are exposed to indoor air or

ventilation environments. The staff noted the GALL AMP XI.M36, "External Surfaces

Monitoring," is the program in the GALL Report that corresponds to the applicant's System

Walkdown Program. The staff reviewed the program description and program elements for

GALL AMP XI.M36 and noted that the scope of this AMP is currently limited to the inspection of

steel (i.e., carbon steel, alloy steel, or cast iron) components in order to manage: (1) loss of

material that may occur in the steel components as a result of general corrosion, pitting

corrosion, or crevice corrosion, or (2) cracking in the coatings that may line the external

surfaces of these steel components. The staff noted that GALL AMP XI.M36, "External

Surfaces Monitoring," does not apply to elastomeric components or to the management of

hardening or loss of strength in elastomeric components. Thus, the staff had several issues

with the applicant's AMR for the SGTS neoprene flexible connections and with crediting the

Systems Walkdown Program to manage hardening and loss of strength in these elastomeric

components.

With respect to the first issue taken on the applicant's AMR, the staff noted that in the

applicant's AMRs on management of changes in material properties for the neoprene flexible

SGTS connections, the applicant credited its Systems Walkdown Program with aging

management of both the internal surfaces that are exposed to the ventilation environment and

the external surfaces that are exposed to the uncontrolled indoor air environment. In contrast,

the staff noted that scope of GALL AMP XI.M36, "External Surfaces Monitoring," does not

include elastomeric components nor does it apply to the management of changes in material

properties (such as hardening and loss of strength) that may occur in elastomeric components.

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The staff also noted the "scope of program" program element in GALL AMP XI.M36, "External

Surfaces Monitoring," states that programs corresponding to GALL AMP XI.M36 may only be

applied to internal surfaces if the "material and environment combinations are the same for

internal and external surfaces such that external surface condition is representative of internal

surface condition, and that when credited for internal surfaces, "the program should describe

the component internal environment and the credited similar external component environment

inspected." In RAI B.2.32-4 by letter dated July 23, 2008, the staff asked the applicant to justify

its basis for crediting the System Walkdown Program to manage cracking and changes in

material properties that may occur in the external surfaces of in-scope components that are

fabricated from either an elastomeric or polymeric material. The staff also asked the applicant

to clarify how a visual examination alone from the external surfaces of these materials would be

capable of detecting the following aging effects: (1) a tightly configured crack that penetrates

the external surface of the component, (2) a subsurface crack or a crack that only penetrates

the internal surface of the materials, and (3) a change in a material property, such as a potential

change in the hardness property or strength property for the elastomer or polymer material

used to fabricate the component. RAI B.2.32-4 is relevant to the acceptance of the applicant's

internal and external surface AMRs for the neoprene flexible SGTS connections. The

applicant's RAI B2.32-4 response is evaluated and accepted by the staff and documented in

SER Section 3.0.3.2.14.

With respect to the second issue taken on the applicant's AMR, the staff noted that in AMP

B.2.32, System Walkdown Program, the applicant credits the program, in part, for aging

management of both cracking and changes in material properties for elastomer (i.e., neoprene

or rubber) and plastic (polymer) components that are exposed to uncontrolled indoor air or

ventilation environments. The staff noted, however, that in LRA Table 3.2.2-7, the applicant did

not provide either a plant-specific AMR or enhanced AMR aligning to GALL AMR V.B-4 that

identified cracking as an applicable aging effect requiring management for the flexible neoprene

SGTS connections that are exposed internally to the ventilation environment or externally to the

uncontrolled indoor air environment. In RAI #3.2.2.2.5-1 by letter dated July 23, 2008, the staff

asked the applicant to justify why LRA Table 3.2.2-7 did not include any AMRs on cracking of

the neoprene flexible SGTS connections that are exposed internally to the ventilation

environment or externally to the uncontrolled indoor air environment, when LRA AMP B.2.32

implies that cracking could occur in these neoprene components. Alternatively, if cracking is an

applicable aging effect requiring management for the internal and external surfaces of these

flexible SGTS connections, the staff requested the applicant in the RAI to amend the LRA to

include AMR's that identify cracking as an AERM for the internal and external surfaces of the

components, and to clarify which AMP or AMPs would be credited with the management of

cracking in the neoprene flexible SGTS connection surfaces that are exposed to uncontrolled

indoor air and to the ventilation environment.

In its response to RAI 3.2.2.2.5-1 dated August 27, 2008, the applicant stated that in Table

3.2.2-7, cracking was inadvertently omitted from the "Aging Effect Requiring Management"

column. The applicant amended the LRA to revise Table 3.2.2-7 to add the aging effect of

cracking for neoprene flexible connections in an internal environment of ventilation and an

external environment of indoor air, and credited the System Walkdown Program to manage this

aging effect. The applicant also revised LRA Section 3.2.2.2.5 to state that because the

relevant conditions for aging that exist in the internal environment are essentially the same as

those that exist in the external environment, the System Walkdown Program is also credited

with managing degradation due to aging of the internal surfaces.

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The staff finds the response acceptable because the applicant added the aging effect of

cracking for neoprene flexible connections and explained why the System Walkdown Program,

which is for inspection of external surfaces, is also credited for managing degradation of

internal surfaces of the flexible connections. The staff's review of the System Walkdown

Program is documented in SER Section 3.0.3.2.14.

Based on the programs identified above, the staff concludes that the applicant's programs meet

SRP-LR Section 3.2.2.2.5 criteria. For those line items that apply to LRA Section 3.2.2.2.5, the

staff determines that the LRA, as amended in response to associated RAIs is consistent with

the GALL Report and that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

during the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.2.2.2.6 Loss of Material Due to Erosion

The staff reviewed LRA Section 3.2.2.2.6 against the criteria in SRP-LR Section 3.2.2.2.6.

LRA Section 3.2.2.2.6 addresses loss of material due to erosion. The applicant stated that this

aging effect is not applicable because SSES is a BWR.

SRP-LR Section 3.2.2.2.6 states that loss of material due to erosion may occur in the stainless

steel high-pressure safety injection (HPSI) pump miniflow recirculation orifice exposed to

treated borated water.

Because SSES is a BWR, the staff finds that this item in SRP-LR Section 3.2.2.2.6 does not

apply to SSES.

Based on the above, the staff concludes SRP-LR Section 3.2.2.2.6 criteria are not applicable.

3.2.2.2.7 Loss of Material Due to General Corrosion and Fouling

The staff reviewed LRA Section 3.2.2.2.7 against the criteria in SRP-LR Section 3.2.2.2.7.

LRA Section 3.2.2.2.7 addresses loss of material due to general corrosion and fouling. The

applicant stated that this aging effect is not applicable because SSES nozzles used for

containment spray are formed of stainless steel. Stainless steel flow elements are used in place

of flow orifices.

SRP-LR Section 3.2.2.2.7 states that loss of material due to general corrosion and fouling may

occur on steel drywell and suppression chamber spray system nozzle and flow orifice internal

surfaces exposed to air - indoor uncontrolled and may cause plugging of the spray nozzles and

flow orifices. This aging mechanism and effect will apply since the spray nozzles and flow

orifices are occasionally wetted even though this system is mostly on standby. The wetting and

drying of these components can accelerate corrosion and fouling. The GALL Report

recommends further evaluation of a plant-specific AMP to ensure that the aging effect is

adequately managed.

SRP-LR Section 3.2.2.2.7 invokes AMR Item 13 in Table 2 of the GALL Report, Volume 1, and

AMR Items V.D-1 in the GALL Report, Volume 2, as applicable to steel drywell and suppression

chamber spray system nozzle and flow orifice internal surfaces exposed to air - indoor

uncontrolled in BWR emergency core cooling systems.

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The staff finds this item is not applicable because SSES nozzles and flow elements used for

containment spray are made of stainless steel, which has no aging effects requiring

management in an air-indoor uncontrolled environment as identified by the GALL Report Item

V.F-12.

Based on the above, the staff concludes SRP-LR Section 3.2.2.2.7 criteria are not applicable.

3.2.2.2.8 Loss of Material Due to General, Pitting, and Crevice Corrosion

The staff reviewed LRA Section 3.2.2.2.8 against the following criteria in SRP-LR

Section 3.2.2.2.8:

(1) LRA Section 3.2.2.2.8 addresses loss of material due to general, pitting, and crevice

corrosion in BWR piping, piping components, and piping elements. The applicant stated

that loss of material due to general, pitting, and crevice corrosion for steel piping

components exposed to treated water is managed by the BWR Water Chemistry

Program and the Chemistry Program Effectiveness Inspection. The BWR Water

Chemistry Program manages aging effects through periodic monitoring and control of

contaminants. The CPEI will provide a verification of the effectiveness of the BWR

Water Chemistry Program to manage loss of material due to general, pitting, and

crevice corrosion through examination of steel piping components.

SRP-LR Section 3.2.2.2.8 states that loss of material due to general, pitting, and crevice

corrosion may occur in BWR steel piping, piping components, and piping elements

exposed to treated water. The existing AMP monitors and controls water chemistry for

BWRs to mitigate degradation. However, control of water chemistry does not preclude

loss of material due to general, pitting, and crevice corrosion at locations with stagnant

flow conditions; therefore, the effectiveness of water chemistry control programs should

be verified to ensure that corrosion does not occur. The GALL Report recommends

further evaluation of programs to verify the effectiveness of water chemistry control

programs. A one-time inspection of selected components at susceptible locations is an

acceptable method to determine whether an aging effect is occurring or is slowly

progressing such that the component's intended functions will be maintained during the

period of extended operation.

The staff reviewed the applicant's BWR Water Chemistry Program. The staff's

evaluation of this program, which is documented in SER Section 3.0.3.1.1, found that

the BWR Water Chemistry Program provides mitigation for the aging effect of loss of

material due to general, pitting and crevice corrosion. The staff reviewed the applicant's

Chemistry Program Effectiveness Inspection. The staffs evaluation of this program,

which is documented in SER Section 3.0.3.1.10, found that the CPEI is a one-time

inspection that is consistent with the GALL Report's recommendations for AMP XI.M32,

"One-Time Inspection." The CPEI includes provisions for inspecting selected

components in areas of low or stagnant flow and is capable of detecting loss of material

due to general, pitting or crevice corrosion, if it should occur in the selected

components. Based on the applicant's use of a one-time inspection consistent with the

recommendations of the GALL Report, the staff finds the applicant's proposed AMPs for

managing the potential aging effect of loss of material due to general, pitting or crevice

corrosion in steel piping, piping components and piping elements exposed to treated

water in the ESF systems to be acceptable.

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(2) LRA Section 3.2.2.2.8 addresses loss of material due to general, pitting, and crevice

corrosion in piping, piping components, and piping elements exposed to treated water.

The applicant stated that containment isolation piping and components are grouped with

similar piping having the same material, environment, aging effects, and aging

management program(s). As stated in Table 3.2.1, the SSES components matching the

description of LRA item number 3.2.1-15 are included in the evaluation of components

for LRA item number 3.2.1-14. Refer to Section 3.2.2.2.8.1 for the details of the

evaluation of aging management for these components.

SRP-LR Section 3.2.2.2.8 states that loss of material due to general, pitting, and crevice

corrosion may occur on the internal surfaces of steel containment isolation piping, piping

components, and piping elements exposed to treated water.- The existing AMP monitors

and controls water chemistry to mitigate degradation. However, control of water

chemistry does not preclude loss of material due to general, pitting, and crevice

corrosion at locations with stagnant flow conditions; therefore, the effectiveness of water

chemistry control programs should be verified to ensure that corrosion does not occur.

The GALL Report recommends further evaluation of programs to verify the

effectiveness of water chemistry control programs. A one-time inspection of selected

components at susceptible locations is an acceptable method to determine whether an

aging effect is occurring or is slowly progressing such that the component's intended

functions will be maintained during the period of extended operation.

Because the grouped components have identical material, environment, aging effect

and aging management program(s) recommended in the GALL Report, the staff finds

the applicant's grouping of components from LRA Table 3.2.1, item 3.2.1-15, with

components in LRA Table 3.2.1, item 3.2.1-14, for the purpose of AMR evaluation to be

acceptable. On this basis, the staff finds it acceptable for the applicant to designate LRA

Table 3.2.1, item 3.2.1 15 as not applicable.

(3) LRA Section 3.2.2.2.8 addresses loss of material due to general, pitting, and crevice

corrosion in piping, piping components, and piping elements exposed to lubricating oil.

The applicant stated that loss of material for steel piping components exposed to

lubricating oil is managed by the Lubricating Oil Analysis Program. The Lubricating Oil

Analysis Program manages aging effects through periodic monitoring and control of

contaminants, including water. The Lubricating Oil Inspection will provide a verification

of the effectiveness of the Lubricating Oil Analysis Program to manage loss of material

due to general, pitting, and crevice corrosion through examination of steel piping

components.

SRP-LR Section 3.2.2.2.8 states that loss of material due to general, pitting, and crevice

corrosion may occur in steel piping, piping components, and piping elements exposed to

lubricating oil. The existing program periodically samples and analyzes lubricating oil to

maintain contaminants within acceptable limits, thereby preserving an environment not

conducive to corrosion. However, control of lube oil contaminants may not always be

fully effective in precluding corrosion; therefore, the effectiveness of lubricating oil

control should be verified to ensure that corrosion does not occur. The GALL Report

recommends further evaluation to verify the effectiveness of lubricating oil programs. A

one-time inspection of selected components at susceptible locations is an acceptable

method to ensure that corrosion does not occur and that component intended functions

will be maintained during the period of extended operation.

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The staff evaluated the Lubricating Oil Analysis Program and the Lubricating Oil

Inspection Program, and the evaluations are documented in SER Sections 3.0.3.2.15

and 3.0.3.1.13 respectively. The staff reviewed the applicant's Lubricating Oil Analysis

Program and determined that this program includes periodic sampling and analysis of

lubricating oil to maintain contaminants within acceptable limits. The staff finds that

these activities are consistent with the recommendations in the GALL Report and are

adequate to manage loss of material due to general, pitting and crevice, corrosion in

steel piping, piping components, and piping elements exposed to lubricating oil. The

staff verified that the applicant has credited its Lubricating Oil Inspection Program to

verify the effectiveness of the Lubricating Oil Analysis Program to manage this aging

effect for ECCS system. The applicant's AMPS are consistent with those recommended

for aging management in SRP-LR Section 3.2.2.2.8, Item #3 and in GALL AMR Item

V.D2-30.

Based on the programs identified above, the staff concludes that the applicant's programs meet

SRP-LR Section 3.2.2.2.8 criteria. For those line items that apply to LRA Section 3.2.2.2.8, the

staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21(a)(3).

3.2.2.2.9 Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced

Corrosion

The staff reviewed LRA Section 3.2.2.2.9 against the criteria in SRP-LR Section 3.2.2.2.9.

LRA Section 3.2.2.2.9 addresses loss of material due to general, pitting, crevice, and MIC. The

applicant stated that this aging effect is not applicable because there are no steel piping, piping

components, or piping elements exposed to soil in the ESF systems for SSES.

SRP-LR Section 3.2.2.2.9 states that loss of material due to general, pitting, crevice, and MIC

may occur in steel (with or without coating or wrapping) piping, piping components, and piping

elements buried in soil. Buried piping and tanks inspection programs rely on industry practice,

frequency of pipe excavation, and OE to manage the aging effects of loss of material from

general, pitting, and crevice corrosion, and MIC. The effectiveness of the buried piping and

tanks inspection program should be verified by evaluation of an applicant's inspection

frequency and OE with buried components to ensure that loss of material does not occur.

The staff reviewed the UFSAR for SSES and verified that the SSES design does not include

any ESF components that are buried or are exposed to soil. Based on this review, the staff

concludes that the applicant has provided an acceptable basis for concluding that the staff's

guidance in SRP-LR Section 3.2.2.2.9, and the AMR items in GALL referenced by this SRP-LR

section, are not applicable for SSES because the ESF design does not include any components

that are exposed to a soil environment or that are buried.

Based on the above, the staff concludes SRP-LR Section 3.2.2.2.9 criteria is not applicable.

3.2.2.2.10 Quality Assurance for Aging Management of Nonsafety-Related Components

SER Section 3.0.4 documents the staff's evaluation of the applicant's QA program.

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3.2.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report

In LRA Tables 3.2.2-1 through 3.2.2-7, the staff reviewed additional details of the AMR results

for material, environment, AERM, and AMP combinations not consistent with or not addressed

in the GALL Report.

In LRA Tables 3.2.2-1 through 3.2.2-7, the applicant indicated, via notes F through J that the

combination of component type, material, environment, and AERM does not correspond to a

line item in the GALL Report. The applicant provided further information about how it will

manage the aging effects. Specifically, note F indicates that the material for the AMR line item

component is not evaluated in the GALL Report. Note G indicates that the environment for the

AMR line item component and material is not evaluated in the GALL Report. Note H indicates

that the aging effect for the AMR line item component, material, and environment combination

is not evaluated in the GALL Report. Note I indicates that the aging effect identified in the GALL

Report for the line item component, material, and environment combination is not applicable.

Note J indicates that neither the component nor the material and environment combination for

the line item is evaluated in the GALL Report.

For component type, material, and environment combinations not evaluated in the GALL

Report, the staff reviewed the applicant's evaluation to determine whether the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB for the period of extended operation. The

staff's evaluation is documented in the following sections.

3.2.2.3.1 Aging Management Review Results - Residual Heat Removal System -

LRA Table 3.2.2-1

The staff reviewed LRA Table 3.2.2-1, which summarizes the results of AMR evaluations for the

RHR system component groups.

In LRA Table 3.2.2-1, the applicant proposed to manage loss of material in copper alloy heat

exchanger tubes and tube sheets in an internal environment of raw water by using the Piping

Corrosion Program. The applicant referenced footnote G for this line item indicating that

environment is not in the GALL Report for this component. However, the staff noted that GALL

Report Item VII.C1-3 has the same component, material, environment and aging effect

combination and recommends GALL AMP XI.M20, Open-Cycle Cooling Water System. The

applicant's Piping Corrosion Program is consistent with GALL AMP XI.M20. The staff's

evaluation of the Piping Corrosion Program is documented in SER Section 3.0.3.2.6. On the

basis that this line item is consistent with GALL Report line item VII.C1-3, the staff finds that the

Piping Corrosion Program will adequately manage the aging effect of loss of material in copper

alloy heat exchanger tubes and tube sheets in an internal environment of raw water through the

period of extended operation.

In LRA Table 3.2.2-1, the applicant proposed to manage reduction of heat transfer in copper

alloy heat exchanger tubes in an internal environment of raw water by using the Piping

Corrosion Program. The applicant referenced footnote G for this line item indicating that

environment is not in the GALL Report for this component. However, the staff noted that GALL

Report Item VII.C1-6 has the same component, material, environment and aging effect

combination and recommends GALL AMP XI.M20, Open-Cycle Cooling Water System. The

applicant's Piping Corrosion Program is consistent with GALL AMP XI.M20. The staff's

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evaluation of the Piping Corrosion Program is documented in SER Section 3.0.3.2.6. On the

basis that this line item is consistent with GALL Report line item VII.C1-6, the staff finds that the

Piping Corrosion Program will adequately manage the aging effect of reduction of heat transfer

in copper alloy heat exchanger tubes in an internal environment of raw water through the period

of extended operation.

In LRA Table 3.2.2-1, the applicant proposed to manage loss of material in nickel based alloy

heat exchanger tube plugs in an internal environment of raw water by using the Piping

Corrosion Program. The applicant referenced footnote G for this line item indicating that

environment is not in the GALL Report for this component. The staff noted that nickel based

alloy is not included in the GALL Report, however, it is a similar material to the copper alloy

material identified in GALL Report Item VII.C-3 for the same component, environment and

aging effect combination. The GALL Report recommends AMP XI.M20, Open-Cycle Cooling

Water System, for item VII.C3. The applicant's Piping Corrosion Program is consistent with

GALL AMP XI.M20. The staff's evaluation of the Piping Corrosion Program is documented in

SER Section 3.0.3.2.6. On the basis that line item in Table 3.2.2-1 is similar to the GALL Report

Item VII.C-3, the staff finds that the Piping Corrosion Program will adequately manage the

aging effect of loss of material in nickel based alloy heat exchanger tube plugs in an internal

environment of raw water through the period of extended operation.

In LRA Table 3.2.2-1, the applicant proposed to manage loss of material of carbon steel piping

in an external environment of indoor air by using the Supplementary Piping/Tank Inspection

Program. The applicant referenced footnote "H" for this line item indicating that aging effect is

not in NUREG-1801 for this component, material and environment combination. The applicant

also referenced footnote 0203 indicating that this is in an aggressive air/water interface

environment.The definition of footnote "H" implies that these line items are not consistent with

GALL Report. However, the LRA has also referenced GALL Report Item V.D2-2 and Table

3.2.1, line item 3.2.1-31. The staff issued RAI 3.2.2.3.1-1 in a letter dated July 23, 2008, to

request the applicant to justify why a GALL Report and Table 1 item is identified if the line item

is not consistent with the GALL Report.

In its letter dated August 22, 2008, in response to RAI 3.2.2.3.1-1, the applicant responded that

the Note H was used incorrectly in LRA Table 3.2.2-1; instead, Note E should have been used.

The applicant also stated that this is consistent with the use of Note E for a similar component,

material and environment combination in Table 3.2.2-2. The applicant revised the LRA Table

3.2.2-1 to change the note from Note H to Note E. The evaluation of this line item is

documented in SER Section 3.2.2.1.3.

In LRA Tables 3.2.2-1 the applicant proposed to manage cracking in copper alloy piping and

piping components in an environment of treated water by using the BWR Water Chemistry

Program, alone. The applicant cited generic Note H for these AMR results, indicating that the

aging effect is not in the GALL Report for this component, material and environment

combination. In a letter dated July 15, 2008, the staff issued RAI 3.2-3, applicable for these

AMR results and for similar AMR results in LRA Tables 3.2.2-3, 3.3.2-3, 3.3.2-25, and 3.4.2-3.

The RAI asked the applicant to provide a technical justification as to why an inspection

program, such as the CPEI is not needed to confirm that the BWR Water Chemistry Program is

effective in preventing the aging effect.

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In a letter dated August 15, 2008, the applicant responded to RAI 3.2-3 by providing the

following response:

For the five AMR results lines listed in LRA Tables 3.2.2-1, 3.2.2-3, 3.3.2-3,

3.3.2-25, and 3.4.2-3, where the material is copper alloy, the environment is

treated water (internal), and the aging effect is cracking, verification of the

effectiveness of the BWR Water Chemistry Program is needed. The CPEI will

provide confirmation of the effectiveness of this program in managing the effects

of aging, including cracking in susceptible materials.

LRA Tables 3.2.2-1, 3.2.2-3, 3.3.2-3, 3.3.2-25, and 3.4.2-3 are revised to reflect

these results.

The staff reviewed the applicant's response and the associated LRA changes. The staff

reviewed the applicant's BWR Water Chemistry Program. The staff's evaluation of this

program, which is documented in SER Section 3.0.3.1.1, found that the BWR Water Chemistry

Program provides mitigation for the aging effect of cracking due to stress corrosion cracking.

The staff reviewed the applicant's Chemistry Program Effectiveness Inspection. The staff's

evaluation of this program, which is documented in SER Section 3.0.3.1.10, found that the

CPEI is a one-time inspection that is consistent with the GALL Report's recommendations for

AMP XI.M32, "One-Time Inspection." The CPEI includes provisions for inspecting selected

components in areas of low or stagnant flow and uses examination techniques that are capable

of detecting cracking, if it should occur in the selected components. Because the BWR Water

Chemistry Program provides mitigation and the CPEI provides detection of the aging effect if it

should occur, the staff finds the applicant's proposed AMPs for managing the potential aging

effect of cracking due to stress corrosion cracking in copper alloy piping and piping components

exposed to treated water in the RHR system to be acceptable. On this basis, the staff finds that

the issue raised in RAI 3.2-3 is resolved by the applicant's LRA changes.

LRA Table 3.2.2-1 summarizes the results of AMRs for the RHR system heat exchangers tube

plugs constructed from nickel based alloy which do not have an external surface in contact with

an environment. Therefore, the environment, aging effect requiring management, and AMRs

are not applicable. The staff agrees with this position because these components do not have

an external surface in contact with an environment because their external surface is in contact

with the inside of the heat exchanger tubes.

The applicant has listed a number of component, material, environment combinations as N/A.

Table 3.0-1, "Internal Environments," defines N/A as "N/A internal is used for components for

which an internal environment is not applicable (e.g., strainer screens, heat exchanger fins, flow

elements)." Table 3.0-2, "External Environments," defines N/A external as "N/A is used for

components for which an external environment is not applicable (e.g., tube plugs)."

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

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3.2.2.3.2 Aging Management Review Results - Reactor Core Isolation Cooling -

LRA Table 3.2.2-2

The staff reviewed LRA Table 3.2.2-2, which summarizes the results of AMR evaluations for the

reactor core isolation cooling component groups.

In LRA Table 3.2.2-2, the applicant proposed to manage cracking in copper alloy turbine lube

oil cooler tubes in an internal environment of treated water by using the Heat Exchanger

Inspection Program. The applicant referenced footnote H for this line item indicating that aging

effect is not in NUREG-1 801 for this component, material and environment combination.

The Heat Exchanger Inspection will use volumetric (RT or UT) techniques to verify the absence

of, or to identify the extent of, SCC on the internal surfaces of the copper alloy (admiralty brass)

tubes that are exposed to the treated water environment. The staff's evaluation of the Heat

Exchanger Inspection Program is documented in SER Section 3.0.3.1.12. Because the treated

water environment is less than 140oF, cracking in copper alloy components is of very low

probability, and therefore, the staff finds a one-time inspection activity that performs volumetric

examination to verify the absence of cracking is an adequate aging management program. On

this basis, the staff finds the Heat Exchanger Inspection Program will adequately manage the

aging effects of cracking in copper alloy heat exchanger tubes in an internal environment of

treated water through the period of extended operation.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.2.2.3.3 Aging Management Review Results - Core Spray System - LRA Table 3.2.2-3

The staff reviewed LRA Table 3.2.2-3, which summarizes the results of AMR evaluations for the

core spray system component groups.

In LRA Tables 3.2.2-3 the applicant proposed to manage cracking in copper alloy piping and

piping components in an environment of treated water by using the BWR Water Chemistry

Program, alone. The applicant cited generic Note H for these AMR results, indicating that the

aging effect is not in the GALL Report for this component, material and environment

combination. In a letter dated July 15, 2008, the staff issued RAI 3.2-3, applicable for these

AMR results and for similar AMR results in LRA Tables 3.2.2-1, 3.3.2-3, 3.3.2-25, and 3.4.2-3.

The RAI asked the applicant to provide a technical justification as to why an inspection

program, such as the CPEI is not needed to confirm that the BWR Water Chemistry Program is

effective in preventing the aging effect.

In a letter dated August 15, 2008, the applicant responded to RAI 3.2-3 by providing the

following response:

For the five AMR results lines listed in LRA Tables 3.2.2-1, 3.2.2-3, 3.3.2-3,

3.3.2-25, and 3.4.2-3, where the material is copper alloy, the environment is

treated water (internal), and the aging effect is cracking, verification of the

effectiveness of the BWR Water Chemistry Program is needed. The Chemistry

Program Effectiveness Inspection will provide confirmation of the effectiveness

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of this program in managing the effects of aging, including cracking in

susceptible materials.

LRA Tables 3.2.2-1, 3.2.2-3, 3.3.2-3, 3.3.2-25, and 3.4.2-3 are revised to reflect

these results.

The staff reviewed the applicant's response and the associated LRA changes. The staff

reviewed the applicant's BWR Water Chemistry Program. The staff's evaluation of this

program, which is documented in SER Section 3.0.3.1.1, found that the BWR Water Chemistry

Program provides mitigation for the aging effect of cracking due to stress corrosion cracking.

The staff reviewed the applicant's Chemistry Program Effectiveness Inspection. The staff's

evaluation of this program, which is documented in SER Section 3.0.3.1.10, found that the

CPEI is a one-time inspection that is consistent with the GALL Report's recommendations for

AMP XI.M32, "One-Time Inspection." The CPEI includes provisions for inspecting selected

components in areas of low or stagnant flow and uses examination techniques that are capable

of detecting cracking, if it should occur in the selected components. Because the BWR Water

Chemistry Program provides mitigation and the CPEI provides detection of the aging effect if it

should occur, the staff finds the applicant's proposed AMPs for managing the potential aging

effect of cracking due to stress corrosion cracking in copper alloy piping and piping components

exposed to treated water in the core spray system to be acceptable. On this basis, the staff

finds that the issue raised in RAI 3.2-3 is resolved by the applicant's LRA changes.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.2.2.3.4 Aging Management Review Results - High Pressure Coolant Injection System -

LRA Table 3.2.2-4

The staff reviewed LRA Table 3.2.2-4, which summarizes the results of AMR evaluations for the

high pressure coolant injection system component groups.

In LRA Table 3.2.2-4, the applicant proposed to manage cracking in copper alloy turbine lube

oil cooler tubes in an internal environment of treated water by using the Heat Exchanger

Inspection Program. The applicant referenced footnote H for this line item indicating that aging

effect is not in NUREG-1801 for this component, material and environment combination.

The Heat Exchanger Inspection will use volumetric (RT or UT) techniques to verify the absence

of, or to identify the extent of, SCC on the internal surfaces of the copper alloy (admiralty brass)

tubes that are exposed to the treated water environment. The staff's evaluation of the Heat

Exchanger Inspection Program is documented in SER Section 3.0.3.1.12. Because the treated

water environment is less than 1400 F, cracking in copper alloy components is of very low

probability, and therefore, the staff finds a one-time inspection activity that performs volumetric

examination to verify the absence of cracking is an adequate aging management program. On

this basis, the staff finds the Heat Exchanger Inspection Program will adequately manage the

aging effects of cracking in copper alloy heat exchanger tubes in an internal environment of

treated water through the period of extended operation.

3-294
In LRA Table 3.2.2-4, the applicant identifies that there are no applicable aging effects requiring

management (AERMs) for synthetic rubber flexible connections (hoses) in the HPCI system

under either internal exposure to the lubricating oil environment or external exposure to the

indoor air environment.

The staff noted in the LRA, the applicant appeared to take inconsistent approach to aging

management of elastomeric, rubber, polymeric, and glass components in the application

because some AMRs for these types of materials the applicant had identified that cracking and

changes in material properties were applicable aging effects requiring management (AERMs),

whereas in other AMRs the applicant concluded that AERMs were not applicable to the

components. In RAI 3.2.2.3-1 by letter dated July 23, 2008, the staff asked the applicant to

consolidate its approach to management of aging in the elastomeric, rubber, polymeric, and

glass ESF system components with the aging management approach that the applicant had

taken for these types of components in the auxiliary systems. In RAI 3.2.2.3-1, Part A, the staff

asked the applicant to justify why it had not identified any AERMs for HPCI synthetic rubber

component surfaces that are exposed to lubricating oil and to indoor air when cracking and

changes in materials had been identified as applicable aging effects for: (1) neoprene and

rubber components in the primary containment atmosphere circulation system under exposure

to indoor air and to ventilation air, (2) neoprene/fiberglass components in the reactor building

HVAC system under exposure to indoor air and to ventilation air, and (3) for Teflon piping in the

sampling system (changes in material properties only) under exposure to indoor air. In RAI

3.3.2.3-1, Part B, the staff asked the applicant to identify those material properties and aging

effects that could be impacted by exposure of these synthetic rubber materials to the lubricating

oil and indoor air environments.

In its letter dated July 28, 2009, the applicant revised Table 3.2.2-4, HPCI system to state that

flex connections exposed to an internal environment of lubricating oil and an external

environment of indoor air were fabricated from stainless steel material and not from synthetic

rubber as stated in the LRA. The applicant further stated that stainless steel flex hoses in a

lubricating oil environment will have an aging effect of loss of material and credited the

Lubricated Oil Analysis and the Lubricating Oil Inspection Programs and referenced Table

3.2.1, item 3.2.1-6. This line is now consistent with GALL Report Item V.D1-24 and the

evaluation of this line is addressed in SER Section 3.2.2.2.3.4.

The applicant also stated that stainless steel flex hoses in an indoor air external environment

will have no aging effects and is consistent with GALL Report Item V.F-12. The staff reviewed

the GALL Report and finds the applicant response acceptable. The issue identified in RAI

3.2.2.3-1 is closed.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.2.2.3.5 Aging Management Review Results - Containment and Suppression System -

LRA Table 3.2.2-5

The staff reviewed LRA Table 3.2.2-5, which summarizes the results of AMR evaluations for the

containment and suppression system component groups. The staff determined that all AMR

evaluation results in LRA Table 3.2.2-5 are consistent with the GALL Report.

3-295
3.2.2.3.6 Aging Management Review Results - Containment Atmosphere Control System -

LRA Table 3.2.2-6

The staff reviewed LRA Table 3.2.2-6, which summarizes the results of AMR evaluations for the

containment atmosphere control system component groups. The staff determined that all AMR

evaluation results in LRA Table 3.2.2-6 are consistent with the GALL Report.

3.2.2.3.7 Aging Management Review Results - Standby Gas Treatment System -

LRA Table 3.2.2-7

The staff reviewed LRA Table 3.2.2-7, which summarizes the results of AMR evaluations for the

SGTS component groups.

In LRA Table 3.2.2-7, the applicant proposed to manage loss of material for galvanized steel

ductwork components exposed to an external environment of outdoor air using the SSES AMP

B.2.32 "System Walkdown Program." The staff noted that the applicant amended its LRA by

letter dated September 26, 2008, to add this AMR line item to LRA Table 3.2.2-7.

The AMR line item credits the AMP B.2.32 "System Walkdown Program" to manage loss of

material for these components. The AMR line item cites Generic Note H, which indicates that

the aging effect is not addressed in GALL Report for this component, environment and material

combination. The staff's evaluation of the AMP B.2.32 "System Walkdown Program" is

documented in SER Section 3.0.3.2.14. The staff determined that this program is a condition

monitoring program that will detect the aging effect of loss of material for metals, including

steel, by periodic surveillance activities and observations of components' external surfaces to

detect aging degradation that are within the scope of license renewal. On the basis that the

applicant will be performing periodic visual inspections of these components, the staff finds the

AMR results for this line item acceptable.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.2.3 Conclusion

The staff concludes that the applicant has provided sufficient information to demonstrate that

the effects of aging for the engineered safety features components within the scope of license

renewal and subject to an AMR will be adequately managed so that the intended function(s) will

be maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21(a)(3).

3.3 Aging Management of Auxiliary Systems

This section of the SER documents the staff's review of the applicant's AMR results for the

auxiliary systems components and component groups of:

" Building Drains Nonradioactive System

" Containment Instrument Gas System

3-296
" Control Rod Drive Hydraulic System

" Control Structure Chilled Water System

* Control Structure HVAC Systems

" Cooling Tower System

• Diesel Fuel Oil System

* Diesel Generator Buildings HVAC Systems

* Diesel Generators System

* Domestic Water System

* Emergency Service Water System

* ESSW Pumphouse HVAC System

* Fire Protection System

* Fuel Pool Cooling And Cleanup System And Fuel Pool And Auxiliaries

* Neutron Monitoring System

* Primary Containment Atmosphere Circulation System

* Process And Area Radiation Monitoring System

* Radwaste Liquid System

* Radwaste Solids Handling

* Raw Water Treatment System

* Reactor Building Chilled Water System

* Reactor Building Closed Cooling Water System

* Reactor Building HVAC System

* Reactor Nonnuclear Instrumentation System

* Reactor Water Cleanup System

* RHR Service Water System

* Sampling System

* Sanitary Drainage

* Service Air System

* Service Water System

" Standby Liquid Control System

• Turbine Building Closed Cooling Water System

* Reactor Recirculation System (NSAS portions)

* Reactor Vessel and Auxiliaries System (NSAS portions)

3.3.1 Summary of Technical Information in the Application

LRA Section 3.3 provides AMR results for the auxiliary systems components and component

groups. LRA Table 3.3.1, "Summary of Aging Management Programs for Auxiliary Systems

Evaluated in Chapter VII of the GALL Report," is a summary comparison of the applicant's

AMRs with those evaluated in the GALL Report for the auxiliary systems components and

component groups.

The applicant's AMRs evaluated and incorporated applicable plant-specific and industry OE in

the determination of AERMs. The plant-specific evaluation included condition reports and

discussions with appropriate site personnel to identify AERMs. The applicant's review of

industry OE included a review of the GALL Report and OE issues identified since the issuance

of the GALL Report.

3.3.2 Staff Evaluation

The staff reviewed LRA Section 3.3 to determine whether the applicant provided sufficient

information to demonstrate that the effects of aging for the auxiliary systems components within

3-297
the scope of license renewal and subject to an AMR, will be adequately managed so that the

intended function(s) will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21(a)(3).

The staff conducted an onsite audit of AMRs to ensure the applicant's claim that certain AMRs

were consistent with the GALL Report. The staff did not repeat its review of the matters

described in the GALL Report; however, the staff did verify that the material presented in the

LRA was applicable and that the applicant identified the appropriate GALL Report AMRs. The

staff's evaluations of the AMPs are documented in SER Section 3.0.3. Details of the staff's

audit evaluation are documented in SER Section 3.3.2.1.

In the onsite audit, the staff also selected AMRs consistent with the GALL Report and for which

further evaluation is recommended. The staff confirmed that the applicant's further evaluations

were consistent with the SRP-LR Section 3.3.2.2 acceptance criteria. The staff's audit

evaluations are documented in SER Section 3.3.2.2.

The staff also conducted a technical review of the remaining AMRs not consistent with or not

addressed in the GALL Report. The technical review evaluated whether all plausible aging

effects have been identified and whether the aging effects listed were appropriate for the

material-environment combinations specified. The staff's evaluations are documented in SER

Section 3.3.2.3.

For SSCs which the applicant claimed were not applicable or required no aging management,

the staff reviewed the AMR line items and the plant's OE to verify the applicant's claims.

Table 3.3-1 summarizes the staff's evaluation of components, aging effects or mechanisms,

and AMPs listed in LRA Section 3.3 and addressed in the GALL Report.

Table 3.3-1 Staff Evaluation for Auxiliary Systems Components in the GALL Report

Component Group Aging Effect/ AMP in GALL Further AMP in LRA, Staff Evaluation

(GALL Report Mechanism Report Evaluation Supplements,

Item No.) in GALL or

Report Amendments

Steel cranes - Cumulative TLAA to be Yes Not applicable Not applicable to

structural girders fatigue damage evaluated for SSES (See SER

exposed to air - structural girders of Section 3.3.2.2.1)

indoor uncontrolled cranes. See the

(external) SRP-LR, Section 4.7

(3.3.1-1) for generic guidance

for meeting the

requirements of

10 CFR 54.21(c)(1).

3-298
Component Group Aging Effect/ AMP in GALL Further AMP in LRA, Staff Evaluation

(GALL Report Mechanism Report Evaluation Supplements,

Item No.) in GALL or

Report Amendments

Steel and stainless Cumulative TLAA, evaluated in Yes TLAA TLAA (See SER

steel piping, piping fatigue damage accordance with Section 3.3.2.2.1)

components, piping 10 CFR 54.21(c)

elements, and heat

exchanger

components

exposed to air -

indoor uncontrolled,

treated borated

water or treated

water

(3.3.1-2)

Stainless steel heat Reduction of Water Chemistry and Yes Not applicable Not applicable. The

exchanger tubes heat transfer One-Time Inspection applicant addressed

exposed to treated due to fouling these components

water under GALL Report

(3.3.1-3) Item number

3.3.1-52.

(See SER Section

3.3.2.2.2)

Stainless steel Cracking due to Water Chemistry and Yes Not applicable Not applicable. The

piping, piping SCC One-Time Inspection normal operating

components, and temperature of the

piping elements Standby Liquid

exposed to sodium Control System is

pentaborate solution below 140°F; and

> 60C (> 1400F) therefore, cracking

(3.3.1-4) due to SCC is not an

aging effect requiring

management.

(See SER Section

3.3.2.2.3.1)

3-299
.Component Group Aging Effect/ AMP in GALL Further AMP in ILRAF, Staff Evaluation

(GALL.Report Mechanism Re'port ,Evaluation -- -Supplements,

__________________ e'port' Ameindments

Stainless steel and Cracking due to A plant-specific Yes Not applicable Not applicable. The

stainless clad steel SCC aging management applicant does not

heat exchanger program is to be have stainless steel

components evaluated, or stainless steel

exposed to treated clad heat

water > 60dC exchangers exposed

(> 140d) to treated water

(3.3.1-5) >600C (>1400F) in

the RWCU system.

RWCU heat

exchangers which

are exposed to this

environment are

carbon steel.

However, stainless

steel heat exchanger

components

exposed to treated

water >60'C

(>140'F) in other

auxiliary systems are

evaluated in item

3.3.1-46.

(See SER Section

3.3.2.2.3.2)

Stainless steel diesel Cracking due to A plant-specific Yes Supplemental See SER Section

engine exhaust SCC aging management Piping and 3.3.2.2.3.3

piping, piping program is to be Tanks

components, and evaluated. Inspection

piping elements Program

exposed to diesel (B.2.28)

exhaust

(3.3.1-6)

Stainless steel non- Cracking due to Water Chemistry and Yes Not applicable Not applicable to

regenerative heat SCC and cyclic a plant-specific BWRs (See SER

exchanger loading verification program. Section 3.3.2.2.4.1)

components An acceptable

exposed to treated verification program

borated water > 60'C is to include

(>: 140F) temperature and

(3.3.1-7) radioactivity

monitoring of the

shell side water, and

eddy current testing

of tubes.

3-300
Component Giroup 4Aging Effect/ •-"f AMP'in GALL Further . AMP in LRA,. Staff Ev'aluation

(GALLReporti Mechanism Report Evaluation. Supplements,

ItmNo) in GALL or, Ke'ort enur s"t.

Stainless steel Cracking due to Water Chemistry and Yes Not applicable Not applicable to

regenerative heat SCC and cyclic a plant-specific BWRs (See SER

exchanger loading verification program. Section 3.3.2.2.4.2)

components The AMP is to be

exposed to treated augmented by

borated water > 60'C verifying the absence

(> 1401F) of cracking due to

(3.3.1-8) SCC and cyclic

loading. A plantspecific aging

management

program is to be

evaluated.

Stainless steel high- Cracking due to Water Chemistry and Yes Not applicable Not applicable to

pressure pump SCC and cyclic a plant-specific BWRs (See SER

casing in PWR loading verification program. Section 3.3.2.2.4.3)

chemical and volume The AMP is to be

control system augmented by

(3.3.1 9) verifying the absence

of cracking due to

SCC and cyclic

loading. A plantspecific aging

management

program is to be

evaluated.

High-strength steel. Cracking due to Bolting Integrity. Yes Not applicable Not Applicable. High.

closure bolting , SCC, cyclic The AMP is to be strength steel bolting

exposed toair with loading augmented by is not used in the

steam or water appropriate auxiliary systems.

leakage. inspection, to detect

(3.311-10) . cracking if the bolts.

are not otherwise

replaced during

maintenance.

Elastomer seals and Hardening and A plant-specific Yes System Consistent with

components loss of strength aging management Walkdown GALL Report

exposed to air - due to elastomer program is to be Program

indoor uncontrolled degradation evaluated. (B.2.32) (See SER Section

(intemal/extemal) 3.3.2.2.5.1)

(3.3.1-11)

Elastomer lining Hardening and A plant-specific Yes Not Applicable See SER Section

exposed to treated loss of strength aging management 3.3.2.2.5.2

water or treated due to elastomer program is to be

borated water degradation evaluated.

(3.3.1-12)

3-301
Component.Group 'Agig EAffect AA in LRAP.A Staff Evaluation

(GALLReport Mechanism Report Evaluation supplements, .ItemNo.),,:.. in GALL or

....._.... _Report .. Amendments.

Boral, boron steel Reduction of A plant-specific Yes BWR Water Consistent with the

spent fuel storage neutron- aging management Chemistry GALL Report

racks neutron- absorbing program is to be Program (B.2.2)

absorbing sheets capacity and evaluated. (See SER Section

exposed to treated loss of material 3.3.2.2.6)

water or treated due to general

borated water corrosion

(3.3.1-13)

Steel piping, piping Loss of material Lubricating Oil Yes Lubricating Oil Consistent with

component, and due to general; Analysis and Analysis GALL Report

piping elements pitting, and One-Time Inspection Program

exposed to crevice (B.2.33) and (See SER Section

lubricating oil corrosion Lubricating Oil 3.3.2.2.7.1)

(3.3.1-14) Inspection

Program

(B.2.25)

Steel reactor coolant Loss of material Lubricating Oil Yes Not applicable Not applicable

pump oil collection due to general, Analysis and

system piping, pitting, and One-Time Inspection (See SER Section

tubing, and valve crevice 3.3.2.2.7.1)

bodies exposed to corrosion

lubricating oil

(3.3.1-15)

Steel reactor coolant Loss of material Lubricating Oil Yes Not applicable Not applicable

pump oil collection due to general, Analysis and

system tank exposed pitting, and One-Time Inspection (See SER Section

to lubricating oil crevice to evaluate the 3.3.2.2.7.1)

(3.3.1-16) corrosion thickness of the

lower portion of the

tank

Steel piping, piping Loss of material Water Chemistry and Yes BWR Water Consistent with

components, and due to general, One-Time.Inspection Chemistry GALL Report

piping elements pitting, and Program (B.2.2)

exposed to treated crevice. and Chemistry (See SER Section

water corrosion. Program 3.3.2.2.7.2)

(3.3.1-17) Effectiveness

Inspection

(B.2.22)

Stainless steel and Loss of A plant-specific Yes System See SER Section

steel diesel engine material/general aging management Walkdown 3.3.2.2.7.3

exhaust piping, (steel only), program is to be Program

piping components, pitting and evaluated. (B.2.32)

and piping elements crevice

exposed to diesel corrosion

exhaust

(3.3.1-18)

3-302
Component Group Aging Effect/ AMP in GALL. Further AMP in. LRA, Staff Evaluation ,(GALL Report Mechanism Report Evaluation Supplements,,

item No.) in-GALL or

" Repbrt Amendments

Steel (with or without Loss of material Buried Piping and No Buried Piping Consistent with

coating or wrapping) due to general, Tanks Surveillance and Tanks GALL Report (See

piping, piping pitting, crevice, Surveillance SER Section

components, and and MIC or (B.2.18) and 3.3.2.2.8)

piping elements Buried Piping

exposed to soil Buried Piping and Yes and Tanks

(3.3.1-19) Tanks Inspection Inspection

(B.2.30)

Steel piping, piping Loss of material Fuel Oil Chemistry Yes Fuel Oil Consistent with

components, piping due to general, and One-Time Chemistry GALL Report

elements, and tanks pitting, crevice, Inspection Program

exposed to fuel oil and MIC, and (B.2.20) and (See SER Section

(3.3.1-20) fouling Chemistry 3.3.2.2.9.1)

Program

Effectiveness

Inspection

-. __ (B.2.22)

Steel heat exchanger Loss of material Lubricating Oil Yes Lubricating Oil Consistent with

components due to general, Analysis and Analysis GALL Report (See

exposed to pitting, crevice, One-Time Inspection (B.2.33) and SER Section

lubricating oil and MIC, and Lubricating Oil 3.3.2.2.9.2)

(3.3.1-21) fouling Inspection

(B.2.25)

Steel with elastomer Loss of material Water Chemistry and Yes Not Applicable See SER Section

lining or stainless due to pitting One-Time Inspection 3.3.2.2.10.1

steel cladding piping, and crevice

piping components, corrosion (only

and piping elements for steel after

exposed to treated lining/cladding

water and treated degradation)

borated water

(3.3.1-22)

Stainless steel and Loss of material Water Chemistry and Yes Closed Cooling Consistent with

steel with stainless due to pitting One-Time Inspection Water GALL Report

steel cladding heat and crevice Chemistry

exchanger corrosion Program (See SER Section

components (B.2.14) and 3.3.2.2.10.2)

exposed to treated Chemistry

water Program

(3.3.1-23) Effectiveness

Inspection

(B.2.22)

Closed Cooling

Water

Chemistry

Program

(B.2.14)

3-303
:ComponentGroup "AgingEffecti AMP in GALL Further AMP in-LRA, Staff Evaluation

(GALL Report Mechanism, Report Evaluation Supplements,

ItermNo.) in GALL or

Report Amendments

Stainless steel and Loss of material Water Chemistry and Yes BWR Water Consistent with

aluminum piping, due to pitting One-Time Inspection Chemistry GALL Report

piping components, and crevice Program (B.2.2),

and piping elements corrosion and Chemistry (See SER Section

exposed to treated Program 3.3.2.2.10.2)

water Effectiveness

(3.3.1-24) Inspection

(B.2.22), or

BWR Water

Chemistry

Program (B.2.2),

or

Closed Cooling

Water

Chemistry

Program

(B.2.14) and

Chemistry

Program

Effectiveness

Inspection

(B.2.22)

Copper alloy HVAC Loss of material A plant-specific Yes System Consistent with

piping, piping due to pitting aging management Walkdown GALL Report

components, piping and crevice program is to be (B.2.32),

elements exposed to corrosion evaluated. Cooling Units (See SER Section

condensation Inspection 3.3.2.2.10.3)

(external) (B.2.23), and

(3.3.1-25) Selective

Leaching

Inspection

(B.2.29)

Copper alloy piping, Loss of material Lubricating Oil Yes Lubricating Oil Consistent with

piping components, due to pitting Analysis and Analysis GALL Report

and piping elements and crevice One-Time Inspection Program

exposed to corrosion (B.2.33) and (See SER Section

lubricating oil Lubricating Oil 3.3.2.2.10.4)

(3.3.1-26) Inspection

Program

i(B.2.25)

Stainless steel Loss of material A plant-specific Yes System Consistent with the

HVAC ducting and due to pitting aging management Walkdown GALL. Report

aluminum HVAC and crevice program is to be (B.2.32),

piping, piping corrosion evaluated. Cooling Units (See SER Section

components and Inspection 3.3.2.2.10.5)

piping elements (B.2.23), and

exposed to Supplemental

condensation Piping/Tank

(3.3.1-27) Inspection

(B.2.28)

3-304
Component Group Aging EffecVt. AMP in GALL Further AMP in LRA, Staff Evaluation

(GALL.Report Mechanism . Report Evaluation Supplements,

Item- No.) in"GALL or,

'___.___ __.._"___....__ ., ..Report Amendments

Copper alloy fire Loss of material A plant-specific Yes Not Applicable See SER Section

protection piping, due to pitting aging management 3.3.2.2.10.6

piping components, and crevice program is to be

and piping elements corrosion evaluated.

exposed to

condensation

(internal)

(3.3.1-28)

Stainless steel Loss of material A plant-specific Yes Not applicable See SER Section

piping, piping due to pitting aging management 3.3.2.2.10.7

components, and and crevice program is to be

piping elements corrosion evaluated.

exposed to soil

(3.3.1-29)

Stainless steel Loss of material Water Chemistry and Yes BWR Water Consistent with

piping, piping due to pitting One-Time Inspection Chemistry GALL Report

components, and and crevice Program (B.2.2)

piping elements corrosion and Chemistry (See SER Section

exposed to sodium Program 3.3.2.2.10.8)

pentaborate solution Effectiveness

(3.3.1-30) Inspection (B.2.22)

Copper alloy piping, Loss of material Water Chemistry and Yes BWR Water Consistent with

piping components, due to pitting, One-Time Inspection Chemistry GALL Report

and piping elements crevice, and Program (B.2.2)

exposed to treated galvanic and Chemistry (See SER Section

water corrosion Program 3.3.2.2.11)

(3.3.1-31) Effectiveness

Inspection

(B.2.22)

Stainless steel, Loss of material Fuel Oil Chemistry Yes Fuel Oil Consistent with the

aluminum and due to pitting, and One-Time Chemistry GALL Report

copper alloy piping, crevice, and MIC Inspection Program

piping components, (P.2.20) and (See SER Section

and piping elements Chemistry 3.3.2.2.12.1)

exposed to fuel oil Program

(3.3.1-32) Effectiveness

Inspection

(B.2.22)

Stainless steel Loss of material Lubricating Oil Yes Lubricating Oil Consistent with

piping, piping due to pitting, Analysis and Analysis GALL Report

components, and crevice, and MIC One-Time Inspection Program

piping elements (B.2.33) and (See SER Section

exposed to Lubricating Oil 3.3.2.2.12.2)

lubricating oil Inspection

(3.3.1-33) Program

(B.2.25)

3-305
.Component Group Aging Effectl/ AMP in GALL Further AMP in.LRA, Staff Evaluation,

(GALL Report Mechanism. Report Evaluatione Supplements,

Item No.) in GALL or

_ _Report Amendments

Elastomer seals and Loss of material A plant-specific Yes Not Applicable See SER Section

components due to wear aging management 3.3.2.2.13

exposed to air - program is to be

indoor uncontrolled evaluated.

(internal or external)

(3.3.1-34)

Steel with stainless Loss of material A plant-specific Yes Not applicable Not applicable to

steel cladding pump due to cladding aging management BWRs (See SER

casing exposed to breach program is to be Section 3.3.2.2.14)

treated borated evaluated.

water

(3.3.1-35) Reference NRC

IN 94-63, "Boric Acid

Corrosion of

Charging Pump

Casings Caused by

Cladding Cracks."

Boraflex spent fuel Reduction of Boraflex Monitoring No Not applicable Not applicable to

storage racks neutron- SSES (See SER

neutron-absorbing absorbing Section 3.3.2.1.1)

sheets exposed to capacity due to

treated water boraflex

(3.3.1-36) degradation

Stainless steel Cracking due to BWR Reactor Water No BWR Water Consistent with

piping, piping SCC, IGSCC Cleanup System Chemistry GALL Report

components, and Program (B.2.2)

piping elements and Chemistry (See SER Section

exposed to treated Program 3.3.2.1.2)

water > 60°C Effectiveness

(> 140F) Inspection

(3.3.1-37) (B.2.22)

Stainless steel Cracking due to BWR Stress No Not applicable Addressed in line

piping, piping SCC Corrosion Cracking item 3.3.1-37.

components, and and Water Chemistry

piping elements

exposed to treated

water > 60C

(> 140F=)

(3.3.1-38) 1 1 1 _1

3-306
Component Group Aging Effect/ AMP in GALL Further AMP in LRA, Staff Evaluation

(GALL Report Mechanism Report Evaluation Supplements,

ItemN0.) in GALL or.

____...________ Report Amendments.

Stainless steel BWR Cracking due to Water Chemistry No Not applicable Not applicable

spent fuel storage SCC because spent fuel

racks exposed to pool water

treated water > 60dC temperature is

(> 140F) maintained well

(3.3.1-39) below 60*C

(<140'F). This

component, material,

environment

combination does

not exist, and the

aging effect

identified in the

GALL Report does

not apply.(See SER

Section 3.3.2.1.1)

Steel tanks in diesel Loss of material Aboveground Steel No Not applicable Not applicable to

fuel oil system due to general, Tanks SSES. (See SER

exposed to air - pitting, and Section 3.3.2.1.1)

outdoor (external) crevice

(3.3.1-40) corrosion

High-strength steel Cracking due to Bolting Integrity No Bolting Integrity Consistent with

closure bolting cyclic loading, Program GALL Report

exposed to air with SCC (B.2.12)

steam or water

leakage

(3.3.1-41)

Steel closure bolting Loss of material Bolting Integrity No Bolting Integrity Consistent with

exposed to air with due to general Program GALL Report

steam or water corrosion (B.2 12)

leakage

(-3.3.1-42)

Steel bolting and Loss of material Bolting Integrity No Bolting Integrity Consistent with

closure bolting due to general, Program GALL Report

exposed to air - pitting, and (B.2.12)

indoor uncontrolled crevice

(external) or air - corrosion

outdoor (external)

(3.3.1-43)

Steel compressed air Loss of material Bolting Integrity No Bolting Integrity Consistent with

system closure due to general, Program GALL Report

bolting exposed to pitting, and (B.2.12)

condensation crevice

(3.3.1-44) corrosion

Steel closure bolting Loss of preload Bolting Integrity No Bolting Integrity Consistent with

exposed to air - due to thermal Program GALL Report

indoor uncontrolled effects, gasket (B.2.12)

(external) creep, and self-

(3.3.1-45) loosening

3-307
Component Group Aging Effect/l AMP in GALL. Further AMP in LRA, Staff Evaluation

(GALL Report Mechanism Report Evaluation Supplements,

Item No.) in GALL or

Report Amendments

Stainless steel and Cracking due to Closed-Cycle No Closed Cooling Consistent with

stainless clad steel SCC Cooling Water Water GALL Report

piping, piping System Chemistry

components, piping Program (See SER Section

elements, and heat (B.2.14) and 3.3.2.1.3)

exchanger Chemistry

components Program

exposed to closed Effectiveness

cycle cooling Inspection

water > 6Mt (B.2.22)

(> 140F)

(3.3.1-46)

Steel piping, piping Loss of material Closed-Cycle No Closed Cooling Consistent with

components, piping due to general, Cooling Water Water GALL Report

elements, tanks, and pitting, and System Chemistry

heat exchanger crevice Program (See SER Section

components corrosion (B.2.14), or 3.3.2.1.4)

exposed to closed

cycle cooling water Closed Cooling

(3.3.1-47) Water

Chemistry

Program

(B.2.14) and

Chemistry

Program

Effectiveness

Inspection

(B.2.22)

Steel piping, piping Loss of material Closed-Cycle No Closed Cooling Consistent with

components, piping due to general, Cooling Water Water GALL Report

elements, tanks, and pitting, crevice, System Chemistry

heat exchanger and galvanic Program (See SER Section

components corrosion (B.2.14) and 3.3.2.1.5.)

exposed to closed Chemistry

cycle cooling water Program

(3.3.1-48) Effectiveness

Inspection

(B.2.22)

Stainless steel; steel

with stainless steel

cladding heat

exchanger

components

exposed to closed

cycle cooling water

(3.3.1-49)

Loss of material

due to MIC

Closed-Cycle

Cooling Water

System

No Not applicable Not applicable to

SSES (See SER

Section 3.3.2.1.1)

3-308
Component Group Aging Effect/ AMP inGALL Further,: AMP in LRA,, Staff Evaluation

(GALL Report. Mechanism Report . Evaluation" Supplements,

Item No 4in, GALL o

_________ ___________ epoiort Amendimeits,

Stainless steel Loss of material Closed-Cycle No Closed Cooling Consistent with

piping, piping due to pitting Cooling Water Water GALL Report

components, and and crevice System Chemistry

piping elements corrosion Program (See SER Section

exposed to closed (B.2.14) and 3.3.2.1.6.)

cycle cooling water Chemistry

(3.3.1-50) Program

Effectiveness

Inspection

(B.2.22)

Copper alloy piping, Loss of material Closed-Cycle No Closed Cooling Consistent with

piping components, due to pitting, Cooling Water Water GALL Report

piping elements, and crevice, and System Chemistry

heat exchanger galvanic Program (See SER Section

components corrosion (B.2.14) and 3.3.2.1.7)

exposed to closed Chemistry

cycle cooling water Program

(3.3.1-51) Effectiveness

Inspection

(B.2.22)_

Steel, stainless steel, Reduction of Closed-Cycle No Heat Exchanger Consistent with

and copper alloy heat transfer Cooling Water Inspection GALL Report (See

heat exchanger due to fouling System (B.2.24) SER Section

tubes exposed to 3.3.2.1.10)

closed cycle cooling

water

(3.3.1-52)

Steel compressed air Loss of material Compressed Air No Area-Based See SER Section

system piping, piping due to general Monitoring NSAS 3.3.2.1.9

components, and and pitting Inspection

piping elements corrosion (B.2.46)

exposed to

condensation

(internal)

(3.3.1-53)

Stainless steel Loss of material Compressed Air No Area-Based See SER Section

compressed air due to pitting Monitoring NSAS 3.3.2.1.9

system piping, piping and crevice Inspection

components, and corrosion (B.2.46)

piping elements

exposed to internal

condensation

(3.3.1-54)

Steel ducting closure Loss of material External Surfaces No System Consistent with

bolting exposed to due to general Monitoring Walkdown GALL Report

air - indoor corrosion Program

uncontrolled (6.2.32)

(external)

(3.3.1-55)

3-309
Component Group Aging Effect/ AMP in GALL Further AMP in LRA, Staff Evaluation

(GALLReport Mechanism Report Evaluation Supplements,

Item No.) in GALL or

__________- ____ _ __ Report AmendmentsSteel HVAC ducting Loss of material External Surfaces No Fire Water Consistent with

and components due to general Monitoring System Program GALL Report

external surfaces corrosion (B.2.17)

exposed to air -

indoor uncontrolled

(external)

(3.3.1-56)

Steel piping and Loss of material External Surfaces No System Consistent with

components external due to general Monitoring Walkdown GALL Report

surfaces exposed to corrosion Program

air - indoor (B.2.32)

uncontrolled

(External)

(3.3.1-57)

Steel external Loss of material External Surfaces No System Consistent with

surfaces exposed to due to general Monitoring Walkdown GALL Report

air - indoor corrosion Program

uncontrolled (B.2.32) and

(external), air - Selective

outdoor (external), Leaching

and condensation Inspection

(external) Program

(3.3.1-58) (B.2.29)

Steel heat exchanger Loss of material External Surfaces No System Consistent with

components due to general, Monitoring Walkdown GALL Report

exposed to air - pitting, and Program

indoor uncontrolled crevice (B.2.32)

(external) or air - corrosion

outdoor (external)

(3.3.1-59)

Steel piping, piping Loss of material External Surfaces No, Not applicable Addressed in line

components, and dueto general, Monitoring item 3.3.1-58 (See

piping elements pitting, and SER Section

exposed to air - crevice 3.3.2.1.1)

outdoor (external) corrosion

(3.3.1-60)

Elastomer fire barrier Increased Fire Protection No Fire Protection Consistent with the

penetration seals hardness, (B.2.16) GALL Report

exposed to shrinkage and

air - outdoor or loss of strength

air - indoor due to

uncontrolled weathering

(3.3.1-61)

Aluminum piping, Loss of material Fire Protection No Not applicable Not applicable to

piping components, due to pitting SSES (See SER

and piping elements and crevice Section 3.3.2.1.1)

exposed to raw water corrosion

(3.3.1-62) 1 1 1

3-310
Component Group ,Agng Effect/ AMP in GALL' Further AMP in LRA, Staff Evaluation

(GALL Report'' Mechanism Report. Evaluation Supplements,

Item No.), in GALL or

Report Amendmnts

Steel fire rated doors Loss of material Fire Protection No Fire Protection Not Consistent with

exposed to air - due to wear (B.2.16) GALL Report

outdoor or

air - indoor (See SER Section

uncontrolled 3.5.2.3.10)

(3.3.1-63)

Steel piping, piping Loss of material Fire Protection and No Fuel Oil Consistent with

components, and due to general, Fuel Oil Chemistry Chemistry GALL Report

piping elements pitting, and Program

exposed to fuel oil crevice (B.2.20) and

(3.3.1-64) corrosion Fire Protection

Program

(6.2.16)

Chemistry

Program

Effectiveness

Inspection

(B.2.22)

Reinforced concrete Concrete Fire Protection and No Not applicable Evaluated in LRA

structural fire barriers cracking and Structures Table 3.5 (See SER

- walls, ceilings and spalling due to Monitoring Program Section 3.3.2.1.1)

floors exposed to air aggressive

- indoor uncontrolled chemical attack,

(3.3.1-65) and reaction

with aggregates

Reinforced concrete Concrete Fire Protection and No Not applicable Evaluated in LRA

structural fire barriers cracking and Structures Table 3.5 (See SER

- walls, ceilings and spalling due to Monitoring Program Section 3.3.2.1.1)

floors exposed to air freeze thaw,

- outdoor aggressive

(3.3.1-66) chemical attack,

and reaction

with aggregates

Reinforced concrete Loss of material Fire Protection and No Notapplicable Evaluated in LRA.

structural fire barriers due to corrosion Structures Table 3.5 (See SER

- walls, ceilings and of embedded Monitoring Program Section 3.3.2.1.1)

floors exposed to air steel

- outdoor or air -

indoor uncontrolled

(3.3.1-67)

Steel piping, piping Loss of material Fire Water System No Fire.Water Consistent with

components, and due to general, System Program GALL Report

piping elements pitting, crevice, (B.2.17)

exposed to raw water and MIC, and

(3.3.1-68) fouling

Stainless steel Loss of material Fire Water System No Fire Water Consistent with

piping, piping due to pitting System Program GALL Report

components, and and crevice (B.2.17)

piping elements corrosion, and

exposed to raw water fouling

(3.3.1-69)

3-311
Component Group Aging Effect/ AMP in.GALL Further AMP in LRA, Staff Evaluation

(GALL Report Mechanism Report Evaluation" Supplements,

Item. No:) .) in GALL, or

- Reort mendments

Copper alloy piping, Loss of material Fire Water System No Fire Water Consistent with

piping components, due to pitting, System Program GALL Report

and piping elements crevice, and (B.2.17)

exposed to raw water MIC, and fouling

(3.3.1-70)

Steel piping, piping Loss of material Inspection of Internal No Supplemental Consistent with

components, and due to general, Surfaces in Piping/Tank GALL Report

piping elements pitting, and Miscellaneous Piping Inspection

exposed to moist air crevice and Ducting Program

or condensation corrosion Components (B.2.28)

(intemal)

(3.3.1-71)

Steel HVAC ducting Loss of material Inspection of Internal No Systems Consistent with

and components due to general, Surfaces in Walkdown GALL Report

internal surfaces pitting, crevice, Miscellaneous Piping program

exposed to' and (for drip and Ducting (B.2.32) (See SER Section

condensation pans and drain Components 3.3.2.1.8)

(internal) lines) MIC

(3.3.1-72)

Steel crane structural Loss of material Inspection of No Crane Consistent with

girders in load due to general Overhead Heavy Inspection GALL Report

handling system corrosion Load and Light Load Program

exposed to air - (Related to (B.2.15)

indoor uncontrolled Refueling) Handling

(external) Systems

(3.3.1-73)

Steel cranes - rails Loss-of material Inspection of, No Not applicable. Evaluated in LRA

exposed to air - due to wear Overhead Heavy Table.3.5 (See SER

indoor uncontrolled Load andLight Load Section 3.3.2.1.1)

(external) (Related to

(3.3.1-74) Refueling) Handling

Systems

Elastomer seals and ýHardening and Open-Cycle Cooling No Not applicable Evaluated in LRA

components loss of strength Water System Table 3.5 (See SER

exposed, to raw water due to elastomer Section 3.3.2.1.1)

(3.3.1-75) degradation;

loss of material

due:to erosion

Steel piping, piping Loss of material Open-Cycle Cooling No Piping Corrosion Consistent with

components, and due to general, Water System Program GALL Report

piping elements pitting, crevice, (B.2.13)

(without lining/ and MIC,

coating or with fouling, and

degraded lining/coating

lining/coating) degradation

exposed to raw water

(3.3.1-76)

Steel heat exchanger Loss of material Open-Cycle Cooling No Piping Corrosion Consistent with

components due to general, Water System Program GALL Report

exposed to raw water pitting, crevice, (B.2.13)

(3.3.1-77) galvanic, and

MIC, and fouling

3-312
Component Group 'Aging Effect/ AMP in GALL Further AMP in LRA,• Staff Evaluation .

(GALL Repo.t.Mec ism Report Evaluation; Supplementsi,

Item No.): i n 'GALL r

/-Report; Amendme6nts.

Stainless steel, Loss of material Open-Cycle Cooling No Piping Corrosion Consistent with

nickel alloy, and due to pitting Water System Program GALL Report

copper alloy piping, and crevice (B.2.13)

piping components, corrosion

and piping elements

exposed to raw water

(3.3.1-78)

Stainless steel Loss of material Open-Cycle Cooling No Piping Corrosion Consistent with

piping, piping due to pitting Water System Program GALL Report

components, and and crevice (B.2.13)

piping elements corrosion, and

exposed to raw water fouling

(3.3.1-79)

Stainless steel and Loss of material Open-Cycle Cooling No Piping Corrosion Consistent with

copper alloy piping, due to pitting, Water System Program GALL Report

piping components, crevice, and MIC (B.2.13)

and piping elements

exposed to raw water

(3.3.1-80)

Copper alloy piping, Loss of material Open-Cycle Cooling No Piping Corrosion Consistent with

piping components, due to pitting, Water System Program GALL Report

and piping elements, crevice, and (B.2.13)

exposed to raw water MIC, and fouling

(3.3.1-81)

Copper alloy heat Loss of material Open-Cycle Cooling No Piping Corrosion Consistent with

exchanger due to pitting, Water System Program GALL Report

components crevice, (B.2.13)

exposed to raw water galvanic, and

(3.3.1-82) MIC, and fouling

Stainless steel and Reduction of Open-Cycle Cooling No Piping Corrosion Consistent with

Copper alloy heat heat transfer Water System Program GALL Report

exchanger tubes due to fouling 1(B.2.13)

exposed to raw water (See SER Section

(3.3.1-83) Heat Exchanger 3.3.2.1.10)

Inspection

(B.2.24)

Copper alloy Loss of material Selective Leaching No Selective Consistent with

> 15% Zn piping, due to selective of Materials Leaching GALL Report

piping components, leaching Inspection

piping elements, and Program

heat exchanger (B.2.29) and

components Cooling Units

exposed to raw Inspection

water, treated water, Program

or closed cycle (B.2.23)

cooling water

(3.3.1-84)

3-313
Component Group Aging Effect/ AMP in GALL Further AMP in LRA, Staff Evaluation

(GALL Report Mechanism. Report Evaluation Supplements,

ItemN) -- in GALL or,

-Report AmnetndmentsGray cast iron piping, Loss of material Selective Leaching No Selective Consistent with

piping components, due to selective of Materials Leaching GALL Report

and piping elements leaching Inspection

exposed to soil, raw Program

water, treated water, (B.2.29)

or closed-cycle

cooling water

(3.3.1-85)

Structural steel (new Loss of material Structures No Not applicable Not applicable to

fuel storage rack due to general, Monitoring Program SSES

assembly) exposed pitting, and

to air - indoor crevice

uncontrolled corrosion

(external)

(3.3.1-86)

Boraflex spent fuel Reduction of Boraflex Monitoring No Not applicable Not applicable to

storage racks neutron- BWRs

neutron-absorbing absorbing

sheets exposed to capacity due to

treated borated boraflex

water degradation

(3.3.1-87)

Aluminum and Loss of material Boric Acid Corrosion No Not applicable Not applicable to

copper alloy due to boric acid BWRs

> 15% Zn piping, corrosion

piping components,

and piping elements

exposed to air with

borated water

leakage

(3.3.1-88)

Steel bolting and Loss of material Boric Acid Corrosion No Not applicable Not applicable to

external surfaces due to boric acid BWRs

exposed to air with corrosion

borated water

leakage

(3.3.1-89)

Stainless steel and Cracking due to Water Chemistry No Not applicable Not applicable to

steel with stainless SCC BWRs

steel cladding piping,

piping components,

piping elements,

tanks, and fuel

storage racks

exposed to treated

borated water > 60t

(> 140'F)

(3.3.1-90)

3-314
Corm-o"nent Groupl] •.:Aging'Effect AMP"A'i FGALLUrher-AMP in LRA. Staff EValuation

(GALLReportv Mechanism; Re 1port Evaluationm 'Supplements,

Atem.;No.7 .In GAL or:

RAeport Amein'dments.

Stainless steel and Loss of material Water Chemistry No Not applicable Not applicable to

steel with stainless due to pitting BWRs

steel cladding piping, and crevice

piping components, corrosion

and piping elements

exposed to treated

borated water

(3.3.1-91)

Galvanized steel None None No None Consistent with

piping, piping GALL Report

components, and

piping elements

exposed to air -

indoor uncontrolled

(3.3.1-92)

Glass piping None None No None Consistent with

elements exposed to GALL Report

air, air - indoor

uncontrolled

(external), fuel oil,

lubricating oil, raw

water, treated water,

and treated borated

water

(3.3.1-93)

Stainless steel and None None No None Consistent with

nickel alloy piping,. GALL Report

piping components,

and piping elements

exposed to air -

indoor uncontrolled

(external)

(3.3.1-94)

Steel and aluminum None None No None Consistent with

piping, piping GALL Report

components, and

piping elements

exposed to air -

indoor controlled

(external)

(3.3.1-95)

Steel and stainless None None No None Consistent with

steel piping, piping GALL Report

components, and

piping elements in

concrete

(3.3.1-96)

3-315
Component.Group Aging. Effect/ AMP in GALL" Further AMP in LRA, Staff Evaluation

(GALL Report Mechanism Report Evaluation, Supplements,

Item No.) in GALL or

-. _______.___"__ ,Report- Amendments

Steel, stainless steel, None None No None Consistent with

aluminum, and GALL Report

copper alloy piping,

piping components,

and piping elements

exposed to gas

(3.3.1-97)

Steel, stainless steel, None None No None Consistent with

and copper alloy GALL Report

piping, piping

components, and

piping elements

exposed to dried air

(3.3.1-98) ..

Stainless steel and None None No Not applicable Not applicable to

copper alloy BW Rs

< 15% Zn piping,

piping components,

and piping elements

exposed to air with

borated water

leakage

(3.3.1-99)

The staff's review of the auxiliary systems component groups followed any one of several

approaches. One approach, documented in SER Section 3.3.2.1, reviewed AMR results for

components that the applicant indicated are consistent with the GALL Report and require no

further evaluation. Another approach, documented in SER Section 3.3.2.2, reviewed AMR

results for components that the applicant indicated are consistent with the GALL Report and for

which further evaluation is recommended. A third approach, documented in SER

Section 3.3.2.3, reviewed AMR results for components that the applicant indicated are not

consistent with, or not addressed in, the GALL Report. The staff's review of AMPs credited to

manage or monitor aging effects of the auxiliary systems components is documented. in SER

Section 3.0.3.

3.3.2.1 AMR Results Consistent with the GALL Report

LRA Section 3.3.2.1 identifies the materials, environments, AERMs, and the following programs

that manage aging effects for the auxiliary systems components:

* BWR Water Chemistry Program

* Flow-Accelerated Corrosion (FAC) Program

* Bolting Integrity Program

* Piping Corrosion Program

* Closed Cooling Water Chemistry Program

* Fire Water System Program . .

* Buried Piping Surveillance Program

* Fuel Oil Chemistry Program

* Chemistry Program Effectiveness Inspection

3-316
* Cooling Units Inspection " Heat Exchanger Inspection

* Lubricating Oil Inspection

* Monitoring and Collection System Inspection

* Supplemental Piping/Tank Inspection

* Selective Leaching Inspection

* Buried Piping and Tanks Inspection Program

* System Walkdown Program

* Lubricating Oil Analysis Program

* Area-Based NSAS Inspection

LRA Tables 3.3.2-1 through 3.3.2-34 summarize AMRs for the auxiliary systems components

and indicate AMRs claimed to be consistent with the GALL Report.

For component groups evaluated in the GALL Report for which the applicant claimed

consistency with the report and for which it does not recommend further evaluation, the staff's

audit and review determined whether the plant-specific components of these GALL Report

component groups were bounded by the GALL Report evaluation.

The applicant noted for each AMR line item how the information in the tables aligns with the

information in the GALL Report. The staff audited those AMRs with notes A through E

indicating how the AMR is consistent with the GALL Report.

Note A indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP is consistent with the GALL

Report AMP. The staff audited these line items to verify consistency with the GALL Report and

validity of the AMR for the site-specific conditions.

Note B indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP takes some exceptions to the

GALL Report AMP. The staff audited these line items to verify consistency with the GALL

Report and verified that the identified exceptions to the GALL Report AMPs have been

reviewed and accepted. The staff also determined whether the applicant's AMP was consistent

with the GALL Report AMP and whether the AMR was valid for the site-specific conditions.

Note C indicates that the component for the AMR line item, although different from, is

consistent with the GALL Report for material, environment, and aging effect. In addition, the

AMP is consistent with the GALL Report AMP. This note indicates that the applicant was unable

to find a listing of some system components in the GALL Report; however, the applicant

identified in the GALL Report a different component with the same material, environment, aging

effect, and AMP as the component under review. The staff audited these line items to verify

consistency with the GALL Report. The staff also determined whether the AMR line item of the

different component was applicable to the component under review and whether the AMR was

valid for the site-specific conditions.

Note D indicates that the component for the AMR line item, although different from, is

consistent with the GALL Report for material, environment, and aging effect. In addition, the

AMP takes some exceptions to the GALL Report AMP. The staff audited these line items to

verify consistency with the GALL Report. The staff verified whether the AMR line item of the

different component was applicable to the component under review and whether the identified

exceptions to the GALL Report AMPs have been reviewed and accepted. The staff also

3-317
determined whether the applicant's AMP was consistent with the GALL Report AMP and

whether the AMR was valid for the site-specific conditions.

Note E indicates that the AMR line item is consistent with the GALL Report for material,

environment, and aging effect, but credits a different AMP. The staff audited these line items to

verify consistency with the GALL Report. The staff also determined whether the credited

AMP would manage the aging effect consistently with the GALL Report AMP and whether the

AMR was valid for the site-specific conditions.

The staff audited and reviewed the information in the LRA. The staff did not repeat its review of

the matters described in the GALL Report; however, the staff did verify that the material

presented in the LRA was applicable and that the applicant identified the appropriate GALL

Report AMRs.

The staff reviewed the LRA to confirm that the applicant: (a) provided a brief description of the

system, components, materials, and environments; (b) stated that the applicable aging effects

were reviewed and evaluated in the GALL Report; and (c) identified those aging effects for the

engineered safety features ESF components that are subject to an AMR. On the basis of its

audit and review, the staff determines that, for AMRs not requiring further evaluation, as

identified in LRA Table 3.3.1, the applicant's references to the GALL Report are acceptable and

no further staff review is required, with the exception of the following AMRs that the applicant

had identified were consistent with the AMRs of the GALL Report and for which the staff felt

were in need of additional clarification and assessment. The staff's evaluations of these AMRs

are provided in the subsections that follow.

3.3.2.1.1 AMR Results Identified as Not Applicable

In LRA Table 3.3.1, item 36, the applicant states that the corresponding AMR result line in the

GALL Report is not applicable because Boraflex is not used as a neutron absorber for spent

fuel racks at SSES. The staff reviewed the documentation supporting the applicant's AMR

evaluation and confirmed the applicant's claim that SSES has no Boraflex as neutron absorber,

and uses Boral instead. Therefore, the staff agrees with the applicant's determination that the

corresponding AMR result line in the GALL Report is not applicable to SSES.

In LRA Table 3.3.1, item 39, the applicant states that for this corresponding AMR result lines in

the GALL Report, cracking due to SCC was not identified as an aging effect requiring

management for stainless steel spent fuel storage racks because the temperature of the spent

fuel pool is maintained well below 1400F. The staff reviewed the documentation supporting the

applicant's AMR evaluation and confirmed the applicant's claim that spent fuel temperature is

maintained below 140 OF. In addition, the staff noted that SCC rarely occurs in austenitic

stainless steel below 140 IF (Metals Handbook, 1988). Therefore, the staff finds that the

corresponding AMR result lines in the GALL Report is not applicable to SSES.

In LRA Table 3.3.1, item 40, the applicant states that the corresponding AMR result line in the

GALL Report is not applicable because steel tanks in the Diesel Fuel Oil System are buried.

The staff reviewed the documentation supporting the applicant's AMR evaluation and confirmed

the applicant's claim that SSES has no steel tanks exposed to outdoor air in the Diesel Fuel Oil

System. Therefore, the staff agrees with the applicant's determination that the corresponding

AMR result line in the GALL Report is not applicable to SSES.

3-318
In LRA Table 3.3.1, item 60, the applicant indicates that for this corresponding AMR result lines

in the GALL Report, steel components that are exposed to air - outdoor (external) are evaluated

in item 3.3.1-58. The staff reviewed the documentation supporting the applicant's AMR

evaluation and confirmed the applicant's claim that the components under this commodity

group are addressed under item 3.3.1-58. In addition, steel components that are externally

exposed to outdoor air are managed by the System Walkdown Program, which is consistent

with the GALL Report for this item 3.3.1-60. Therefore, the staff agrees with the applicant's

determination that the corresponding AMR result lines in the GALL Report are evaluated

elsewhere in the application.

In LRA Table 3.3.1, items 49 and 62, the applicant indicates the component or the aging effects

for these line items is not applicable. The staff reviewed the documentation supporting the

applicant's AMR evaluation and confirmed the applicant's claim that the components and the

aging effect under this commodity group are not applicable to SSES. On this basis, the staff

agrees with the applicant's corresponding AMR result line in the GALL Report is not applicable

to SSES.

In LRA Table 3.3.1, items 65, 66 and 67, the applicant states that for these corresponding AMR

result lines in the GALL Report, loss of material, cracking and spalling were not identified as an

aging effects requiring management for reinforced concrete structural fire barriers exposed to

indoor or outdoor uncontrolled air. The staff reviewed the documentation supporting the

applicant's AMR evaluation and noted that reinforced concrete structural fire barriers were

evaluated in the following tables: Table 3.5.2-2, 3.5.2-3, 3.5.2-4, 3.5.2-5, 3.5.2-6, 3.5.2-7, and

3.5.2-8. In addition, the staff noted that though the applicant did not identify loss of material,

cracking and spalling as aging effects, the applicant did manage the components with Structure

Monitoring Program and Fire Protection Program, which are consistent with the GALL Report.

Therefore, the staff agrees with the applicant's management of the components under 3.3.1

items 65, 66, and 67.

In LRA Table 3.3.1, item 74, the applicant states that for these corresponding AMR result lines

in the GALL Report, loss of material due to wear was not identified as an aging effect requiring

management for steel cranes - rails exposed to indoor uncontrolled air. The staff reviewed the

documentation supporting the applicant's AMR evaluation and noted that steel cranes rails were

evaluated in the following tables: Table 3.5.2-2, 3.5.2-4, 3.5.2-6, 3.5.2-7, 3.5.2-8, and 3.5.2-10.

In addition, the staff noted that though the applicant did not identify loss of material due to wear

as an aging effect, the applicant did manage the components with Crane Inspection Program,

which are consistent with the GALL Report. Therefore, the staff agrees with the applicant's

management of the components under 3.3.1 item 74.

In LRA Table 3.3.1, item 75, the applicant states that hardening, loss of strength, and loss of

material were not identified as aging effects requiring management for elastomers that are

exposed to raw water in the Auxiliary Systems for SSES. The staff confirmed that line item

3.3.1-75 applies to GALL Report Item VII.C.1 and VII.C.2 in the service water system. The staff

reviewed LRA Table 2.3.3-11, and Table 3.3.2-11, Emergency Service Water and noted that

elastomers are not included in the scope of license renewal for this system. On the basis that

elastomers in emergency service water system are not included in the scope of license renewal,

the staff agrees with the applicant that item 3.3.1-75 is not applicable.

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3.3.2.1.2 Cracking due to Stress Corrosion Cracking (SCC), Intergranular Stress Corrosion

Cracking (IGSCC)

LRA Tables 3.3.2-3, 3.3.2-24, 3.3.2-25, 3.3.2-27, and 3.3.2-34 include AMR results for stainless

steel components in an environment of treated water with temperature greater than 600C

(>1400 F) and with an aging effect of cracking due to SCC or IGSCC. There are four AMR result

lines in LRA Table 3.3.2-3 where the components are accumulators, filters, piping and valve

bodies in the control rod drive hydraulic system; three lines in LRA Table 3.3.2-24 where the

components are piping, tubing and valve bodies in the reactor non-nuclear instrumentation

system; three lines in LRA Table 3.3.2-25 where the components are orifices, tubing, and piping

and piping components in the reactor water cleanup system; one line in LRA Table 3.3.2-27

where the components are piping and piping components in the sampling system; and one line

in LRA Table 3.3.2-34 where the components are piping and piping components in the reactor

vessel and auxiliaries system (NSAS portions). For these AMR results, the applicant credited

use of the BWR Water Chemistry Program, alone, with managing the aging effect. The

applicant cited generic Note E, indicating that the result is consistent with the corresponding

GALL Report item for material, environment and aging effect, but a different AMP is credited.

The staff noted that for the corresponding line in SRP-LR Table 3.3-1 and in GALL Report,

Volume 1, Table 3, the recommended AMP is GALL AMP XI.M25, Closed-Cycle Cooling Water

System, which includes both preventive measures, such as control of water chemistry, to

minimize the potential for SCC and IGSCC, and inspection to monitor the effectiveness of the

water chemistry program to control cracking due to SCC or IGSCC. Because the applicant

recommended the BWR Water Chemistry Program, alone, and no inspection activity credited to

monitor effectiveness of the chemistry program, the staff issued RAI 3.3-3 in a letter dated

July 15, 2008, asking the applicant to justify why an inspection is not needed to verify the

effectiveness of the water chemistry program and confirm that cracking is not occurring in these

components.

In a letter dated August 15, 2008, the applicant responded to RAI 3.3-3 by providing the

following response:

For the AMR results identified in LRA Section 3.3 (Tables 3.3.2-3, 3.3.2-24,

3.3.2-25, 3.3.2-27, and 3.3.2-34) that refer to the GALL Report Item VII.E3-16,

verification of the effectiveness of the BWR Water Chemistry Program is needed

to confirm that cracking is not occurring in these components.

The affected LRA Tables are revised to explicitly credit the Chemistry Program

Effectiveness Inspection in combination with the BWR Water Chemistry

Program.

The staff reviewed the applicant's response and all of the associated LRA changes. The staff

noted that for all of the AMR results being questioned by the staff, the applicant revised the

AMPs to be the BWR Water Chemistry Program in combination with the Chemistry Program

Effectiveness Inspection, rather than the BWR Chemistry Program, alone. The revised AMR

result lines continued to cite generic Note E, indicating that the material, environment and aging

effect are consistent with the GALL Report, but a different aging management program is

credited.

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The staff reviewed the applicant's BWR Water Chemistry Program. The staff's evaluation of

this program, which is documented in SER Section 3.0.3.1.1, found that the BWR Water

Chemistry Program provides mitigation for the aging effect of cracking due to SCC or IGSCC.

The staff reviewed the applicant's Chemistry Program Effectiveness Inspection. The staff's

evaluation of this program, which is documented in SER Section 3.0.3.1.10, found that the

Chemistry Program Effectiveness Inspection is a one-time inspection that is consistent with the

GALL Report's recommendations for AMP XI.M32, "One-Time Inspection." The CPEI includes

provisions for inspecting selected components in areas of low or stagnant flow and implements

inspection methods that are capable of detecting cracking due to SCC or IGSCC, if it should

occur in the selected components. Because the BWR Water Chemistry Program provides

mitigation and the CPEI provides detection of the aging effect if it should occur, the staff finds

the applicant's proposed AMPs for managing the potential aging effect of cracking due to SCC

or IGSCC for stainless steel piping, piping components, and piping elements exposed to treated

water >60*C (>1400F) in the control rod drive hydraulics system, the reactor non-nuclear

instrumentation system, the reactor water cleanup system, the sampling system, and the

reactor vessel and auxiliaries system (NSAS portions) to be acceptable. The staff also finds that

the applicant's response to RAI 3.3-3, together with the associated LRA changes, resolves the

issues raised in that RAI.

Based on the programs identified and the LRA changes made in response to RAI 3.3-3, the

staff concludes that the applicant's AMR results are acceptable because the AMPs provide both

detection and mitigation for the aging effect of cracking due to SCC and IGSCC in the subject

components. For those items that apply to LRA Table 3.3.1, item 3.3.1-37, the staff determines

that the LRA, as amended in response to an associated RAI, is consistent with the GALL

Report and that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB during the

period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.3.2.1.3 Cracking Due to Stress Corrosion Cracking

In LRA Table 3.3.1, Item 3.3.1-46, addresses cracking due to stress corrosion cracking for

stainless steel piping, piping components and heat exchanger components with the internal

surfaces exposed to treated water greater than 140°F in the Reactor Building Closed Cooling

Water System and Sampling System. The GALL Report recommends GALL AMP XI.M21,

"Closed-Cycle Cooling Water System" to manage this aging effect. The staff noted that based

on the applicant's response to RAI B.2.14-2 in letter dated August 12, 2008, the applicant

amended the LRA so that the AMR line items in LRA Table 2 that reference this line item in

GALL Report Table 1 also credit AMP B.2.22 "Chemistry Program Effectiveness Inspection"

and cite Generic Note E, indicating that the AMR line items are consistent with GALL Report

material, environment, and aging effect, but a different aging management program is credited.

The staff reviewed the AMR results lines that reference Note E and determines that the

material, environment, and aging effect are consistent with the GALL Report.

The staff reviewed the applicant's AMP B.2.14 "Closed Cooling Water Chemistry Program" and

AMP B.2.22 "Chemistry Program Effectiveness Inspection" and its evaluations are documented

in SER Section 3.0.3.2.7 and 3.0.3.1.10, respectively. The staff verified that this aging

management program includes activities that are consistent with the recommendations in the

GALL AMP XI.M21 to maintain high water purity, which is effective for managing loss of

material due to general, pitting and crevice corrosion for steel components exposed to a treated

water environment. The staff further noted the Closed Cooling Water Chemistry Program is an

existing SSES program that properly monitors components and controls corrosion inhibitor

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concentrations for components, within the scope of license renewal, consistent with relevant

EPRI water chemistry guidelines. The staff confirmed that the Chemistry Program

Effectiveness Inspection will be used to verify the effectiveness of the applicant's Closed

Cooling Water Chemistry Program to manage cracking and that a combination of appropriate

volumetric and visual examination techniques (such as VT-1 or VT-3) will be performed by

qualified personnel on a sample population of most susceptible subject components. On this

basis, the staff finds that AMR results addressed by this line item that credit these programs are

acceptable.

3.3.2.1.4 Loss of Material Due to General, Pitting and Crevice Corrosion

In LRA Table 3.3.1, Item 3.3.1-47, addresses loss of material due to general, pitting, and

crevice corrosion for steel chiller and piping components, tanks, pump casings, valve bodies

and unit coolers with the internal surfaces exposed to treated water in the Process and Area

Radiation Monitoring System, Reactor Building Chilled Water, HVAC and Closed Cooling Water

Systems, and Control Structure Chilled Water and HVAC System. The GALL Report

recommends GALL AMP XI.M21, "Closed-Cycle Cooling Water System" to manage this aging

effect. The staff noted that based on the applicant's response to RAI B.2.14-2 in letter dated

August 12, 2008, the applicant amended the LRA so that the AMR line items in LRA Table 2

that reference this line item in GALL Report Table 1 also credit AMP B.2.22 "Chemistry

Program Effectiveness Inspection" and cite Generic Note E, indicating that the AMR line items

are consistent with GALL Report material, environment, and aging effect, but a different aging

management program is credited. The staff reviewed the AMR results lines that reference Note

E and determines that the material, environment, and aging effect are consistent with the GALL

Report. By letter dated December 11, 2008, the applicant supplemented its response to RAI

B.2.14-2 in which the applicant stated that the aging effect of loss of material for steel

components exposed to a treated water environment in the Diesel Jacket Cooling Water

System is managed only by the Closed Cooling Water Chemistry Program because corrosion

probes have been installed. Further discussion is provided in SER Section 3.0.3.2.7 in which

the applicant responded to RAI B.2.14-3. The applicant's supplemental response provided

clarification as to why the CPEI was not credited for these steel components in the Diesel

Jacket Cooling Water System, and these AMR line items are consistent with the GALL Report

under GALL AMR Item VII.H2-23.

The staff reviewed the applicant's AMP B.2.14 "Closed Cooling Water Chemistry Program" and

AMP B.2.22 "Chemistry Program Effectiveness Inspection" and its evaluations are documented

in SER Section 3.0.3.2.7 and 3.0.3.1.10, respectively. The staff verified that this aging

management program includes activities that are consistent with the recommendations in the

GALL AMP XI.M21 to maintain high water purity, which is effective for managing loss of

material due to general, pitting and crevice corrosion for steel components exposed to a treated

water environment. The staff further noted the Closed Cooling Water Chemistry Program is an

existing SSES program that properly monitors components and controls corrosion inhibitor

concentrations for components, within the scope of license renewal, consistent with relevant

EPRI water chemistry guidelines. The staff confirmed that the CPEI will be used to verify the

effectiveness of the applicant's Closed Cooling Water Chemistry Program to manage loss of

material and that a combination of appropriate volumetric and visual examination techniques

(such as VT-1 or VT-3) will be performed by qualified personnel on a sample population of most

susceptible subject components. On this basis, the staff finds that AMR results addressed by

this line item that credit these programs are acceptable.

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3.3.2.1.5 Loss of Material Due to General, Pitting, Crevice and Galvanic Corrosion

In LRA Table 3.3.1, Item 3.3.1-48, addresses loss of material due to general, pitting, crevice

and galvanic corrosion for steel chiller and heat exchanger components with the internal

surfaces exposed to treated water in the Fuel Pool Cooling System, Containment Instrument

Gas System, Reactor Building Chilled Water and Closed Cooling Water Systems, Reactor

Water Cleanup System, Sampling System, Turbine Building Closed Cooling Water System and

Control Structure Chilled Water System. The GALL Report recommends GALL AMP XI.M21,

"Closed-Cycle Cooling Water System" to manage this aging effect. The staff noted that based

on the applicant's response to RAI B.2.14-2 in letter dated August 12, 2008, the applicant

amended the LRA so that the AMR line items in LRA Table 2 that reference this line item in

GALL Report Table 1 also credit AMP B.2.22 "Chemistry Program Effectiveness Inspection"

and cite Generic Note E, indicating that the AMR line items are consistent with GALL Report

material, environment, and aging effect, but a different aging management program is credited.

The staff reviewed the AMR results lines that reference Note E and determines that the

material, environment, and aging effect are consistent with the GALL Report.

The staff reviewed the applicant's AMP B.2.14 "Closed Cooling Water Chemistry Program" and

AMP B.2.22 "Chemistry Program Effectiveness Inspection" and its evaluations are documented

in SER Section 3.0.3.2.7 and 3.0.3.1.10, respectively. The staff verified that this aging

management program includes activities that are consistent with the recommendations in the

GALL AMP XI.M21 to maintain high water purity, which is effective for managing loss of

material due to general, pitting, crevice, and galvanic corrosion for steel components exposed

to a treated water environment. The staff further noted the Closed Cooling Water Chemistry

Program is an existing SSES program that properly monitors components and controls

corrosion inhibitor concentrations for components, within the scope of license renewal,

consistent with relevant EPRI water chemistry guidelines. The staff confirmed that the CPEI will

be used to verify the effectiveness of the applicant's Closed Cooling Water Chemistry Program

to manage loss of material and that a combination of appropriate volumetric and visual

examination techniques (such as VT-1 or VT-3) will be performed by qualified personnel on a

sample population of most susceptible subject components. On this basis, the staff finds that

AMR results addressed by this line item that credit these programs are acceptable.

3.3.2.1.6 Loss of Material Due to Pitting and Crevice Corrosion

In LRA Table 3.3.1, Item 3.3.1-50, addresses loss of material due to pitting and crevice

corrosion for stainless steel unit cooler, heat exchanger and chiller components, piping

components, orifices, pump casings, tubing and valve bodies with the internal surfaces exposed

to treated water in the Reactor Building Chilled Water, HVAC and Closed Cooling Water

Systems, Sampling System, Diesel Generator Systems (Intake/Exhaust, Jacket Water,

Lubricating Oil and NSAS Components) and Control Structure Chilled Water System. The

GALL Report recommends GALL AMP XI.M21, "Closed-Cycle Cooling Water System" to

manage this aging effect. The staff noted that based on the applicant's response to RAI

B.2.14-2 in letter dated August 12, 2008, and supplemental response to RAI B.2.14-2 by letter

dated December 11, 2008, the applicant amended the LRA so that the AMR line items in LRA

Table 2 that reference this line item in GALL Report Table 1 also credit AMP B.2.22 "Chemistry

Program Effectiveness Inspection" and cite Generic Note E, indicating that the AMR line items

are consistent with GALL Report material, environment, and aging effect, but a different aging

management program is credited. The staff reviewed the AMR results lines that reference note

E and determines that the material, environment, and aging effect are consistent with the GALL

Report.

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The staff reviewed the applicant's AMP B.2.14 "Closed Cooling Water Chemistry Program" and

AMP B.2.22 "Chemistry Program Effectiveness Inspection" and its evaluations are documented

in SER Section 3.0.3.2.7 and 3.0.3.1.10, respectively. The staff verified that this aging

management program includes activities that are consistent with the recommendations in the

GALL AMP XI.M21 to maintain high water purity, which is effective for managing loss of

material due pitting and crevice corrosion for stainless steel components exposed to a treated

water environment. The staff further noted the Closed Cooling Water Chemistry Program is an

existing SSES program that properly monitors components and controls corrosion inhibitor

concentrations for components, within the scope of license renewal, consistent with relevant

EPRI water chemistry guidelines. The staff confirmed that the CPEI will be used to verify the

effectiveness of the applicant's Closed Cooling Water Chemistry Program to manage loss of

material and that a combination of appropriate volumetric and visual examination techniques

(such as VT-1 or VT-3) will be performed by qualified personnel on a sample population of most

susceptible subject components. On this basis, the staff finds that AMR results addressed by

this line item that credit these programs are acceptable.

3.3.2.1.7 Loss of Material Due to Pitting, Crevice and Galvanic Corrosion

In LRA Table 3.3.1, Item 3.3.1-51, addresses loss of material due to pitting, crevice and

galvanic corrosion for copper and copper alloy chiller and heat exchanger components, piping

and piping components and elements with the internal surfaces exposed to treated water in the

Process and Area Radiation Monitoring System, Containment Instrument Gas System, Reactor

Building Chilled Water, HVAC and Closed Cooling Water Systems, Sampling System and

Control Structure Chilled Water, Diesel Generator Systems (Intake/Exhaust, Jacket Water,

Lubricating Oil and NSAS Components) and Control Structure HVAC System. The GALL

Report recommends GALL AMP XI.M21, "Closed-Cycle Cooling Water System" to manage this

aging effect. The staff noted that based on the applicant's response to RAI B.2.14-2 in letter

dated August 12, 2008, and supplemental response to RAI B.2.14-2 by letter dated December

11, 2008, the applicant amended the LRA so that the AMR line items in LRA Table 2 that

reference this line item in GALL Report Table 1 also credit AMP B.2.22 "Chemistry Program

Effectiveness Inspection" and cite Generic Note E, indicating that the AMR line items are

consistent with GALL Report material, environment, and aging effect, but a different aging

management program is credited. The staff reviewed the AMR results lines that reference Note

E and determines that the material, environment, and aging effect are consistent with the GALL

Report.

The staff reviewed the applicant's AMP B.2.14 "Closed Cooling Water Chemistry Program" and

AMP B.2.22 "Chemistry Program Effectiveness Inspection" and its evaluations are documented

in SER Section 3.0.3.2.7 and 3.0.3.1.10, respectively. The staff verified that this aging

management program includes activities that are consistent with the recommendations in the

GALL AMP XI.M21 to maintain high water purity, which is effective for managing loss of

material due to pitting, crevice, and galvanic corrosion for copper and copper alloy components

exposed to a treated water environment. The staff further noted the Closed Cooling Water

Chemistry Program is an existing SSES program that properly monitors components and

controls corrosion inhibitor concentrations for components, within the scope of license renewal,

consistent with relevant EPRI water chemistry guidelines. The staff confirmed that the CPEI will

be used to verify the effectiveness of the applicant's Closed Cooling Water Chemistry Program

to manage loss of material and that a combination of appropriate volumetric and visual

examination techniques (such as VT-1 or VT-3) will be performed by qualified personnel on a

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sample population of most susceptible subject components. On this basis, the staff finds that

AMR results addressed by this line item that credit these programs are acceptable.

3.3.2.1.8 Loss of Material Due to General, Pitting, Crevice and Microbiologically-Influenced

Corrosion

In LRA Table 3.3.1, Item 3.3.1-72, addresses loss of material due to general, pitting, crevice

and microbiologically influenced corrosion for steel HVAC ducting and components internal

surfaces exposed to condensation (internal) in the Primary Containment Atmosphere

Circulation System. The GALL Report recommends GALL AMP XI.M38, "Inspection of Internal

Surfaces in Miscellaneous Piping and Ducting Components" to manage this aging effect. The

AMR line items in LRA Table 2 that reference this line item in GALL Report Table 1 cite Generic

Note E, indicating that the AMR line items are consistent with GALL Report material,

environment, and aging effect, but a different aging management program is credited. The

staff reviewed the AMR results lines that reference Note E and determines that the material,

environment, and aging effect are consistent with the GALL Report.

The staff reviewed the applicant's AMP B.2.32 "System Walkdown Program" and its evaluation

is documented in SER Sections 3.0.3.2.15. The staff determined that this aging management

program which include surveillance activities and observations that are adequate to manage

loss of material due to general corrosion for steel components exposed to ventilation (internal)

addressed by this AMR are consistent with those activities recommend by GALL AMP XI.M38,

"Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components." However

the applicant is crediting the AMP B.2.32, which performs visual inspections of the external

surfaces only, for the internal surfaces of fan and unit cooler housings. The staff felt that

additional information was needed and therefore, by letter dated July 23, 2008, the staff issued

RAI 3.x.2.1-1 requesting the applicant to justify the basis for crediting AMP B.2.32, which

performs visual inspections of external surfaces only, for the internal surfaces of ducting and

components internal surfaces exposed to condensation (internal) environments only. The

applicant responded to RAI 3.x.2.1-1, in a letter dated August 22, 2008. The applicant stated

that the internal and external surfaces of the ventilation components are exposed to the same

environment because the function of this system is to circulate the air within containment. The

staff noted that if condensation were to occur, that it is expected to form on the external

surfaces of the components. The applicant further stated that visual inspections of the external

surface for loss of material will be conservatively representative of the condition internal

surface, because the external surface may be subjected to condensation. The staff noted that

this is consistent with the recommendations given in the program element, "scope of program",

of GALL AMP XI.M36 "External Surfaces Monitoring", in which a visual inspection of the

external surfaces may be representative of the internal surfaces if the environment is the same

for the external and internal surfaces. The staff noted that for the unit cooler housings the AMP

B.2.23 "Cooling Units Inspection" will supplement the AMP B.2.32 "System Walkdown Program"

because this component may be subjected to condensation on the internal surface and the staff

confirmed that the AMP B.2.23 will provide verification if degradation has occurred on the

internal surfaces of this component and the effectiveness of the AMP B.2.32 "System

Walkdown Program" for managing loss of material. On the basis of its review, the staff finds

the applicable portion of the applicant's response that references GALL Item VII.F3-3 to be

acceptable because (1) the environments of the external surface and internal surface is the

same and consistent with the recommendations provided in GALL that an visual inspection of

the external surface can be credited for managing aging of the internal surfaces if the

environments are the same and (2) the applicant has credited a one-time inspection to verify if

degradation has occurred and the effectiveness of the Systems Walkdown Program when

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condensation may form on the internal surface. On this basis, the staff finds this AMR results

for this line item acceptable.

3.3.2.1.9 Loss of Material

LRA Table 3.3.1, line items 3.3.1-53 and 3.3.1-54 address the results of an AMR for steel and

stainless steel compressed air piping, piping components, and piping elements exposed

internal condensation, respectively. The applicant states that the aging effect requiring

management is loss of material and proposes to use the Area-Based NSAS Inspection to

manage the effects of aging.

The applicant has indicated generic Note E for this line item which is consistent with the GALL

report for material, environment, and aging effect, but a different aging management program.

The staff noted that the GALL Report recommends GALL AMP XI.M24, "Compressed Air

Monitoring." The applicant cited a plant-specific note which states that internal condensation is

collected in strainers, drain traps, tanks and associated piping and this moisture has

conservatively been considered a raw water environment, but there is no resulting condensation

on the external surface of the components. The staff noted that the applicant referenced the

GALL AMR Items VII.D-2 and VII.D-4, which are applicable to compressed air systems,

because the component/material/aging effect and environment combination corresponded to

those that were applicable to the applicant, noting that the applicant conservatively considered

internal condensation as raw water. The staff further noted that the piping and piping

components applicable to this AMR that is being addressed here, in the Containment

Instrument Gas and Service Air System, is not compressed air.

The staff's evaluation of the Area-Based NSAS Inspection is documented in SER Section

3.0.3.3.1. The staff noted that this program is a plant-specific program that performs an

appropriate combination of established volumetric and visual inspection techniques

(nondestructive examination techniques) that will be performed by a qualified personnel on a

sample population of those components in scope of this program. The staff further noted that

the applicant will perform the inspections of the components within the scope of this program

within 10 years prior to entering the period of extended operation. The staff determined the

inspection techniques will be capable of detecting loss of material and the applicant will initiate

corrective actions if an unacceptable loss of material or wall thinning has occurred that may

have a spatial interaction with safety-related components, as determined by engineering

evaluation. On the basis that the applicant will be performing an appropriate combination of a

visual inspection and volumetric testing for these components, the staff finds the AMR results

for this line item acceptable.

3.3.2.1.10 Reduction of Heat Transfer due to Fouling

In its letter dated June 30, 2008, in response to RAI B.2.17-2, the applicant amended Table

3.3.2-13, Fire Protection System, to credit the Heat Exchanger Inspection Program to manage

the aging effect of reduction of heat transfer due to fouling for copper alloy heat exchanger and

oil cooler tubes in raw water internal environment. The applicant applied footnote "E" and

referenced GALL Report Item VII.C1-6. The staff reviewed the AMR results lines that reference

Note E and determines that the component type, material, environment, and aging effect are

consistent with the GALL Report. However, the staff noted that where the GALL Report

recommends AMP XI.M20, "Open-Cycle Cooling Water System," the applicant proposed using

the Heat Exchanger Inspection Program. The staff noted that these heat exchangers are not

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included in the GL 89-13 program and will not therefore be in the scope of the Open-Cycle

Cooling Water Program. The applicant instead uses the Fire Water System Program to

manage loss of material due to corrosion, MIC or biofouling and includes actions to ensure no

significant corrosion, MIC, or biofouling has occurred. However, in addition, the applicant has

credited the one-time Heat Exchanger Inspection Program to provide direct evidence as to

whether, and to what extent, reduction in heat transfer due to fouling has occurred or is likely to

occur that could result in a loss of intended function.

On the basis that the applicant is crediting the Fire Water Inspection Program to ensure no

significant fouling is occurring and crediting the Heat Exchanger inspection Program to obtain

direct evidence of fouling, the staff finds that implementation of the Heat Exchanger Inspection

will ensure that the heat transfer capabilities of the subject heat exchangers, and the pressure

boundary integrity of the subject tubes, are maintained consistent with the current licensing

basis during the period of extended operation.

In LRA Table 3.3.2-4, the applicant stated that reduction of heat.transfer of control structure

chilled water chiller evaporator copper and copper alloy tubes in an internal environment of

treated water is managed by the Heat Exchanger Inspection Program.

The staff noted that the applicant applied Note E to this item. The applicant referenced LRA

Table 3.3-1, item 3.3.1-52 and GALL Report Volume 2, item VII.C2-2. The staff reviewed the

AMR results lines that reference Note E and determines that the component type, material,

environment, and aging effect are consistent with the GALL Report. However, the staff noted

that where the GALL Report recommends AMP XI.M21, "Closed-Cycle Cooling Water System,"

the applicant proposed using the Heat Exchanger Inspection Program.

The GALL recommended AMP XI.M21, Closed-Cycle Cooling Water System, recommends

preventive measures to minimize corrosion and testing and inspection to monitor the effects of

corrosion, whereas the applicant is proposing only a one-time inspection activity. The staff

noted that the heat exchangers in question are the chiller evaporators OS1 18A/B and chiller oil

cooler OS1 19A/B. The applicant has credited the Closed-Cycle Cooling Water System program

to manage loss of material for these two components and credited the Heat Exchanger

Inspection Program to manage reduction of heat transfer. The staff noted that water chemistry

is maintained by the Closed-Cycle Cooling Water System Program in accordance with the EPRI

guidelines to minimize an aggressive environment. However, the applicant's Closed-Cycle

Cooling Water System does not perform inspections for reduction of heat transfer due to

fouling. The heat exchanger inspection will provide direct evidence as to whether, and to what

extent, reduction in heat transfer due to fouling has occurred or is likely to occur that could

result in a loss of intended function. On this basis, the staff finds that the implementation of the

Heat Exchanger Inspection will ensure that the heat transfer capabilities of the subject heat

exchangers are maintained consistent with the current licensing basis during the period of

extended operation.

SER Section 3.3.2.1 Conclusion. The staff evaluated the applicant's claim of consistency with

the GALL Report. The staff also reviewed information pertaining to the applicant's consideration

of recent OE and proposals for managing aging effects. On the basis of its review, the staff

concludes that the AMR results, which the applicant claimed to be consistent with the GALL

Report, are indeed consistent with its AMRs. Therefore, the staff concludes that the applicant

has demonstrated that the effects of aging for these components will be adequately managed

so that their intended function(s) will be maintained consistent with the CLB during the period of

extended operation, as required by 10 CFR 54.21(a)(3).

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3.3.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation is

Recommended

In LRA Section 3.3.2.2, the applicant further evaluates of aging management, as recommended

by the GALL Report, for the auxiliary systems components and provides information concerning

how it will manage the following aging effects:

* cumulative fatigue damage

* reduction of heat transfer due to fouling

* cracking due to SCC

* cracking due to SCC and cyclic loading

* hardening and loss of strength due to elastomer degradation

* reduction of neutron-absorbing capacity and loss of material due to general corrosion

* loss of material due to general, pitting, and crevice corrosion

* loss of material due to general, pitting, crevice, and MIC

* loss of material due to general, pitting, crevice, MIC and fouling

* loss of material due to pitting and crevice corrosion

" loss of material due to pitting, crevice, and galvanic corrosion

" loss of material due to pitting, crevice, and MIC

* loss of material due to wear

* loss of material due to cladding breach

* QA for aging management of nonsafety-related components

For component groups evaluated in the GALL Report, for which the applicant claimed

consistency with the report and for which the report recommends further evaluation, the staff

audited and reviewed the applicant's evaluation to determine whether it adequately addressed

the issues further evaluated. In addition, the staff reviewed the applicant's further evaluations

against the criteria contained in SRP-LR Section 3.3.2.2. The staff's review of the applicant's

further evaluation follows.

3.3.2.2.1 Cumulative Fatigue Damage

LRA Section 3.3.2.2.1 states that fatigue is a TLAA, as defined in 10 CFR 54.3. Applicants must

evaluate TLAAs in accordance with 10 CFR 54.21(c)(1). SER Section 4.3 documents the staff's

review of the applicant's evaluation of this TLAA.

3,3.2.2.2 Reduction of Heat Transfer Due to Fouling

The staff reviewed LRA Section 3.3.2.2.2 against the criteria in SRP-LR Section 3.3.2.2.2.

LRA Section 3.3.2.2.2 addresses reduction of heat transfer due to fouling. The applicant stated

that there are no SSES components compared to LRA item number 3.3.1-03. For Auxiliary

Systems, stainless steel heat exchanger tubes in treated water are evaluated under LRA item

number 3.3.1-52. Fouling of stainless steel heat exchanger tubes in treated water is managed

by the Closed Cooling Water Chemistry Program. The Closed Cooling Water Chemistry

Program manages aging effects through periodic monitoring and control of contaminants.

Based on review of plant-specific OE, the Closed Cooling Water Chemistry Program is effective

in managing fouling through control of microorganisms and corrosion products.

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SRP-LR Section 3.3.2.2.2 states that reduction of heat transfer due to fouling may occur in

stainless steel heat exchanger tubes exposed to treated water. The existing program controls

water chemistry to manage reduction of heat transfer due to fouling. However, control of water

chemistry may be inadequate; therefore, the GALL Report recommends that the effectiveness

of water chemistry control programs should be verified to ensure that reduction of heat transfer

due to fouling does not occur. A one-time inspection is an acceptable method to ensure that

reduction of heat transfer does not occur and that component intended functions will be

maintained during the period of extended operation.

The staff noted that LRA Table 3.3.1, item 3.3.1-52 includes the same components, material

and aging effect as LRA Table 3.3.1, item 3.3.1-3, and that the closed cycle cooling water

environment is also a treated water environment. The staff reviewed the components evaluated

under LRA Table 3.3.2, item 3.3.1-52 and noted that the only stainless steel heat exchanger

components are for the diesel generator jacket water heat exchangers, which does not include

primary water on either side of the heat exchanger tubes. Because the component, material

and aging effects are identical and both environments are non-primary treated water, the staff

finds it acceptable for the applicant to include the evaluations for LRA Table 3.3.1, item 3.3.1-3,

with the evaluations for LRA Table 3.3.1, item 3.3.1-52. On this basis, the staff finds it

acceptable to designate LRA Table 3.3.1, item 3.3.1-3 as not applicable.

Based on the above, the staff concludes SRP-LR Section 3.3.2.2.2 criteria is not applicable.

3.3.2.2.3 Cracking Due to Stress Corrosion Cracking

The staff reviewed LRA Section 3.3.2.2.3 against the following criteria in SRP-LR

Section 3.3.2.2.3:

(1) LRA Section 3.3.2.2.3 addresses cracking due to SCC in the BWR Standby Liquid

Control System. The applicant stated that this aging effect is not applicable because the

normal operating temperature is below 1401F during normal plant operation.

SRP-LR Section 3.3.2.2.3 states that cracking due to SCC may occur in the stainless

steel piping, piping components, and piping elements of the BWR SLC system that are

exposed to sodium pentaborate solution greater than 60t (1401F). The existing

AMP monitors and controls water chemistry to manage the aging effects of cracking due

to SCC. However, high concentrations of impurities in crevices and with stagnant flow

conditions may cause SCC; therefore, the GALL Report recommends that the

effectiveness of water chemistry control programs should be verified to ensure that SCC

does not occur. A one-time inspection of selected components at susceptible locations

is an acceptable method to ensure that SCC does not occur and that component

intended functions will be maintained during the period of extended operation.

The staff reviewed the boundary drawing for the standby liquid control system and

confirmed that all components of the system exposed to sodium pentaborate during

normal operation are outside the drywell in an area of the reactor building that does not

exceed 100OF during normal operation. The staff also noted that both the GALL Report

and the SRP-LR state that the threshold for initiation of cracking due to SCC is a

temperature greater than 600C (>1400 F). Because ambient temperature of the standby

liquid control system components exposed to sodium pentaborate is below 60*C

(<1400 F) during normal plant operation, the staff finds that the aging effect of cracking

due to SCC is not applicable for these components. On this basis, the staff finds it

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acceptable for the applicant to designate LRA Table 3.3.1, item 3.3.1-4 as not

applicable.

(2) LRA Section 3.3.2.2.3 addresses cracking due to SCC in heat exchanger components.

The applicant stated that there are no SSES components that compare to LRA item

number 3.3.1-05. The reactor water cleanup regenerative and nonregenerative heat

exchangers at SSES are exposed to temperatures above 1400F, however, the

components are carbon steel. Therefore, the applicant stated that this aging effect is not

applicable because the heat exchanger components are carbon steel.

SRP-LR Section 3.3.2.2.3 states that cracking due to SCC may occur in stainless steel

and stainless clad steel heat exchanger components exposed to treated water greater

than 601 (1401F). The GALL Report recommends further evaluation of a plant-specific

AMP to ensure that the aging effect is adequately managed.

The line item 3.3.1-05 is applicable to the GALL items VII.E3-3 and VII.E3-19 in the

reactor water cleanup system; however, at SSES these components are made of

carbon steel. The applicant stated that other auxiliary systems have stainless steel heat

exchanger components exposed to treated water greater than 60t (140 OF), but these

components are addressed in Table 3.3.1, line item 3.3.1-46. The staff confirmed that

LRA Tables 3.3.2-22 and 3.3.2-27 identify these components for aging effect of cracking

and are managed by the Closed Cooling Water Chemistry Program, which is consistent

with the GALL Report. On the basis that the applicant has no stainless steel or stainless

steel clad heat exchanger components exposed to treated water at temperatures

greater than 600C (>1400F) in the RWCU system, and that cracking due to SSC is not

an expected aging effect applicable for carbon steel heat exchanger components, the

staff finds it acceptable for the applicant to designate LRA Table 3.3.1, item 3.3.1-5, as

not applicable.

(3) LRA Section 3.3.2.2.3 addresses cracking due to SCC in diesel engine exhaust piping,

piping components, and piping elements. The applicant stated that this aging effect is

not applicable because these components are exposed internally to ambient air, and

remain dry during normal plant operation.

SRP-LR Section 3.3.2.2.3 states that cracking due to SCC may occur in stainless steel

diesel engine exhaust piping, piping components, and piping elements exposed to diesel

exhaust. The GALL Report recommends further evaluation of a plant-specific AMP to

ensure that the aging effect is adequately managed.

In a teleconference dated December 5, 2008, the staff had further discussion with the

applicant on why cracking due to SCC was not considered to be an AERM for the

stainless steel emergency diesel generator exhaust piping surfaces that are exposed

internally to diesel exhaust. The applicant clarified that the AMR methodology identified

that the emergency diesel generators are operating only periodically and that the

exhaust environment that results from operations of the generators is not a source of

contaminants and is dry.

In AMR Item AP-33 in Table IL.A of NUREG-1833, "Technical Bases for Revision to the

License Renewal Guidance Documents," the staff provides the following basis on why it

is important to identify cracking due to SCC as an AERM for the internal surfaces of

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stainless steel emergency diesel generator exhaust piping that are exposed to diesel

exhaust (i.e. combusted diesel fuel).

The Staff has accepted the position that the possible stress corrosion

cracking of stainless steel diesel engine exhaust piping, piping

components, and piping elements is managed by a plant-specific aging

management program. The FCS SER section 3.3.2.4.3 identifies

stainless steel as a material in diesel exhaust gas environment with loss

of material and cracking as viable aging effects. GALL Rev. 0 Chapter

VIIH.2.4-a only identifies carbon steel and loss of material due to general,

pitting, and crevice corrosion of steel diesel engine combustion air

exhaust subsystem components that are exposed to hot diesel engine

exhaust gases containing moisture and particulates. Similar components

constructed of stainless steel were observed to be susceptible to cracking

in hot diesel exhaust gas. A plant-specific aging management program

will be evaluated to provide reasonable assurance that the component's

intended functions will be maintained within the CLB for the period of

extended operation.

The diesel exhaust that results from operations of emergency diesel generators is made

up mostly of carbon dioxide (C02) and water (H20) in the vapor state. However, there

may be some amount of liquid state water (moisture) in the exhaust. Diesel exhaust may

also contain some contaminants because the oil fractions that make up the diesel fuel

prior to combustion may contain small percentages of nitrogen, sulfur or halogen atomic

elements impurities. Thus, the staff noted that its basis in NUREG-1833 differed from

the applicant's basis because NUREG supports that staff's basis that diesel exhaust

could contain enough moisture and particulate containments and that these

contaminants lead to cracking in the internal stainless steel emergency diesel generator

exhaust piping surfaces that are exposed to the diesel exhaust environment. Thus,

based on a comparison of the applicant's position against the relative information in

NUREG-1833, the staff took the position that the applicant had not taken a conservative

position relative to aging management of cracking due to SCC in the internal surfaces of

stainless steel emergency diesel generator exhaust piping that are exposed to diesel

exhaust. In a teleconference dated January 5, 2009, the staff discussed the applicant's

basis for managing cracking in the stainless steel diesel generator exhaust piping,

piping components, and piping elements that are exposed to a diesel exhaust

environment. During this teleconference, the applicant stated that it would amend the

LRA to identify cracking as an applicable aging effect for the internal stainless steel

diesel generator exhaust piping, piping component, and piping element surfaces that are

exposed to the diesel exhaust environment and that AMP B.2.28, Supplemental Piping

and Tanks Inspection Program, will be credited to manage cracking in the internal

component surfaces that are exposed to diesel exhaust.

The staff confirmed that the Supplemental Piping and Tanks Inspection Program

includes a number of inspection methods, including volumetric (RT or UT) and visual

(VT-i or VT-3 or equivalent) examination techniques that will be performed by qualified

personnel on a sample population of subject components. The staff noted that the

Subsection IWA-2000 of the ASME Code Section Xl lists volumetric and VT-1 visual

examination techniques as valid inspection methods for the detection of cracking in

metallic components. The staff also noted that GALL AMP XI.M32, "One-Time

Inspection," indicates that one-time inspection programs are valid AMPs for cases

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where: (1) the components may be susceptible to the gradual accumulation or

concentration of agents that, if present, could promote certain aging effects, and (2)

where additional verification is necessary in order to confirm that degradation is not

occurring in the components or is progressing at a very slow propagation rate, or else to

trigger additional corrective actions if unacceptable degradation is detected in the

components.

The staff verified that, in the applicant's letter of January 12, 2009, the applicant made

the appropriate changes to the AMRs for the stainless steel emergency diesel exhaust

piping to credit the AMP B.2.28, Supplemental Piping and Tanks Inspection Program,

for the management of cracking in the internal stainless steel diesel generator exhaust

piping, piping component, and piping element surfaces that are exposed to diesel

exhaust. The staff also verified that, in the applicant's letter of January 12, 2009, the

applicant amended AMP B.2.28 to add these components to the scope of the AMP.

Therefore, based on this assessment, the staff finds that the applicant has provided an

acceptable basis for crediting the Supplemental Piping and Tanks Inspection Program

for aging management of cracking because: (1) the emergency diesel generators are

only periodically operated in accordance with plant technical specifications or transient

operating procedures, (2) the applicant's basis is consistent with criteria in GALL AMP

XI.M32 on when one-time inspection programs can be credited for aging management,

and (3) the applicant's Supplemental Piping and Tanks Inspection Program includes

volumetric examination methods and VT-1 or enhanced VT-1 visual inspection methods,

which are valid techniques for the detection of cracking in the stainless steel

components.

Based on the above, the staff concludes that the applicant meets SRP-LR Section 3.3.2.2.3

criteria. The staff determines that the LRA, as amended in response to a staff concern, is

consistent with the GALL Report and that the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended function(s) will be maintained consistent

with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.2.4 Cracking Due to Stress Corrosion Cracking and Cyclic Loading

The staff reviewed LRA Section 3.3.2.2.4 against the following criteria in SRP-LR

Section 3.3,2.2.4:

(1) LRA Section 3.3.2.2.4 addresses cracking due to SCC and cyclic loading in stainless

steel PWR nonregenerative heat exchanger components exposed to treated borated

water greater than 60tC (1400F) in the chemical and volume control system. The

applicant stated that this aging effect is not applicable because SSES is a BWR.

SRP-LR Section 3.3.2.2.4 states that cracking due to SCC and cyclic loading may occur

in stainless steel PWR nonregenerative heat exchanger components exposed to treated

borated water greater than 609 (140F) in the chemical and volume control system.

The staff confirmed in SRP-LR Table 3.3-1, Item 7, is only applicable to PWR plants.

Because SSES is a BWR, the staff finds that this item in SRP-LR Section 3.3.2.2.4.1

does not apply to SSES.

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(2) LRA Section 3.3.2.2.4 addresses cracking due to SCC and cyclic loading in stainless

steel PWR regenerative heat exchanger components exposed to treated borated water

greater than 60tC (1401F). The applicant stated that this aging effect is not applicable

because SSES is a BWR.

SRP-LR Section 3.3.2.2.4 states that cracking due to SCC and cyclic loading may occur

in stainless steel PWR regenerative heat exchanger components exposed to treated

borated water greater than 60 tC (140 OF).

The staff confirmed in SRP-LR Table 3.3-1, Item 8, is only applicable to PWR plants.

Because SSES is a BWR, the staff finds that this item in SRP-LR Section 3.3.2.2.4.2

does not apply to SSES.

(3) LRA Section 3.3.2.2.4 addresses cracking due to SCC and cyclic loading in stainless

steel pump casing for the PWR high-pressure pumps in the chemical and volume

control system. The applicant stated that this aging effect is not applicable because

SSES is a BWR.

SRP-LR Section 3.3.2.2.4 states that cracking due to SCC and cyclic loading may occur

in the stainless steel pump casing for the PWR high-pressure pumps in the chemical

and volume control system. The existing AMP monitors and controls primary water

chemistry in PWRs to manage the aging effects of cracking due to SCC. However,

control of water chemistry does not preclude cracking due to SCC and cyclic loading;

therefore, the effectiveness of water chemistry control programs should be verified to

ensure that cracking does not occur.

The staff confirmed in SRP-LR Table 3.3-1, Item 9, is only applicable to PWR plants.

Because SSES is a BWR, the staff finds that this item in SRP-LR Section 3.3.2.2.4.3

does not apply to SSES.

Based on the above, the staff concludes SRP-LR Section 3.3.2.2.4 criteria are not applicable.

3.3.2.2.5 Hardening and Loss of Strength Due to Elastomer Degradation

The staff reviewed LRA Section 3.3.2.2.5 against the following criteria in SRP-LR

Section 3.3.2.2.5:

(1) LRA Section 3.3.2.2.5 addresses hardening and loss of strength due to elastomer

degradation in components of heating and ventilation systems. The applicant stated that

only the elastomers used in flexible connections in the Reactor Building HVAC and the

Primary Containment Atmosphere Circulation System were identified as requiring aging

management. Levels of ionizing radiation in the Reactor Building and of ionizing

radiation and thermal exposure inside Containment exceeded threshold levels for

cracking and changes in material properties. Elastomers in HVAC systems in other

buildings do not exceed threshold levels for radiation or temperature. The System

Walkdown Program is credited for aging management of elastomers in the Reactor

Building HVAC and Primary Containment Atmosphere Circulation systems.

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SRP-LR Section 3.3.2.2.5 states that hardening and loss of strength due to elastomer

degradation may occur in elastomer seals and components of heating and ventilation

systems exposed to air - indoor uncontrolled (internal/external). The GALL Report

recommends further evaluation of a plant-specific AMP to ensure that these aging

effects are adequately managed.

SRP-LR Section 3.3.2.2.5.1 invokes AMR Item 11 in Table 3 of the GALL Report,

Volume 1, and AMR Items VII.F1-7, VII.F2-7, VII.F3-7 and VII.F4-6 in the GALL Report,

Volume 2, as applicable to elastomeric seals and components in control room, auxiliary

and radwaste, primary containment, and diesel generator building heating and ventilation

systems that are exposed either internally or externally to uncontrolled indoor air.

The staff reviewed LRA Section 3.3.2.2.5.1 against the staff's recommended regulatory

criteria in SRP-LR Section 3.3.2.2.5.1 and the recommendations for these components

in GALL AMR Items VII.F1-7, VII.F2-7, VII.F3-7 and VII.F4-6, as applicable to the

elastomeric seals and components in the control room, auxiliary and radwaste, primary

containment, and diesel generator building HVAC systems that are exposed either

internally or externally to uncontrolled indoor air.

The staff noted that the applicant aligned all of its AMR's for the elastomeric auxiliary

system seals and components, as given in LRA Tables 3.3.2-7, "Aging Management

Review Results - Diesel Generator Buildings HVAC Systems," 3.3.2-9, "Aging

Management Review Results - Diesel Generators System," 3.3.2-5, "Aging

Management Review Results - Control Structure HVAC Systems," 3.3.2-8, "Aging

Management Review Results - Diesel Generator Buildings HVAC Systems," 3.3.2-16,

"Aging Management Review Results - Primary Containment Atmosphere Circulation

System," "3.3.2-13, "Aging Management Review Results - Fire Protection System," and

3.3.2-23, "Aging Management Review Results - Reactor Building HVAC System," to

AMR Item 11 in Table 3 of the GALL Report, Volume 1, but also noted that the applicant

was not always consistent in identifying whether hardening or loss of strength were

applicable aging effects requiring management (AERMs).

Specifically, the staff noted that, in the applicant's AMRs for elastomeric components in

the reactor building HVAC system and the primary containment air processing system

that aligned to GALL AMR VII.F3-7, the applicant identified that cracking and changes in

material properties were applicable AERMs only for the neoprene rubber or fiberglass

flexible connections (expansion joints) in the reactor building HVAC system exposed to

external uncontrolled indoor air and for neoprene expansion joints in the primary

containment air processing system exposed to internal ventilation and external

uncontrolled indoor air. For these components the applicant credited its Systems

Walkdown Program to managing cracking and changes in material properties. The staff

noted that the applicant did not identify cracking and changes in material properties as

applicable AERMs for the internal neoprene rubber and fiberglass expansion joint

surfaces in the reactor building HVAC system that are exposed to the ventilation

environment and this was not consistent with the applicant's aging management

approach taken for the analogous internal neoprene component surfaces in the primary

containment air processing system.

The staff also noted that the applicant's ventilation and indoor air environment

groupings, as given in LRA Tables 3.0-1 or 3.0-2, cover a range of specific environments

and environmental conditions. In the applicant's environmental discussions for these

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groupings, the staff noted insufficient evidence that the ventilation environment and the

uncontrolled indoor air environment are equivalent. The applicant's discussion also did

not establish the threshold being used for radiologically-induced aging and the maximum

radiological levels the components would be exposed to, or whether the temperatures for

the specific environments have the potential to exceed a thermally-induced aging

threshold of 950F.

The staff noted that the applicant had aligned the table 2 AMR items for the following

supplemental HVAC or non-HVAC components to AMR Item 11 in Table 3 of the GALL

Report, Volume 1 and either to GALL AMR VII.F1-7, VII.F2-7, VII.F3-7, or VII.F4-6:

(1) silicone rubber heat exchanger tube plugs in the diesel generator intake

exhaust systems under exposure to the ventilation environment,

(2) elastomeric (synthetic rubber) flexible connections (hoses) in the diesel

generator system, and fire protection system under external exposure to

uncontrolled indoor air,

(3) neoprene flexible connections in the diesel generator buildings HVAC system

that are exposed internally to the ventilation environment and externally to the

uncontrolled indoor air environment,

(4) neoprene/asbestos flexible connections in the diesel generator buildings

HVAC system and the control structure HVAC system that are exposed internally

to the ventilation environment and externally to the uncontrolled indoor air

environment, and

(5) neoprene/fiberglass flexible connections in the diesel generator buildings

HVAC system and the control structure HVAC system that is exposed internally to

the ventilation environment and externally to the uncontrolled indoor air

environment.

However, in these AMRs, the staff noted that the applicant did not identify any AERMs

for the elastomeric/polymeric component surfaces that are exposed either to a

ventilation air environment or an uncontrolled indoor air environment, and that in LRA

Section 3.3.2.2.5.1, the applicant only justified this by stating the temperatures and

radiation levels for the elastomers/polymeric materials in these systems "do not exceed

threshold levels for radiation or temperature."

Thus, the staff had the following issues with the applicant's AMRs for the elastomeric

and polymeric auxiliary system components that the applicant had aligned to AMR Item

11 in Table 3 of the GALL Report, Volume 1 and either to GALL AMR VII.F1-7, VII.F2-7,

VII.F3-7, or VII.F4-6:

The applicant did not provide sufficient evidence that the environmental

conditions between the ventilation environments were equivalent to an

uncontrolled, indoor air environment. Thus, for those elastomeric or polymeric

components that the applicant had identified as being subject to the aging

effects of "cracking" or "changes in material properties," the applicant did not

provide sufficient basis why the external visual examinations performed under

the Systems Walkdown Program could be used as the basis for managing

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cracks/subsurface cracks that only break the internal surface or change in

material property exposed to the ventilation environment.

* For those elastomeric or polymeric components that the applicant had identified

as being subject to the aging effect of "changes in material properties," the

applicant did not define the specific material properties that could be impacted by

exposure to either the ventilation environment or the uncontrolled indoor air

environment.

* The applicant did not provide a sufficient basis for concluding that there are not

any applicable AERMs for the surfaces of the neoprene and fiberglass flexible

connections in the reactor building HVAC that are exposed to internal ventilation

when cracking and changes in material properties were identified as applicable

AERMs for the neoprene expansion joints in the primary containment air

processing system exposed to internal ventilation. Also the applicant did not

provide the levels of ionizing radiation in the Reactor Building and of ionizing

radiation and thermal exposure inside Containment that may have exceeded

threshold levels for cracking and changes in material properties.

" For those supplemental HVAC or non-HVAC elastomeric or polymeric

components that the applicant had aligned to the GALL item, but had not

identified any applicable AERMs under exposure to an indoor air or ventilation

environment, the applicant did not establish an acceptable basis for concluding

that there are not any AERMS for the components. Specifically, the applicant did

not establish how high the temperatures and radiation levels could reach under

the specific environmental conditions for the subsystems exposed to these

environments. Nor did the applicant identify the radiation level threshold for

concluding that radiation-induced cracking or material property changes could

occur in the polymetric/elastomeric materials used to fabricate these auxiliary

system components.

In RAI 3.3.2.2.5.1-1, Part A, by letter dated July 23, 2008, the staff asked the applicant

to specify the polymetric/elastomeric material properties that are within the scope of the

applicant's aging effect "change in material properties." In RAI 3.3.2.2.5.1-1, Part B, by

the same letter, the staff asked the applicant to justify, using a valid technical basis, why

cracking and changes in material properties was not identified as an applicable AERM

for the neoprene or fiberglass flexible connection (expansion joint) surfaces in the

reactor building HVAC system that are exposed internally to the ventilation environment

when these aging effects had been identified as AERMs for the neoprene expansion

joint surfaces in the primary containment air processing system that are exposed

internally to the ventilation system.

In its letter dated August 27, 2008, in response to RAI 3.3.2.2.5.1-1 Part A, the applicant

stated that the specific material properties that could be impacted by exposure to either

the ventilation or uncontrolled indoor air environment are hardening (e.g., embrittlement,

decrease in elasticity) and loss of strength (e.g., elongation, loss of tensile strength, and,

with exposure to ionizing radiation, swelling or melting). The applicant also stated that

both types of material property changes could occur as a result of prolonged exposure to

high temperature (95 0F or higher), high radiation levels (equal to or greater than 10E6

rads total integrated dose (TID)), or to ultraviolet radiation or ozone.

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In response to RAI 3.3.2.2.5.1-1 Part B, the applicant provided rationale for not

identifying aging effects requiring management for neoprene or fiberglass flexible

connections in the Reactor Building HVAC system. The applicant provided a summary of

the stressors in the Reactor Building where these flexible connections are located. The

applicant further stated that:

" There are no sources of ionizing radiation within the ventilation environment of

the Reactor Building HVAC system that could cause the radiation levels to

exceed the threshold level of 10E6 rads TID,

" There are no additional heat sources within the ventilation environment of the

Reactor Building HVAC system that could contribute to prolonged thermal

exposure to a temperature of 950F or higher,

" The ventilation environment of the Reactor Building HVAC system contains no

sources of ultraviolet radiation or ozone.

Therefore, the applicant concluded that for neoprene components in the Reactor

Building HVAC system there are no aging effects requiring management.

The staff reviewed the applicant response to RAI 3.3.2.2.5-1, Parts A and B and finds

the applicant response acceptable because (1) the applicant adequately defined the

specific material properties that could be affected by exposure to ventilation atmosphere,

and (2) the applicant identified the location where these flexible connections are located

in the Reactor Building and defined the stressors that could cause the aging effects in

neoprene flexible connections at those locations. The applicant response is consistent

with the GALL Report definitions of neoprene material in Section IX and the threshold

limits of the stressors as recommended in the GALL Report Section IX. On the basis of

its review, the staff finds that neoprene flexible hoses in the Reactor Building HVAC

system will not experience the aging effects of cracking and change in material

properties in a ventilation environment.

In RAI 3.3.2.2.5.1-2, Part A, by letter dated July 23, 2008, the staff asked to applicant to

clarify, using a valid technical basis, why the environmental conditions for an internal

ventilation environment is considered to be equivalent to the environmental conditions

that are applicable to an external uncontrolled indoor air environment. In RAI 3.3.2.2.5.1-

2, Part B the staff asked the applicant, for each environment that is within the scope the

"ventilation" environmental grouping or "indoor air/protected from weather"

environmental grouping in the LRA, to identify and justify the basis the radiologicalinduced (gamma ray) aging threshold and threshold that is used to screen

polymer/elastomer components in these environments for age related degradation

(including cracking, hardening, loss of strength, or other material property changes), and

to identify what the maximum-to-minimum temperature ranges and maximum gamma

radiation levels are for these specific environments.

In its letter dated August 27, 2008, in response to RAI 3.3.2.2.5.1-2, the applicant stated

the following for Part A:

As described in LRA Table 3.0-1, internal ambient environments found inside

components, such as piping and tanks that are either vented or otherwise open to

the ambient conditions in their location, are also included in the "ventilation"

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environment grouping. It is reasonable to assume that, for such components, the

relevant conditions that can lead to aging, such as temperature and moisture, are

the same both inside and outside the component. In these cases, the condition of

the external surface is expected to be representative of the internal surface

condition.

Also included in the "ventilation" environment grouping is ambient air that may be

conditioned by filtering, heating, cooling, or dehumidification, or some

combination thereof, in order to maintain a suitable environment for equipment

operation or personnel occupancy. For components exposed internally to this

environment, it is reasonable to assume that the relevant conditions that can lead

to aging are generally less aggressive, or at least no more aggressive, than the

ambient air to which the same components are exposed externally. In these

cases, aging of the external surfaces is expected to progress at a faster rate than

aging of the internal surfaces.

In both of these cases, the System Walkdown Program, which is consistent with

the GALL AMP XI.M36 External Surfaces Monitoring, may be credited with aging

management.

In response to Part B, the applicant stated that ionizing radiation, temperatures, and

exposure to ultraviolet radiation and ozone were all within the threshold limits as

recommended in the GALL Report. The applicant provided a table identifying the

minimum and maximum normal operating temperature and the maximum total integrated

dose for specific buildings/areas within the plant and within the scope of license renewal.

The applicant stated that the maximum temperature in each building represents a hot

spot or a design consideration for HVAC, and the temperature is not expected to equal

or exceed 95°F for a prolonged period of time.

The staff reviewed the applicant response for RAI 3.3.2.2.5.1-2, Part A and finds that the

applicant has provided an adequate technical basis to conclude that the internal

ventilation environments are considered equivalent to or less aggressive than the

external uncontrolled indoor-air environment. Therefore, the staff finds that the System

Walkdown Program, which manages the aging effects of the external surfaces of the

piping, can also be credited for the internal surfaces on the basis that these two

environments are similar. The staff reviewed the applicant response for RAI 3.3.2.2.5.1-

2, Part B and finds that the applicant has appropriately identified the temperatures and

total integrated dose levels in the various structures that are within the scope of license

renewal. The applicant response is consistent with the GALL Report definition of the

threshold limits of the stressors as recommended in the GALL Report Section IX. On this

basis, the staff finds the applicant response adequate.

In RAI B.2.32-4, the staff asked the applicant to justify its basis for crediting the System

Walkdown Program to manage cracking and changes in material properties that may

occur in the internal surfaces of in-scope components that are fabricated from either an

elastomeric or polymeric material. The staff also asked the applicant to clarify how visual

examinations alone from the external surfaces of these materials would be capable of

detecting the following aging effects: (1) a tightly configured crack that penetrates the

external surface of the component, (2) a subsurface crack or a crack that only

penetrates the internal surface of the materials, and (3) a change in a material property,

such as a potential change in the hardness property or strength property for the

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elastomer or polymer material used to fabricate the component. RAI B.2.32-4 is relevant

to the acceptance of the applicant's AMR basis for neoprene and fiberglass flexible

connection (expansion joint) surfaces in the reactor building HVAC system and primary

containment air processing system that are exposed internally to the ventilation

environment or externally to the uncontrolled indoor air environment. The staff's

acceptance of the System Walkdown Program to manage the aging effects of cracking

and change of material properties for elastomers and the discussion of RAI B.2.32-4 are

documented in SER Section 3.0.3.2.14. Based on this review, the staff concludes that

the System Walkdown Program will adequately manage the aging effects of cracking

and change in material properties of neoprene flexible hoses during the period of

extended operation.

In RAI 3.3.2.2.5.1-3, Part A, and RAI 3.3.2.3-1 by letter dated July 23, 2008, the staff

asked the applicant to provide its basis why there are not any applicable AERMs

identified for the following component/material/environmental combinations:

(1) silicone rubber heat exchanger tube plugs in the diesel generator intake

exhaust systems under exposure to the ventilation environment,

(2) elastomeric (synthetic rubber) flexible connections (hoses) in the diesel

generator system and fire protection system under external exposure to

uncontrolled indoor air,

(3) neoprene flexible connections in the diesel generator buildings HVAC system

that are exposed internally to the ventilation environment and externally to the

uncontrolled indoor air environment,

(4) neoprene/asbestos flexible connections in the diesel generator buildings

HVAC system and the control structure HVAC system that are exposed

internally to the ventilation environment and externally to the uncontrolled

indoor air environment, and

(5) neoprene/fiberglass flexible connections in the diesel generator buildings

HVAC system and the control structure HVAC system that is exposed

internally to the ventilation environment and externally to the uncontrolled

indoor air environment.

In RAI 3.3.2.2.5.1-2, Part B, the staff asked the applicant to identify what its thermallyinduced and radiologically-induced thresholds are for concluding that thermally-induced

and radiologically-induced cracking and changes in material properties could occur for

the component/material/environmental combinations discussed in Part A of the

questions and what the maximum temperature and radiation levels will be for the specific

ventilation and/or indoor air environments that the system components are exposed to.

In its letter dated August 27, 2008, in response to RAI 3.3.2.2.5.1-3, Parts A and B, and

RAI 3.3.2.3-1, the applicant provided a listing of the structures in which the above

identified component/material/environment combinations is located. In all those

locations, the applicant indicated that threshold limits for ionizing radiation, temperature,

ultraviolet radiation and ozone levels will not be exceeded.

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On the basis that the recommended threshold levels of the GALL Report will not be

exceeded, the staff concludes that the identified component/material/environment

combinations will not have any aging effects requiring management.

(2) LRA Section 3.3.2.2.5 addresses hardening and loss of strength due to elastomer

degradation in spent fuel cooling and cleanup systems. The applicant stated that this

aging effect is not applicable because elastomer linings do not perform an intended

function.

SRP-LR Section 3.3.2.2.5 states that hardening and loss of strength due to elastomer

degradation may occur in elastomer linings of the filters, valves, and ion exchangers in

spent fuel pool cooling and cleanup systems (BWR and PWR) exposed to treated water

or treated borated water. The GALL Report recommends that a plant-specific AMP be

evaluated to determine and assess the qualified life of the linings in the environment to

ensure that these aging effects are adequately managed.

For BWR designs, SRP-LR Section 3.3.2.2.5.2 invokes AMR Item 12 in Table 3 of the

GALL Report, Volume 1, and AMR Item VII.A4-1 in the GALL Report, Volume 2, as

applicable to elastomeric liners in BWR spent fuel cooling and cleanup systems that are

exposed internally to the treated water environment of the spent fuel pool coolant

The staff verified that the applicant does not credit any elastomeric liners in the SSES

fuel pool, fuel pool and cleanup system, or fuel pool auxiliaries for aging management.

However, the staff noted that the applicant did align one other auxiliary system AMR for

elastomeric components to the staff's AMR recommendations in AMR Item 12 in Table 3

of the GALL Report, Volume 1, and GALL AMR Item VII.A4-1. In this AMR, the applicant

identified that the silicone rubber heat exchanger tube plugs in diesel generator intake

and exhaust systems are exposed internally to a treated water environment and are

within the scope of an AMR. In this AMR, the applicant stated that there are not any

applicable aging effects requiring management (AERMs) for the internal tube plug

surfaces that are exposed to a treated water environment. The staff noted that the

applicant did not provide any basis for concluding that there are not any applicable

AERMs for the tube plug surfaces that are exposed the treated water environment. The

staff noted that, in contrast to the applicant's determination, GALL AMR VII.A4-1

identifies that elastomeric materials may degrade (i.e., harden or lose strength) under

exposure to treated water.

In RAI 3.3.2.2.5.2-1, by letter dated July 23, 2008, the staff asked the applicant to justify

its basis for concluding that the silicone tube plugs in the diesel generator intake/exhaust

system heat exchangers would not degrade (i.e., harden or lose strength) for the tube

plug surfaces that are exposed to the treated water environment.

In its letter dated August 27, 2008, in response to RAI 3.3.2.2.5.2-1, the applicant stated

that change in material properties and cracking of elastomers, such as silicone, may be

due to ionizing radiation, thermal exposure, or exposure to ultrasonic radiation or ozone.

The applicant further stated that:

, The silicone tube plugs are located in the Diesel Generator Buildings,

where the total integrated dose is well below 1OE6rads. Also, during

normal plant operation, the silicone tube plugs are exposed to a treated

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water environment that is not expected to contain or to release any

measurable ionizing radiation.

" To ensure proper diesel generator operation, Diesel Generator Rooms A,

B, C and D are individually ventilated and heated to maintain a

temperature in the range of approximately 850 F to 950 F. Also, during

normal plant operation, the diesel generators are in a standby mode, so

the silicone tube plugs are exposed to a treated water temperature that is

expected to be approximately the same as the ambient air temperature.

* The tube plugs are fabricated of silicone rather than natural rubber, and

silicone has been demonstrated to have excellent resistance to ultraviolet

radiation and ozone. The treated water environment associated with the

Diesel Generator intake/exhaust system contains no sources of ultraviolet

radiation or ozone.

Therefore, the applicant stated that change in material properties and cracking is not an

aging effect requiring management because none of these stressors exceed their

threshold limits.

The staff reviewed the applicant response to RAI 3.3.2.2.5.2-1, and finds the applicant

response acceptable because (the applicant identified the location where these silicone

tube plugs are located in the Diesel Generator Building and defined the stressors that

could cause the aging effects at those locations. Although these silicone plugs are in a

treated water environment, the staff noted that the stressors that could cause aging

degradation in the diesel generator system and in the diesel generator building are not

the same as in the spent fuel pool and cleanup system where a higher radiation level

and temperatures could be experienced. The staff finds that the applicant's response

provides an acceptable basis for concluding that cracking and changes in material

properties are not applicable aging effects for these components because: (1) the

environmental conditions are at temperatures less than or equal to 95°F and do not

include sources of radiation or ozone, (2) this is consistent with the GALL Table IX.C

that cracking and changes in material properties are only applicable aging effect if the

component operating termperatures are greater than 950F, or if they are exposed to

radiation or ozone.

Based on the programs identified above, the staff concludes that the applicant's programs meet

SRP-LR Section 3.3.2.2.5 criteria. For those line items that apply to LRA Section 3.3.2.2.5, the

staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21(a)(3).

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3.3.2.2.6 Reduction of Neutron-Absorbing Capacity and Loss of Material Due to General

Corrosion

The staff reviewed LRA Section 3.3.2.2.6 against the criteria in SRP-LR Section 3.3.2.2.6.

LRA Section 3.3.2.2.6 addresses reduction of neutron-absorbing capacity and loss of material

due to general corrosion. The applicant stated that these aging effects are not applicable

because Boral, the neutron-absorbing medium, does not degrade as a result of long-term

exposure to radiation, and Boral is stable, durable, and corrosion resistant.

SRP-LR Section 3.3.2.2.6 states that reduction of neutron-absorbing capacity and loss of

material due to general corrosion may occur in the neutron-absorbing sheets of BWR and PWR

spent fuel storage racks exposed to treated water or treated borated water. The GALL Report

recommends further evaluation of a plant-specific AMP to ensure that these aging effects are

adequately managed.

During its review the staff noted the referenced GALL Report Item VII.A2-3 lists the aging

effects as reduction of neutron absorbing capacity and loss of material due to general

corrosion. However the AMR result line item in LRA Table 3.5.2-2 uses footnote E for the

combination of Boral, treated water, loss of material and BWR Water Chemistry Program. Also

during its review, the staff found industry operating experience of aluminum cations being found

in the spent fuel pool water that could potentially be from the aluminum poison cans or from the

Boral material made from aluminum-boron carbide composite. By letter dated June 13, 2008,

the staff sent RAI 3.3.2.2.6-1 to ask the applicant whether plant-specific operating experience

exists at SSES in which aluminum cations were found in the spent fuel pool water and to

explain the source of the aluminum. The staff further asked the applicant to justify the basis for

not crediting a one-time inspection to determine the effectiveness of the BWR Water Chemistry

Program in managing these aging effects.

By letter dated July 24, 2008, the applicant stated in its response letter that SSES does not

have plant-specific operating experience with respect to the presence of aluminum cations in

the spent fuel pool. The staff noted that the industry operating experience related to the

galvanic corrosion between the stainless steel enclosure and the aluminum clad is applicable to

PWR's, because of the presence of boric acid in the spent fuel pool water which supports this

type of corrosion. SSES is a BWR plant that does not contain boric acid in the spent fuel pool.

SSES utilizes Boral plates which are contained in sealed tubes manufactured under an

accepted Quality Assurance Program, which would prevent the spent fuel pool water from

making contact with the Boral material. The applicant also provided plant-specific results from

the Boral sample coupons. Half of the Boral coupon inventory are non-vented in order to

simulate the expected conditions of the spent fuel pool where the water was not in contact with

the Boral. The other half of the coupons were vented to simulate the conditions if the Boral was

in contact with the -spent fuel pool water. The applicant stated the results of the Boral coupons

that were non-vented have not shown signs of blistering, pitting corrosion or loss of neutronabsorbing capacity. The results of the vented Boral coupons have shown some blistering on the

edges, but neutron attenuation testing has shown the Boral has retained its design properties

for neutron attenuation. On the basis of its review, the staff finds the applicant's response

acceptable, because aluminum cations have not been found in the spent fuel pool water and

the test results have not shown loss of neutron absorbing capability from Boral sample coupons

representative of the poison cans in the spent fuel pool.

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The staff noted that the applicant's proposed AMP for managing loss of material due to pitting

and crevice corrosion is the BWR Water Chemistry Program, alone, without a confirmatory

inspection program. The applicant had not provided sufficient justification to explain how the

BWR Water Chemistry Program, alone, will provide adequate management for the potential

aging effect of loss of material due to pitting or crevice corrosion, therefore the staff issued RAI

3.3-1 by letter July 15, 2008. The RAI asks the applicant to justify why an inspection program,

such as the CPEI is not needed to confirm that age related degradation of the components is

not occurring.

In a letter dated August 15, 2008, the applicant responded to RAI 3.3-1 by providing a response

to the RAI, citing both industry and plant-specific data. Excerpts from that response are

repeated below:

The technical justification of the Boral neutron-absorbing capability aging

assessment is based on plant-specific and industry operating experience. Loss

of material of aluminum in treated water due to general corrosion is not an aging

effect requiring management consistent with the GALL (e.g., VII.A4-5), but loss

of material due to crevice and pitting corrosion is an aging effect requiring

management and is managed by the BWR Water Chemistry Program...

Industry Experience:

A search of industry experience (INPO EPIX database) revealed ... that no

instances of reduction of Boral neutron-absorbing capability have been

experienced by other nuclear plants.

SSES Plant-Specific Operating Experience:

Half of the SSES Boral sample coupons are non-vented, simulating the expected

condition at the racks. These have not shown any blistering, pitting corrosion or

loss of neutron-absorbing capability. The other half of the SSES Boral coupons

are vented, simulating a portion of the fuel rack having a bad weld, allowing

water into the area with the Boral plates. These vented samples have shown

blistering near the edges of the plate due to the porous nature of the cut edge of

the plate, where water interacts with the Boron matrix and radiation to generate

gases that blister the plate. This effect has, in some cases, caused the outer

metal layer of the Boral plate (sample) to blister out and press flat against the

outer tube that contains it. This contact in a demineralized water environment

has shown no signs of galvanic or other corrosion. Neutron attenuation testing

has shown that these plates still retain the required design properties for neutron

attenuation. Weighing of the samples has shown no loss of material, although

some minor gains in weight (post drying) may be related to the water

intrusion/interaction with decay products.

The most recent Boral coupon tests (year 20 coupon test) for Units 1 and 2 were

performed by independent testing facilities in 2003 and 2005, respectively. The

range of water chemistry conditions to which the Boral coupons were subjected

are within the fuel pool chemistry specification limits as delineated in the

Susquehanna Chemistry Manual.

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By letter dated April 13, 2009, the staff sent RAI 3.3.2.2.6-2 to ask the licensee to describe the

decay products that were said to be responsible for minor weight gains in the Boral surveillance

coupons. The licensee responded in letter dated May 13, 2009 that the decay products are

corrosion products from the oxidation of aluminum. The staff has reviewed the information and

has found it acceptable, since there would be some aluminum corrosion products present due

to general corrosion of aluminum following initial installation.

By letter dated August 15, 2008, the licensee described the Boral coupon testing program.

Boral sample coupons are removed from the spent fuel pool periodically for testing and

evaluated for corrosion or other degradation of the neutron absorber by comparing various

physical characteristics. Additional Boral coupons are scheduled to be removed from the spent

fuel storage pool and analyzed at years 30 and 40 under a current licensing commitment per

UFSAR Section 9.1.2.3.3.

By letter dated April 13, 2009, the staff sent RAI 3.3.2.2.6-3 to ask the licensee additional

questions about the Boral coupon testing. The licensee responded in a letter dated May 13,

2009 that there were three sets of coupons left in each unit's pool. The licensee also made

Commitment 61 to continue Boral coupon testing in the period of extended operation. The staff

had a teleconference with the licensee on May 21, 2009 to clarify Commitment 61. In response

dated May 28, 2009 the licensee made an amendment to Commitment 61 to add: "SSES

UFSAR section 9.1.2.3.3 Inservice Inspection will be revised to identify the coupon testing

schedule during the period of extended operation. SSES UFSAR section 9.1.2.3.3.2. Test

Coupon Inspection will be revised to require neutron attenuation testing as part of the

inspection of test coupons removed from the spent fuel pool." The staff has reviewed the

response and commitment to perform Boral coupon testing including neutron attenuation

testing in the period of extended operation. The staff finds this acceptable since SSES has a

sufficient amount of coupons to perform the testing, providing assurance that degradation of the

neutron absorbing material would be detected. The staff finds that the commitment to revise

the UFSAR to reflect the changes above is acceptable since the revision would provide

adequate assurance that the Boral coupon testing would be performed in the period of

extended operation. Therefore, the staff has found the response and commitment to be

acceptable.

From the RAI responses dated August 15, 2008, and May 13, 2009, the licensee described the

Water Chemistry Program. Based on SSES plant-specific experience of Boral coupon

inspections and testing, the loss of material aging effect has been and will continue to be

adequately managed by the BWR Water Chemistry Program. The BWR Water Chemistry

Program would monitor and control water chemistry parameters within limits to mitigate loss of

material due to crevice or pitting corrosion. The scheduled Boral sample coupon testing is a

verification of effectiveness of the credited BWR Water Chemistry program. The staff also

notes that both industry and current plant-specific operating experience show that aging effects

do not occur or progress very slowly for Boral neutron-absorbing sheets exposed to treated

water in a spent fuel pool. The staff has reviewed this response and has determined that the

Water Chemistry Program, as validated by the Boral coupon testing program, will adequately

manage loss of material in the period of extended operation.

The staff reviewed the BWR Water Chemistry Program which will control the quality of the

spent fuel pool water to prevent the loss of material of the aluminum cladding and boroncarbide materials within. The staff's evaluation of the BWR Water Chemistry Program is

documented in SER Section 3.0.3.1.1. The applicant has demonstrated with industry and plant3-344
specific experience that aging effects do not occur or progress very slowly in a treated water

environment and the commitment for continued Boral coupon testing provides confirmation of

the effectiveness of the BWR Water Chemistry Program. The staff finds crediting of the BWR

Water Chemistry Program, for managing the aging effects of loss of material of the Boral

neutron-absorbing sheets exposed to treated water in the spent fuel pool to be acceptable.

By letter dated April 13, 2009, the staff sent RAIs 3.3.2.2.6-5 through 3.3.2.2.6-6 to ask the

licensee additional questions about operating experience. The licensee responded in a letter

dated May 13, 2009 with the following excerpts:

"Testing of Boral coupons at Susquehanna has continued and although some

blistering of the aluminum cladding has been observed on vented test coupons,

evaluations have shown that the boron areal density remains within specification.

The unvented coupons have always been found in the as-fabricated condition

with the surface appearing as mill finish Boral. The vented coupons have shown

signs of surface blistering, but the blisters (where aluminum clad delaminated

from core) are only conditions of appearance and have not had any affect on the

Boral neutron absorbing capacity.

In September 2008, an attempt to remove an irradiated fuel assembly from

storage cell location PP-2 in the SSES Unit 1 Spent Fuel Storage Pool (SFSP)

was unsuccessful. That particular fuel assembly currently remains in cell PP-2,

and the surrounding/adjacent cells currently do not have fuel stored in them.

Visual inspections of the surrounding cells have not identified any poison can

deformation or the presence of any foreign material causing interference with the

assembly. PPL has not determined the cause of this condition in the PP-2

storage cell at this time.

As a result of the issue with the assembly in the PP-2 Unit 1 SFSP cell, and a

previous incident in March 2006 in which a blade guide could not be inserted into

the Unit 1 SFSP cell C-13, a visual inspection of cell C-13 was performed during

the recent Unit 2 14th refueling and inspection outage (U2-14RIO) in May 2009.

Significant bulging of one of the four poison can walls was observed. The cell is

currently empty and will not be used for storage. Cell C-13 and the surrounding

adjacent cells historically have been reserved for storage of non-fuel

components (e.g., blade guides) and are not used to store spent fuel

assemblies. The condition of cell C-13 has been entered into the SSES

Corrective Action Program for evaluation and determination of necessary followup activities. Although the cause of the deformation in cell C-13 has not yet been

determined, industry operating experience suggests it may be the result of

hydrogen gas generation from either moisture contained in the Boral at the time

of manufacture or a leaking seal weld in the poison can.

The Susquehanna SFSPs contain over 5000 locations where spent fuel

assemblies are typically stored. During fuel handling activities over the past few

years, and in particular, during the most recent fuel movements prior to and

during the U2-14RIO, no other significant interference issues have been

encountered, nor have there been any other similar observations of rack

deformation. This suggests the issues related to cells PP-2 and C-13 are

isolated incidents and are not indicative of a widespread fuel storage rack

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problem. Further evaluations and follow-up actions are being conducted via the

SSES Corrective Action Program. Based on the evaluations that have been

performed to-date and past industry experience, PPL finds that there is no

current safety concern with the Susquehanna SFSPs.

In addition to the recent SSES operating experience, [EPRI Technical Report,

"Handbook of Neutron Absorber Materials for Spent Nuclear Fuel Transportation

and Storage Applications, "November 2006 edition] includes a summary of inservice experience with Boral. The two primary issues identified in the summary

of operating experience are loss of material due to corrosion and blistering of the

aluminum cladding of the Boral sheets. As discussed in response to the

preceding RAIs, these issues are not safety concerns for Susquehanna. Neither

corrosion or blistering has resulted in loss of neutron absorbing capability of the

Boral material at Susquehanna, and [EPRI Technical Report, "Handbook of

Neutron Absorber Materials for Spent Nuclear Fuel Transportation and Storage

Applications, "November 2006 edition] reaches a similar conclusion based on the

operating experience reported in that document. PPL-is not aware of any other

operating experience that is applicable to Susquehanna."

The staff has reviewed and confirmed the operating experience and finds this acceptable since

the operating experience supports the conclusion that the implementation of the Boral coupon

testing will continue to be able to manage the loss of neutron-absorbing capacity and

degradation of Boral effectively.

Based on the above, the staff concludes that the applicant meets SRP-LR Section 3.3.2.2.6

criteria. The staff determines that the LRA is consistent with the GALL Report and that the

applicant has demonstrated that the effects of aging will be adequately managed so that the

intended function(s) will be maintained consistent with the CLB during the period of extended

operation, as required by 10 CFR 54.21(a)(3).

3.3.2.2.7 Loss of Material Due to General, Pitting, and Crevice Corrosion

The staff reviewed LRA Section 3.3.2.2.7 against the following criteria in SRP-LR

Section 3.3.2.2.7:

(1) LRA Section 3.3.2.2.7 addresses loss of material due to general, pitting, and crevice

corrosion in the reactor coolant pump oil collection system. The applicant stated that this

aging effect is not applicable because the SSES primary containment is inerted during

normal operation, which meets the requirements of item 111.0 in 10 CFR Part 50

Appendix R.

SRP-LR Section 3.3.2.2.7 states that loss of material due to general, pitting, and crevice

corrosion may occur in steel piping, piping components, and piping elements, including

the tubing, valves, and tanks in the reactor coolant pump oil collection system, exposed

to lubricating oil (as part of the fire protection system). The existing AMP periodically

samples and analyzes lubricating oil to maintain contaminants within acceptable limits,

thereby preserving an environment not conducive to corrosion. However, control of lube

oil contaminants may not always be fully effective in precluding corrosion; therefore, the

effectiveness of lubricating oil control should be verified to ensure that corrosion does

not occur. The GALL Report recommends further evaluation of programs to manage

corrosion to verify the effectiveness of the lubricating oil program. A one-time inspection

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of selected components at susceptible locations is an acceptable method to ensure that

corrosion does not occur and that component intended functions will be maintained

during the period of extended operation. In addition, corrosion may occur at locations in

the reactor coolant pump oil collection tank where water from wash-downs may

accumulate; therefore, the effectiveness of the program should be verified to ensure that

corrosion does not occur. The GALL Report recommends further evaluation of programs

to manage loss of material due to general, pitting, and crevice corrosion, including

determination of the thickness of the lower portion of the tank. A one-time inspection is

an acceptable method to ensure that corrosion does not occur and that component

intended functions will be maintained during the period of extended operation.

The staff verified that only piping, piping components and elements that align to GALL

AMR VII.F1-19 and VII.H2-20 for the Fire Protection, Reactor Building Chilled Water,

Control Structure Chilled Water and Diesel Generator Lubricating Oil and NSAS

Component Systems that are fabricated from steel materials are applicable to SSES.

The staff evaluated the Lubricating Oil Analysis Program and the Lubricating Oil

Inspection Program, and the evaluations are documented in SER Sections 3.0.3.2.15

and 3.0.3.2.13 respectively. The staff reviewed the applicant's Lubricating Oil Analysis

Program and determined that this program includes periodic sampling and analysis of

lubricating oil to maintain contaminants within acceptable limits. The staff finds that

these activities are consistent with the recommendations in the GALL Report and are

adequate to manage loss of material due to general, pitting and crevice corrosion for

steel piping, piping components and elements exposed to lubricating oil internally or

externally. The staff verified that the applicant has credited its Lubricating Oil Inspection

Program to verify the effectiveness of the Lubricating Oil Analysis Program to manage

this aging effect. The applicant's AMPS are consistent with those recommended for

aging management in SRP-LR Section 3.3.2.2.7, Item #1 and in GALL AMR Items

VII.F1-19 and VII.H2-20.

Based on the program identified above, the staff concludes that the applicant's program

meet SRP-LR 3.3.2.2.7 Item #1 criteria and therefore the applicant's AMRs are

consistent with those under GALL Report Item VII.F1-19 and VII.H2-20. For those line

items that apply to LRA Section 3.3.2.2.7 Item #1, the staff determines that the LRA is

consistent with the GALL Report and that the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended function(s) will be

maintained consistent with the CLB during the period of extended operation, as required

by 10 CFR 54.21(a)(3).

LRA Section 3.3.2.2.7, item 1 states that item numbers 3.3.1-15 and 3.3.1-16 of LRA

Table 3.3.1 are not applicable to SSES, which align to the GALL Report Items VII.G-26

and VII.G-27. The staff noted that SSES is of BWR design and contains a primary

containment that is inerted during normal operation, thus SSES meets the requirements

of 10 CFR Part 50 Appendix R Section 111.0, and is not required to have an oil collection

system for the reactor coolant pump by the rule. The staff confirmed that since SSES is

a BWR with an inert primary containment atmosphere, it has no reactor coolant pump oil

collection system. Therefore, aging of the piping, tubing, valves bodies, and tanks in the

reactor coolant pump oil collection system are not applicable for SSES. Thus, the staff

finds the applicant's conclusion that the aging effect loss of material due to general,

pitting and crevice corrosion is not applicable to SSES, acceptable because SSES does

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not have a reactor coolant pump oil collection system and GALL Items VII.G-26 and

VII.G-27 do not apply.

(2) LRA Section 3.3.2.2.7 addresses loss of material due to general, pitting, and crevice

corrosion in the BWR reactor water cleanup and shutdown cooling systems. The

applicant stated that loss of material due to general, pitting, and crevice corrosion for

steel piping components exposed to treated water is managed by the BWR Water

Chemistry Program. The BWR Water Chemistry Program manages aging effects

through periodic monitoring and control of contaminants. The CPEI will provide a

verification of the effectiveness of the BWR Water Chemistry Program to manage loss

of material due to general, pitting, and crevice corrosion through examination of steel

piping components.

SRP-LR Section 3.3.2.2.7 states that loss of material due to general, pitting, and crevice

corrosion may occur in steel piping, piping components, and piping elements in the

BWR reactor water cleanup and shutdown cooling systems exposed to treated water.

The existing AMP monitors and controls reactor water chemistry to manage the aging

effects of loss of material from general, pitting, and crevice corrosion. However, high

concentrations of impurities in crevices and with stagnant flow conditions may cause

general, pitting, or crevice corrosion; therefore, the effectiveness of the chemistry

control program should be verified to ensure that corrosion does not occur. The GALL

Report recommends further evaluation of programs to manage loss of material from

general, pitting, and crevice corrosion to verify the effectiveness of the water chemistry

program. A one-time inspection of selected components at susceptible locations is an

acceptable method to ensure that corrosion does not occur and that component

intended functions will be maintained during the period of extended operation.

The staff noted that in addition to applying this AMR result for reactor water cleanup

system components, the applicant also applied this AMR result for carbon steel piping

and valve bodies exposed to treated water in the fuel pool cooling and cleanup system

and fuel pools and auxiliaries (LRA Table 3.3.2-14, pages 3.3-253 and 3.3-357), for

carbon steel piping components exposed to treated water in the process and area

radiation monitoring system (LRA Table 3.3.2-17, page 3.3-269), for carbon steel

accumulators, piping, valve bodies, and piping and piping components exposed to

treated water in the control rod drive hydraulics system (LRA Table 3.3.2-3, pages 3.3-

102, 3.3-105, 3.3-107, and 3.3-108), and for carbon steel accumulators exposed to

treated water in the standby liquid control system (LRA Table 3.3.2 31, page 3.3-339).

For all of these AMR result lines, the applicant proposed to manage the aging effect of

loss of material for carbon steel components in a treated water environment with a

combination of the BWR Water Chemistry Program and the Chemistry Program

Effectiveness Inspection.

The staff reviewed the applicant's BWR Water Chemistry Program. The staff's

evaluation of this program, which is documented in SER Section 3.0.3.1.1, found that

the BWR Water Chemistry Program provides mitigation for the aging effect of loss of

material due to general, pitting, and crevice corrosion. The staff reviewed the applicant's

Chemistry Program Effectiveness Inspection. The staff's evaluation of this program,

which is documented in SER Section 3.0.3.1.10, found that the CPEI is a one-time

inspection that is consistent with the GALL Report's recommendations for AMP XI.M32,

"One-Time Inspection." The CPEI includes provisions for inspecting selected

components in areas of low or stagnant flow and is capable of detecting loss of material

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due to general, pitting and crevice corrosion, if it should occur in the selected

components. Because the BWR Water Chemistry Program provides mitigation and the

CPEI provides detection of the aging effect if it should occur, the staff finds the

applicant's proposed AMPs for managing the aging effect of loss of material due to

general, pitting, and crevice corrosion for carbon steel components exposed to treated

water in the reactor water cleanup system, the fuel pool cooling and cleanup system and

fuel pools and auxiliaries, the process and area radiation monitoring system, the control

rod drive hydraulics system, and the standby liquid control system to be acceptable.

(3) LRA Section 3.3.2.2.7 addresses loss of material due to general, pitting, and crevice

corrosion in diesel exhaust piping, piping components, and piping elements. The

applicant stated that loss of material due to general corrosion for steel piping

components exposed to diesel exhaust is managed by the System Walkdown Program.

Loss of material due to corrosion was not identified as an applicable aging effect for the

stainless steel diesel exhaust piping flexible connections and tubing which are located

inside the diesel generator buildings. The diesel exhaust system is normally in standby

mode and the inside surfaces of the components are dry and not subject to any type of

wetting.

SRP-LR Section 3.3.2.2.7 states that loss of material due to general (steel only), pitting,

and crevice corrosion may occur in steel and stainless steel diesel exhaust piping,

piping components, and piping elements exposed to diesel exhaust. The GALL Report

recommends further evaluation of a plant-specific AMP to ensure that the aging effect is

adequately managed.

SRP-LR Section 3.3.2.2.7.3 references AMR item 18 in Table 3 of the GALL Report,

Volume 1 and AMR item VII.H2-2 in Table VII.H2 of the GALL Report, Volume 2 as the

applicable AMRs for evaluating loss of material due to general, pitting, and crevice

corrosion in steel and stainless steel diesel generator piping, piping components, and

piping elements that are exposed to a diesel exhaust environment. The aging

management guidance in these AMRs for diesel generator exhaust piping is consistent

with that given SRP-LR Section 3.3.2.2.7.3.

The staff noted that the applicant's AMR items on loss of material in emergency diesel

generator exhaust piping components are given in AMR item 3.1.1-18 of LRA Table

3.3.1 and in the AMR items in LRA Table 3.3.2-9, "Aging Management Review Results -

Diesel Generators System," that have reference links LRA AMR item 3.1.1-18. The staff

confirmed that LRA Table 3.3.2-9 did include AMRs for the managing loss of material

due to general, pitting, and crevice corrosion in internal steel emergency diesel

generator piping, piping components, and piping elements surfaces that are exposed to

a ventilation environment and that these AMRs were referenced to GALL AMR VII.H2-2.

The staff also confirmed that in these AMRs, the applicant credited AMP B.2.32,

Systems Walkdown Program, to manage loss of material in the internal steel diesel

generator exhaust piping, piping components, and piping element surfaces that are

exposed to a ventilation (in this case diesel exhaust) environment.

The staff noted that its Systems Walkdown Program, the applicant identifies that the

AMP is consistent the staff's recommended program elements in GALL AMP XI.M36,

"External Surfaces Monitoring Program," which is a program that is credited only for

managing loss of material that occurs in external metal component surfaces, or for

aging management of their external paint or coating surfaces in the components are

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painted or coating with plastic coatings. The staff also noted that the "scope of program"

program element in GALL AMP XI.M36 states the a program corresponding to the GALL

AMP XI.M36 may only be used to internal component surfaces if the "material and

environment combinations are the same for internal and external surfaces such that

external surface condition is representative of internal surface condition."

The staff noted that, in LRA Table 3.0-1 of the application, the applicant equates the

emergency diesel generator exhaust environment to be the equivalent of the applicant's

"ventilation environment" for the application, which is defined by the applicant as follows:

Ventilation air and compressed air and gases. Ventilation air is defined as

ambient air that is conditioned to maintain a suitable environment for

equipment operation or personnel occupancy. Ventilation air may be

conditioned by filtering, heating, cooling, dehumidification or some

combination.

Internal ambient environments found inside components such as piping

and tanks that are either vented or otherwise open to the ambient

conditions in their location are also included under this environment, as

are exhaust gases, such as from a diesel engine.

While ventilation is predominantly an internal environment, the external

surfaces of mechanical components may be exposed to ventilation (e.g.,

cooling unit tubes in HVAC systems).

Comparable GALL environments: Air - Indoor Uncontrolled, Air -

Outdoor, Condensation, Diesel Exhaust

The diesel exhaust that results from operations of emergency diesel generators is made

up mostly of carbon dioxide (C02) and water (H20) in the vapor state. However, there

may be some amount of liquid state water (moisture) in the exhaust. Diesel exhaust may

also contain some contaminants because the oil fractions that make up the diesel fuel

prior to its combustion may contain small percentages of nitrogen, sulfur or halogen

atomic elements impurities. These type of environmental conditions are reflected in the

staff's environmental description in GALL Table IX.D for diesel exhaust, which states

that diesel exhaust contains "gases, fluids, and particulates." The staff took issue with

equating the diesel exhaust environment to the indoor ventilation environment that

would be on the outside of these piping, piping components, and piping elements

because the diesel exhaust could contain significant levels of moisture and

contaminants that are not normally present in the indoor ventilation air. Thus, the staff

was of the opinion that the applicant was not justified in crediting the System Walkdown

Program for managing loss of material the internal emergency diesel generator piping,

piping component, and piping element surfaces that are exposed to diesel exhaust

because the diesel exhaust could create more harsh conditions than would the normal

ventilated air inside of the diesel generators rooms.

In a teleconference dated January 5, 2009, the staff discussed the applicant's basis for

managing loss of material in the steel stainless steel diesel generator exhaust piping,

piping components, and piping elements that are exposed to a diesel exhaust

environment. During this teleconference, the applicant stated that it will amend the LRA

to identify loss of material as an applicable aging effect for the internal steel and

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stainless steel diesel generator exhaust piping, piping component, and piping element

surfaces that are exposed to the diesel exhaust environment and to credit a one-time

examination of the internal components surfaces using the examinations techniques of

the AMP B.2.28, Supplemental Piping and Tanks Inspection Program for aging

management of this aging effect.

The staff confirmed that the applicant's Supplemental Piping and Tanks Inspection

Program is a one-time inspection program for miscellaneous plant piping and tank

components and that the AMP credits a combination of established volumetric (RT or

UT) and visual (VT-1 or VT-3 or equivalent) examination techniques performed by

qualified personnel on a sample population of subject components. The staff noted that

the Subsection IWA-2000 of the ASME Code Section XI lists volumetric and VT-1 visual

examination techniques as valid inspection methods for the detection of cracking in

metallic components. The staff also noted that GALL AMP XI.M32, "One-Time

Inspection," indicates that one-time inspection programs are valid AMPs for cases

where: (1) the components may be susceptible to the gradual accumulation or

concentration of agents that, if present, could promote certain aging effects, and (2)

where additional verification is necessary in order to confirm that degradation is not

occurring in the components or is progressing at a very slow propagation rate, or else to

trigger additional corrective actions if unacceptable degradation is detected in the

components.

The staff verified that, in the applicant's letter of January 12, 2009, the applicant made

the appropriate changes to the AMRs for the steel stainless steel emergency diesel

exhaust piping, piping components, and piping elements to credit the AMP B.2.28,

Supplemental Piping and Tanks Inspection Program, to manage loss of material in the

internal steel and stainless steel diesel generator exhaust piping, piping component, and

piping element surfaces that are exposed to diesel exhaust. The staff also verified that,

in the applicant's letter of January 12, 2009, the applicant made amended AMP B.2.28

to add the diesel exhaust piping to the scope of the AMP. Therefore, based on this

assessment, the staff finds that the applicant has provided an acceptable basis for

crediting the Supplemental Piping and Tanks Inspection Program for aging

management of loss of material in these components because: (1) the emergency

diesel generators are only periodically operated in accordance with plant technical

specifications or transient operating procedures, (2) the applicant's basis is consistent

with criteria in GALL AMP XI.M32 on when one-time inspection programs can be

credited for aging management, and (3) the applicant's Supplemental Piping and Tanks

Inspection Program includes volumetric examination methods and VT-1 or VT-3 visual

inspection methods, which are valid techniques for the detection of loss of material in

these steel and stainless steel diesel exhaust components.

Based on the programs identified above, the staff concludes that the applicant's programs meet

SRP-LR Section 3.3.2.2.7 criteria. For those line items that apply to LRA Section 3.3.2.2.7, the

staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21(a)(3).

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3.3.2.2.8 Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced

Corrosion

The staff reviewed LRA Section 3.3.2.2.8 against the criteria in SRP-LR Section 3.3.2.2.8.

LRA Section 3.3.2.2.8 addresses loss of material due to general, pitting, crevice, and

microbiologically influence corrosion (MIC). The applicant stated that loss of material due to

general, pitting, and crevice corrosion and MIC for steel piping components with coatings buried

in soil is managed by the Buried Piping and Tanks Inspection Program. Loss of material for

buried steel piping components with damaged coatings and buried in soil is managed by the

Buried Piping Surveillance Program.

SRP-LR Section 3.3.2.2.8 states that loss of material due to general, pitting, and crevice

corrosion, and MIC may occur in steel (with or without coating or wrapping) piping, piping

components, and piping elements buried in soil. Buried piping and tanks inspection programs

rely on industry practice, frequency of pipe excavation, and OE to manage the effects of loss of

material from general, pitting, and crevice corrosion and MIC. The effectiveness of the buried

piping and tanks inspection program should be verified to evaluate an applicant's inspection

frequency and OE with buried components, ensuring that loss of material does not occur.

The Buried Piping and Tanks Inspection Program is discussed in SER Section 3.0.3.2.13. The

Buried Piping and Tanks Inspection Program relies on examination of buried steel piping and

piping components with coatings during routine maintenance or by using focused inspections at

least once in the ten years prior to entering the period of extended operation and at least once

during the first ten years of entering the period of extended operation. The Buried Piping

Surveillance Program is discussed in SER Section 3.0.3.2.10. The Buried Piping Surveillance

Program relies on the use of cathodic protection to protect buried steel piping with damaged

coatings. Reference electrodes are placed along the buried piping which are used to measure

the potential of the buried piping to ensure that it is adequately protected by the cathodic

protection system. In addition, -coating conduction measurements are taken to indicate that the

protective coatings are adequately installed, and current requirements are trended to insure

that further damage to the coatings is not occurring. Finally, pipe to soil potential surveys are

performed on an annual basis to further demonstrate adequate protection of the buried steel

piping with damaged coatings.

Based on the programs identified, the staff concludes that the applicant's AMR results are

acceptable because the AMPs provide both detection and mitigation for the aging effect of loss

of material due to general, pitting, and crevice corrosion and MIC for steel piping

components with coatings buried in soil in the subject components. For those items that apply

to LRA Table 3.3.1, item 3.3.1 19 and Table 3.4.1, item 3.4.1-17, the staff determines that the

LRA is consistent with the GALL Report and that the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended function(s) will be maintained

consistent with the CLB during the period of extended operation, as required by 10 CFR

54.21 (a)(3).

Based on the programs identified above, the staff concludes that the applicant's programs meet

SRP-LR Section 3.3.2.2.8 criteria. For those line items that apply to LRA Section 3.3.2.2.8, the

staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21(a)(3).

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3.3.2.2.9 Loss of Material Due to General, Pitting, Crevice, Microbiologically-Influenced

Corrosion and Fouling

The staff reviewed LRA Section 3.3.2.2.9 against the following criteria in SRP-LR

Section 3.3.2.2.9:

(1) LRA Section 3.3.2.2.9 addresses loss of material due to general, pitting, crevice, MIC

and fouling in piping, piping components, and piping elements exposed to fuel oil. The

applicant stated that loss of material due to general, pitting, and crevice corrosion and

MIC for steel piping components and tanks exposed to fuel oil is managed by the Fuel

Oil Chemistry Program. The Fuel Oil Chemistry Program manages aging effects through

periodic monitoring and control of contaminants. The CPEI will provide a verification of

the effectiveness of the Fuel Oil Chemistry Program to manage loss of material due to

general, pitting, and crevice corrosion through examination of steel piping components

and tanks exposed to fuel oil. Fouling is not identified as an aging effect for fuel oil.

SRP-LR Section 3.3.2.2.9 states that loss of material due to general, pitting, and crevice

corrosion, MIC, and fouling may occur in steel piping, piping components, piping

elements, and tanks exposed to fuel oil. The existing AMP relies on fuel oil chemistry

programs to monitor and control fuel oil contamination to manage loss of material due to

corrosion or fouling. Corrosion or fouling may occur at locations where contaminants

accumulate. The effectiveness of fuel oil chemistry programs should be verified to

ensure that corrosion does not occur. The GALL Report recommends further evaluation

of programs to manage loss of material due to general, pitting, and crevice corrosion,

MIC, and fouling to verify the effectiveness of fuel oil chemistry programs. A one-time

inspection of selected components at susceptible locations is an acceptable method to

ensure that corrosion does not occur and that component intended functions will be

maintained during the period of extended operation.

The staff noted the applicant's statement in the LRA that fouling is not identified as an

aging effect for fuel oil. However, the staff could find no basis for that statement

provided in the LRA. The staff issued RAI 3.3.2.2.9.1-1 by letter dated July 15, 2008,

asking the applicant to provide a basis for the statement that fouling is not identified as

an aging effect for fuel oil.

In a letter dated August 15, 2008, the applicant responded to RAI 3.3.2.2.9.1-1 by

providing the following response:

The quality of fuel oil is verified upon receipt and before it is delivered to the plant's fuel

oil storage tanks, and introduced into the fuel oil system, to ensure that it does not

contain contaminants, such as sediment, that could cause fouling. The potential for

water contamination in the fuel oil during transfer and storage is, however, assumed.

Therefore, the only foulants that would be expected in the fuel oil would be those that

result from corrosion of steel piping and components, i.e., corrosion products. By

managing loss of material due to general, pitting, crevice, and microbiologically induced

corrosion, corrosion products will be controlled, and fouling will not occur. Therefore,

fouling is not identified as an aging effect for fuel oil.

The staff reviewed the applicant's response and finds its acceptable because it provides

a reasonable technical justification, based on fuel oil testing upon receipt, prior to

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introducing the fuel oil into the fuel oil storage tanks, and on control of potential

corrosion products, as to why fouling is not expected to occur for steel components

exposed to a fuel oil environment. The issues raised in RAI 3.3.2.2.9.1-1 are resolved by

the applicant's response.

The staff reviewed the applicant's Fuel Oil Chemistry Program. The staff's evaluation of

this program, which is documented in SER Section 3.0.3.2.11, found that the Fuel Oil

Chemistry Program provides aging management for loss of material due to general,

pitting, and crevice corrosion and MIC through monitoring and control of fuel oil

contamination such as water or microbiological organisms. The staff reviewed the

applicant's Chemistry Program Effectiveness Inspection. The staff's evaluation of this

program, which is documented in SER Section 3.0.3.1.10, found that the CPEI is a onetime inspection that is consistent with the GALL Report's recommendations for AMP

XI.M32, "One-Time Inspection." The CPEI includes provisions for inspecting selected

components determined to be most susceptible to the aging effect(s) of interest and is

capable of detecting loss of material due to general, pitting and crevice corrosion, and

MIC, if it should occur in the selected components. Based on the applicant's use of a

one-time inspection consistent with the recommendations of the GALL Report, the staff

finds the applicant's proposed AMPs for managing the potential aging effect of loss of

material due to general, pitting, and crevice corrosion, and MIC for steel piping, piping

components, piping elements, and tanks exposed to fuel oil in the diesel fuel oil system

and in the fire protection system to be acceptable.

(2) LRA Section 3.3.2.2.9 addresses loss of material due to general, pitting, crevice, MIC

and fouling in piping, piping components, and piping elements exposed to lubricating oil.

The applicant stated that loss of material due to general, pitting, and crevice corrosion

and MIC for steel piping components exposed to lubricating oil is managed by the

Lubricating Oil Analysis Program. The Lubricating Oil Analysis Program manages aging

effects through periodic monitoring and control of contaminants, including water. The

Lubricating Oil Inspection will provide a verification of the effectiveness of the

Lubricating Oil Analysis Program to manage loss of material due to general, pitting, and

crevice corrosion and MIC through examination of steel piping components. The

Lubricating Oil Analysis Program will also manage reduction in heat transfer due to

fouling of heat exchanger tubes exposed to lubricating oil. For those heat exchangers

within the scope of GL 89-13 for SSES, the Piping Corrosion Program is credited with

managing fouling of heat exchanger tubes exposed to lubricating oil.

SRP-LR Section 3.3.2.2.9 states that loss of material due to general, pitting, and crevice

corrosion, MIC, and fouling may occur in steel heat exchanger components exposed to

lubricating oil. The existing AMP periodically samples and analyzes lubricating oil to

maintain contaminants within acceptable limits, thereby preserving an environment not

conducive to corrosion. However, control of lube oil contaminants may not always be

fully effective in precluding corrosion; therefore, the effectiveness of lubricating oil

control should be verified to ensure that corrosion does not occur. The GALL Report

recommends further evaluation of programs to manage corrosion to verify the

effectiveness of lubricating oil programs. A one-time inspection of selected components

at susceptible locations is an acceptable method to ensure that corrosion does not occur

and that component intended functions will be maintained during the period of extended

operation.

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The staff verified that only heat exchanger components that align to GALL AMR VII.H2-5

for the Control Structure Chilled Water system that are fabricated from steel materials

are applicable to SSES,

The staff evaluated the Lubricating Oil Analysis Program and the Lubricating Oil

Inspection Program, and the evaluations are documented in SER Sections 3.0.3.2.15

and 3.0.3.2.13 respectively. The staff reviewed the applicant's Lubricating Oil Analysis

Program and determined that this program includes periodic sampling and analysis of

lubricating oil to maintain contaminants within acceptable limits. The staff finds that

these activities are consistent with the recommendations in the GALL Report and are

adequate to manage loss of material due to pitting, crevice, and microbiologicallyinfluenced corrosion in steel piping, piping components, and piping elements exposed to

lubricating oil. The staff verified that the applicant has credited its Lubricating Oil

Inspection Program to verify the effectiveness of the Lubricating Oil Analysis Program to

manage this aging effect. The applicant's AMPS are consistent with those

recommended for aging management in SRP-LR Section 3.3.2.2.9, Item #2 and in

GALL AMR Item VII.H2-5.

Based on the programs identified above, the staff concludes that the applicant's programs meet

SRP-LR Section 3.3.2.2.9 criteria. For those line items that apply to LRA Section 3.3.2.2.9, the

staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21(a)(3).

3.3,2.2.10 Loss of Material Due to Pitting and Crevice Corrosion

The staff reviewed LRA Section 3.3.2.2.10 against the following criteria in SRP-LR

Section 3.3.2.2.10:

(1) LRA Section 3.3.2.2.10 addresses loss of material due to pitting and crevice corrosion in

steel piping with elastomer lining or stainless steel cladding. The applicant stated that

this aging effect is not applicable because elastomer linings are not credited for

protection of metallic components, and are therefore, not subject to AMR. There are no

steel with stainless steel cladding piping components that are exposed to treated water

or treated borated water in the Auxiliary Systems for SSES.

SRP-LR Section 3.3.2.2.10 states that loss of material due to pitting and crevice

corrosion may occur in BWR and PWR steel piping with elastomer lining or stainless

steel cladding exposed to treated water and treated borated water if the cladding or

lining is degraded. The existing AMP monitors and controls reactor water chemistry to

manage the aging effects of loss of material from pitting and crevice corrosion.

However, high concentrations of impurities in crevices and with stagnant flow conditions

may cause pitting or crevice corrosion; therefore, the effectiveness of water chemistry

control programs should be verified to ensure that corrosion does not occur. The GALL

Report recommends further evaluation of programs to manage loss of material from

pitting and crevice corrosion to verify the effectiveness of water chemistry control

programs. A one-time inspection of selected components at susceptible locations is an

acceptable method to ensure that corrosion does not occur and that component

intended functions will be maintained during the period of extended operation.

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For applicable steel BWR piping, SRP-LR Section 3.3.2.2.10.1 invokes AMR Item 22 in

Table 3 of the GALL Report, Volume 1, and GALL AMR Item VII.A4-12, applicable to the

steel piping in the spent fuel pool cooling and cleanup (purification) systems designed

with elastomeric linings or stainless steel cladding, where the elastomeric lining or

stainless steel cladding has been determined to be degraded and the underlying steel

material is exposed to treated water or borated treated water.

The staff verified that the LRA does not credit internal elastomeric liners in the

components of the fuel pool cooling and cleanup system, or fuel pool auxiliaries for

aging management. The staff also verified that the steel piping components in the SSES

fuel pool cooling and cleanup systems and fuel pool auxiliaries do not include any

internal stainless steel cladding. Based on this review, the staff concludes that the

applicant has provided an acceptable basis for concluding that the supplemental

evaluation recommendations in SRP-LR Section 3.3.2.2.10.1 and in GALL AMR VII.A4-

12 are not applicable to the LRA because the staff has verified that the applicant does

not credit any elastomeric liner in the fuel pool cooling and cleanup systems for aging

management and because the staff has verified that the fuel pool cooling and cleanup

systems do not include any steel components that are lined with internal stainless steel

cladding.

(2) LRA Section 3.3.2.2.10 addresses loss of material due to pitting and crevice corrosion in

piping, piping components, piping elements, and heat exchanger components. The

applicant stated that loss of material due to pitting and crevice corrosion for stainless

steel heat exchanger components exposed to treated water is managed by the Closed

Cooling Water Chemistry Program. The Closed Cooling Water Chemistry Program

manages aging effects through periodic monitoring and control of contaminants.

SRP-LR Section 3.3.2.2.10 states that loss of material due to pitting and crevice

corrosion may occur in stainless steel and aluminum piping, piping components, piping

elements, and for stainless steel and steel with stainless steel cladding heat exchanger

components exposed to treated water. The existing AMP monitors and controls reactor

water chemistry to manage the aging effects of loss of material from pitting and crevice

corrosion. However, high concentrations of impurities in crevices and with stagnant flow

conditions may cause pitting or crevice corrosion; therefore, the effectiveness of water

chemistry control programs should be verified to ensure that corrosion does not occur.

The GALL Report recommends further evaluation of programs to manage loss of

material from pitting and crevice corrosion to verify the effectiveness of water chemistry

control programs. A one-time inspection of selected components at susceptible

locations is an acceptable method to ensure that corrosion does not occur and that

component intended functions will be maintained during the period of extended

operation.

The staff reviewed LRA Section 3.3.2.2.10.2 and the discussions in LRA Table 3.3.1,

items 3.3.1 23 and 3.3.1 24, against the criteria in SRP-LR Section 3.3.2.2.10, item 2,

which states that loss of material due to pitting and crevice corrosion may occur in

stainless steel and aluminum piping, piping components, piping elements, and for

stainless steel and steel with stainless steel cladding heat exchanger components

exposed to treated water. The SRP-LR states that the existing AMP monitors and

controls reactor water chemistry to manage the aging effects of loss of material from

pitting and crevice corrosion. However, high concentrations of impurities in crevices and

with stagnant flow conditions may cause pitting or crevice corrosion; therefore, the

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effectiveness of water chemistry control programs should be verified to ensure that

corrosion does not occur. The GALL Report recommends further evaluation of programs

to manage loss of material from pitting and crevice corrosion to verify the effectiveness

of water chemistry control programs. The SRP-LR states that a one-time inspection of

selected components at susceptible locations is an acceptable method to ensure that

corrosion does not occur and that component intended functions will be maintained

during the period of extended operation.

The staff noted that the only AMR results referring to LRA Table 3.3.1, item 3.3.1 23,

are for stainless steel heat exchanger components associated with diesel generator

jacket water cooling. By letter dated August 12, 2008, and December 11, 2008, the

applicant amended its LRA such that aluminum heat exchanger components associated

with diesel generator lubricating oil cooling references LRA Table 3.3.1, item 3.3.1 24, in

response to RAI B.2.14-2. For the stainless steel components, which are exposed to

treated water in the closed cooling water system, as amended by its supplemental

response to RAI B.2.14-2 by letter dated December 11, 2008, the applicant proposed to

manage loss of material due to pitting and crevice corrosion using the Closed Cooling

Water Chemistry Program and and the CPEI in lieu of the Water Chemistry and OneTime Inspection programs as recommended in the GALL Report.

The staff reviewed the applicant's Closed Cooling Water Chemistry Program. The staff's

evaluation of this program, which is documented in SER Section 3.0.3.2.7, found that

the Closed Cooling Water Chemistry Program provides mitigation for the aging effect of

loss of material due to corrosion by control of closed cooling water system chemistry

consistent with applicable EPRI water chemistry guidelines. In addition, the Closed

Cooling Water Chemistry Program includes monitoring for corrosion and is

supplemented by a separate one-time inspection of other, representative areas serviced

by the closed cooling water system. The one-time inspections are performed as part of

the Chemistry Program Effectiveness Inspection, which the staff evaluates in SER

Section 3.0.3.1.10. The staff confirmed that the CPEI will be used to verify the

effectiveness of the applicant's Closed Cooling Water Chemistry Program to manage

loss of material and that a combination of appropriate volumetric and visual examination

techniques (such as VT-1 or VT-3) will be performed by qualified personnel on a sample

population of most susceptible subject components. Because the Closed Cooling Water

Chemistry Program provides both mitigation of, and monitoring for pitting and crevice

corrosion and the applicant will confirm the effectiveness of its chemistry program with a

one-time inspection performed by the CPEI the staff finds use of the Closed Cooling

Water Chemistry Program and the CPEI acceptable for managing the aging effect of

loss of material due to pitting and crevice corrosion in stainless steel heat exchanger

components exposed to treated water in the diesel generator jacket water cooling

subsystem.

In LRA Table 3.3.1, Item 3.3.1-24, the applicant stated that the BWR Water Chemistry

Program and the CPEI are credited to manage loss of material for stainless steel and

aluminum components exposed to treated water. The applicant also stated that the

BWR Water Chemistry Program, alone, is credited to manage loss of material for spent

fuel storage racks made of aluminum. Furthermore, the applicant stated that the BWR

Water Chemistry Program, alone, is credited to manage cracking of aluminum

components exposed to treated water; however, that statement was deleted from the

LRA as part of the applicant's response to RAI 3.3-2, discussed both near the end of

this subsection and in SER Subsection 3.3.2.3.3.

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The staff noted that for all stainless steel components where the AMR results are

referenced to LRA Table 3.3.1, item 3.3.1-24, the aging effect is loss of material due to

pitting and crevice corrosion and the applicant states that this aging effect will be

managed by a combination of the BWR Water Chemistry Program and the Chemistry

Program Effectiveness Inspection. These results are consistent with AMR results in the

GALL Report for the same material, environment and aging effect combination.

The staff noted that there are three AMR result lines referenced to LRA Table 3.3.1,

item 3.3.1 24 where the material is aluminum. One of the lines is for aluminum

accumulator (pistons) in the control rod drive hydraulic system exposed to treated water

where the aging effect of loss of material is managed with a combination of the BWR

Water Chemistry Program and the Chemistry Program Effectiveness Inspection; this

AMR result is consistent with the GALL Report. One of the lines is for aluminum spent

fuel pool storage racks exposed to treated water where the aging effect of loss of

material is managed with the BWR Water Chemistry Program, alone; this AMR result is

not consistent with the GALL Report, but it is acceptable, as discussed below. One of

the lines is for aluminum accumulator (pistons) in the control rod drive hydraulic system

exposed to treated water where the applicant proposed to managed the aging effect of

cracking with the BWR Water Chemistry Program, alone; however, in response to RAI

3.3-2 the applicant revised the this AMR result and the LRA as discussed below and in

SER Subsection 3.3.2.2.3.

In the LRA the applicant provides plant-specific Note 0515 to explain use of the BWR

Water Chemistry Program, alone, for managing loss of material from the aluminum

spent fuel storage racks. In Note 0515 the applicant states that one-time inspection is

not applicable for the spent fuel racks because the spent fuel pool does not contain

areas of low or stagnant flow where pitting or crevice corrosion would likely occur. Note

0515 also refers to the GALL Report, Chapter VII.A2, where the Water Chemistry

Program, alone, is credited with managing the aging effect of cracking due to stress

corrosion cracking in stainless steel spent fuel storage racks. On the basis that there are

no areas of low or stagnant flow in the spent fuel pool where contaminants causing

corrosion might collect, and the applicant's proposed AMP is consistent with the AMP

recommended in the GALL Report, Chapter VII.A2, item VII.A2-6, for similar stainless

steel components in a spent fuel pool environment, the staff finds the applicant's use of

the BWR Water Chemistry Program, alone, for managing loss of material from the

aluminum spent fuel storage racks in a treated water environment to be acceptable.

The staff reviewed the applicant's BWR Water Chemistry Program. The staff's

evaluation of this program, which is documented in SER Section 3.0.3.1.1, found that

the BWR Water Chemistry Program provides mitigation for the aging effect of loss of

material due to general, crevice and pitting corrosion. The staff reviewed the Chemistry

Program Effectiveness Inspection. The staff's evaluation of this program, which is

documented in SER Section 3.0.3.1.10, found that the applicant's CPEI is a one-time

inspection that is consistent with the GALL Report's recommendations for AMP XI.M32,

"One-Time Inspection." The CPEI includes provisions for inspecting selected

components in areas of low or stagnant flow and is capable of detecting loss of material

due to general, pitting or crevice corrosion, if it should occur in the selected

components. Based on the applicant's use of a one-time inspection consistent with the

recommendations of the GALL Report, the staff finds the applicant's use of the BWR

Water Chemistry Program and the CPEI for managing the potential aging effect of loss

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of material due to pitting and crevice corrosion for stainless steel and aluminum

components exposed to treated water to be acceptable.

In LRA Table 3.3.2-3 (page 3.3-103), the applicant identified the aging effect of cracking

as applicable for the aluminum pistons in the control rod drive accumulators which are

exposed to an environment of treated water. The applicant proposed use of the BWR

Water Chemistry Program, alone, for managing this aging effect in this component and

cited generic Note H, indicating that the aging effect is not in the GALL Report for the

component, material and environment combination. The staff issued RAI 3.3-2 by letter

dated July 15, 2008, asking that the applicant provide further information to justify that

the BWR Water Chemistry Program, alone, without an inspection to confirm program

effectiveness, provides adequate aging management for this component. The RAI also

asked the applicant to explain why the aging effect of cracking is referenced to LRA

Table 3.3.1, item 3.3.1-24, where the aging effect is loss of material due to pitting and

crevice corrosion.

In a letter dated August 15, 2008, the applicant responded to RAI 3.3-2 by providing the

following response:

For the AMR results item listed on page 3.3-103 of the LRA for accumulator (pistons)

made of aluminum in a treated water environment with an aging effect of cracking, Note

H is the appropriate generic note because the aging effect, cracking, is not in the GALL

Report for aluminum exposed to treated water. However, because the GALL Report

Item VIII.E3-7 is for loss of material, the GALL Report Volume 2 item number and the

Table 1 item number should have been identified as "N/A."

For this AMR result item, verification of the effectiveness of the BWR Water Chemistry

Program is needed to confirm that cracking is not occurring in these components.

As part of the RAI response, the applicant revised the AMR result line in LRA Table

3.3.2 3, page 3.3-103. The revised AMR result line shows that for accumulators

(pistons) made of aluminum in a treated water environment the aging effect of cracking

will be managed by a combination of the BWR Water Chemistry Program and the

Chemistry Program Effectiveness Inspection. Generic Note H continues to apply for this

AMR result line, indicating that the aging effect is not in the GALL Report for this

component, material and environment combination. The revised AMR result line no

longer refers to GALL Volume 2 or LRA Table 1 items, and the staff's evaluation of this

AMR result, as revised, is documented in SER Subsection 3.3.2.3.3.

The applicant responded to RAI B.2.14-2 by letter dated August 12, 2008, and

supplemented its response by letter dated December 11, 2008. It is response and

supplemental response the applicant amended its LRA such that the materialenvironment-aging effect combination of aluminum-treated water (internal)-loss of

material referenced LRA Table 3.3.1, item 3.3.1 24. For the aluminum components,

which are exposed to treated water in the closed cooling water system, the applicant

proposed to manage loss of material due to pitting and crevice corrosion using a

combination of the Closed Cooling Water Chemistry Program and the CPEI in lieu of the

Water Chemistry and One-Time Inspection programs as recommended in the GALL

Report.

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The staff reviewed the applicant's Closed Cooling Water Chemistry Program. The staff's

evaluation of this program, which is documented in SER Section 3.0.3.2.7, found that

the Closed Cooling Water Chemistry Program provides mitigation for the aging effect of

loss of material due to corrosion by control of closed cooling water system chemistry

consistent with applicable EPRI water chemistry guidelines. In addition, the Closed

Cooling Water Chemistry Program includes monitoring for corrosion and is

supplemented by a separate one-time inspection of other, representative areas serviced

by the closed cooling water system. The one-time inspections are performed as part of

the Chemistry Program Effectiveness Inspection, which the staff evaluates in SER

Section 3.0.3.1.10. The staff confirmed that the CPEI will be used to verify the

effectiveness of the applicant's Closed Cooling Water Chemistry Program to manage

loss of material and that a combination of appropriate volumetric and visual examination

techniques (such as VT-1 or VT-3) will be performed by qualified personnel on a sample

population of most susceptible subject components. Because the Closed Cooling Water

Chemistry Program provides both mitigation of, and monitoring for pitting and crevice

corrosion and the applicant will confirm the effectiveness of its chemistry program with a

one-time inspection performed by the CPEI the staff finds use of the Closed Cooling

Water Chemistry Program and the CPEI acceptable for managing the aging effect of

loss of material due to pitting and crevice corrosion in aluminum heat exchanger

components exposed to treated water in the diesel generator lubricating oil cooling

subsystem.

(3) LRA Section 3.3.2.2.10 addresses loss of material due to pitting and crevice corrosion in

HVAC piping, piping components, and piping elements. The applicant stated that the

Cooling Units Inspection is a one-time inspection that will detect and characterize loss of

material due to pitting and crevice corrosion for copper alloy HVAC piping components

in an external environment with potential for wetting.

SRP-LR Section 3.3.2.2.10 states that loss of material due to pitting and crevice

corrosion may occur in copper alloy heating, ventilation, and air conditioning (HVAC)

piping, piping components, and piping elements exposed to condensation (external).

The GALL Report recommends further evaluation of a plant-specific AMP to ensure that

the aging effect is adequately managed.

The GALL report, under Items VII.F1-16, VII.F2-14, VII.F3-16 and VII.F4-12

recommends that a plant-specific program be credited to manage this aging effect for

copper alloy HVAC piping, piping components and piping elements in the Auxiliary

Systems.

The staff verified that only heat exchanger components, piping and piping components

and valve bodies that align to GALL AMRs VII.F1-16, VII.F2-14 and VII.F4-12 for the

Domestic Water System, Emergency Service Water System, Fire Protection System,

Raw Water Treatment System, Reactor Building Chilled Water System, RHR Service

Water System, Sampling System, Service Water System, Control Structure Chilled

Water System and Diesel Generator System that are fabricated from copper alloy

materials are applicable to SSES that credit the System Walkdown Program.

The staff reviewed the applicant's System Walkdown Program and its evaluation is

documented in SER Sections 3.0.3.1.9. The staff determined that the System

Walkdown Program which includes periodic visual inspections performed during system

walkdowns, are adequate to manage loss of material due to pitting and crevice

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corrosion for copper alloy HVAC piping, piping components, and piping elements

exposed to indoor and outdoor air environment with the potential for wetting addressed

by this AMR. The staff finds that the System Walkdown Program performs periodic

visual inspections of external surfaces during periodic system to detect aging effects

that could result in a loss of the component's intended function. The staff finds that this

program includes activities that are consistent with the recommendations in the GALL

Report, and that it is adequate to manage loss of material due to pitting and crevice

corrosion for copper alloy HVAC piping, piping components and piping elements

exposed condensation on the external surface.

The staff reviewed the applicant's Cooling Units Inspection Program, which uses a

combination of volumetric and visual examination techniques to identify evidence of loss

of material or lack thereof. The staff's evaluation of the Cooling Units Inspection

Program is documented in SER Section 3.0.3.1.11. Because the Cooling Units

Inspection is performed at selected susceptible locations, and employs a combination of

volumetric and visual inspection techniques, the staff finds that the Cooling Units

Inspection Program will adequately manage the aging effects of loss of material in this

wetted environment.

(4) LRA Section 3.3.2.2.10 addresses loss of material due to pitting and crevice corrosion in

piping, piping components, and piping elements exposed to lubricating oil. The applicant

stated that loss of material due to pitting and crevice corrosion for copper alloy piping

components exposed to lubricating oil is managed by the Lubricating Oil Analysis

Program. The Lubricating Oil Analysis Program manages aging effects through periodic

monitoring and control of contaminants, including water. The Lubricating Oil Inspection

will provide a verification of the effectiveness of the Lubricating Oil Analysis Program to

manage loss of material due to pitting and crevice corrosion through examination of

copper alloy piping components

SRP-LR Section 3.3.2.2.10 states that loss of material due to pitting and crevice

corrosion may occur in copper alloy piping, piping components, and piping elements

exposed to lubricating oil. The existing AMP periodically samples and analyzes

lubricating oil to maintain contaminants within acceptable limits, thereby preserving an

environment not conducive to corrosion. However, control of lube oil contaminants may

not always be fully effective in precluding corrosion; therefore, the effectiveness of

lubricating oil control should be verified to ensure that corrosion does not occur. The

GALL Report recommends further evaluation of programs to manage corrosion to verify

the effectiveness of lubricating oil programs. A one-time inspection of selected

components at susceptible locations is an acceptable method to ensure that corrosion

does not occur and that component intended functions will be maintained during the

period of extended operation.

The staff verified that only piping, piping components and elements that align to GALL

AMR VII.C2-5 and VII.H2-10 for the Fire Protection, Control Structure Chilled Water and

Diesel Generator Lubricating Oil and NSAS Component systems that are fabricated

from copper alloy materials are applicable to SSES.

The staff reviewed the applicant's Lubricating Oil Analysis Program and determined that

this program includes periodic sampling and analysis of lubricating oil to maintain

contaminants within acceptable limits. The staff finds that these activities are consistent

with the recommendations in the GALL Report and are adequate to manage loss of

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material due to pitting and crevice corrosion for copper alloy piping, piping components,

and piping elements exposed to lubricating oil.

The staff evaluated the Lubricating Oil Analysis Program and the Lubricating Oil

Inspection Program, and the evaluations are documented in SER Sections 3.0.3.2.15

and 3.0.3.2.13 respectively. The staff verified that the applicant has credited its

Lubricating Oil Inspection Program to verify the effectiveness of the Lubricating Oil

Analysis Program to manage this aging effect. The applicant's AMPS are consistent with

those recommended for aging management in SRP-LR Section 3.3.2.2.10, Item #4 and

in GALL AMR Item VII.C2-5 and VII.H2-10.

Based on the program identified above, the staff concludes that the applicant's program

meet SRP-LR Section 3.2.2.2.10 Item (4) criteria and therefore the applicant's AMRs

are consistent with those under GALL Report Item VII.C2-5 and VII.H2-10. For those

line items that apply to LRA Section 3.2.2.2.10 Item #4, the staff determines that the

LRA is consistent with the GALL Report and that the applicant has demonstrated that

the effects of aging will be adequately managed so that the intended function(s) will be

maintained consistent with the CLB during the period of extended operation, as required

by 10 CFR 54.21(a)(3).

During its review, the staff noted that the applicant identified in LRA Table 3.3.2-4,

Control Structure Chilled Water System, a Type-2 line item that utilized a standard Note

I and plant-specific Note 0310, claiming that the aging effect, loss of material due to

pitting and crevice corrosion, is not applicable to SSES for this component, material and

environment combination. The applicant states that this Type-2 item is not applicable to

SSES because this tubing that is exposed to lubricating oil internally is made of copper

with less than 15% zinc, therefore is not susceptible to this aging effect and environment

combination. The staff verified in the GALL Report, Chapter IX.C that components

made of copper alloy with less than 15% zinc are resistant to loss of material due to

pitting and crevice corrosion. Based on this assessment, the staff concludes that this

Type-2 item in LRA Table 3.3.2-4 is not applicable to SSES.

(5) LRA Section 3.3.2.2.10 addresses loss of material due to pitting and crevice corrosion in

HVAC piping, piping components, and piping elements and ducting. The applicant

stated that the Cooling Units Inspection is a one-time inspection credited with detecting

and characterizing the condition of aluminum and stainless steel HVAC components

exposed to condensation. The System Walkdown Program is credited for managing loss

of material due to pitting and crevice corrosion for the external surfaces of stainless

steel HVAC components exposed to condensation.

SRP-LR Section 3.3.2.2.10 states that loss of material due to pitting and crevice

corrosion may occur in HVAC aluminum piping, piping components, and piping elements

and stainless steel ducting and components exposed to condensation. The GALL

Report recommends further evaluation of a plant-specific AMP to ensure that the aging

effect is adequately managed.

The GALL report, under Item VII.F1-1, VII.F2-1, VII.F3-1, VII.F1-14, VII.F2-12, VII.F3-14

and VII.F4-10 recommends that a plant-specific program be credited to this aging effect

for stainless steel ducting and components and piping elements in the Auxiliary

Systems.

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The staff verified that only ducting and components that align to GALL AMRs VII.F1-1,

VII.F2-1 and VII.F3-1 for the Emergency Service Water System, Fire Protection System,

Fuel Pool Cooling System, Primary Containment Atmosphere Circulation System,

Process and Area Radiation Monitoring System, Reactor Building Chilled Water and

HVAC System, RHR Service Water System, Sampling System and Control Structure

Chilled Water System that are fabricated from stainless steel and steel materials are

applicable to SSES that credit the Systems Walkdown Program.

The staff reviewed the applicant's System Walkdown Program and its evaluation is

documented in SER Sections 3.0.3.1.9. The staff determined that the System

Walkdown Program which includes periodic visual inspections performed during system

walkdowns, are adequate to manage loss of material due to pitting and crevice

corrosion for stainless steel and steel ducting and components exposed to indoor and

outdoor air environment with the potential for wetting addressed by this AMR. The staff

finds that the System Walkdown Program performs periodic visual inspections of

external surfaces during periodic system to detect aging effects that could result in a

loss of the component's intended function. The staff finds that this program includes

activities that are consistent with the recommendations in the GALL Report, and that it is

adequate to manage loss of material due to pitting and crevice corrosion for stainless

steel and steel ducting and components exposed indoor and outdoor air with the

potential for wetting on the external surface.

Subsection 3.3.2.2.10.5 is referenced in the LRA Table 3.3.1 for line item 3.3.1-27. In

the discussion column of Table 3.3.1, item 3.3.1-27, the LRA states that the Cooling

Units Inspection will also detect and characterize cracking of aluminum HVAC cooling

unit fins, for which Note H is used. However, a review of Table 2s did not identify a line

item where this is identified. The staff issued RAI 3.3.1-6 by letter dated July 9, 2008, to

request the applicant to clarify where in Table 2s the Cooling Units Inspection is credited

for managing cracking of aluminum HVAC cooling unit fins.

In its letter dated August 8, 2008, the applicant responded to RAI 3.3.1-6 by stating that

the Cooling Unit Inspection Program is not credited for managing cracking of aluminum

HVAC cooling unit fins. The applicant revised LRA Table 3.3.1, item 3.3.1-27 and the

associated LRA Section 3.3.2.2.10.5 to remove the statement crediting the Cooling Unit

Inspection Program in conjunction with cracking of aluminum HVAC cooling unit fins.

The staff reviewed the applicant's response and the LRA revision. With the removal of

the statement crediting the Cooling Unit Inspection Program for cracking of aluminum

HVAC cooling fins, Table 3.3.1,. Item 3.3.1-27 and Section 3.3.2.2.10.5 are consistent

with Table 2s, where cracking of aluminum fins is not addressed and there is no

discrepancy between Table 1 and Table 2. On this basis, the staff finds the response

acceptable.

The staff reviewed the Cooling Units Inspection Program, which uses a combination of

volumetric and visual examination techniques to identify evidence of loss of material or

lack thereof. The staff's evaluation of the Cooling Units Inspection Program is

documented in SER Section 3.0.3.1.11. Because the Cooling Units Inspection is

performed at selected susceptible locations, and employs a combination of volumetric

and visual inspection techniques, the staff finds that the Cooling Units Inspection

Program will adequately manage the aging effects of loss of material in this wetted

environment.

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In the discussion column of Table 3.3.1, item 3.3.1-27, the LRA states that the System

Walkdown Program, the Cooling Units Inspection, and the Supplemental Piping/Tank

Inspection are credited to manage loss of material and references Section 3.3.2.2.10.5

for further evaluation. However, Section 3.3.2.2.10.5 does not address the

Supplemental Piping/Tank Inspection. The staff issued RAI 3.3.2.2.10.5-1 by letter

dated July 9, 2008, to request the applicant to resolve this discrepancy.

In its letter dated August 8, 2008, the applicant responded to RAI 3.3.2.2.10.5-1 by

amending the LRA to add the following in LRA Section 3.3.2.2.10.5

The Supplemental Piping/Tank Inspection is a one-time inspection

credited with detecting and characterizing the condition of stainless steel

components that are exposed to moist air, particularly the aggressive

alternate wet/dry environment that exists at air-water interfaces.

On the basis that the applicant amended the LRA to resolve the discrepancy between

Table 3.3.1, item 3.3.1-27 discussion column and this Subsection, the staff finds the

response acceptable. The Supplementary Piping/Tank Inspection Program is discussed

below.

In Table 3.3.2-14, Fuel Pool Cooling System, item 3.3.1-27 is referenced on three line

items, stainless steel piping (in two environments) and stainless steel skimmer surge

tanks. Table 3.3.2-14 also references for these three line items footnote 0303, which

states that loss of material is due to crevice and/or pitting corrosion caused by alternate

wetting and drying, not condensation, at the air-water interface. The applicant has

chosen to apply SRP-LR Section 3.3.2.2.10.5 to these three line items, even though the

stainless piping is in fuel pool cooling system with an environment similar to ventilation.

The applicant referenced GALL Report Volume 2, items VII.F1-1. The staff noted that

where the GALL Report recommends a plant-specific aging management program, the

applicant proposed using the Supplementary Piping/Tank Inspection Program.

The staff reviewed the Supplementary Piping/Tank Inspection Program, which uses a

combination of volumetric and visual examination techniques to identify evidence of loss

of material or lack thereof. The staff's evaluation of the Supplementary Piping/Tank

Inspection Program is documented in SER Section 3.0.3.1.16. Because the

Supplementary Piping/Tank Inspection is performed at very specific locations of

air/water interface, and employs a combination of volumetric and visual inspection

techniques, the staff finds that the Supplementary Piping/Tank Inspection Program will

adequately manage the aging effects of loss of material in this aggressive environment.

(6) LRA Section 3.3.2.2.10 addresses loss of material due to pitting and crevice corrosion in

the fire protection system. The applicant stated that this aging effect is not applicable

because the components are open to local ambient air conditions such that

condensation will not occur and are not subject to continuous wetting or alternate

wetting and drying that would constitute an aggressive environment.

SRP-LR Section 3.3.2.2.10 states that loss of material due to pitting and crevice

corrosion may occur in copper alloy fire protection system piping, piping components,

and piping elements exposed to internal condensation. The GALL Report recommends

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further evaluation of a plant-specific AMP to ensure that the aging effect is adequately

managed.

The staff reviewed the GALL Report and noted that for copper alloy components in airindoor environment, line item V.F-3 identifies no aging effect and no aging management

program is required. On the basis that these copper alloy fire protection components are

open to the atmosphere and do not see continuous wetting or alternate wetting and

drying, the staff finds that consistent with the GALL Report, loss of material due to

pitting and crevice corrosion is not an aging effect requiring management.

(7) LRA Section 3.3.2.2.10 addresses loss of material due to pitting and crevice corrosion in

stainless steel piping, piping components, and piping elements exposed to soil. The

applicant stated that this aging effect is not applicable to auxiliary systems and is

evaluated in steam and power conversion systems.

SRP-LR Section 3.3.2.2.10 states that loss of material due to pitting and crevice

corrosion may occur in stainless steel piping, piping components, and piping elements

exposed to soil.

LRA Table 3.3.1 states that there are no SSES components comparable to LRA item

number 3.3.1-29. The staff verified that there are no components that are comparable.

The only stainless steel piping subject to AMR for SSES that is exposed to soil is

located in the Condensate Transfer and Storage System and is evaluated in the Steam

and Power Conversion group for LRA item number 3.4.1-17. The staff's evaluation of

the stainless steel piping exposed to soil in the Condensate Transfer and Storage

System is documented in SER Section 3.4.2.2.7.2.

(8) LRA Section 3.3.2.2.10 addresses loss of material due to pitting and crevice corrosion in

BWR SLC system. The applicant stated that loss of material due to pitting and crevice

corrosion for stainless steel piping components exposed to sodium pentaborate solution

is managed by the BWR Water Chemistry Program. The BWR Water Chemistry

Program manages aging effects through periodic monitoring and control of

contaminants. The CPEI will provide a verification of the effectiveness of the BWR

Water Chemistry Program to manage loss of material due to pitting and crevice

corrosion through examination of stainless steel piping components exposed to sodium

pentaborate solution.

SRP-LR Section 3.3.2.2.10 states that loss of material due to pitting and crevice

corrosion may occur in stainless steel piping, piping components, and piping elements

of the BWR SLC system exposed to sodium pentaborate solution. The existing

AMP monitors and controls water chemistry to manage the aging effects of loss of

material due to pitting and crevice corrosion. However, high concentrations of impurities

in crevices and with stagnant flow conditions may cause loss of material due to pitting

and crevice corrosion; therefore, the GALL Report recommends that the effectiveness of

water chemistry control programs should be verified to ensure that this aging does not

occur. A one-time inspection of selected components at susceptible locations is an

acceptable method to ensure that loss of material due to pitting and crevice corrosion

does not occur and that component intended functions will be maintained during the

period of extended operation.

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The staff reviewed the applicant's BWR Water Chemistry Program. The staff's

evaluation of this program, which is documented in SER Section 3.0.3.1.1, determined

that the BWR Water Chemistry Program provides mitigation for the aging effect of loss

of material due to pitting and crevice corrosion. The staff reviewed the applicant's

Chemistry Program Effectiveness Inspection. The staff's evaluation of this program,

which is documented in SER Section 3.0.3.1.10, found that the CPEI is a one-time

inspection that is consistent with the GALL Report's recommendations for AMP XI.M32,

"One-Time Inspection." The CPEI includes provisions for inspecting selected

components in areas of low or stagnant flow and is capable of detecting loss of material

due to pitting or crevice corrosion, if it should occur in the selected components. Based

on the applicant's use of a one-time inspection consistent with the recommendations of

the GALL Report, the staff finds the applicant's proposed AMPs for managing the

potential aging effect of loss of material due to pitting or crevice corrosion in stainless

steel piping components exposed to sodium pentaborate solution in the standby liquid

control system to be acceptable.

Based on the programs identified above, the staff concludes that the applicant's programs meet

SRP-LR Section 3.3.2.2.10 criteria. For those line items that apply to LRA Section 3.3.2.2.10,

the staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21(a)(3).

3.3.2.2.11 Loss of Material Due to Pitting, Crevice, and Galvanic Corrosion

The staff reviewed LRA Section 3.3.2.2.11 against the criteria in SRP-LR Section 3.3.2.2.11.

LRA Section 3.3.2.2.11 addresses loss of material due to pitting, crevice, and galvanic

corrosion. The applicant stated that loss of material due to pitting, crevice, and galvanic

corrosion for copper alloy piping components exposed to treated water is managed by the BWR

Water Chemistry Program. The BWR Water Chemistry Program manages aging effects

through periodic monitoring and control of contaminants. The CPEI will provide a verification of

the effectiveness of the BWR Water Chemistry Program to manage loss of material due to

pitting, crevice, and galvanic corrosion through examination of copper alloy piping components

exposed to treated water.

SRP-LR Section 3.3.2.2.11 states that loss of material due-to pitting, crevice, and galvanic

corrosion may occur in copper alloy piping, piping components, and piping elements exposed to

treated water. Therefore, the GALL Report recommends that the effectiveness of water

chemistry control programs should be verified to ensure that this aging does not occur. A onetime inspection of selected components at susceptible locations is an acceptable method to

ensure that loss of material due to pitting and crevice corrosion does not occur and that

component intended functions will be maintained during the period of extended operation.

The staff reviewed the applicant's BWR Water Chemistry Program. The staff's evaluation of

this program, which is documented in SER Section 3.0.3.1.1, determined that the BWR Water

Chemistry Program provides mitigation for the aging effect of loss of material due to pitting,

crevice and galvanic corrosion. The staff reviewed the applicant's Chemistry Program

Effectiveness Inspection. The staff's evaluation of this program, which is documented in SER

Section 3.0.3.1.10, found that the CPEI is a one-time inspection that is consistent with the

GALL Report's recommendations for AMP XI.M32, "One-Time Inspection." The CPEI includes

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provisions for inspecting selected components in areas of low or stagnant flow and is capable of

detecting loss of material due to pitting, crevice or galvanic corrosion, if it should occur in the

selected components. Based on the applicant's use of a one-time inspection consistent with the

recommendations of the GALL Report, the staff finds the applicant's proposed AMPs for

managing the potential aging effect of loss of material due to pitting, crevice or galvanic

corrosion in copper alloy piping components exposed to treated water in the reactor water

cleanup system and in the control rod drive hydraulic system to be acceptable.

Based on the programs identified above, the staff concludes that the applicant's programs meet

SRP-LR Section 3.3.2.2.11 criteria. For those line items that apply to LRA Section 3.3.2.2.11,

the staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21(a)(3).

3.3.2.2.12 Loss of Material Due to Pitting, Crevice, and Microbiologically-Influenced Corrosion

The staff reviewed LRA Section 3.3.2.2.12 against the following criteria in SRP-LR

Section 3.3.2.2.12:

(1) LRA Section 3.3.2.2.12 addresses loss of material due to pitting, crevice, and MIC in

piping, piping components, and piping elements exposed to fuel oil. The applicant stated

that there are no aluminum piping components exposed to fuel oil that are subject to

AMR for SSES. Loss of material due to pitting and crevice corrosion and MIC for

stainless steel and copper alloy piping components exposed to fuel oil is managed by

the Fuel Oil Chemistry Program. The Fuel Oil Chemistry Program manages aging

effects through periodic monitoring and control of contaminants. The CPEI will provide a

verification of the effectiveness of the Fuel Oil Chemistry Program to manage loss of

material due to pitting and crevice corrosion and MIC through examination of stainless

steel and copper alloy piping components exposed to fuel oil. Though not credited, the

Fire Protection Program provides indirect confirmation of whether degradation of these

components has occurred, and that the component intended function is maintained.

SRP-LR Section 3.3.2.2.12 states that loss of material due to pitting and crevice

corrosion, and MIC may occur in stainless steel, aluminum, and copper alloy piping,

piping components, and piping elements exposed to fuel oil. The existing AMP relies on

the fuel oil chemistry program for monitoring and control of fuel oil contamination to

manage loss of material due to corrosion; however, corrosion may occur at locations

where contaminants accumulate and the effectiveness of fuel oil chemistry control

should be verified to ensure that corrosion does not occur. The GALL Report

recommends further evaluation of programs to manage corrosion to verify the

effectiveness of the fuel oil chemistry control program. A one-time inspection of selected

components at susceptible locations is an acceptable method to ensure that corrosion

does not occur and that component intended functions will be maintained during the

period of extended operation.

The staff reviewed the applicant's Fuel Oil Chemistry Program. The staff's evaluation of

this program, which is documented in SER Section 3.0.3.2.1, found that the Fuel Oil

Chemistry Program provides aging management for loss of material due to pitting and

crevice corrosion and MIC through monitoring and control of fuel oil contamination such

as water or microbiological organisms. The staff reviewed the applicant's Chemistry

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Program Effectiveness Inspection. The staff's evaluation of this program, which is

documented in SER Section 3.0.3.1.10, found that the CPEI is a one-time inspection

that is consistent with the GALL Report's recommendations for AMP XI.M32, "One-Time

Inspection." The CPEI includes provisions for inspecting selected components

determined to be most susceptible to the aging effect(s) of interest and is capable of

detecting loss of material due to pitting or crevice corrosion or MIC, if it should occur in

the selected components. Based on the applicant's use of a one-time inspection

consistent with the recommendations of the GALL Report, the staff finds the applicant's

proposed AMPs for managing the potential aging effect of loss of material due to pitting

and crevice corrosion and MIC for stainless steel or copper alloy piping components

exposed to fuel oil in the diesel fuel oil system and in the fire protection system to be

acceptable.

(2) LRA Section 3.3.2.2.12 addresses loss of material due to pitting, crevice, and MIC in

piping, piping components, and piping elements exposed to lubricating oil. The applicant

stated that loss of material due to pitting and crevice corrosion and MIC for stainless

steel piping components exposed to lubricating oil is managed by the Lubricating Oil

Analysis Program. The Lubricating Oil Analysis Program manages aging effects through

periodic monitoring and control of contaminants, including water. The Lubricating Oil

Inspection will provide a verification of the effectiveness of the Lubricating Oil Analysis

Program to manage loss of material due to pitting and crevice corrosion and MIC

through examination of stainless steel piping components.

SRP-LR Section 3.3.2.2.12 states that loss of material due to pitting, crevice, and MIC

may occur in stainless steel piping, piping components, and piping elements exposed to

lubricating oil. The existing program periodically samples and analyzes lubricating oil to

maintain contaminants within acceptable limits, thereby preserving an environment not

conducive to corrosion. However, control of lube oil contaminants may not always be

fully effective in precluding corrosion; therefore, the effectiveness of lubricating oil

control should be verified to ensure that corrosion does not occur. The GALL Report

recommends further evaluation of programs to manage corrosion to verify the

effectiveness of lubricating oil programs. A one-time inspection of selected components

at susceptible locations is an acceptable method to ensure that corrosion does not occur

and that component intended functions will be maintained during the period of extended

operation.

The staff verified that only piping, piping components and elements that align to GALL

AMR VII.H2-17 for the Diesel Generator Lubricating Oil system that are fabricated from

stainless steel materials are applicable to SSES.

The staff evaluated the Lubricating Oil Analysis Program and the Lubricating Oil

Inspection Program, and the evaluations are documented in SER Sections 3.0.3.2.15

and 3.0.3.2.13 respectively. The staff reviewed the applicant's Lubricating Oil Analysis

Program and determined that this program includes periodic sampling and analysis of

lubricating oil to maintain contaminants within acceptable limits. The staff finds that

these activities are consistent with the recommendations in the GALL Report and are

adequate to manage loss of material due to pitting, crevice, and microbiologicallyinfluenced corrosion in stainless steel piping, piping components, and piping elements

exposed to lubricating oil. The staff verified that the applicant has credited its

Lubricating Oil Inspection Program to verify the effectiveness of the Lubricating Oil

Analysis Program to manage this aging effect. The applicant's AMPS are consistent with

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those recommended for aging management in SRP-LR Section 3.3.2.2.12, Item #2 and

in GALL AMR Item VII.H2-17.

Based on the program identified above, the staff concludes that the applicant's program

meet SRP-LR Section 3.3.2.2.12, Item #2 criteria and therefore the applicant's AMRs

are consistent with those under GALL Report Item VII.H2-17. For those line items that

apply to LRA Section 3.3.2.2.12, Item #2, the staff determines that the LRA is consistent

with the GALL Report and that the applicant has demonstrated that the effects of aging

will be adequately managed so that the intended function(s) will be maintained

consistent with the CLB during the period of extended operation, as required by 10 CFR

54.21 (a)(3).

Based on the programs identified above, the staff concludes that the applicant's programs meet

SRP-LR Section 3.3.2.2.12 criteria. For those line items that apply to LRA Section 3.3.2.2.12,

the staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

3.3.2.2.13 Loss of Material Due to Wear

The staff reviewed LRA Section 3.3.2.2.13 against the criteria in SRP-LR Section 3.3.2.2.13.

LRA Section 3.3.2.2.13 addresses loss of material due to wear. The applicant stated that this

aging effect is not applicable because wear only occurs during the performance of an active

function, as a result of improper design, application or operation, or to a very small degree with

insignificant consequences.

SRP-LR Section 3.3.2.2.13 states that loss of material due to wear may occur in the elastomer

seals and components exposed to air - indoor uncontrolled (internal or external). The GALL

Report recommends further evaluation to ensure that the aging effect is adequately managed.

For applicable steel BWR piping, SRP-LR Section 3.3.2.2.13 invokes AMR Item 34 in Table 3 of

the GALL Report, Volume 1, and GALL AMR Item VII.F1-5, VII.F1-6, VII.F2-5, VII.F2-6, VII.F3-

5, VII.F3-6, VII.F4-4 and VII.F4-5, as applicable to the management of loss of material due to

wear in elastomeric seals and components in control room area ventilation, auxiliary and

radwaste area ventilation, primary containment heating and ventilation, and diesel generator

building ventilation systems under internal and external exposure to uncontrolled indoor air.

The staff reviewed the information in LRA Section 3.3.2.2.13 against the staff's

recommendations in SRP-LR Section 3.3.2.2.13 and in GALL AMR items Item VII.F1-5, VII.F1-

6, VII.F2-5, VII.F2-6, VII.F3-5, VII.F3-6, VII.F4-4 and VII.F4-5, as applicable to the management

of loss of material due to wear in elastomeric seals and components in control room area

ventilation, auxiliary and radwaste area ventilation, primary containment heating and ventilation,

and diesel generator building ventilation systems under internal and external exposure to

uncontrolled indoor air.

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The staff confirmed that the scope of the applicant's application includes the following AMR

tables for auxiliary HVAC systems:

* Table 3.3.2-5, Aging Management Results for Control Structure HVAC Systems

• Table 3.3.2-8, Diesel Generator Buildings HVAC Systems

• Table 3.3.2-12, ESSW Pumphouse HVAC System

* Table 3.3.2-16, Primary Containment Atmosphere Circulation System

• Tabl3 3.3.2-23, Reactor Building HVAC System

The staff noted that these AMR Tables did not include any AMRs on management of loss of

material due to wear in elastomeric HVAC seals and components or that were aligned to AMR

Item 34 in Table 3 of the GALL Report, Volume 1, or to GALL AMR Item VII.F1-5, VII.F1-6,

VII.F2-5, VII.F2-6, VII.F3-5, VII.F3-6, VII.F4-4 or VII.F4-5. The staff also noted that the

applicant's basis for concluding that loss of material due to wear was based on a misplaced

conclusion. Specifically, the staff noted that the applicant based its conclusion that loss of

material due to wear was not an AERM on the fact that wear is an active loss of material

mechanism and not on the fact that the elastomeric HVAC seals and components for which

wear is plausible are active components or components that are replaced on a qualified or

specified frequency. The staff noted that the fact that wear is an active loss of material

mechanism did not provide any logical basis for concluding that wear was not plausible aging

mechanisms for any passive, long-lived elastomeric seals or components in these HVAC

systems.

In RAI 3.3.2.2.13-1, by letter dated July 23, 2008, the staff informed the applicant that the fact

that wear is an active aging mechanism does not provide a valid or acceptable basis for

concluding that the passive long-lived elastomeric HVAC seals or components are not subject

to potential loss of material due to wear. In this RAI, the staff asked the applicant to provide a

valid basis why loss-of material due to wear is not considered to be an AERM for the

elastomeric seals and components in the control structure HVAC systems, diesel generator

building HVAC systems, ESSW pumphouse HVAC system, primary containment atmosphere

circulation system, or reactor building HVAC system.

In its letter dated August 27, 2008, in response to RAI 3.3.2.2.13-1, the applicant provided the

following bases, that have been documented in industry guidance on the aging of elastomers,

upon which it concluded that loss of material due to wear is not an aging effect requiring

management for elastomer seals and components:

" the elastomer seals and components were selected based on their suitability for the

service in which they would be applied, i.e., they were properly designed;

* the elastomer seals and components were properly applied and installed, i.e., within

allowable pre-compression and offset limits, thus preventing significant relative motion

between the contacting surfaces; and,

* the systems in which the elastomer seals and components are installed are operated in

accordance with procedures that have been developed based on standard industry good

practices, thus preventing excessive vibration and unintended component movements

Flexible connections are used in applications where some movement between the joined piping,

ductwork, and components is expected to occur. However, as indicated above, the flexible

connections are securely attached to the joined components such that there is no relative

movement between the connection of the flexible connection and the component. The flexible

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connection is designed to accommodate relative movements, however proper design and

installation ensures that the flexible connection does not make contact with itself or with other

nearby components

Therefore, the applicant concluded that there is no relative motion expected between contacting

surfaces and wear is not an aging effect requiring management.

The staff reviewed the applicant response and reviewed the definition of wear in the GALL

Report Section IX.F. The GALL Report defines wear as the removal of surface layers due to

relative motion between two surfaces or under the influence of hard abrasive powder. The

GALL Report further states that wear occurs in parts that experience intermittent relative motion

or frequent manipulation. The staff determined that use of flexible connections in systems that

experience vibration minimizes relative motion of the piping system, thereby minimizing wear.

These systems are designed to account for relative motion and therefore, the staff finds that for

elastomeric seals and components in control room area ventilation, auxiliary and radwaste area

ventilation, primary containment heating and ventilation, and diesel generator building

ventilation systems under internal and external exposure to uncontrolled indoor air do not

experience loss of material due to wear. On this basis the staff finds the applicant response

acceptable.

Therefore, the staff concludes that loss of material due to wear is not an aging effect requiring

management for elastomer seals and components exposed to air - indoor uncontrolled (internal

or external).

Based on the above, the staff concludes SRP-LR Section 3.3.2.2.13 criteria are not applicable.

3.3.2.2.14 Loss of Material Due to Cladding Breach

The staff reviewed LRA Section 3.3.2.2.14 against the criteria in SRP-LR Section 3.3.2.2.14.

LRA Section 3.3.2.2.14 addresses loss of material due to cladding breach. The applicant stated

that this aging effect is not applicable because SSES is a BWR.

SRP-LR Section 3.3.2.2.14 states that loss of material due to cladding breach may occur in

PWR steel charging pump casings with stainless steel cladding exposed to treated borated

water.

The staff reviewed the documentation supporting the applicant's AMR evaluation and confirmed

the applicant's claim that SSES has no steel with stainless steel cladding pump casing exposed

to treated borated water, an environment only exist in PWR. Therefore, the staff agrees with

the applicant's determination that the corresponding AMR result line in the GALL Report is not

applicable to SSES.

Based on the above, the staff concludes SRP-LR Section 3.3.2.2.14 criteria are not applicable.

3.3.2.2.15 Quality Assurance for Aging Management of Nonsafety-Related Components

SER Section 3.0.4 documents the staff's evaluation of the applicant's QA program.

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3.3.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report

In LRA Tables 3.3.2-1 through 3.3.2-34, the staff reviewed additional details of the AMR results

for material, environment, AERM, and AMP combinations not consistent with or not addressed

in the GALL Report.

In LRA Tables 3.3.2-1 through 3.3.2-34, the applicant indicated, via notes F through J that the

combination of component type, material, environment, and AERM does not correspond to a

line item in the GALL Report. The applicant provided further information about how it will

manage the aging effects. Specifically, note F indicates that the material for the AMR line item

component is not evaluated in the GALL Report. Note G indicates that the environment for the

AMR line item component and material is not evaluated in the GALL Report. Note H indicates

that the aging effect for the AMR line item component, material, and environment combination

is not evaluated in the GALL Report. Note I indicates that the aging effect identified in the GALL

Report for the line item component, material, and environment combination is not applicable.

Note J indicates that neither the component nor the material and environment combination for

the line item is evaluated in the GALL Report.

For component type, material, and environment combinations not evaluated in the GALL

Report, the staff reviewed the applicant's evaluation to determine whether the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB for the period of extended operation. The

staff's evaluation is documented in the following sections.

3.3.2.3.1 Aging Management Review Results - Building Drains Nonradioactive System -

LRA Table 3.3.2-1

The staff reviewed LRA Table 3.3.2-1, which summarizes the results of AMR evaluations for the

building drains nonradioactive system component groups.

In LRA Table 3.3.2-1, the applicant proposed to manage loss of material due for cast iron,

carbon steel and copper alloy material for piping and piping components exposed to an internal

environment of raw water using the AMP B.2.46 "Area-Based NSAS Inspection."

The AMR line items credit the AMP B.2.46 "Area-Based NSAS Inspection" to manage loss of

material for these components. The AMR line item cites Generic Note G, which indicates that

the environment is not addressed in GALL Report for this component and material combination.

The staff's evaluation of the AMP B.2.46 is documented in SER Section 3.0.3.3.1. The staff

noted that this program is a plant-specific program that performs an appropriate combination of

established volumetric and visual inspection techniques (nondestructive examination

techniques) that will be performed by a qualified personnel on a sample population of those

components in scope of this program. The staff further noted that the applicant will perform the

inspections of the components within the scope of this program within 10 years prior to entering

the period of extended operation. The staff determined the inspection techniques will be

capable of detecting loss of material and the applicant will initiate corrective actions if an

unacceptable loss of material or wall thinning has occurred that may have a spatial interaction

with safety-related components, as determined by engineering evaluation. On the basis that

the applicant will be performing an appropriate combination of a visual inspection and

volumetric testing for these components, the staff finds the AMR results for this line item

acceptable.

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In LRA Table 3.3.2-1, the applicant proposed to manage loss of material due to selective

leaching for cast iron and copper alloy material for piping and piping components exposed to an

internal environment of raw water using the AMP B.2.29 "Selective Leaching Inspection."

The AMR line items credit the AMP B.2.29 "Selective Leaching Inspection" to manage loss of

material due to selective leaching for these components. The AMR line item cites Generic Note

G, which indicates that the environment is not addressed in GALL Report for this component

and material combination. The staff's evaluation of the AMP B.2.29 is documented in SER

Section 3.0.3.2.17. The staff noted that this program is a one-time inspection that will perform

a combination of visual inspection and hardness testing to determine if loss of material due to

selective leaching has occurred. The staff further noted that the applicant will perform the

inspections of the components within the scope of this program within 10 years prior to entering

the period of extended operation such that the condition of the material is more representative

of the conditions during the period of extended operation. The staff determined the applicants

proposed inspection techniques to detect loss of material due to selective leaching are

consistent with the inspection techniques recommended in GALL AMP XI.M33 and the

applicant will initiate corrective actions based on the evaluation of the results of these

inspections. The staff noted that the GALL Report recommends the use of the Selective

Leaching Program for the same combination of material/environment/aging effect in items

VII.C1-10, and VII.C1-11 for different systems. On the basis that the applicant will be

performing a combination of a visual inspection and hardness test for these components and

these AMR material/environment/aging effect combination is consistent with the GALL AMR

Item VII.C1-10 and VII.C1-1 1, for copper alloy and cast iron respectively, the staff finds the

AMR results for this line item acceptable.

LRA Table 3.3.2-1 summarizes the results of AMRs for the Building Drains Nonradioactive

System piping and piping components constructed out of copper alloy and exposed to indoor air

(external). The applicant proposed no aging effect and therefore that no AMP is required.

The applicant has indicated that generic Note G is applicable for these items. Generic Note G is

"Environment not in NUREG-1 801 for this component and material." The staff confirmed that

this environment is not in GALL for this component and material. The staff also agrees that

there will not be any aging mechanism for this material/environment combination and that no

AMP is required. This conclusion is based on the fact that comprehensive tests conducted over

a 20-year period under ASTM supervision have confirmed the suitability of copper and copper

alloys for atmospheric exposure as cited in Metals Handbook, Volume 13, "Corrosion"

(American Society for Metals International, 1987).

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.2 Aging Management Review Results - Containment Instrument Gas System -

LRA Table 3.3.2-2

The staff reviewed LRA Table 3.3.2-2, which summarizes the results of AMR evaluations for the

containment instrument gas system component groups.

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In LRA Table 3.3.2-2, the applicant proposed to manage cracking of copper alloy for heat

exchanger shells in the Containment Instrument Gas System exposed to an internal

environment of treated water using the AMP B.2.14 "Closed Cooling Water Chemistry

Program."

The AMR line item credits the Closed Cooling Water Program to manage cracking for these

components. The AMR line item cites Generic Note H, which indicates that the aging effect is

not addressed in the GALL Report for this component, material and environment combination.

The Closed Cooling Water Chemistry Program is an existing program that properly monitors

components and controls corrosion inhibitor concentrations for components, within the scope of

license renewal, consistent with relevant EPRI water chemistry guidelines.

The applicant responded to RAI B.2.14-2, in a letter dated August 12, 2008. The applicant

clarified that the one-time inspection performed as part of the AMP B.2.22, "Chemistry Program

Effectiveness Inspection" will be used to supplement AMP B.2.14, "Closed Cooling Water

Chemistry Program" in all instances where AMP B.2.14 is credited for aging management in

LRA Table-2 items, with the exception of the Diesel Jacket Water Cooling System. The staff

reviewed the applicant's AMP B.2.14 "Closed Cooling Water Chemistry Program" and AMP

B.2.22 "Chemistry Program Effectiveness Inspection" and its evaluations are documented in

SER Section 3.0.3.2.7 and 3.0.3.1.10, respectively. The staff verified that this aging

management program includes activities that are consistent with the recommendations in the

GALL AMP XI.M21 to maintain high water purity, which is effective for managing cracking for

copper and copper alloy components exposed to a treated water environment. The staff further

noted the Closed Cooling Water Chemistry Program is an existing program that properly

monitors components and controls corrosion inhibitor concentrations for components, within the

scope of license renewal, consistent with relevant EPRI water chemistry guidelines. The staff

confirmed that the CPEI will be used to verify the effectiveness of the applicant's Closed

Cooling Water Chemistry Program to manage cracking and that a combination of appropriate

volumetric and visual examination techniques (such as VT-1 or VT-3) will be performed by

qualified personnel on a sample population of most susceptible subject components. On this

basis, the staff finds that these AMR results will be adequately managed by these programs.

In LRA Table 3.3.2-2, the applicant proposed to manage loss of material due for carbon steel

material for piping and piping components exposed to an internal environment of raw water

using the AMP B.2.46 "Area-Based NSAS Inspection."

The AMR line items credit the AMP B.2.46 "Area-Based NSAS Inspection" to manage loss of

material for these components. The AMR line item cites Generic Note G, which indicates that

the environment is not addressed in GALL Report for this component and material combination.

The staff's evaluation of the AMP B.2.46 is documented in SER Section 3.0.3.3.1. The staff

noted that this program is a plant-specific program that performs an appropriate combination of

established volumetric and visual inspection techniques (nondestructive examination

techniques) that will be performed by a qualified personnel on a sample population of those

components in scope of this program. The staff further noted that the applicant will perform the

inspections of the components within the scope of this program within 10 years prior to entering

the period of extended operation. The staff determined the inspection techniques will be

capable of detecting loss of material and the applicant will initiate corrective actions if an

unacceptable loss of material or wall thinning has occurred that may have a spatial interaction

with safety-related components, as determined by engineering evaluation. On the basis that the

applicant will be performing an appropriate combination of a visual inspection and volumetric

testing for these components, the staff finds the AMR results for this line item acceptable.

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LRA Table 3.3.2-2 summarizes the results of AMRs for the Containment Instrument Gas

System copper alloy (brass) heat exchanger shells for comrpressors exposed to indoor air

(external). The applicant proposed no aging effect and therefore that no AMP is required.

The applicant has indicated that generic Note G is applicable for these items. Generic Note G is

"Environment not in NUREG-1 801 for this component and material." The staff confirmed that

this environment is not in GALL for this component and material. The staff also agrees that

there will not be an aging mechanism for this material/environment combination and that no

AMP is required because copper alloy in air-indoor internal environment has no aging effect.

This conclusion is based on the fact that comprehensive tests conducted over a 20-year period

under ASTM supervision have confirmed the suitability of copper and copper alloys for

atmospheric exposure which is much more severe than indoor air environment as cited in

Metals Handbook, Volume "13, "Corrosion" (American Society for Metals International, 1987).

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3,3.2.3.3 Aging Management Review Results - Control Rod Drive Hydraulic System -

LRA Table 3.3.2-3

The staff reviewed LRA Table 3.3.2-3, which summarizes the results of AMR evaluations for the

CRD hydraulic system component groups.

In LRA Tables 3.3.2-3 the applicant proposed to manage cracking in copper alloy piping and

piping components, and in aluminum accumulator (pistons), in an environment of treated water

by using the BWR Water Chemistry Program. The applicant cited generic Note H for these

AMR results, indicating that the aging effect is not in the GALL Report for this component,

material and environment combination. In a letter dated July 15, 2008, the staff issued RAI 3.2-

3, applicable for the copper components and for similar AMR results in LRA Tables 3.2.2-1,

3.2.2-3, 3.3.2-25, and 3.4.2 3. In the same letter, the staff also issued RAI 3.3 2, applicable for

the aluminum components. The RAIs asked the applicant to provide a technical justification as

to why an inspection program, such as the CPEI is not needed to confirm that the BWR Water

Chemistry Program is effective in preventing the aging effect.

In a letter dated August 15, 2008, the applicant responded to RAI 3.2-3 and 3.3-2 by providing

the following responses:

RAI 3.2-3 Response:

For the five AMR results lines listed in LRA Tables 3.2.2-1, 3.2.2-3, 3.3.2-3, 3.3.2-25, and 3.4.2-

3, where the material is copper alloy, the environment is treated water (internal), and the aging

effect is cracking, verification of the effectiveness of the BWR Water Chemistry Program is

needed. The CPEI will provide confirmation of the effectiveness of this program in managing

the effects of aging, including cracking in susceptible materials. LRA Tables 3.2.2-1, 3.2.2-3,

3.3.2-3, 3.3.2-25, and 3.4.2-3 are revised to reflect these results.

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RAI 3.3-2 Response:

For the AMR results item listed on page 3.3-103 of the LRA for accumulator (pistons) made of

aluminum in a treated water environment with an aging effect of cracking, verification of the

effectiveness of the BWR Water Chemistry Program is needed. The CPEl will provide

confirmation of the effectiveness of this program in managing the effects of aging, including

cracking of susceptible materials. The affected LRA Tables are revised.

The staff reviewed the applicant's response and the associated LRA changes. The staff

reviewed the applicant's BWR Water Chemistry Program. The staff's evaluation of this

program, which is documented in SER Section 3.0.3.1.1, found that the BWR Water Chemistry

Program provides mitigation for the aging effect of cracking due to stress corrosion cracking.

The staff reviewed the applicant's Chemistry Program Effectiveness Inspection. The staff's

evaluation of this program, which is documented in SER Section 3.0.3.1.10, found that the

CPEI is a one-time inspection that is consistent with the GALL Report's recommendations for

AMP XI.M32, "One-Time Inspection." The CPEI includes provisions for inspecting selected

components in areas of low or stagnant flow and uses examination techniques that are capable

of detecting cracking, if it should occur in the selected components. Because the BWR Water

Chemistry Program provides mitigation and the CPEI provides detection of the aging effect if it

should occur, the staff finds the applicant's proposed AMPs for managing the potential aging

effect of cracking in copper alloy piping and piping components and in aluminum accumulator

(pistons) exposed to treated water in the control rod drive hydraulic system to be acceptable.

On this basis, the staff finds that the issues raised in RAIs 3.2 3 and 3.3-2 are resolved by the

applicant's LRA changes.

LRA Table 3.3.2-3 summarizes the results of AMRs for control rod drive hydraulics system

piping and piping components constructed using copper alloy exposed to indoor air (external).

The applicant proposed that there is no aging effect for the material environment combination

and that no AMR is required.

The applicant has indicated that generic Note G is applicable for these items. Generic Note G is

"Environment not in NUREG-1 801 for this component and material." The staff confirmed that

this environment is not in GALL for the component and material. The staff also agrees that

there will not be an aging mechanism for this material/environment combination, and that no

AMP is required.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.4 Aging Management Review Results - Control Structure Chilled Water System -

LRA Table 3.3.2-4

The staff reviewed LRA Table 3.3.2-4, which summarizes the results of AMR evaluations for the

control structure chilled water system component groups.

In LRA Table 3.3.2-4, the applicant proposed to manage cracking of copper alloy for chiller

evaporator and oil cooler tubes and plugs in the Control Structure Chilled Water System

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exposed to an internal and external environment of treated water using the AMP B.2.14 "Closed

Cooling Water Chemistry Program."

The AMR line item credits the Closed Cooling Water Program to manage cracking for these

components. The AMR line item cites Generic Note H, which indicates that the aging effect is

not addressed in the GALL Report for this component, material and environment combination.

The Closed Cooling Water Chemistry Program is an existing program that properly monitors

components and controls corrosion inhibitor concentrations for components, within the scope of

license renewal, consistent with relevant EPRI water chemistry guidelines.

The applicant responded to RAI B.2.14-2, in a letter dated August 12, 2008. The applicant

clarified that the one-time inspection performed as part of the AMP B.2.22, "Chemistry Program

Effectiveness Inspection" will be used to supplement AMP B.2.14, "Closed Cooling Water

Chemistry Program" in all instances where AMP B.2.14 is credited for aging management in

LRA Table-2 items, with the exception of the Diesel Jacket Water Cooling System. The staff

reviewed the applicant's AMP B.2.14 "Closed Cooling Water Chemistry Program" and AMP

B.2.22 "Chemistry Program Effectiveness Inspection" and its evaluations are documented in

SER Section 3.0.3.2.7 and 3.0.3.1.10, respectively. The staff verified that this aging

management program includes activities that are consistent with the recommendations in the

GALL AMP XI.M21 to maintain high water purity, which is effective for managing cracking for

copper and copper alloy components exposed to a treated water environment. The staff further

noted the Closed Cooling Water Chemistry Program is an existing program that properly

monitors components and controls corrosion inhibitor concentrations for components, within the

scope of license renewal, consistent with relevant EPRI water chemistry guidelines. The staff

confirmed that the CPEI will be used to verify the effectiveness of the applicant's Closed

Cooling Water Chemistry Program to manage cracking and that a combination of appropriate

volumetric and visual examination techniques (such as VT-1 or VT-3) will be performed by

qualified personnel on a sample population of most susceptible subject components. On this

basis, the staff finds that these AMR results will be adequately managed by these programs.

In LRA Table 3.3.2-4, the applicant proposed to manage reduction of heat transfer for copper

alloy greater than 15 percent zinc material for chiller oil cooler tubes exposed to an external

environment of lubricating oil using the Lubricating Oil Analysis Program, supplemented by the

Lubricating Oil Inspection. The AMR line item cites Generic Note H, which indicates that the

aging effect is not addressed in the GALL Report for this component, environment and material

combination.

The staff evaluated the Lubricating Oil Analysis Program and the Lubricating Oil Inspection

Program, and the evaluations are documented in SER Sections 3.0.3.2.15 and 3.0.3.2.13,

respectively. The Lubricating Oil Analysis Program is an existing program, that when enhanced,

will include sample locations from the control structure chiller, and will properly monitor relevant

conditions, such as particulate and water concentrations, viscosity, neutralization number and

flash point, that can lead to start and spread of loss of material or reduction in heat transfer

capability. The program's monitoring is based on manufacturer's recommendations, equipment

importance and accessibility and ASTM standards for lubricating oils. The applicant will

supplement this program with the Lubricating Oil Inspection, which will provide direct evidence

as to whether and to what extent reduction of heat transfer has occurred, thus providing

evidence of the effectiveness of the Lubricating Oil Analysis Program. The staff finds

lubricating oil in contact with the control structure chiller components will be properly monitored

and the aging effect of reduction in heat transfer of copper alloy greater than 15 percent zinc

exposed to an external environment of lube oil will be adequately managed by these programs.

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In LRA Table 3.3.2-4, the applicant proposed to manage loss of material due to selective

leaching for copper alloy material for valve bodies exposed to an external environment of indoor

air using the AMP B.2.29 "Selective Leaching Inspection."

The AMR line items credit the AMP B.2.29 "Selective Leaching Inspection" to manage loss of

material due to selective leaching for these components. The AMR line item cites Generic Note

H, which indicates that the aging effect is not addressed in the Gall Report for this component,

material and environment combination. The staff's evaluation of the AMP B.2.29 is

documented in SER Section 3.0.3.2.17. The staff noted that this program is a one-time

inspection that will perform a combination of visual inspection and hardness testing to

determine if loss of material due to selective leaching has occurred. The staff further noted that

the applicant will perform the inspections of the components within the scope of this program

within 10 years prior to entering the period of extended operation such that the condition of the

material is more representative of the conditions during the period of extended operation. The

staff determined the applicants proposed inspection techniques to detect loss of material due to

selective leaching are consistent with the inspection techniques recommended in GALL AMP

XI.M33 and the applicant will initiate corrective actions based on the evaluation of the results of

these inspections. On the basis that the applicant will be performing a combination of a visual

inspection and hardness test, which is consistent with the recommendations in GALL AMP

XI.M33, for these components, the staff finds the AMR results for this line item acceptable.

In Table 3.3.2-4, the LRA states that for glass skid-mounted sight glass components under

internal exposure to an air-gas environment, there are no aging effects identified and no aging

management program is required. The staff found that the plant-specific AMR for the exposure

of the glass skid-mounted sight glass components under internal exposure to an air-gas

environment (an uncontrolled air environment) was consistent with the AMR in GALL Report

Item VII.J-08 for exposure of glass components to uncontrolled indoor air environments. Based

on this review, the staff finds that the applicant has provided a valid basis for concluding that

there are not any AERMs for the glass skid-mounted sight glass components because the

applicant's AMR is consistent with GALL Report Item VII.J-08.

LRA Table 3.3.2-4 summarizes the results of AMRs for the Control Structure Chilled Water

System copper tubing (skid mounted) exposed to lubricating oil (internal). The applicant

proposed no aging effect and therefore that no AMP is required.

The applicant has indicated that generic Note I is applicable for these items. Generic Note I is

"Aging effect in NUREG-1 801 for this component, material, and environment is not applicable."

Plant-specific Note 310 stated that "copper contains less than 15% zinc, and therefore is not

susceptible to loss of material in this environment." The staff agrees that there will not be an

aging mechanism for this material/environment combination for copper tubing containing less

than 15% Zn and that no AMP is required. The GALL Report line items V EP-1 1-1, VII AP-10-J

and VIII SP-7-1 have copper alloy exposed to lubricating oil with no aging effect and no aging

management program required. The same will be true for the Control Structure Chilled

Water System copper tubing because it has the same material/environment combination as the

GALL Report Chapter V and VII material/environment and will have the same aging effect and

aging management program.

LRA Table 3.3.2-4 summarizes the results of AMRs for the Control Structure Chilled Water

System sight gauges (skid mounted) constructed from glass and exposed to air-gas (internal).

The applicant proposed no aging effect and therefore that no AMP is required.

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The applicant has indicated that generic Note G is applicable for these items. Generic Note G is

"Environment not in NUREG-1 801 for this component and material." The staff confirmed that

this environment is not in GALL for this component and material. The staff also agrees that

there will not be an aging mechanism for this material/environment combination and that no

AMP is required. This conclusion is based on the fact that there have been no aging effects

observed for glass components in this environment. Ref: Handbook of Glass Properties, N. P.

Bansal and R. H. Doremua, Academic Press 1986, pg. 646.

The staff reviewed LRA Table 3.3.2-4 which summarizes the results of AMRs for the Control

Structure Chilled Water System copper alloy (copper-nickel or brass) chiller tube plugs. The

applicant proposed that this system meets the definitions given above and therefore the

environment, aging effect requiring management, and AMR should be classified as not

applicable. The staff agrees with this proposal because these components do not have an

internal surface because they are solid and therefore, there will not be an aging effect requiring

an AMP.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.5 Aging Management Review Results - Control Structure HVAC Systems -

LRA Table 3.3.2-5

The staff reviewed LRA Table 3.3.2-5, which summarizes the results of AMR evaluations for the

control structure HVAC systems component groups.

In LRA Table 3.3.2-5, the applicant proposed to manage cracking of copper alloy for heating

and ventilation unit structure channels and cooling unit control and computer room channels in

the Control Structure HVAC System exposed to an internal and external environment of treated

water using the AMP B.2.14 "Closed Cooling Water Chemistry Program."

The AMR line item credits the Closed Cooling Water Program to manage cracking for these

components. The AMR line item cites Generic Note H, which indicates that the aging effect is

not addressed in the GALL Report for this component, material and environment combination.

The Closed Cooling Water Chemistry Program is an existing program that properly monitors

components and controls corrosion inhibitor concentrations for components, within the scope of

license renewal, consistent with relevant EPRI water chemistry guidelines.

The applicant responded to RAI B.2.14-2, in a letter dated August 12, 2008. The applicant

clarified that the one-time inspection performed as part of the AMP B.2.22, "Chemistry Program

Effectiveness Inspection" will be used to supplement AMP B.2.14, "Closed Cooling Water

Chemistry Program" in all instances where AMP B.2.14 is credited for aging management in

LRA Table-2 items, with the exception of the Diesel Jacket Water Cooling System. The staff

reviewed the applicant's AMP B.2.14 "Closed Cooling Water Chemistry Program" and AMP

B.2.22 "Chemistry Program Effectiveness Inspection" and its evaluations are documented in

SER Section 3.0.3.2.7 and 3.0.3.1.10, respectively. The staff verified that this aging

management program includes activities that are consistent with the recommendations in the

GALL AMP XI.M21 to maintain high water purity, which is effective for managing cracking for

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copper and copper alloy components exposed to a treated water environment. The staff further

noted the Closed Cooling Water Chemistry Program is an existing program that properly

monitors components and controls corrosion inhibitor concentrations for components, within the

scope of license renewal, consistent with relevant EPRI water chemistry guidelines. The staff

confirmed that the CPEI will be used to verify the effectiveness of the applicant's Closed

Cooling Water Chemistry Program to manage cracking and that a combination of appropriate

volumetric and visual examination techniques (such as VT-1 or VT-3) will be performed by

qualified personnel on a sample population of most susceptible subject components. On this

basis, the staff finds that these AMR results will be adequately managed by these programs.

In LRA Table 3.3.2-5, the applicant proposed to manage loss of material due for carbon steel

material for piping and piping components and humidifier housings exposed to an internal

environment of raw water using the AMP B.2.46 "Area-Based NSAS Inspection."

The AMR line items credit the AMP B.2.46 "Area-Based NSAS Inspection" to manage loss of

material for these components. The AMR line item cites Generic Note G, which indicates that

the environment is not addressed in GALL Report for this component and material combination.

The staff's evaluation of the AMP B.2.46 is documented in SER Section 3.0.3.3.1. The staff

noted that this program is a plant-specific program that performs an appropriate combination of

established volumetric and visual inspection techniques (nondestructive examination

techniques) that will be performed by a qualified personnel on a sample population of those

components in scope of this program. The staff further noted that the applicant will perform the

inspections of the components within the scope of this program within 10 years prior to entering

the period of extended operation. The staff determined the inspection techniques will be

capable of detecting loss of material and the applicant will initiate corrective actions if an

unacceptable loss of material or wall thinning has occurred that may have a spatial interaction

with safety-related components, as determined by engineering evaluation. On the basis that

the applicant will be performing an appropriate combination of a visual inspection and

volumetric testing for these components, the staff finds the AMR results for this line item

acceptable.

In LRA Table 3.3.2-5, the applicant proposed to manage loss of material due to selective

leaching for copper alloy material for the computer room floor cooling unit, control room floor

cooling unit and the control structure heating and ventilation unit exposed to an external

environment of indoor air using the AMP B.2.29 "Selective Leaching Inspection." By letter

dated July 25, 2008, the applicant amended its LRA to credit AMP B.2.29 for aging

management of these AMR line items.

The AMR line items credit the AMP B.2.29 "Selective Leaching Inspection" to manage loss of

material due to selective leaching for these components. The AMR line item cites Generic Note

H, which indicates that the aging effect is not addressed in the Gall Report for this component,

material and environment combination. The staff's evaluation of the AMP B.2.29 is

documented in SER Section 3.0.3.2.17. The staff noted that this program is a one-time

inspection that will perform a combination of visual inspection and hardness testing to

determine if loss of material due to selective leaching has occurred. The staff further noted that

the applicant will perform the inspections of the components within the scope of this program

within 10 years prior to entering the period of extended operation such that the condition of the

material is more representative of the conditions during the period of extended operation. The

staff determined the applicant's proposed inspection techniques to detect loss of material due

to selective leaching are consistent with the inspection techniques recommended in GALL AMP

XI.M33 and the applicant will initiate corrective actions based on the evaluation of the results of

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these inspections. On the basis that the applicant will be performing a combination of a visual

inspection and hardness test, which is consistent with the recommendations in GALL AMP

XI.M33, for these components, the staff finds the AMR results for this line item acceptable.

LRA Table 3.3.2-5 summarizes the results of AMRs for the Control Structure HVAC System

cooling unit, cooling coils, copper alloy (brass), copper tubing, flow element valve bodies,

computer and control room floor cooling coils, and aluminum flow elements exposed to

ventilation (internal and external). The applicant proposed no aging effect and therefore that no

AMP is required.

The applicant has indicated that generic Note G is applicable for these items. Generic Note G

is "Environment not in NUREG-1 801 for this component and material." The staff confirmed that

this environment is not in GALL for this component and material. The staff also agrees that

there will not be an aging mechanism for this material/environment combination and that no

AMP is required. The staff noted aluminum has an excellent resistance to corrosion when

exposed to a humid air (outdoor environment). In most environments the aluminum oxide film

bonds strongly to its surface and if damaged, reforms immediately. On a surface freshly

abraded and then exposed to air, the oxide film is only 5 to 10 nanometers thick but highly

effective in protecting the aluminum from corrosion. Therefore, aluminum exposed to an

outdoor air environment has no applicable aging effect. (M. G. Fontana, "Corrosion

Engineering, Third Edition, McGraw-Hill, 1986.) Copper alloy in an air-indoor internal

environment has no aging effect. This conclusion is based on the fact that comprehensive tests

conducted over a 20-year period under ASTM supervision have confirmed the suitability of

copper and copper alloys for atmospheric exposure as cited in Metals Handbook, Volume 13,

"Corrosion" (American Society for Metals International, 1987).

The staff reviewed LRA Table 3.3.2-5 which summarizes the results for the Control Structure

HVAC System air strengtheners and fins constructed out of aluminum. The applicant proposed

that this system meets the definitions given above and therefore the environment, aging effect

requiring management, and AMR should be classified as not applicable. The staff agrees with

this proposal because these components do not have an internal surface because they are

solid and therefore, there will not be an aging effect requiring an AMP.

In LRA Table 3.3.2-5, the applicant proposed to manage reduction of heat transfer of aluminum

cooling unit fins in an external environment of ventilation by using the Cooling Units Inspection

Program. The applicant referenced footnote "H" for this line item indicating that aging effect is

not in the GALL Report for this component, material and environment combination.

The staff noted the Cooling Unit Inspection Program will detect and characterize the condition

of cooling unit components that are exposed to a ventilation environment, and provides direct

evidence as to whether and to what extent, reduction of heat transfer has occurred, or is likely

to occur that could result in a loss of intended function. In its letter dated July 25, 2008, the

applicant responded to RAI B.2.23-2 stating that visual inspection (VT-3 or equivalent)

techniques will be used to determine whether reduction in heat transfer is occurring. The

applicant also stated that the specific inspection technique will be determined prior to the

inspection activities and will be consistent with the recommendations in GALL AMP XI.M32. The

staff's evaluation of the Cooling Units Inspection Program is documented in SER Section

3.0.3.1.11. Because the Cooling Units Inspection Program performs visual inspection to

determine if any fouling has occurred that could cause reduction of heat transfer, and on the

basis that the visual inspection technique will be consistent with the recommendation in GALL

AMP XI.M32, the staff finds the Cooling Units Inspection Program will adequately manage the

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aging effect of reduction of heat transfer in cooling unit components exposed to a ventilation

environment.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.6 Aging Management Review Results - Cooling Tower System - LRA Table 3.3.2-6

The staff reviewed LRA Table 3.3.2-6, which summarizes the results of AMR evaluations for the

cooling tower system component groups. The staff determined that all AMR evaluation

results in LRA Table 3.3.2-6 are consistent with the GALL Report.

3.3.2.3.7 Aging Management Review Results - Diesel Fuel Oil System - LRA Table 3.3.2-7

The staff reviewed LRA Table 3.3.2-7, which summarizes the results of AMR evaluations for the

diesel fuel oil system component groups.

In LRA Table 3.3.2-7 the applicant proposed to manage cracking in copper alloy level gauges,

orifices, tubing, and valve bodies in an environment of fuel oil using the Fuel Oil Chemistry

Program, alone. The staff noted that the Fuel Oil Chemistry Program does not include a

component inspection activity and issued RAI 3.3-5 by letter dated July 15, 2008, asking the

applicant to explain how effectiveness of the Fuel Oil Chemistry Program will be confirmed for

these components.

In a letter dated August 15, 2008, the applicant responded to RAI 3.3-5 by providing the

following response:

For the seven AMR result lines listed in LRA Table 3.3.2-7, where the aging effect is cracking

and the AMP is designated as the Fuel Oil Chemistry Program, verification of the effectiveness

of the Fuel Oil Chemistry Program is needed to confirm that cracking is not occurring in these

components.

The CPEI will detect and characterize the condition of materials managed by the Fuel Oil

Chemistry Program. Implementation of the CPEI will provide confirmation of the effectiveness

of this program in managing the effects of aging, including cracking of the susceptible

materials.

The applicant revised the seven (7) affected lines in LRA Table 3.3.2-7 to show that the Fuel Oil

Chemistry Program in combination with the CPEI will be used to manage the aging effect of

cracking for copper alloy components exposed to fuel oil in the diesel fuel oil system.

The staff reviewed the applicant's Fuel Oil Chemistry Program. The staff's evaluation of this

program, which is documented in SER Section 3.0.3.2.1, found that the Fuel Oil Chemistry

Program provides aging management for loss of material and is also credited with mitigating

the aging effect of cracking in susceptible materials through monitoring and control of fuel oil

contamination such as water or microbiological organisms, which might produce ammonia that

would cause cracking in copper alloy. The staff reviewed the applicant's Chemistry Program

Effectiveness Inspection. The staff's evaluation of this program, which is documented in SER

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Section 3.0.3.1.10, found that the CPEI is a one-time inspection that is consistent with the

GALL Report's recommendations for AMP XI.M32, "One-Time Inspection." The CPEI includes

provisions for inspecting selected components determined to be most susceptible to the aging

effect(s) of interest and uses examination techniques that are capable of detecting cracking if it

should occur in the selected components. Based on the applicant's use of a one-time inspection

consistent with the recommendations of the GALL Report, the staff finds the applicant's

proposed AMPs provide both mitigation and detection for the potential aging effect of cracking

in copper alloy components exposed to fuel oil in the diesel fuel oil system. On this basis, the

staff finds that the applicant's proposed AMPs provide adequate aging management and that

the issue raised in RAI 3.3-5 is resolved by the applicant's LRA changes.

In LRA Table 3.3.2-7, the applicant proposed to manage loss of material due to selective

leaching for cast iron and copper alloy material for level gauges, orifices, piping/tubing, pump

casings and valve bodies exposed to an internal environment of fuel oil using the AMP B.2.29

"Selective Leaching Inspection."

The AMR line items credit the AMP B.2.29 "Selective Leaching Inspection" to manage loss of

material due to selective leaching for these components. The AMR line item cites Generic Note

H, which indicates that the aging effect is not addressed in the Gall Report for this component,

material and environment combination. The staff's evaluation of the AMP B.2.29 is documented

in SER Section 3.0.3.2.17. The staff noted that this program is a one-time inspection that will

perform a combination of visual inspection and hardness testing to determine if loss of material

due to selective leaching has occurred. The staff further noted that the applicant will perform the

inspections of the components within the scope of this program within 10 years prior to entering

the period of extended operation such that the condition of the material is more representative of

the conditions during the period of extended operation. The staff determined the applicants

proposed inspection techniques to detect loss of material due to selective leaching are

consistent with the inspection techniques recommended in GALL AMP XI.M33 and the applicant

will initiate corrective actions based on the evaluation of the results of these inspections. On the

basis that the applicant will be performing a combination of a visual inspection and hardness

test, which is consistent with the recommendations in GALL AMP XI.M33, for these components,

the staff finds the AMR results for this line item acceptable.

In LRA Table 3.3.2-7, the applicant proposed to manage loss of material of carbon steel tanks

in an external environment of ventilation by using the Supplementary Piping/Tank Inspection

Program. The applicant referenced footnote "G" for this line item indicating that environment is

not in the GALL Report for this component and material combination. The environment is an

aggressive environment of air-water interface.

The staff reviewed the Supplementary Piping/Tank Inspection Program, which uses a

combination of volumetric and visual examination techniques to identify evidence of loss of

material or lack thereof. The staff's evaluation of the Supplementary Piping/Tank Inspection

Program is documented in SER Section 3.0.3.1.16. Because the Supplementary Piping/Tank

Inspection is performed at very specific locations of air/water interface, and employs a

combination of volumetric and visual inspection techniques, the staff finds that the

Supplementary Piping/Tank Inspection Program will adequately manage the aging effects of

loss of material in this aggressive environment.

In Table 3.3.2-7, the LRA states that for synthetic rubber flexible connections in a fuel oil

internal environment in the diesel fuel oil system, there are no aging effects requiring

management. In RAI 3.3.2.3-1, part A by letter dated July 23, 2008, the staff asked the

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applicant to justify why it had not identified any aging effects requiring management for these

system-material-environment combinations. In RAI 3.3.2.3-1, part B, the staff asked the

applicant to identify those material properties that could be impacted by exposure of these

materials and other materials such as plastic, synthetic rubber, butyl rubber and Teflon, to

either a treated water, raw water, fuel oil, lubricating oil, ventilation air, indoor air, and air-gas

(including Freon) environments. Finally, in RAI 3.3.2.3-1, part C, the staff asked the applicant to

identify the AMP that will be credited for aging management if PPL does identify that are

applicable AERMs for any of these system-material-environmental combinations.

In its letter dated August 27, 2008, in response to RAI 3.3.2.3-1 part A, the applicant stated that

the applicable aging effects for elastomers (including butyl rubber, synthetic rubber, neoprene,

and silicone) are change in material properties and cracking, which may be due to ionizing

radiation, thermal exposure, and exposure to ultraviolet radiation or ozone. The applicant

provided the threshold level for ionizing radiation as 1 0E6 rads, for temperature as greater than

95°F, and for ultraviolet radiation and ozone as prolonged exposure. The applicant further

stated that, except for certain areas in the Reactor Building, where ionizing radiation could be

more than the threshold limit, the other buildings are all in an environment that is within the

threshold limits. Therefore, the applicant concluded that there are no aging effects requiring

management for synthetic rubber flexible connections in a fuel oil internal environment in the

diesel fuel oil system.

In response to RAI 3.3.2.3-1, part B, the applicant stated that the specific material properties

that could be impacted by exposure to treated water, raw water, fuel oil, lubricating oil,

ventilation air, indoor air, and air-gas (including Freon) environments are hardening (e.g.,

embrittlement, decrease in elasticity) and loss of strength (e.g., elongation, loss of tensile

strength, and, with exposure to ionizing radiation, swelling or melting). The applicant further

stated that hardening and loss of strength could occur as a result of prolonged exposure to high

temperature, high radiation levels, or to ultraviolet radiation or ozone.

In response to RAI 3.3.2.3.-1, part C, the applicant stated that there are no aging effects requiring

management for the system-material-environment combinations listed in RAI 3.3.2.3-1, except for

those that have already been identified in the LRA as noted in the response to Part B.

The staff reviewed the applicant response to RAI 3.3.2.3-1, parts A, B and C, and finds the

applicant response acceptable because the applicant defined the stressors that could cause the

aging effects in various structures. The applicant response is consistent with the GALL Report

definitions of the threshold limits of the stressors as recommended in the GALL Report Section

IX. On the basis of its review, the staff finds for synthetic rubber flexible connections in a fuel oil

internal environment in the diesel fuel oil system, there are no aging effects requiring

management.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report.

LRA Table 3.3.2-7, summarizes the results of AMRs for the Diesel Fuel Oil System, orifices

constructed using copper alloy (brass), level gauges (day tank) constructed from copper alloy

(bronze), heat exchangers channels, covers and shells constructed from copper alloy (coppernickel), valve bodies and tubing (and fittings) constructed from copper alloy (brass and bronze)

exposed to indoor air (external), level gauges (day tank) constructed from copper alloy (brass)

exposed to ventilation (internal), and piping and piping components constructed from copper

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and exposed to lubricating oil (internal). The applicant proposes that for these combinations of

components, materials and environment conditions, there is no aging effect requiring

management and therefore that no AMR is required.

The applicant has indicated that the GALL Note G is applicable for these items. Note G is

"Environment not in NUREG-1 801 for this component and material." The staff confirmed that

this environment is not in the GALL for these components and materials. The staff also agrees

that there will not be an aging mechanism for this material/environment combination and that no

AMP is required. Copper alloy in an air-indoor internal environment has no aging effect. This

conclusion is based on the fact that comprehensive tests conducted over a 20-year period

under ASTM supervision have confirmed the suitability of copper and copper alloys for

atmospheric exposure as cited in Metals Handbook, Volume 13, "Corrosion" (American Society

for Metals International, 1987).

LRA Table 3.3.2-7 summarizes the results of an AMR for the Diesel Fuel Oil System piping and

piping components constructed from carbon steel and exposed to outdoor air (external). The

applicant claims that for these combinations of components, materials and environment there is

no aging effect requiring management and therefore no AMR is required. The applicant

references plant-specific Note 0361. Plant-specific Note 0361 states, Nonsafety-related vent

and fill piping and piping components in the Diesel Fuel Oil System are normally empty and are

attached to safety-related components (storage tanks or piping) that are anchored in below

grade vaults or within Seismic Category I buildings. As such, degradation of the vent and fill

piping or piping components will not result in a loss of support for safety-related components to

which they are attached. Also, there is no high pressure, other motive force, or medium in the

air to cause degradation." Because these components are normally empty, and because even

if for some reason, they would fail, they would not affect the intended function of safety-related

components, and they are not in scope for license renewal the staff finds this to be acceptable.

The applicant also references Table 3.3.1-58 which covers "Steel external surfaces exposed to

air-indoor uncontrolled (external), air-outdoor (external), and condensation (external)" and

identifies the aging effect as "Loss of material due to general corrosion" and the AMP as

External Surfaces Monitoring. The LRA, in the discussion section states "The System

Walkdown Program also manages loss of material due to crevice and/or pitting corrosion due to

condensation." The discussion states that this AMR is consistent with GALL while the line item

in Table 3.3.2-7 reference Note I, which states that the aging effect is not applicable.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.8 Aging Management Review Results - Diesel Generator Buildings HVAC Systems -

LRA Table 3.3.2-8

The staff reviewed LRA Table 3.3.2-8, which summarizes the results of AMR evaluations for the

diesel generator buildings HVAC systems component groups.

LRA Table 3.3.2-8 summarizes the results of AMRs for the Diesel Generator Building HVAC

System flexible connectors (ductwork) constructed from neoprene/fiberglass and

neoprene/asbestos and neoprene exposed to ventilation (internal) and indoor air (external). The

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applicant proposes that these components, materials, environment combinations have no aging

effects requiring management and therefore no AMP is required.

The applicant has indicated that generic Note I is applicable for these items. Generic Note I is

"Aging effect in NUREG-1801 for this component, material, and environment is not applicable."

The staff agrees that there will not be an aging mechanism for this material/environment

combination.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.9 Aging Management Review Results - Diesel Generators System - LRA Table 3.3.2-9

The staff reviewed LRA Table 3.3.2-9, which summarizes the results of AMR evaluations for the

diesel generators system component groups.

In LRA Table 3.3.2-9, the applicant proposed to manage loss of material of nickel alloy (monel)

for heat exchanger heating core tube plugs in the Diesel Generator Intake/Exhaust System

exposed to an internal environment of treated water using the AMP B.2.14 "Closed Cooling

Water Chemistry Program."

The AMR line item credits the AMP B.2.14 "Closed Cooling Water Chemistry Program." to

manage loss of material for these components. The AMR line item cites Generic Note G, which

indicates that the environment is not addressed in GALL Report for this component and

material combination. The Closed Cooling Water Chemistry Program is an existing SSES

program that properly monitors components and controls corrosion inhibitor concentrations for

components, within the scope of license renewal, consistent with relevant EPRI water chemistry

guidelines.

The applicant responded to RAI B.2.14-2, in a letter dated August 12, 2008, and supplemented

its response by letter dated December 11, 2008. The applicant clarified that the one-time

inspection performed as part of the AMP B.2.22, "Chemistry Program Effectiveness Inspection"

will be used to supplement AMP B.2.14, "Closed Cooling Water Chemistry Program" in all

instances where AMP B.2.14 is credited for aging management in LRA Table-2 items, with the

exception of the Diesel Jacket Water Cooling System. The staff reviewed the applicant's SSES

AMP B.2.14 "Closed Cooling Water Chemistry Program" and AMP B.2.22 "Chemistry Program

Effectiveness Inspection" and its evaluations are documented in SER Section 3.0.3.2.7 and

3.0.3.1.10, respectively. The staff verified that this aging management program includes

activities that are consistent with the recommendations in the GALL AMP XI.M21 to maintain

high water purity, which is effective for managing loss of material for nickel alloy components

exposed to a treated water environment. The staff further noted the Closed Cooling Water

Chemistry Program is an existing program that properly monitors components and controls

corrosion inhibitor concentrations for components, within the scope of license renewal,

consistent with relevant EPRI water chemistry guidelines. The staff confirmed that the CPEI will

be used to verify the effectiveness of the applicant's Closed Cooling Water Chemistry Program

to manage loss of material and that a combination of appropriate volumetric and visual

examination techniques (such as VT-1 or VT-3) will be performed by qualified personnel on a

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sample population of most susceptible subject components. On this basis, the staff finds that

these AMR results will be adequately managed by these programs.

In LRA Table 3.3.2-9, the applicant proposed to manage cracking of copper alloy for piping,

piping components, tubing, fittings, valve bodies, heater immersion sheaths, and heat

exchanger components in the Diesel Generator Lubricating Oil, Jacket Water, Intake/Exhaust

and NSAS Component System exposed to an internal or external environment of treated water

using the AMP B.2.14 "Closed Cooling Water Chemistry Program."

The AMR line item credits the Closed Cooling Water Program to manage cracking for these

components. The AMR line item cites Generic Note H, which indicates that the aging effect is

not addressed in the GALL Report for this component, material and environment combination.

The Closed Cooling Water Chemistry Program is an existing program that properly monitors

components and controls corrosion inhibitor concentrations for components, within the scope of

license renewal, consistent with relevant EPRI water chemistry guidelines.

The applicant responded to RAI B.2.14-2, in a letter dated August 12, 2008. The applicant

clarified that the one-time inspection performed as part of the AMP B.2.22, "Chemistry Program

Effectiveness Inspection" will be used to supplement AMP B.2.14, "Closed Cooling Water

Chemistry Program" in all instances where AMP B.2.14 is credited for aging management in

LRA Table-2 items, with the exception of the Diesel Jacket Water Cooling System. The staff

reviewed the applicant's AMP B.2.14 "Closed Cooling Water Chemistry Program" and AMP

B.2.22 "Chemistry Program Effectiveness Inspection" and its evaluations are documented in

SER Section 3.0.3.2.7 and 3.0.3.1.10, respectively. The staff verified that this aging

management program includes activities that are consistent with the recommendations in the

GALL AMP XI.M21 to maintain high water purity, which is effective for managing cracking for

copper and copper alloy components exposed to a treated water environment. The staff further

noted the Closed Cooling Water Chemistry Program is an existing program that properly

monitors components and controls corrosion inhibitor concentrations for components, within the

scope of license renewal, consistent with relevant EPRI water chemistry guidelines. The staff

confirmed that the CPEI will be used to verify the effectiveness of the applicant's Closed

Cooling Water Chemistry Program to manage cracking and that a combination of appropriate

volumetric and visual examination techniques (such as VT-1 or VT-3) will be performed by

qualified personnel on a sample population of most susceptible subject components. On this

basis, the staff finds that these AMR results will be adequately managed by these programs.

In LRA Table 3.3.2-9, the applicant proposed to manage loss of material for aluminum material

for heat exchanger shells exposed to an internal environment of lubricating oil using the

Lubricating Oil Analysis Program, supplemented by the Lubricating Oil Inspection. The AMR

line item cites Generic Note G, which indicates that the environment is not addressed in GALL

Report for this component and material combination.

The staff evaluated the Lubricating Oil Analysis Program and the Lubricating Oil Inspection

Program, and the evaluations are documented in SER Sections 3.0.3.2.15 and 3.0.3.2.13,

respectively. The Lubricating Oil Analysis Program is an existing SSES program that will

properly monitor relevant conditions, such as particulate and water concentrations, viscosity,

neutralization number and flash point that can lead to start and spread of loss of material or

reduction in heat transfer capability. The program's monitoring is based on manufacturer's

recommendations, equipment importance and accessibility and ASTM standards for lubricating

oils. The applicant will supplement this program with the Lubricating Oil Inspection, which will

provide direct evidence as to whether and to what extent reduction of heat transfer has

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occurred, thus providing evidence of the effectiveness of the Lubricating Oil Analysis Program.

On the basis of its review, the staff finds that because these the lubricating oil in contact with

components will properly monitor relevant conditions, such as particulate and water

concentrations, viscosity, neutralization number and flash point and then supplemented by a

one-time inspection, "Lubricating Oil Inspection" to confirm program effectiveness that the aging

effect of loss of material of aluminum exposed to an external environment of lube oil will be

adequately managed by these programs.

In LRA Table 3.2.2-9, the applicant proposed to manage reduction of heat transfer in copper

alloy heat exchanger tubes in an external environment of lubricating oil by using the Piping

Corrosion Program. The applicant referenced footnote H for this line item indicating that aging

effect is not in the GALL Report for this component, material and environment combination.

However, the staff noted that GALL Report Item V.D2-9 has the same aging effect for this

component, material and environment. The GALL Report recommends GALL AMP XI.M39,

Lubricating Oil Analysis, and GALL AMP XI.M32, One-Time Inspection. Since the internal

environment of these tubes is raw water, these heat exchangers are included in the GL 89-13

program. Therefore, the applicant is proposing to use the Piping Corrosion Program, which is

consistent with GALL AMP XI.M20, Open-Cycle Cooling Water System.

The staff reviewed the Piping Corrosion Program, which is a combination of condition

monitoring program (consisting of inspections, surveillances, and testing to detect the presence

of, and to assess the extent of, fouling and loss of material) and a mitigation program

(consisting of chemical treatments and cleaning activities to minimize fouling and loss of

material). The staff's evaluation of the Piping Corrosion program is documented in SER Section

3.0.3.2.6. Because the Piping Corrosion Program includes both the chemistry treatment and

cleaning for mitigation and inspection for verification, the staff finds that the Piping Corrosion

Program will adequately manage the aging effects of reduction of heat transfer in copper alloy

heat exchanger tubes in an external environment of lubricating oil through the period of

extended operation.

In Table 3.3.2-9, the LRA states that for synthetic rubber flexible connections in a lubricating oil

internal environment in the diesel generator system, there are no aging effects requiring

management. In RAI 3.3.2.3-1, part A by letter dated July 23, 2008, the staff asked the

applicant to justify why it had not identified any aging effects requiring management for these

system-material-environment combinations. In RAI 3.3.2.3-1, part B, the staff asked the

applicant to identify those material properties that could be impacted by exposure of these

materials and other materials such as plastic, synthetic rubber, butyl rubber and Teflon, to

either a treated water, raw water, fuel oil, lubricating oil, ventilation air, indoor air, and air-gas

(including Freon) environments. Finally, in RAI 3.3.2.3-1, part C, the staff asked the applicant to

Identify the AMP or AMPs that will be credited for aging management if PPL does identify

applicable AERMs for any of these system-material-environmental combinations.

In its letter dated August 27, 2008, in response to RAI 3.3.2.3-1 part A, the applicant stated that

the applicable aging effects for elastomers (including butyl rubber, synthetic rubber, neoprene,

and silicone) are change in material properties and cracking, which may be due to ionizing

radiation, thermal exposure, or exposure to ultraviolet radiation or ozone. The applicant

provided the threshold level for ionizing radiation as 1 0E6 rads, for temperature as greater than

950F, and for ultraviolet radiation and ozone as prolonged exposure. The applicant further

stated that, except for certain areas in the Reactor Building, where ionizing radiation could be

more than the threshold limit, the other buildings are all in an environment that is within the

threshold limits. Therefore, the applicant concluded that there are no aging effects requiring

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management for synthetic rubber flexible connections in a lubricating oil internal environment in

the diesel generator system.

In response to RAI 3.3.2.3-1, part B, the applicant stated that the specific material properties

that could be impacted by exposure to treated water, raw water, fuel oil, lubricating oil,

ventilation air, indoor air, and air-gas (including Freon) environments are hardening (e.g.,

embrittlement, decrease in elasticity) and loss of strength (e.g., elongation, loss of tensile

strength, and, with exposure to ionizing radiation, swelling or melting). The applicant further

stated that hardening and loss of strength could occur as a result of prolonged exposure to high

temperature, high radiation levels, or to ultraviolet radiation or ozone.

In response to RAI 3.3.2.3.-1, part C, the applicant stated that there are no aging effects

requiring management for the system-material-environment combinations listed in RAI 3.3.2.3-

1, except for those that have already been identified in the LRA as noted in the response to

part B.

The staff reviewed the applicant response to RAI 3.3.2.3-1, parts A, B and C, and finds the

applicant response acceptable because the applicant defined the stressors that could cause the

aging effects in various structures. The applicant response is consistent with the GALL Report

definitions of the threshold limits of the stressors as recommended in the GALL Report Section

IX. On the basis of its review, the staff finds for synthetic rubber flexible connections in a

lubricating oil internal environment in the diesel generator system, there are no aging effects

requiring management.

In Table 3.3.2-9, the LRA states that for plastic (Lucite) level gauges in internal ventilation,

lubricating oil and external indoor air environments, and plastic (poly-carbonate) filters in air/gas

internal and indoor air external environments in the diesel generator system, there are no aging

effects requiring management. In RAI 3.3.2.3-1, by letter dated July 23, 2008, the staff asked

the applicant to justify why it had not identified any aging effects requiring management for

these system-material-environment combinations.

In its letter dated August 27, 2008, in response to RAI 3.3.2.3-1, the applicant stated that

Degradation of plastic materials is considered a design issue. Plastic is either completely

resistant to the environment to which it is exposed, or it deteriorates. Acceptability for the use of

plastics in any particular environment is a design-driven criterion, and once the appropriate

material is chosen, the component will have no aging effects that require management. That is,

the occurrence of any aging effects is considered a design deficiency that will be detected and

corrected within the current license period.

Therefore, based on a review of industry operating experience and the expectation of proper

design and application of the material, aging of plastics is not considered to require further

evaluation for license renewal.

The staff reviewed the applicant response and concurs that the selection of plastic material is a

design consideration for the system and environment; and once selected for the environment of

ventilation, lubricating oil or indoor air, aging of plastic material is not expected. The staff

acknowledges that plastic, like glass, is an impervious material and as identified in the GALL

Report Item VII.J-8, glass has no aging effects requiring management in an indoor air

environment. The staff has not observed any age related industry experience for plastic

material in internal ventilation or air/gas and external indoor air environments, and therefore,

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finds that for plastic (Lucite) level gauges in internal ventilation, lubricating oil and external

indoor air environments, and plastic (poly-carbonate) filters in air/gas internal and indoor air

external environments in the diesel generator system will not experience any aging effects

requiring management.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report.

LRA Table 3.3.2-9 summarizes the results of AMRs for the Diesel Generators Lubrication Oil

System heat exchangers end bells and shells constructed from aluminum and exposed to

indoor air (external). The applicant proposed that there is no aging effect for the material

environment combination and that no AMR is required.

LRA Table 3.3.2-9 summarizes the results of AMRs for Diesel Generators System starting air

and intake/exhaust valve bodies constructed from nickel alloys (nickel-iron), valve bodies and

orifices constructed from copper alloy (bronze), and filter bodies and heat exchanger fins

constructed from aluminum exposed to indoor air (external) and ventilation (external). The

applicant proposed that there is no aging effect for the material environment combination and

that no AMR is required.

The staff finds that this conclusion is acceptable for nickel iron alloys because nickel iron alloys

show very low corrosion rates in atmospheric exposure as discussed in F. L. LaQue and H. R.

Copson, "Corrosion Resistance of Metals and Alloys," Second Edition, Reinhold Publishing

Corporation, New York, 1963. The staff finds that this conclusion is acceptable for copper

alloys because copper alloys in air-indoor internal environment has no aging effect. This

conclusion is based on the fact that comprehensive tests conducted over a 20-year period

under ASTM supervision have confirmed the suitability of copper and copper alloys for

atmospheric exposure (which is more severe than indoor air or ventilation) as cited in Metals

Handbook, Volume 13, "Corrosion" (American Society for Metals International, 1987). The staff

finds that his is acceptable for aluminum because aluminum exposed internally to an indoor air

environment and externally to ventilation has no applicable aging effect as discussed in M. G.

Fontana, "Corrosion Engineering, Third Edition, McGraw-Hill, 1986.

LRA Table 3.3.2-9 summarizes the results of AMRs for the Diesel Generators System

intake/exhaust heat exchanger cooling core and heating core tube plugs constructed from

nickel alloys (model), heat exchanger cooling core and heating core tube sheets constructed

from copper alloy (copper-nickel), heat exchanger cooling core and heating core tubes

constructed from copper alloy (copper-nickel) exposed to ventilation (external), heat exchanger

water boxes constructed from copper alloy (copper-nickel), and valve bodies constructed from

copper alloy (bronze) and exposed to indoor air (exterior), and filter housings constructed from

galvanized steel exposed to outdoor air (exterior). For these components, materials and

environment combinations, the applicant proposed no aging effect requiring management and

no requirement for an AMP.

The applicant has indicated that generic Note G is applicable for these items. Generic Note G is

"Environment not in NUREG-1801 for this component and material." The staff confirmed that

this environment is not in the GALL Report for these components and materials. The staff

agrees that there will be no aging effect for the tube plugs because they are not exposed to an

external environment. The staff agrees with this position because these components do not

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have an external surface in contact with an environment because their external surface is in

contact with the inside of the heat exchanger tubes.

The staff also agrees that there will not be an aging mechanism for the remaining

material/environment combinations and that no AMP is required. The staff noted items include

the external surface of components (e.g., heat exchanger shells, piping and piping components,

and tanks) that do not contain chilled water, raw water, domestic water or cooling unit drainage

and, therefore, do not experience condensation. For copper alloys, items match GALL items

V.F-3 and VIII.I-2 for closed water systems, but no such item exists in GALL (Chapter VII) for

closed cooling water auxiliary systems.

LRA Table 3.3.2-9 summarizes the results of AMRs for diesel generators NSAS components,

process system piping and piping components constructed using copper alloy exposed to

indoor air (external). The applicant proposed that there is no aging effect for the material

environment combination and that no AMR is required.

The applicant has indicated that generic Note G is applicable for these items. Generic Note G is

"Environment not in NUREG-1 801 for this component and material." The staff confirmed that

this environment is not in GALL for the component and material. The staff also agrees that

there will not be an aging mechanism for this material/environment combination, and that no

AMP is required.

LRA Table 3.3.2-9 summarizes the results of AMRs for the Diesel Generator intake/exhaust

heat exchanger fins constructed from aluminum, diesel generators jacket water heat exchanger

tube plugs constructed from copper alloy (copper-nickel) and stainless steel. The applicant

proposed that this system meets the definitions given above and therefore the environment,

aging effect requiring management, and AMR should be classified as not applicable. The staff

agrees with this proposal because these components do not have an internal surface.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.10 Aging Management Review Results - Domestic Water System - LRA Table 3.3.2-10

The staff reviewed LRA Table 3.3.2-10, which summarizes the results of AMR evaluations for

the domestic water system component groups.

In LRA Table 3.3.2-10, the applicant proposed to manage loss of material due for copper alloy

material for piping and piping components exposed to an internal environment of raw water

using the AMP B.2.46 "Area-Based NSAS Inspection."

The AMR line items credit the AMP B.2.46 "Area-Based NSAS Inspection" to manage loss of

material for these components. The AMR line item cites Generic Note G, which indicates that

the environment is not addressed in GALL Report for this component and material combination.

The staff's evaluation of the AMP B.2.46 is documented in SER Section 3.0.3.3.1. The staff

noted that this program is a plant-specific program that performs an appropriate combination of

established volumetric and visual inspection techniques (nondestructive examination

techniques) that will be performed by qualified personnel on a sample population of those

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components in scope of this program. The staff further noted that the applicant will perform the

inspections of the components within the scope of this program within 10 years prior to entering

the period of extended operation. The staff determined the inspection techniques will be

capable of detecting loss of material and the applicant will initiate corrective actions if an

unacceptable loss of material or wall thinning has occurred that may have a spatial interaction

with safety-related components, as determined by engineering evaluation. On the basis that

the applicant will be performing an appropriate combination of a visual inspection and

volumetric testing for these components, the staff finds the AMR results for this line item

acceptable.

In LRA Table 3.3.2-10, the applicant proposed to manage cracking for copper alloy material for

piping and piping components exposed to an internal environment of raw water using the AMP

B.2.46 "Area-Based NSAS Inspection."

The AMR line items credit the AMP B.2.46 "Area-Based NSAS Inspection" to manage cracking

for these components. The AMR line item cites Generic Note G, which indicates that the

environment is not addressed in GALL Report for this component and material combination.

The staff's evaluation of the AMP B.2.46 is documented in SER Section 3.0.3.3.1. The staff

noted that this program is a plant-specific program that performs an appropriate combination of

established volumetric and visual inspection techniques (nondestructive examination

techniques) that will be performed by a qualified personnel on a sample population of those

components in scope of this program. The staff further noted that the applicant will perform the

inspections of the components within the scope of this program within 10 years prior to entering

the period of extended operation. The staff determined the inspection techniques will be

capable of detecting cracking and the applicant will initiate corrective actions if an unacceptable

loss of material or wall thinning has occurred that may have a spatial interaction (e.g., leakage)

with safety-related components, as determined by engineering evaluation. On the basis that

the applicant will be performing an appropriate combination of a visual inspection and

volumetric testing for these components, the staff finds the AMR results for this line item

acceptable.

In LRA Table 3.3.2-10, the applicant proposed to manage loss of material due to selective

leaching for copper alloy material for piping and piping components exposed to an internal

environment of raw water and external environment of indoor air using the AMP B.2.29

"Selective Leaching Inspection."

The AMR line items credit the AMP B.2.29 "Selective Leaching Inspection" to manage loss of

material due to selective leaching for these components. The AMR line item cites Generic Note

G, which indicates that the environment is not addressed in GALL Report for this component

and material combination. The staff's evaluation of the AMP B.2.29 is documented in SER

Section 3.0.3.2.17. The staff noted that this program is a one-time inspection that will perform

a combination of visual inspection and hardness testing to determine if loss of material due to

selective leaching has occurred. The staff further noted that the applicant will perform the

inspections of the components within the scope of this program within 10 years prior to entering

the period of extended operation such that the condition of the material is more representative

of the conditions during the period of extended operation. The staff determined the applicants

proposed inspection techniques to detect loss of material due to selective leaching are

consistent with the inspection techniques recommended in GALL AMP XI.M33 and the

applicant will initiate corrective actions based on the evaluation of the results of these

inspections. On the basis that the applicant will be performing a combination of a visual

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inspection and hardness test, which is consistent with the recommendations in GALL AMP

XI.M33, for these components, the staff finds the AMR results for this line item acceptable.

In Table 3.3.2-10, the LRA states that for glass liner in the domestic water tank under internal

exposure to a raw water environment, there are no aging effects identified and no aging

management program is required. In RAI 3.3.2.3-1, Part A by letter dated July 23, 2008, the

staff asked the applicant to justify why it had not identified any aging effects requiring

management for these system-material-environment combinations.

In its letter dated August 27, 2008, in response to RAI 3.3.2.3-1 Part A, the applicant stated

that:

The relevant conditions that could result in aging degradation of glass are high

temperature water, and/or the presence of hydrofluoric acid or caustic alkalis.

Hydrofluoric acid and caustic alkalis are not expected to exist in the raw water

environment of the domestic water system. When hot water attacks glass, it is

not dissolved in the usual sense but is hydrolytically decomposed. Resistance to

water varies from excellent to poor depending on the composition of the glass.

Furthermore, glass-lined steel combines the corrosion resistance of glass with

the strength of steel, making it useful for equipment operating at elevated

temperature and pressure. Glass-lined steel has excellent resistance to

corrosion over a wide range of pH and environments. As such, it is expected that

the glass lining for the water heater tank is properly designed and selected for

the service in which it is used. Therefore, there are no aging effects requiring

management for the subject glass components in the domestic water system.

The staff found that the plant-specific AMR for the exposure of the glass liner in the domestic

water tank under internal exposure to a raw water environment was consistent with the AMR in

GALL AMR item VII.J-1 1 for exposure of glass components to raw water environments. Based

on this review, the staff finds that the applicant has provided a valid basis for concluding that

there are not any AERMs for the glass lining in the domestic water system tank because the

applicant's AMR is consistent with GALL AMP VII.J-1 1.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.3.2.3.11 Aging Management Review Results - Emergency Service Water System -

LRA Table 3.3.2-11

The staff reviewed LRA Table 3.3.2-11, which summarizes the results of AMR evaluations for

the emergency service water system component groups.

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In LRA Table 3.3.2-11, the applicant proposed to manage loss of material for stainless steel

material for piping and piping components exposed to an external environment of outdoor air

using the AMP B.2.32 "System Walkdown Program."

The AMR line item credits the AMP B.2.32 "System Walkdown Program" to manage loss of

material for these components. The AMR line item cites Generic Note G, which indicates that

the environment is not addressed in GALL Report for this component and material combination.

The staff's evaluation of the AMP B.2.32 "System Walkdown Program" is documented in SER

Section 3.0.3.2.15. The staff determined that this program is a condition monitoring program

that will detect the aging effect of loss of material for metals, including stainless steel, by

periodic surveillance activities and observations of components' external surfaces to detect

aging degradation that are within the scope of license renewal. The staff also determined that

these activities are adequate to manage loss of material for stainless steel piping and piping

components exposed to air-outdoor. On this basis, the staff finds the AMR results for this line

item acceptable.

In LRA Table 3.3.2-11, the applicant proposed to manage loss of material due to selective

leaching for copper alloy material for piping and piping components exposed to an internal

environment of raw water using the AMP B.2.46 "Area-Based NSAS Inspection."

The AMR line items credit the AMP B.2.46 "Area-Based NSAS Inspection" to manage loss of

material for these components. The AMR line item cites Generic Note H, which indicates that

the aging effect is not addressed in the Gall Report for this component, material and

environment combination. The staff's evaluation of the AMP B.2.46 is documented in SER

Section 3.0.3.3.1. The staff noted that this program is a plant-specific program that performs

an appropriate combination of established volumetric and visual inspection techniques

(nondestructive examination techniques) that will be performed by a qualified personnel on a

sample population of those components in scope of this program. The staff further noted that

the applicant will perform the inspections of the components within the scope of this program

Iwithin 10 years prior to entering the period of extended operation. The staff determined the

inspection techniques will be capable of detecting cracking and the applicant will initiate

corrective actions if an unacceptable loss of material or wall thinning has occurred that may

have a spatial interaction with safety-related components, as determined by engineering

evaluation. On the basis that the applicant will be performing an appropriate combination of a

visual inspection and volumetric testing for these components, the staff finds the AMR results

for this line item acceptable.

In LRA Table 3.3.2-11, the applicant proposed to manage loss of material due to selective

leaching for copper alloy material for piping and piping components exposed to an external

environment of indoor air using the AMP B.2.29 "Selective Leaching Inspection."

The AMR line items credit the AMP B.2.29 "Selective Leaching Inspection" to manage loss of

material due to selective leaching for these components. The AMR line item cites Generic Note

H, which indicates that the aging effect is not addressed in the Gall Report for this component,

material and environment combination. The staff's evaluation of the AMP B.2.29 is

documented in SER Section 3.0.3.2.17. The staff noted that this program is a one-time

inspection that will perform a combination of visual inspection and hardness testing to

determine if loss of material due to selective leaching has occurred. The staff further noted that

the applicant will perform the inspections of the components within the scope of this program

within 10 years prior to entering the period of extended operation such that the condition of the

material is more representative of the conditions during the period of extended operation. The

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staff determined the applicants proposed inspection techniques to detect loss of material due to

selective leaching are consistent with the inspection techniques recommended in GALL AMP

XI.M33 and the applicant will initiate corrective actions based on the evaluation of the results of

these inspections. On the basis that the applicant will be performing a combination of a visual

inspection and hardness test, which is consistent with the recommendations in GALL AMP

XI.M33, for these components, the staff finds the AMR results for this line item acceptable.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.12 Aging Management Review Results - ESSW Pumphouse HVAC System -

LRA Table 3.3.2-12

The staff reviewed LRA Table 3.3.2-12, which summarizes the results of AMR evaluations for

the ESSW Pumphouse HVAC system component groups. The staff determined that all AMR

evaluation results in LRA Table 3.3.2-12 are consistent with the GALL Report.

3.3.2.3.13 Aging Management Review Results - Fire Protection System - LRA Table 3.3.2-13

The staff reviewed LRA Table 3.3.2-13, which summarizes the results of AMR evaluations for

the fire protection system component groups.

In LRA Table 3.3.2-13, the applicant proposed to manage loss of material due to selective

leaching for cast iron, gray cast iron and copper alloy material for heat exchanger components,

piping, piping components and elements, strainers and sprinkler heads exposed to an external

environment of indoor air using the AMP B.2.29 "Selective Leaching Inspection."

The AMR line items credit the AMP B.2.29 "Selective Leaching Inspection" to manage loss of

material due to selective leaching for these components. The AMR line item cites Generic Note

H, which indicates that the aging effect is not addressed in the Gall Report for this component,

material and environment combination. The staff's evaluation of the AMP B.2.29 is

documented in SER Section 3.0.3.2.17. The staff noted that this program is a one-time

inspection that will perform a combination of visual inspection and hardness testing to

determine if loss of material due to selective leaching has occurred. The staff further noted that

the applicant will perform the inspections of the components within the scope of this program

within 10 years prior to entering the period of extended operation such that the condition of the

material is more representative of the conditions during the period of extended operation. The

staff determined the applicants proposed inspection techniques to detect loss of material due to

selective leaching are consistent with the inspection techniques recommended in GALL AMP

XI.M33 and the applicant will initiate corrective actions based on the evaluation of the results of

these inspections. On the basis that the applicant will be performing a combination of a visual

inspection and hardness test, which is consistent with the recommendations in GALL AMP

XI.M33, for these components, the staff finds the AMR results for this line item acceptable.

In LRA Table 3.3.2-13, the applicant proposed to manage loss of material due to selective

leaching for cast iron pump casings exposed to an internal environment of fuel oil using the

AMP B.2.29 "Selective Leaching Inspection."

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The AMR line items credit the AMP B.2.29 "Selective Leaching Inspection" to manage loss of

material due to selective leaching for these components. The AMR line item cites Generic Note

H, which indicates that the aging effect is not addressed in the Gall Report for this component,

material and environment combination. The staffs evaluation of the AMP B.2.29 is

documented in SER Section 3.0.3.2.17. The staff noted that this program is a one-time

inspection that will perform a combination of visual inspection and hardness testing to

determine if loss of material due to selective leaching has occurred. The staff further noted that

the applicant will perform the inspections of the components within the scope of this program

within 10 years prior to entering the period of extended operation such that the condition of the

material is more representative of the conditions during the period of extended operation. The

staff determined the applicants proposed inspection techniques to detect loss of material due to

selective leaching are consistent with the inspection techniques recommended in GALL AMP

XI.M33 and the applicant will initiate corrective actions based on the evaluation of the results of

these inspections. On the basis that the applicant will be performing a combination of a visual

inspection and hardness test, which is consistent with the recommendations in GALL AMP

XI.M33, for these components, the staff finds the AMR results for this line item acceptable.

In LRA Table 3.3.2-13, the applicant proposed to manage loss of material due to selective

leaching for cast iron pump casings and copper alloy tubing exposed to an internal environment

of lubricating oil using the AMP B.2.29 "Selective Leaching Inspection."

The AMR line items credit the AMP B.2.29 "Selective Leaching Inspection" to manage loss of

material due to selective leaching for these components. The AMR line item cites Generic Note

H, which indicates that the aging effect is not addressed in the Gall Report for this component,

material and environment combination. The staffs evaluation of the AMP B.2.29 is

documented in SER Section 3.0.3.2.17. The staff noted that this program is a one-time

inspection that will perform a combination of visual inspection and hardness testing to

determine if loss of material due to selective leaching has occurred. The staff further noted that

the applicant will perform the inspections of the components within the scope of this program

within 10 years prior to entering the period of extended operation such that the condition of the

material is more representative of the conditions during the period of extended operation. The

staff determined the applicants proposed inspection techniques to detect loss of material due to

selective leaching are consistent with the inspection techniques recommended in GALL AMP

XI.M33 and the applicant will initiate corrective actions based on the evaluation of the results of

these inspections. On the basis that the applicant will be performing a combination of a visual

inspection and hardness test, which is consistent with the recommendations in GALL AMP

XI.M33, for these components, the staff finds the AMR results for this line item acceptable.

In LRA Table 3.3.2-13, the LRA states that for copper alloy sprinkler heads in indoor air,

outdoor air and ventilation environments there are no aging effects. The applicant has

referenced footnotes "G" and "0322." Footnote "0322" states that the Fire Water System

Program is credited with aging management for all sprinkler heads, regardless of whether aging

effects requiring management have been identified.

The staff has determined that copper alloy in an indoor, uncontrolled air environment exhibits

no aging effect and that the component or structure will therefore remain capable of performing

its intended functions consistent with the CLB for the period of extended operation. This

conclusion is based on the fact that comprehensive tests conducted over a 20-year period

under the supervision of ASTM have confirmed the suitability of copper and copper alloy for

atmospheric exposure as cited in Metals Handbook, Volume 13, Corrosion, American Society

for Metals, 1987. Based on this review, the staff finds that because the copper alloy sprinkler

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heads are exposed to an internal environment that is open to local ambient air conditions such

that condensation will not occur, loss of material due to pitting and crevice corrosion is not an

aging effect requiring management.

However, the applicant has committed (Commitment No. 46) to enhance the Fire Water System

Program prior to entering the period of extended operation to require testing or replacement of

sprinkler heads in service for 50 years. On the basis that sprinkler heads are normally open to

the atmosphere and that the applicant is committing to testing or replacement of sprinkler

heads in service for 50 years, the staff finds these AMR line items to be acceptable.

In Table 3.3.2-13, the LRA states that for synthetic rubber flexible connections in internal

environments of fuel oil, raw water and lubricating oil, and for teflon flexible connections in

internal raw water environment, there are no aging effects identified and no aging management

program is required. The staff issued RAI 3.3.2.3.13-1 by letter dated July 23, 2008, to request

the applicant to provide a justification why no aging effects are identified.

In its letter dated August 22, 2008, the applicant responded to RAI 3.3.2.3-13 by stating that

change in material properties and cracking of elastomers, such as synthetic rubber may be due

to ionizing radiation, thermal exposure, or exposure to ultraviolet radiation, or ozone. The

applicant also stated that for polymers, such as Teflon, change in material properties may result

from exposure to gamma radiation, but cracking is not a potential aging effect, and change in

material properties is not influenced by thermal exposure or exposure to ultraviolet radiation or

ozone.

The applicant stated that:

1) The lubricating oil, fuel oil, and raw water environments of the fire protection

system contain no sources of ionizing radiation. Therefore, change in

material properties and cracking due to ionizing radiation are not aging

effects requiring management for synthetic rubber or Teflon components that

are exposed to lubricating oil, fuel oil, or raw water.

2) Thermal exposure is an applicable aging mechanism for synthetic rubber

components only if they are exposed for prolonged periods to a temperature

greater than 950F. Since there are no significant sources of heat within the

diesel driven fire pump room, the applicant assumed that the ambient

temperature will not exceed 950F over a prolonged period. Additionally, the

fire protection system is in the standby mode during normal plant operation,

so there is normally no flow through the system, and the lubricating oil, fuel

oil, and raw water temperatures are approximately the same as the ambient

temperature. Therefore, change in material properties and cracking due to

thermal exposure are not aging effects requiring management for synthetic

rubber flexible connections that are exposed to lubricating oil, fuel oil, or raw

water.

3) Ultraviolet radiation and ozone are applicable aging mechanisms only for

natural rubber components that are exposed to sources of ultraviolet

radiation and ozone. Synthetic rubbers have demonstrated excellent

resistance to ultraviolet radiation and ozone. The lubricating oil, fuel oil, and

raw water environments contain no sources of ultraviolet radiation and

ozone. Therefore, change in material properties and cracking due to

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ultraviolet radiation and ozone are not aging effects requiring management

for synthetic rubber flexible connections that are exposed to lubricating oil,

fuel oil, or raw water.

Based on its review, the staff finds the applicant's response has satisfactorily identified

stressors and thresholds for which hardening and loss of strength are aging effects for

elastomer components and applied aging management for these cases. Where the stressors

and thresholds for which hardening and loss of strength are not exceeded, aging management

is not required. This is also confirmed by the GALL Report, Section IX.C, which defines

elastomer materials and states that hardening and loss of strength of elastomers can be

induced by elevated temperatures (over 950 F), and additional aging factors such as exposure to

ozone, oxidation, and radiation. Therefore, the staff finds the applicant response to be

acceptable.

In Table 3.3.2-13, the LRA states that for copper and copper alloy tubing and valve bodies in an

air-indoor external environment, there are no aging effects identified and no aging management

program is required. The applicant has referenced footnote "G", environment not in the GALL

Report for this component and material. However, the staff noted GALL Report Item V.F-3

identifies copper alloy in an air-indoor uncontrolled external environment with no aging effects

and no aging management program. On the basis that the GALL Report recommends no aging

effects for copper alloy piping components in an air-indoor external environment, the staff finds

these line items acceptable.

In its letter dated June 30, 2008, in response to RAI B.2.17-2, the applicant amended Table

3.3.2-13, Fire Protection System, to credit the Heat Exchanger Inspection Program to manage

the aging effect of reduction of heat transfer due to fouling for copper alloy oil cooler tubes in a

lubricating oil external environment. The applicant applied footnote "H." The staff noted that the

internal environment of these tubes is raw water and the internal surfaces are managed by the

Fire Water System Program for loss of material, which includes actions to ensure no significant

corrosion, MIC, or biofouling has occurred, and the Heat Exchanger Inspection Program for

reduction of heat transfer. The staff reviewed the Heat Exchanger Inspection Program, which

will be inspecting the inner and the external surface of the tubes to detect for fouling. The staff's

evaluation of the Heat Exchanger Inspection Program is documented in Section 3.0.3.1.12.

On the basis that the applicant is crediting the Fire Water Inspection Program to ensure no

significant fouling is occurring and crediting the Heat Exchanger inspection Program to obtain

direct evidence of fouling for the internal surfaces of the tubes, the staff finds that

implementation of the Heat Exchanger Inspection for the external surfaces of the tubes in a

lubricating oil environment will ensure that the heat transfer capabilities of the subject heat

exchangers, and the pressure boundary integrity of the subject tubes, are maintained

consistent with the current licensing basis during the period of extended operation.

In Table 3.3.2-13, the LRA states that for synthetic rubber flexible connections in fuel oil and

raw water internal environments in the fire protection system, there are no aging effects

requiring management. In RAI 3.3.2.3-1, Part A by letter dated July 23, 2008, the staff asked

the applicant to justify why it had not identified any aging effects requiring management for

these system-material-environment combinations.

In its letter dated August 27, 2008, in response to RAI 3.3.2.3-1 Part A, the applicant stated that

the applicable aging effects for elastomers (including butyl rubber, synthetic rubber, neoprene,

and silicone) are change in material properties and cracking, which may be due to ionizing

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radiation, thermal exposure, or exposure to ultraviolet radiation or ozone. The applicant

provided the threshold level for ionizing radiation as 10E6 rads, for temperature as greater than

95'F, and for ultraviolet radiation and ozone as prolonged exposure. The applicant further

stated that, except for certain areas in the Reactor Building, where ionizing radiation could be

more than the threshold limit, the other buildings are all in an environment that is within the

threshold limits. Therefore, the applicant concluded that there are no aging effects requiring

management for synthetic rubber flexible connections in fuel oil and raw water internal

environments in the fire protection system.

The staff reviewed the applicant response to RAI 3.3.2.3-1, Part A, and finds the applicant

response acceptable because the applicant defined the stressors that could cause the aging

effects in various structures. The applicant response is consistent with the GALL Report

definitions of the threshold limits of the stressors as recommended in the GALL Report Section

IX. On the basis of its review, the staff finds for synthetic rubber flexible connections in a fuel oil

internal environment in the diesel fuel oil system, there are no aging effects requiring

management.

In Table 3.3.2-13, the LRA states that for Teflon flexible connections in raw water internal and

indoor air external environments in the fire protection system, there are no aging effects

requiring management. In RAI 3.3.2.3-1, Part A by letter dated July 23, 2008, the staff asked

the applicant to justify why it had not identified any aging effects requiring management for

these system-material-environment combinations.

In its letter dated August 27, 2008, in response to RAI 3.3.2.3-1, Part A, the applicant stated

that:

The only applicable aging effect for Teflon is change in material properties.

Change in material properties of Teflon may be due to exposure to gamma

radiation. Thermal exposure and exposure to ultraviolet radiation or ozone are

not applicable aging mechanisms for Teflon.

Gamma radiation is an applicable aging mechanism for Teflon components only

if the total integrated dose (TID) is equal to or greater than 10E4 rads. The

Teflon components in the Fire Protection System are located in the Circulating

Water Pumphouse, an area of the plant where ionizing radiation levels are such

that the TID over a 60-year period, which includes the period of extended

operation, will not equal or exceed 1 0E3 rads.

Also, there are no sources of gamma radiation expected to exist in the raw water

of the Fire Protection System or the treated water environment of the Sampling

System.

Therefore, change in material properties and cracking due to ionizing radiation

are not aging effects requiring management for these components.

The staff reviewed the applicant response and noted that these flexible connections are located

in an area where the ionizing radiation is less than the threshold value of 1 0E6 rads. On this

basis, the staff finds the applicant response acceptable and concludes that for Teflon flexible

connections in raw water internal and indoor air external environments in the fire protection

system, there are no aging effects requiring management.

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On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report.

In Table 3.3.2-13, the LRA states that for galvanized steel piping in an outdoor external

environment, there are no aging effects identified and no aging management program is

required. The applicant has referenced footnote "G", environment not in the GALL Report for

this component and material.

The staff finds that as discussed in M. G. Fontana, "Corrosion Engineering, Third Edition,

McGraw-Hill, 1986, this is acceptable for galvanized steel in an outdoor environment because

the corrosion protection of the zinc coating is enhanced by the build-up of corrosion products

deposited out of solution. The staff finds galvanized steel in an outdoor environment has no

aging effects that require aging management because galvanized steel in an outdoor

environment has no applicable aging effect as discussed in M. G. Fontana, "Corrosion

Engineering, Third Edition, McGraw-Hill, 1986.

In Table 3.3.2-13, the LRA states that for copper alloy halon spray nozzles in an environment of

ventilation, there are no aging effects identified and no aging management program is required.

The applicant has referenced footnote "G", environment not in the GALL Report for this

component and material.

The staff noted that these spray nozzles are in the halon system, which is normally a dry air

environment. The staff also noted that these spray nozzles are open to atmosphere. In LRA

Table 3.0-1, Internal Environments, the applicant stated that internal ambient environment

inside components that are open to the ambient conditions in their location are also included

under ventilation environment. Since the spray nozzles are open to atmosphere and would

normally be exposed to internal air environment, the staff finds that this material/environment is

similar to GALL Report Item VII.1-2, for copper alloy components in an air-indoor uncontrolled

environment, with no aging effects and no aging management program required. Based on this

review, the staff finds that for copper alloy halon spray nozzles in an environment of ventilation,

there are no aging effects identified and no aging management program is required.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.14 Aging Management Review Results - Fuel Pool Cooling and Cleanup System and

Fuel Pool and Auxiliaries - LRA Table 3.3.2-14

The staff reviewed LRA Table 3.3.2-14, which summarizes the results of AMR evaluations for

the fuel pool cooling and cleanup system and fuel pool and auxiliaries component groups.

The staff reviewed LRA Table 3.3.2-14 which summarizes the results of AMRs for fuel pool

cooling screens for skimmer surge tanks which are constructed from stainless steel. The

applicant proposed that this system meets the definitions given above and therefore the

environment, aging effect requiring management, and AMR should be classified as not

applicable. The staff agrees with this proposal because these components do not have an

internal surface.

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On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended, operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.15 Aging Management Review Results - Neutron Monitoring System -

LRA Table 3.3.2-15

The staff reviewed LRA Table 3.3.2-15, which summarizes the results of AMR evaluations for

the neutron monitoring system component groups. The staff determined that all AMR evaluation

results in LRA Table 3.3.2-15 are consistent with the GALL Report.

3.3.2.3.16 Aging Management Review Results - Primary Containment Atmosphere Circulation

System - LRA Table 3.3.2-16

The staff reviewed LRA Table 3.3.2-16, which summarizes the results of AMR evaluations for

the primary containment atmosphere circulation system component groups. The staff

determined that all AMR evaluation results in LRA Table 3.3.2-16 are consistent with the GALL

Report.

3.3.2.3.17 Aging Management Review Results - Process and Area Radiation Monitoring

System - LRA Table 3.3.2-17

The staff reviewed LRA Table 3.3.2-17, which summarizes the results of AMR evaluations for

the process and area radiation monitoring system component groups.

In LRA Table 3.3.2-17, the applicant proposed to manage cracking of copper alloy for piping

and piping components in the Process and Area Radiation Monitoring System exposed to an

internal environment of treated water using the AMP B.2.14 "Closed Cooling Water Chemistry

Program."

The AMR line item credits the Closed Cooling Water Program to manage cracking for these

components. The AMR line item cites Generic Note H, which indicates that the aging effect is

not addressed in the GALL Report for this component, material and environment combination.

The Closed Cooling Water Chemistry Program is an existing SSES program that properly

monitors components and controls corrosion inhibitor concentrations for components, within the

scope of license renewal, consistent with relevant EPRI water chemistry guidelines.

The applicant responded to RAI B.2.14-2, in a letter dated August 12, 2008. The applicant

clarified that the one-time inspection performed as part of the AMP B.2.22, "Chemistry Program

Effectiveness Inspection" will be used to supplement AMP B.2.14, "Closed Cooling Water

Chemistry Program" in all instances where AMP B.2.14 is credited for aging management in

LRA Table-2 items, with the exception of the Diesel Jacket Water Cooling System. The staff

reviewed the applicant's AMP B.2.14 "Closed Cooling Water Chemistry Program" and AMP

B.2.22 "Chemistry Program Effectiveness Inspection" and its evaluations are documented in

SER Section 3.0.3.2.7 and 3.0.3.1.10, respectively. The staff verified that this aging

management program includes activities that are consistent with the recommendations in the

GALL AMP XI.M21 to maintain high water purity, which is effective for managing cracking for

copper and copper alloy components exposed to a treated water environment. The staff further

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noted the Closed Cooling Water Chemistry Program is an existing program that properly

monitors components and controls corrosion inhibitor concentrations for components, within the

scope of license renewal, consistent with relevant EPRI water chemistry guidelines. The staff

confirmed that the CPEI will be used to verify the effectiveness of the applicant's Closed

Cooling Water Chemistry Program to manage cracking and that a combination of appropriate

volumetric and visual examination techniques (such as VT-1 or VT-3) will be performed by

qualified personnel on a sample population of most susceptible subject components. On this

basis, the staff finds that these AMR results will be adequately managed by these programs.

LRA Table 3.3.2-17 summarizes the results of AMRs for process and area radiation monitoring

system piping and piping components constructed using copper alloy exposed to indoor air

(external). The applicant proposed that there is no aging effect for the material environment

combination and that no AMR is required.

The applicant has indicated that generic Note G is applicable for these items. Generic Note G is

"Environment not in NUREG-1801 for this component and material." The staff confirmed that

this environment is not in GALL for the component and material. The staff also agrees that

there will not be an aging mechanism for this material/environment combination, and that no

AMP is required.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.18 Aging Management Review Results - Radwaste Liquid System - LRA

Table 3.3.2-18

The staff reviewed LRA Table 3.3.2-18, which summarizes the results of AMR evaluations for

the radwaste liquid system component groups.

In LRA Table 3.3.2-18, the applicant proposed to manage loss of material due to selective

leaching for cast iron for piping and piping components exposed to an internal environment of

raw water using the AMP B.2.29 "Selective Leaching Inspection."

The AMR line items credit the AMP B.2.29 "Selective Leaching Inspection" to manage loss of

material due to selective leaching for these components. The AMR line item cites Generic Note

G, which indicates that the environment is not addressed in GALL Report for this component

and material combination. The staff's evaluation of the AMP B.2.29 is documented in SER

Section 3.0.3.2.17. The staff noted that this program is a one-time inspection that will perform

a combination of visual inspection and hardness testing to determine if loss of material due to

selective leaching has occurred. The staff further noted that the applicant will perform the

inspections of the components within the scope of this program within 10 years prior to entering

the period of extended operation such that the condition of the material is more representative

of the conditions during the period of extended operation. The staff determined the applicants

proposed inspection techniques to detect loss of material due to selective leaching are

consistent with the inspection techniques recommended in GALL AMP XI.M33 and the

applicant will initiate corrective actions based on the evaluation of the results of these

inspections. The staff noted that the GALL Report recommends the use of the Selective

Leaching Program for the same combination of material/environment/aging effect in items

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VII.C1-1 1 for a different system. On the basis that the applicant will be performing a

combination of a visual inspection and hardness test for these components and these AMR

material/environment/aging effect combination is consistent with the GALL AMR Item VII.C1-1 1

for cast iron, the staff finds the AMR results for this line item acceptable.

In LRA Table 3.3.2-18, the applicant proposed to manage loss of material in piping and piping

components, and cleanouts and pump casings in an internal environment of raw water by using

the Monitoring and Collection System Inspection Program. The applicant referenced footnote G

for this line item indicating that environment is not in the GALL Report for this component and

material combination. The applicant also referenced footnote 0356, which indicates that

uncontrolled drainage in the radwaste liquids system is considered to be a raw water

environment.

The staff noted that these components are in scope for a structural integrity function only to

ensure that its failure does not impact other safety-related system and components. The staff

reviewed the Monitoring and Collection System Inspection Program, which uses a combination

of volumetric and visual examination techniques to identify evidence of loss of material or lack

thereof. The staffs evaluation of the Monitoring and Collection System Inspection Program is

documented in SER Section 3.0.3.1.15. Because the Monitoring and Collection System

Inspection is performed at susceptible locations, and employs a combination of volumetric and

visual inspection techniques, the staff finds that the Monitoring and Collection System

Inspection Program will adequately manage the aging effects of loss of material in this

aggressive environment.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.19 Aging Management Review Results - Radwaste Solids Handling System -

LRA Table 3.3.2-19

The staff reviewed LRA Table 3.3.2-19, which summarizes the results of AMR evaluations for

the radwaste solids handling system component groups.

In LRA Table 3.3.2-19, the applicant proposed to manage loss of material due for carbon steel,

stainless steel and copper alloy material for piping and piping components and tanks exposed

to an internal environment of raw water using the AMP B.2.46 "Area-Based NSAS Inspection."

The AMR line items credit the AMP B.2.46 "Area-Based NSAS Inspection" to manage loss of

material for these components. The AMR line item cites Generic Note G, which indicates that

the environment is not addressed in GALL Report for this component and material combination.

The staff's evaluation of the AMP B.2.46 is documented in SER Section 3.0.3.3.1. The staff

noted that this program is a plant-specific program that performs an appropriate combination of

established volumetric and visual inspection techniques (nondestructive examination

techniques) that will be performed by qualified personnel on a sample population of those

components in scope of this program. The staff further noted that the applicant will perform the

inspections of the components within the scope of this program within 10 years prior to entering

the period of extended operation. The staff determined the inspection techniques will be

capable of detecting loss of material and the applicant will initiate corrective actions if an

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unacceptable loss of material or wall thinning has occurred that may have a spatial interaction

with safety-related components, as determined by engineering evaluation. On the basis that

the applicant will be performing an appropriate combination of a visual inspection and

volumetric testing for these components, the staff finds the AMR results for this line item

acceptable.

In LRA Table 3.3.2-19, the applicant proposed to manage loss of material due to selective

leaching for copper alloy material for piping and piping components exposed to an internal

environment of raw water using the AMP 8.2.46 "Area-Based NSAS Inspection."

The AMR line items credit the AMP B.2.46 "Area-Based NSAS Inspection" to manage loss of

material for these components. The AMR line item cites Generic Note G, which indicates that

the environment is not addressed in GALL Report for this component and material combination.

The staff's evaluation of the AMP B.2.46 is documented in SER Section 3.0.3.3.1. The staff

noted that this program is a plant-specific program that performs an appropriate combination of

established volumetric and visual inspection techniques (nondestructive examination

techniques) that will be performed by qualified personnel on a sample population of those

components in scope of this program. The staff further noted that the applicant will perform the

inspections of the components within the scope of this program within 10 years prior to entering

the period of extended operation. The staff determined the inspection techniques will be

capable of detecting cracking and the applicant will initiate corrective actions if an unacceptable

loss of material or wall thinning has occurred that may have a spatial interaction (e.g., leakage)

with safety-related components, as determined by engineering evaluation. On the basis that

the applicant will be performing an appropriate combination of a visual inspection and

volumetric testing for these components, the staff finds the AMR results for this line item

acceptable.

In LRA Table 3.3.2-19, the applicant proposed to manage loss of material due to selective

leaching for copper alloy for piping and piping components exposed to an internal environment

of raw water using the AMP B.2.29 "Selective Leaching Inspection."

The AMR line items credit the AMP B.2.29 "Selective Leaching Inspection" to manage loss of

material due to selective leaching for these components. The AMR line item cites Generic Note

G, which indicates that the environment is not addressed in GALL Report for this component

and material combination. The staff's evaluation of the AMP B.2.29 is documented in SER

Section 3.0.3.2.17. The staff noted that this program is a one-time inspection that will perform

a combination of visual inspection and hardness testing to determine if loss of material due to

selective leaching has occurred. The staff further noted that the applicant will perform the

inspections of the components within the scope of this program within 10 years prior to entering

the period of extended operation such that the condition of the material is more representative

of the conditions during the period of extended operation. The staff determined the applicants

proposed inspection techniques to detect loss of material due to selective leaching are

consistent with the inspection techniques recommended in GALL AMP XI.M33 and the

applicant will initiate corrective actions based on the evaluation of the results of these

inspections. The staff noted that the GALL Report recommends the use of the Selective

Leaching Program for the same combination of material/environment/aging effect in items

VII.C1-10 for a different system. On the basis that the applicant will be performing a

combination of a visual inspection and hardness test for these components and these AMR

material/environment/aging effect combination is consistent with the GALL AMR Item VII.C1 -10

for copper alloy, the staff finds the AMR results for this line item acceptable.

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LRA Table 3.3.2-19 summarizes the results of AMRs for the Radwaste Solids Handling System

piping and piping components constructed from copper alloy and exposed to indoor air

(external) and the applicant proposed that this material-environment combination has no aging

effects requiring management and no AMR is required.

The applicant has indicated that generic Note G is applicable for these items. Generic Note G is

"Environment not in NUREG-1801 for this component and material." The staff confirmed that

this environment is not in the GALL Report for this component and material. The staff also

agrees that there will not be an aging mechanism for this material/environment combination and

that no AMP is required. Copper alloys in an air-indoor internal environment have no aging

effect. This conclusion is based on the fact that comprehensive tests conducted over a 20-year

period under ASTM supervision have confirmed the suitability of copper and copper alloys for

atmospheric exposure (which is more severe than indoor air) as cited in Metals Handbook,

Volume 13, "Corrosion" (American Society for Metals International, 1987).

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.20 Aging Management Review Results - Raw Water Treatment System -

LRA Table 3.3.2-20

The staff reviewed LRA Table 3.3.2-20, which summarizes the results of AMR evaluations for

the raw water treatment system component groups.

In LRA Table 3.3.2-20, the applicant proposed to manage loss of material due to selective

leaching for cast iron and copper alloy material for valve bodies exposed to an external

environment of outdoor air using the AMP B.2.29 "Selective Leaching Inspection."

The AMR line items credit the AMP B.2.29 "Selective Leaching Inspection" to manage loss of

material due to selective leaching for these components. The AMR line item cites Generic Note

H, which indicates that the aging effect is not addressed in the Gall Report for this component,

material and environment combination. The staff's evaluation of the AMP B.2.29 is

documented in SER Section 3.0.3.2.17. The staff noted that this program is a one-time

inspection that will perform a combination of visual inspection and hardness testing to

determine if loss of material due to selective leaching has occurred. The staff further noted that

the applicant will perform the inspections of the components within the scope of this program

within 10 years prior to entering the period of extended operation such that the condition of the

material is more representative of the conditions during the period of extended operation. The

staff determined the applicants proposed inspection techniques to detect loss of material due to

selective leaching are consistent with the inspection techniques recommended in GALL AMP

XI.M33 and the applicant will initiate corrective actions based on the evaluation of the results of

these inspections. On the basis that the applicant will be performing a combination of a visual

inspection and hardness test, which is consistent with the recommendations in GALL AMP

XI.M33, for these components, the staff finds the AMR results for this line item acceptable.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

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adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.21 Aging Management Review Results - Reactor Building Chilled Water System -

LRA Table 3.3.2-21

The staff reviewed LRA Table 3.3.2-21, which summarizes the results of AMR evaluations for

the reactor building chilled water system component groups.

In LRA Table 3.3.2-21, the applicant proposed to manage cracking of copper alloy for piping

and piping components in the Reactor Building Chilled Water System exposed to an internal

environment of treated water using the AMP B.2.14 "Closed Cooling Water Chemistry

Program."

The AMR line item credits the Closed Cooling Water Program to manage cracking for these

components. The AMR line item cites Generic Note H, which indicates that the aging effect is

not addressed in the GALL Report for this component, material and environment combination.

The Closed Cooling Water Chemistry Program is an existing SSES program that properly

monitors components and controls corrosion inhibitor concentrations for components, within the

scope of license renewal, consistent with relevant EPRI water chemistry guidelines.

The applicant responded to RAI B.2.14-2, in a letter dated August 12, 2008. The applicant

clarified that the one-time inspection performed as part of the AMP B.2.22, "Chemistry Program

Effectiveness Inspection" will be used to supplement AMP B.2.14, "Closed Cooling Water

Chemistry Program" in all instances where AMP B.2.14 is credited for aging management in

LRA Table-2 items, with the exception of the Diesel Jacket Water Cooling System. The staff

reviewed the applicant's AMP B.2.14 "Closed Cooling Water Chemistry Program" and AMP

B.2.22 "Chemistry Program Effectiveness Inspection" and its evaluations are documented in

SER Section 3.0.3.2.7 and 3.0.3.1.10, respectively. The staff verified that this aging

management program includes activities that are consistent with the recommendations in the

GALL AMP XI.M21 to maintain high water purity, which is effective for managing cracking for

copper and copper alloy components exposed to a treated water environment. The staff further

noted the Closed Cooling Water Chemistry Program is an existing SSES program that properly

monitors components and controls corrosion inhibitor concentrations for components, within the

scope of license renewal, consistent with relevant EPRI water chemistry guidelines. The staff

confirmed that the CPEI will be used to verify the effectiveness of the applicant's Closed

Cooling Water Chemistry Program to manage cracking and that a combination of appropriate

volumetric and visual examination techniques (such as VT-1 or VT-3) will be performed by

qualified personnel on a sample population of most susceptible subject components. On this

basis, the staff finds that these AMR results will be adequately managed by these programs.

In LRA Table 3.3.2-21, the applicant proposed to manage loss of material due to selective

leaching for copper alloy material for piping and piping components exposed to an internal

environment of raw water using the AMP B.2.46 "Area-Based NSAS Inspection."

The AMR line items credit the AMP B.2.46 "Area-Based NSAS Inspection" to manage loss of

material for these components. The AMR line item cites Generic Note H, which indicates that

the aging effect is not addressed in the Gall Report for this component, material and

environment combination. The staff's evaluation of the AMP B.2.46 is documented in SER

Section 3.0.3.3.1. The staff noted that this program is a plant-specific program that performs

an appropriate combination of established volumetric and visual inspection techniques

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(nondestructive examination techniques) that will be performed by a qualified personnel on a

sample population of those components in scope of this program. The staff further noted that

the applicant will perform the inspections of the components within the scope of this program

within 10 years prior to entering the period of extended operation. The staff determined the

inspection techniques will be capable of detecting cracking and the applicant will initiate

corrective actions if an unacceptable loss of material or wall thinning has occurred that may

have a spatial interaction with safety-related components, as determined by engineering

evaluation. On the basis that the applicant will be performing an appropriate combination of a

visual inspection and volumetric testing for these components, the staff finds the AMR results

for this line item acceptable.

In LRA Table 3.3.2-21, the applicant proposed to manage loss of material due to selective

leaching for cast iron and copper alloy material for chillers, piping and piping components and

elements exposed to an external environment of indoor air using the AMP B.2.29 "Selective

Leaching Inspection."

The AMR line items credit the AMP B.2.29 "Selective Leaching Inspection" to manage loss of

material due to selective leaching for these components. The AMR line item cites Generic Note

H, which indicates that the aging effect is not addressed in the Gall Report for this component,

material and environment combination. The staff's evaluation of the AMP B.2.29 is

documented in SER Section 3.0.3.2.17. The staff noted that this program is a one-time

inspection that will perform a combination of visual inspection and hardness testing to

determine if loss of material due to selective leaching has occurred. The staff further-noted that

the applicant will perform the inspections of the components within the scope of this program

within 10 years prior to entering the period of extended operation such that the condition of the

material is more representative of the conditions during the period of extended operation. The

staff determined the applicants proposed inspection techniques to detect loss of material due to

selective leaching are consistent with the inspection techniques recommended in GALL AMP

XI.M33 and the applicant will initiate corrective actions based on the evaluation of the results of

these inspections. On the basis that the applicant will be performing a combination of a visual

inspection and hardness test, which is consistent with the recommendations in GALL AMP

XI.M33, for these components the staff finds the AMR results for this line item acceptable.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.22 Aging Management Review Results - Reactor Building Closed Cooling Water

System - LRA Table 3.3.2-22

The staff reviewed LRA Table 3.3.2-22, which summarizes the results of AMR evaluations for

the reactor building closed cooling water system component groups.

In LRA Table 3.3.2-22, the applicant proposed to manage cracking of copper alloy for piping

and piping components in the Reactor Building Closed Cooling Water System exposed to an

internal environment of treated water using the AMP B.2.14 "Closed Cooling Water Chemistry

Program."

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The AMR line item credits the Closed Cooling Water Program to manage cracking for these

components. The AMR line item cites Generic Note H, which indicates that the aging effect is

not addressed in the GALL Report for this component, material and environment combination.

The staff noted that on LRA page 3.3-289 in LRA Table 3.3.2-22, the applicant referenced a

NUREG-1801 Volume 2 item and then cited a Note H, which indicates that this aging effect is

not in NUREG-1801 for this component, material and environment combination. It was unclear

to the staff why the applicant referenced a GALL line item and cited a Note H, therefore by

letter dated July 23, 2008, the staff issued RAI 3.3.2-4, requesting the applicant to clarify the

applicability of this GALL item to the LRA Table 2 item. By letter dated August 22, 2008, the

applicant responded to RAI 3.3.2-4, in which the applicant stated this was an error in the LRA

and that based upon their review, this was the only instance in which copper alloy subject to

cracking in a treated water environment referenced a GALL item. The staff confirmed the

applicant amended the LRA to remove the reference to the GALL line item and replaced it with

"N/A." On the basis of its review, the staff finds the applicant's response acceptable because

the LRA was amended and the error was corrected.

During its review, it was unclear to the staff whether SSES would be supplementing the Closed

Cooling Water Chemistry Program with a one-time inspection, either the Chemistry

Effectiveness Program or Heat Exchanger Inspection Program. Therefore by letter dated

August 12, 2008, the staff issued RAI B.2.14-2 requesting the applicant to clarify whether an

appropriate one-time inspection will supplement the Closed Cooling Water Chemistry Program

whenever credited and to identify which one-time inspection would be used.

The applicant responded to RAI B.2.14-2, in a letter dated August 12, 2008. The applicant

clarified that the one-time inspection performed as part of the AMP B.2.22, "Chemistry Program

Effectiveness Inspection" will be used to supplement B.2.14, "Closed Cooling Water Chemistry

Program" in all instances where AMP B.2.14 is credited for aging management in LRA Table-2

items, with the exception of the Diesel Jacket Water Cooling System. The staff reviewed the

applicant's AMP B.2.14 "Closed Cooling Water Chemistry Program" and AMP B.2.22

"Chemistry Program Effectiveness Inspection" and its evaluations are documented in SER

Section 3.0.3.2.7 and 3.0.3.1.10, respectively. The staff verified that this aging management

program includes activities that are consistent with the recommendations in the GALL AMP

XI.M21 to maintain high water purity, which is effective for managing cracking for copper and

copper alloy components exposed to a treated water environment. The staff further noted the

Closed Cooling Water Chemistry Program is an existing SSES program that properly monitors

components and controls corrosion inhibitor concentrations for components, within the scope of

license renewal, consistent with relevant EPRI water chemistry guidelines. The staff confirmed

that the CPEI will be used to verify the effectiveness of the applicant's Closed Cooling Water

Chemistry Program to manage cracking and that a combination of appropriate volumetric and

visual examination techniques (such as VT-1 or

VT-3) will be performed by qualified personnel on a sample population of most susceptible

subject components. On this basis, the staff finds that these AMR results will be adequately

managed by these programs.

LRA Table 3.3.2-22 summarizes the results of AMRs for reactor building closed cooling water,

system piping and piping components constructed using copper alloy exposed to indoor air

(external). The applicant proposed that there is no aging effect for the material environment

combination and that no AMR is required.

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The applicant has indicated that generic Note G is applicable for these items. Generic Note G is

"Environment not in NUREG-1 801 for this component and material." The staff confirmed that

this environment is not in GALL for the component and material. The staff also agrees that

there will not be an aging mechanism for this material/environment combination, and that no

AMP is required.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.23 Aging Management Review Results - Reactor Building HVAC System -

LRA Table 3.3.2-23

The staff reviewed LRA Table 3.3.2-23, which summarizes the results of AMR evaluations for

the reactor building HVAC system component groups.

In Table 3.3.2-23, the LRA states that for glass sight gauges in the reactor building HVAC

system exposed to Freon environment, there are no aging effects identified and no aging

management program is required. The staff was concerned, however, that the Freon

environment for the glass sight gauges in the reactor building HVAC system might create

sufficiently cold environments for the glass material that could, at a minimum impact the

fracture toughness of the material. Hence, the staff was concerned that the Freon environment

might impact the tolerance of the glass material to withstand an existing crack in the glass

material used to fabricate the components (i.e., reduce the flaw tolerance of the material). In

RAI 3.3.2.3-2 by letter dated July 23, 2008, the staff asked the applicant to justify why reduction

of fracture toughness and cracking would not be applicable aging effects requiring

management for the surfaces of glass sight gauges in the reactor building HVAC system under

internal exposure to an air - gas (Freon) environment.

In its letter dated August 27, 2008, in response to RAI 3.3.2.3-2, the applicant stated:

The only relevant conditions that could result in aging degradation (such as

cracking) of glass, as identified by industry operating experience, and by

research conducted by the Electric Power Research Institute, are exposure to

high-temperature water, and/or exposure to hydrofluoric acid or caustic alkalis.

High-temperature water, hydrofluoric acid, and caustic alkalis are not expected to

exist in the air-gas (Freon) environment of the Reactor Building HVAC System.

Exposure to low temperature has not been identified as a relevant condition that

could result in aging degradation of glass. Also, reduction in fracture toughness

has not been identified as an applicable aging effect for glass, which is by

definition a brittle material when subject to impact.

Additionally, the coldest part of the refrigeration cycle, expansion, is typically in

the range of approximately 30'F to 40'F, which is not exceptionally cold. The

subject glass sight gauges, however, are located between the components of

compression and expansion cycles, where the temperature is typically in the

range of approximately 950 F to 11 0°F.

3-409
The staff reviewed the applicant response and noted that the coldest temperature the glass

material would experience during normal operation is between 30°F to 400F, which are not very

cold temperatures and at those temperatures the glass material will be resistant to cracking.

Based on the operating conditions, and also the location of the sight glasses between

components of compression and expansion cycles, the staff finds that the glass material in a

Freon environment will not experience any aging effects requiring management.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report.

LRA Table 3.3.2-23 summarizes the AMR results for the emergency switchgear (SWGR) and

load center rooms cooling coils constructed from copper exposed to ventilation (internal) and

the applicant proposed that this material-environment combination has no aging effects

requiring management and no AMR is required.

The applicant has indicated that generic Note I is applicable for these items. Generic Note I is

"Aging effect in NUREG-1 801 for this component, material, and environment is not applicable."

The staff agrees that there will not be an aging mechanism for this material/environment

combination. This conclusion is based on the fact that comprehensive tests conducted over a

20-year period under ASTM supervision have confirmed the suitability of copper and copper

alloys for atmospheric exposure (which is more severe or ventilation) as cited in Metals

Handbook, Volume 13, "Corrosion" (American Society for Metals International, 1987).

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

LRA Table 3.3.2-23 summarizes the AMR results for reactor building HVAC system valve

bodies made from copper alloy (bronze and brass) and tubing made from copper and exposed

to indoor air (external), sight gauges made from glass exposed to air-gas (Freon) (internal),

piping and cooling units, emergency SWGR and load center room DX type cooling coils made

from copper and exposed to indoor air (external), and cooling units, emergency SWGR and

load center rooms cooling coils made from copper alloy (copper-nickel) exposed to ventilation

(external). The applicant proposed that this material-environment combination has no aging

effects requiring management and no AMR is required.

The applicant has indicated that generic Note G is applicable for these items. Generic Note G is

"Environment not in NUREG-1 801 for this component and material." The staff confirmed that

this environment is not in GALL for this component and material. The staff also agrees that

there will not be an aging mechanism for this material/environment combination and that no

AMP is required. Copper alloy in air-indoor internal environment has no aging effect. This

conclusion is based on the fact that comprehensive tests conducted over a 20-year period

under ASTM supervision have confirmed the suitability of copper and copper alloys for

atmospheric exposure (which is more severe than indoor air) as cited in Metals Handbook,

Volume 13, "Corrosion" (American Society for Metals International, 1987). This conclusion is

also based on the fact that there have been no aging effects observed for glass components in

this air environment. Ref: Handbook of Glass Properties, N. P. Bansal and R. H. Doremua,

Academic Press 1986, pg. 646.

3-410
The staff reviewed LRA Table 3.3.2-23 which summarizes the results of AMRs for the Reactor

Building HVAC System, unit coolers, CSP pump room RHR pump room, RCIC pump room, and

HPCI pump room tube plugs constructed from stainless steel, and unit coolers, CSP pump

room, RHR pump room, RCIC pump room, and HPCI pump room fins constructed from copper,

and condenser water cooled tube plugs constructed from copper alloy (copper-nickel). The

applicant proposed that this system meets the definitions given above and therefore the

environment, aging effect requiring management, and AMR should be classified as not

applicable. The staff agrees with this proposal because these components do not have an

internal surface because they are solid and therefore, there will not be an aging effect requiring

an AMP.

In LRA Table 3.3.2-23, the applicant proposed to manage reduction of heat transfer of copper

cooling unit fins in an external environment of ventilation by using the Cooling Units Inspection

Program. The applicant referenced Note H for this line item indicating that aging effect is not in

the GALL Report for this component, material and environment combination.

The staff noted the Cooling Unit Inspection Program will detect and charaterize the condition of

cooling unit components that are exposed to a ventilation environment, and provides direct

evidence as to whether, and to what extent, reduction of heat transfer has occurred, or is likely

to occur that could result in a loss of intended function. In its letter dated July 25, 2008, the

applicant responded to RAI B.2.23-2 stating that visual inspection (VT-3 or equivalent)

techniques will be used to determine whether reduction in heat transfer is occurring. The

applicant also stated that the specific inspection technique will be determined prior to the

inspection activities and will be consistent with the recommendations in GALL AMP XI.M32. The

staff's evaluation of the Cooling Units Inspection Program is documented in SER Section

3.0.3.1.11. Because the Cooling Units Inspection Program performs visual inspection to

determine if any fouling has occurred that could cause reduction of heat transfer, and on the

basis that the visual inspection technique will be consistent with the recommendation in GALL

AMP XI.M32, the staff finds the Cooling Units Inspection Program will adequately manage the

aging effect of reduction of heat transfer in cooling unit components exposed to a ventilation

environment.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.24 Aging Management Review Results - Reactor Nonnuclear Instrumentation System -

LRA Table 3.3.2-24

The staff reviewed LRA Table 3.3.2-24, which summarizes the results of AMR evaluations for

the reactor nonnuclear instrumentation system component groups. The staff determined that all

AMR evaluation results in LRA Table 3.3.2-24 are consistent with the GALL Report.

3.3.2.3.25 Aging Management Review Results - Reactor Water Cleanup System -

LRA Table 3.3.2-25

The staff reviewed LRA Table 3.3.2-25, which summarizes the results of AMR evaluations for

the reactor water cleanup system component groups.

3-411
In LRA Tables 3.2.2-25 the applicant proposed to manage cracking in copper alloy piping and

piping components in an environment of treated water by using the BWR Water Chemistry

Program, alone. The applicant cited generic Note H for these AMR results, indicating that the

aging effect is not in the GALL Report for this component, material and environment

combination. In a letter dated July 15, 2008, the staff issued RAI 3.2-3, applicable for these

AMR results and for similar AMR results in LRA Tables 3.2.2-1, 3.2.2-3, 3.3.2-3, and 3.4.2 3.

The RAI asked the applicant to provide a technical justification as to why an inspection

program, such as the CPEI is not needed to confirm that the BWR Water Chemistry Program is

effective in preventing the aging effect.

In a letter dated August 15, 2008, the applicant responded to RAI 3.3-3 by providing the

following response:

For the five AMR results lines listed in LRA Tables 3.2.2-1, 3.2.2-3, 3.3.2-3, 3.3.2-25, and 3.4.2-

3, where the material is copper alloy, the environment is treated water (internal), and the aging

effect is cracking, verification of the effectiveness of the BWR Water Chemistry Program is

needed. The CPEI will provide confirmation of the effectiveness of this program in managing

the effects of aging, including cracking in susceptible materials.

LRA Tables 3.2.2-1, 3.2.2-3, 3.3.2-3, 3.3.2-25, and 3.4.2-3 are revised to reflect these results.

The staff reviewed the applicant's response and the associated LRA changes. The staff

reviewed the applicant's BWR Water Chemistry Program. The staff's evaluation of this

program, which is documented in SER Section 3.0.3.1.1, found that the BWR Water Chemistry

Program provides mitigation for the aging effect of cracking due to stress corrosion cracking.

The staff reviewed the applicant's Chemistry Program Effectiveness Inspection. The staff's

evaluation of this program, which is documented in SER Section 3.0.3.1.10, found that the

CPEI is a one-time inspection that is consistent with the GALL Report's recommendations for

AMP XI.M32, "One-Time Inspection." The CPEI includes provisions for inspecting selected

components in areas of low or stagnant flow and uses examination techniques that are capable

of detecting cracking, if it should occur in the selected components. Because the BWR Water

Chemistry Program provides mitigation and the CPEI provides detection of the aging effect if it

should occur, the staff finds the applicant's proposed AMPs for managing the potential aging

effect of cracking due to stress corrosion cracking in copper alloy piping and piping components

exposed to treated water in the reactor water cleanup system to be acceptable. On this basis,

the staff finds that the issue in RAI 3.2 3 is resolved by the applicant's LRA changes.

In LRA Table 3.3.2-25, the applicant applied Note H for carbon steel piping and valve bodies

exposed to an internal environment of treated water in the reactor water cleanup system. The

applicant proposed to manage loss of material due to flow-accelerated corrosion by using the

Flow-Accelerated Corrosion Program. The definition of footnote "H" implies that these line items

are not consistent with GALL Report. However, the applicant has identified GALL Report Item

VII.E3-18, which is for loss of material due to general, pitting and crevice corrosion.

Furthermore, footnote "H" states that aging effect is not in the GALL Report for this component,

material and environment combination. Yet in the same table, the LRA has another line item for

the same component, material and environment combination with an aging effect of loss of

material due to flow-accelerated corrosion where the LRA has referenced footnote "A" and

correctly identified GALL Report Item VIII.D2-8.

3-412
Since the GALL Report addresses the aging effect of loss of material due to flow-accelerated

corrosion for this component, material and environment combination, the staff issued RAI

3.3.2.3.25-1 by letter dated July 9, 2008, requesting the applicant to justify why footnote "H"

was identified in these two line items and footnote "A" in other line item in the same system.

The staff also asked the applicant to justify why a GALL Report item number was referenced

with footnote "H."

In its letter dated August 8, 2008, the applicant responded to RAI 3.3.2.3.25-1 by stating that

there is no line item in GALL Chapter VII, Section E3, Reactor Water Cleanup System, for loss

of material due to flow-accelerated corrosion and therefore, comparison to Chapter VII should

not have been made. The applicant further stated that similar to other line items in Table

3.3.2-25 for which the FAC program was credited, comparison should have been made to

GALL Item VIII.D2-8. The applicant revised the subject line item to refer to GALL Item VIII.D2-8

and Table 3.4.1, item 3.4.1-29, which is applicable to FAC. The applicant changed footnote H to

footnote A and the line item is consistent with the GALL Report.

The staff reviewed the changes and compared them with GALL Item VIII.D2-8, and noted that

the material, environment, aging effect and recommended AMP are the same as in the GALL

Report. On this basis, the staff finds the applicant response acceptable.

LRA Table 3.3.2-25 summarizes the results of AMRs for reactor water cleanup system piping

and piping components constructed using copper alloy exposed to indoor air (external). The

applicant proposed that there is no aging effect for the material environment combination and

that no AMR is required.

The applicant has indicated that generic Note G is applicable for these items. Generic Note G is

"Environment not in NUREG-1 801 for this component and material." The staff confirmed that

this environment is not in GALL for the component and material. The staff also agrees that

there will not be an aging mechanism for this material/environment combination, and that no

AMP is required.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.26 Aging Management Review Results - RHR Service Water System -

LRA Table 3.3.2-26

The staff reviewed LRA Table 3.3.2-26, which summarizes the results of AMR evaluations for

the RHR service water system component groups.

In LRA Table 3.3.2-26, the applicant proposed to manage loss of material for stainless steel

material for piping and piping components exposed to an external environment of outdoor air

using the AMP B.2.32 "System Walkdown Program."

The AMR line item credits the AMP B.2.32 "System Walkdown Program" to manage loss of

material for these components. The AMR line item cites Generic Note G, which indicates that

the environment is not addressed in GALL Report for this component and material combination.

The staff's evaluation of the AMP B.2.32 "System Walkdown Program" is documented in SER

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Section 3.0.3.2.15. The staff determined that this program is a condition monitoring program

that will detect the aging effect of loss of material for metals, including stainless steel, by

periodic surveillance activities and observations of components' external surfaces to detect

aging degradation that are within the scope of license renewal. The staff also determined that

these activities are adequate to manage loss of material for stainless steel piping and piping

components exposed to air-outdoor. On the basis that the applicant will be performing periodic

visual inspections of these components, the staff finds the AMR results for this line item

acceptable.

In LRA Table 3.3.2-26, the applicant proposed to manage loss of material due to selective

leaching for copper alloy material for piping and piping components exposed to an internal

environment of raw water using the AMP B.2.46 "Area-Based NSAS Inspection."

The AMR line items credit the AMP B.2.46 "Area-Based NSAS Inspection" to manage loss of

material for these components. The AMR line item cites Generic Note H, which indicates that

the aging effect is not addressed in the Gall Report for this component, material and

environment combination. The staff's evaluation of the AMP B.2.46 is documented in SER

Section 3.0.3.3.1. The staff noted that this program is a plant-specific program that performs

an appropriate combination of established volumetric and visual inspection techniques

(nondestructive examination techniques) that will be performed by a qualified personnel on a

sample population of those components in scope of this program. The staff further noted that

the applicant will perform the inspections of the components within the scope of this program

within 10 years prior to entering the period of extended operation. The staff determined the

inspection techniques will be capable of detecting cracking and the applicant will initiate

corrective actions if an unacceptable loss of material or wall thinning has occurred that may

have a spatial interaction with safety-related components, as determined by engineering

evaluation. On the basis that the applicant will be performing an appropriate combination of a

visual inspection and volumetric testing for these components, the staff finds the AMR results

for this line item acceptable.

In LRA Table 3.3.2-26, the applicant proposed to manage loss of material due to selective

leaching for copper alloy material for piping and piping components and elements exposed to

an external environment of indoor air using the AMP B.2.29 "Selective Leaching Inspection."

The AMR line items credit the AMP B.2.29 "Selective Leaching Inspection" to manage loss of

material due to selective leaching for these components. The AMR line item cites Generic Note

H, which indicates that the aging effect is not addressed in the Gall Report for this component,

material and environment combination. The staff's evaluation of the AMP B.2.29 is documented

in SER Section 3.0.3.2.17. The staff noted that this program is a one-time inspection that will

perform a combination of visual inspection and hardness testing to determine if loss of material

due to selective leaching has occurred. The staff further noted that the applicant will perform

the inspections of the components within the scope of this program within 10 years prior to

entering the period of extended operation such that the condition of the material is more

representative of the conditions during the period of extended operation. The staff determined

the applicants proposed inspection techniques to detect loss of material due to selective

leaching are consistent with the inspection techniques recommended in GALL AMP XI.M33 and

the applicant will initiate corrective actions based on the evaluation of the results of these

inspections. On the basis that the applicant will be performing a combination of a visual

inspection and hardness test, which is consistent with the recommendations in GALL AMP

XI.M33, for these components, the staff finds the AMR results for this line item acceptable.

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In LRA Table 3.3.2-26, the applicant proposed to manage loss of material of carbon steel piping

in an internal environment of ventilation by using the Supplementary Piping/Tank Inspection

Program. The applicant referenced footnote "G" for this lire item indicating that environment is

not in the GALL Report for this component and material combination. The environment is an

aggressive environment of air-water interface.

The staff reviewed the Supplementary Piping/Tank Inspection Program, which uses a

combination of volumetric and visual examination techniques to identify evidence of loss of

material or lack thereof. The staff's evaluation of the Supplementary Piping/Tank Inspection

Program is documented in SER Section 3.0.3.1.16. Because the Supplementary Piping/Tank

Inspection Program is performed at very specific locations of air/water interface, and employs a

combination of volumetric and visual inspection techniques, the staff finds that the

Supplementary Piping/Tank Inspection Program will adequately manage the aging effects of

loss of material in this aggressive environment.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.3.2.3.27 Aging Management Review Results - Sampling System - LRA Table 3.3.2-27

The staff reviewed LRA Table 3.3.2-27, which summarizes the results of AMR evaluations for

the sampling system component groups.

In LRA Table 3.3.2-27, the applicant proposed to manage cracking of copper alloy for piping

and piping components and chiller components (condenser channel header, evaporator shell

and integral piping/tubing) in the Sampling System exposed to an internal environment of

treated water using the AMP B.2.14 "Closed Cooling Water Chemistry Program."

The AMR line item credits the Closed Cooling Water Program to manage cracking for these

components. The AMR line item cites Generic Note H, which indicates that the aging effect is

not addressed in the GALL Report for this component, material and environment combination.

The Closed Cooling Water Chemistry Program is an existing SSES program that properly

monitors components and controls corrosion inhibitor concentrations for components, within the

scope of license renewal, consistent with relevant EPRI water chemistry guidelines.

The applicant responded to RAI B.2.14-2, in a letter dated August 12, 2008. The applicant

clarified that the one-time inspection performed as part of the AMP B.2.22, "Chemistry Program

Effectiveness Inspection" will be used to supplement AMP B.2.14, "Closed Cooling Water

Chemistry Program" in all instances where AMP B.2.14 is credited for aging management in

LRA Table-2 items, with the exception of the Diesel Jacket Water Cooling System. The staff

reviewed the applicant's AMP B.2.14 "Closed Cooling Water Chemistry Program" and AMP

B.2.22 "Chemistry Program Effectiveness Inspection" and its evaluations are documented in

SER Section 3.0.3.2.7 and 3.0.3.1.10, respectively. The staff verified that this aging

management program includes activities that are consistent with the recommendations in the

GALL AMP XI.M21 to maintain high water purity, which is effective for managing cracking for

copper and copper alloy components exposed to a treated water environment. The staff further

noted the Closed Cooling Water Chemistry Program is an existing SSES program that properly

monitors components and controls corrosion inhibitor concentrations for components, within the

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scope of license renewal, consistent with relevant EPRI water chemistry guidelines. The staff

confirmed that the CPEI will be used to verify the effectiveness of the applicant's Closed

Cooling Water Chemistry Program to manage cracking and that a combination of appropriate

volumetric and visual examination techniques (such as VT-1 or VT-3) will be performed by

qualified personnel on a sample population of most susceptible subject components. On this

basis, the staff finds that these AMR results will be adequately managed by these programs.

In LRA Table 3.3.2-27, the applicant proposed to manage loss of material due to selective

leaching for copper alloy material for chiller components (channel/header, integral piping/tubing

and evaporator shell) exposed to an external environment of indoor air using the AMP B.2.29

"Selective Leaching Inspection."

The AMR line items credit the AMP B.2.29 "Selective Leaching Inspection" to manage loss of

material due to selective leaching for these components. The AMR line item cites Generic Note

H, which indicates that the aging effect is not addressed in the Gall Report for this component,

material and environment combination. The staff's evaluation of the AMP B.2.29 is documented

in SER Section 3.0.3.2.17. The staff noted that this program is a one-time inspection that will

perform a combination of visual inspection and hardness testing to determine if loss of material

due to selective leaching has occurred. The staff further noted that the applicant will perform

the inspections of the components within the scope of this program within 10 years prior to

entering the period of extended operation such that the condition of the material is more

representative of the conditions during the period of extended operation. The staff determined

the applicants proposed inspection techniques to detect loss of material due to selective

leaching are consistent with the inspection techniques recommended in GALL AMP XI.M33 and

the applicant will initiate corrective actions based on the evaluation of the results of these

inspections. On the basis that the applicant will be performing a combination of a visual

inspection and hardness test, which is consistent with the recommendations in GALL AMP

XI.M33, for these components, the staff finds the AMR results for this line item acceptable.

In Table 3.3.2-27, the LRA states that for Teflon piping and piping components in treated water

internal environment in the sampling system, there are no aging effects requiring management.

In RAI 3.3.2.3-1, part A by letter dated July 23, 2008, the staff asked the applicant to justify why

it had not identified any aging effects requiring management for these system-materialenvironment combinations.

In its letter dated August 27, 2008, in response to RAI 3.3.2.3-1, Part A, the applicant stated

that:

The only applicable aging effect for Teflon is change in material properties.

Change in material properties of Teflon may be due to exposure to gamma

radiation. Thermal exposure and exposure to ultraviolet radiation or ozone are

not applicable aging mechanisms for Teflon.

Gamma radiation is an applicable aging mechanism for Teflon components only

if the total integrated dose (TID) is equal to or greater than 10E4 rads. The

Teflon components in the Fire Protection System are located in the Circulating

Water Pumphouse, an area of the plant where ionizing radiation levels are such

that the TID over a 60-year period, which includes the period of extended

operation, will not equal or exceed 10E3 rads. Also, there are no sources of

gamma radiation expected to exist in the raw water of the Fire Protection System

or the treated water environment of the Sampling System. Therefore, change to

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the material properties and cracking due to ionizing radiation are not aging

effects requiring management for these components.

The staff reviewed the applicant response and noted that these piping and piping components

are located in an area where the ionizing radiation is less than the threshold value of 10E6 rads.

On this basis, the staff finds the applicant response acceptable and concludes that for Teflon

piping and piping components in treated water internal environment in the sampling system,

there are no aging effects requiring management.

In Table 3.3.2-27, the applicant stated that Teflon piping and piping components in an indoor air

external environment has an aging effect of change in material properties and has credited the

System Walkdown Program to manage this aging effect. In its letter dated August 27, 2008, in

response to RAI 3.3.2.3-1, the applicant stated that these Teflon piping and piping components

are located in areas of the Reactor Building where these components could be exposed to

ionizing radiation greater than 10E6 rads and to temperatures greater than 950F. Therefore, the

applicant has identified the aging effect of change in material properties.

In RAI B.2.32-4, the staff asked the applicant to justify its basis for crediting the System

Walkdown Program to manage cracking and changes in material properties that may occur in

the internal surfaces of in-scope components that are fabricated from non-metallic material. In

its letter dated August 12, 2008, in response to RAI B.2.32-4, the applicant revised the LRA to

include additional enhancements to address the management of changes in material properties

of elastomer and polymer materials. The staff's acceptance of the System Walkdown Program

to manage this aging effect and its discussion of RAI B.2.32-4 are documented in SER Section

3.0.3.2.14. The staff determined the applicant will supplement a visual inspection performed

during periodic system walkdowns with a supplemental physical manipulation and/or prodding

to inspect elastomer and polymer components. The staff noted that the physical manipulation

will aid the visual inspection in detecting age-related degradation because changes in material

properties and cracking can be detected during manipulation of elastomeric and polymeric

components by the relative inflexibility of the component, or by the failure of the component to

return to its previous shape or configuration. Based on this review, the staff concludes that the

System Walkdown Program will adequately manage the aging effect of change in material

properties of Teflon piping and piping components during the period of extended operation.

LRA Table 3.3.2-27 summarizes the results of AMRs for sampling system piping and piping

components constructed using copper alloy exposed to indoor air (external). The applicant

proposed that there is no aging effect for the material environment combination and that no

AMR is required.

The applicant has indicated that generic Note G is applicable for these items. Generic Note G is

"Environment not in NUREG-1801 for this component and material." The staff confirmed that

this environment is not in GALL for the component and material. The staff also agrees that

there will not be an aging mechanism for this material/environment combination, and that no

AMP is required.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

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3.3.2.3.28 Aging Management Review Results - Sanitary Drainage System LRA Table 3.3.2-28

The staff reviewed LRA Table 3.3.2-28, which summarizes the results of AMR evaluations for

the sanitary drainage system component groups.

In LRA Table 3.3.2-28, the applicant proposed to manage loss of material due for cast iron and

carbon steel material for piping and piping components exposed to an internal environment of

raw water using the AMP B.2.46 "Area-Based NSAS Inspection."

The AMR line items credit the AMP B.2.46 "Area-Based NSAS Inspection" to manage loss of

material for these components. The AMR line item cites Generic Note G, which indicates that

the environment is not addressed in GALL Report for this component and material combination.

The staffs evaluation of the AMP B.2.46 is documented in SER Section 3.0.3.3.1. The staff

noted that this program is a plant-specific program that performs an appropriate combination of

established volumetric and visual inspection techniques (nondestructive examination

techniques) that will be performed by a qualified personnel on a sample population of those

components in scope of this program. The staff further noted that the applicant will perform the

inspections of the components within the scope of this program within 10 years prior to entering

the period of extended operation. The staff determined the inspection techniques will be

capable of detecting loss of material and the applicant will initiate corrective actions if an

unacceptable loss of material or wall thinning has occurred that may have a spatial interaction

with safety-related components, as determined by engineering evaluation. On the basis that the

applicant will be performing an appropriate combination of a visual inspection and volumetric

testing for these components, the staff finds the AMR results for this line item acceptable.

In LRA Table 3.3.2-28, the applicant proposed to manage loss of material due to selective

leaching for cast iron for piping and piping components exposed to an internal environment of

raw water using the AMP B.2.29 "Selective Leaching Inspection."

The AMR line items credit the AMP B.2.29 "Selective Leaching Inspection" to manage loss of

material due to selective leaching for these components. The AMR line item cites Generic Note

G, which indicates that the environment is not addressed in GALL Report for this component

and material combination. The staff's evaluation of the AMP B.2.29 is documented in SER

Section 3.0.3.2.17. The staff noted that this program is a one-time inspection that will perform

a combination of visual inspection and hardness testing to determine if loss of material due to

selective leaching has occurred. The staff further noted that the applicant will perform the

inspections of the components within the scope of this program at least 10 years prior to

entering the period of extended operation such that the condition of the material is more

representative of the conditions during the period of extended operation. The staff determined

the applicants proposed inspection techniques to detect loss of material due to selective

leaching are consistent with the inspection techniques recommended in GALL AMP XI.M33 and

the applicant will initiate corrective actions based on the evaluation of the results of these

inspections. The staff noted that the GALL Report recommends the use of the Selective

Leaching Program for the same combination of material/environment/aging effect in items

VII.C1-1 1 for a different system. On the basis that the applicant will be performing a

combination of a visual inspection and hardness test for these components and these AMR

material/environment/aging effect combination is consistent with the GALL AMR Item VII.C1-1 1

for cast iron, the staff finds the AMR results for this line item acceptable.

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On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.29 Aging Management Review Results - Service Air System - LRA Table 3.3.2-29

The staff reviewed LRA Table 3.3.2-29, which summarizes the results of AMR evaluations for

the service air system component groups. The staff determined that all AMR evaluation results

in LRA Table 3.3.2-29 are consistent with the GALL Report.

3.3.2.3.30 Aging Management Review Results - Service Water System - LRA Table 3.3.2-30

The staff reviewed LRA Table 3.3.2-30, which summarizes the results of AMR evaluations for

the service water system component groups.

In LRA Table 3.3.2-30, the applicant proposed to manage cracking for copper alloy material for

piping and piping components exposed to an internal environment of raw water using the AMP

B.2.46 "Area-Based NSAS Inspection."

The AMR line items credit the AMP B.2.46 "Area-Based NSAS Inspection" to manage loss of

material for these components. The AMR line item cites Generic Note H, which indicates that

the aging effect is not addressed in the Gall Report for this component, material and

environment combination. The staff's evaluation of the AMP B.2.46 is documented in SER

Section 3.0.3.3.1. The staff noted that this program is a plant-specific program that performs

an appropriate combination of established volumetric and visual inspection techniques

(nondestructive examination techniques) that will be performed by qualified personnel on a

sample population of those components in scope of this program. The staff further noted that

the applicant will perform the inspections of the components within the scope of this program I

within 10 years prior to entering the period of extended operation. The staff determined the

inspection techniques will be capable of detecting cracking and the applicant will initiate

corrective actions if an unacceptable loss of material or wall thinning has occurred that may

have a spatial interaction with safety-related components, as determined by engineering

evaluation. On the basis that the applicant will be performing an appropriate combination of a

visual inspection and volumetric testing for these components, the staff finds the AMR results

for this line item acceptable.

In LRA Table 3.3.2-30, the applicant proposed to manage loss of material due to selective

leaching for copper alloy material for piping and piping components exposed to an external

environment of indoor air using the AMP B.2.29 "Selective Leaching Inspection."

The AMR line items credit the AMP B.2.29 "Selective Leaching Inspection" to manage loss of

material due to selective leaching for these components. The AMR line item cites Generic Note

H, which indicates that the aging effect is not addressed in the GALL Report for this

component, material and environment combination. The staff's evaluation of the AMP B.2.29 is

documented in SER Section 3.0.3.2.17. The staff noted that this program is a one-time

inspection that will perform a combination of visual inspection and hardness testing to

determine if loss of material due to selective leaching has occurred. The staff further noted that

the applicant will perform the inspections of the components within the scope of this program

within 10 years prior to entering the period of extended operation such that the condition of the

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material is more representative of the conditions during the period of extended operation. The

staff determined the applicants proposed inspection techniques to detect loss of material due to

selective leaching are consistent with the inspection techniques recommended in GALL AMP

XI.M33 and the applicant will initiate corrective actions based on the evaluation of the results of

these inspections. On the basis that the applicant will be performing a combination of a visual

inspection and hardness test, which is consistent with the recommendations in GALL AMP

XI.M33, for these components, the staff finds the AMR results for this line item acceptable.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.31 Aging Management Review Results - Standby Liquid Control System -

LRA Table 3.3.2-31

The staff reviewed LRA Table 3.3.2-31, which summarizes the results of AMR evaluations for

the SLC system component groups.

In LRA Table 3.3.2-31, the applicant proposed to manage loss of material of stainless steel

tanks in an internal environment of ventilation by using the Supplementary Piping/Tank

Inspection Program. The applicant referenced footnote "J" for this line item indicating that

neither the component nor the material and environment combination is evaluated in the GALL

Report. The. applicant also references footnote 0338, indicating loss of material is due to

crevice and/or pitting corrosion at the air/water interface within the SLC Storage Tank.

The staff reviewed the Supplementary Piping/Tank Inspection Program, which uses a

combination of volumetric and visual examination techniques to identify evidence of loss of

material or lack thereof. The staff's evaluation of the Supplementary Piping/Tank Inspection

Program is documented in SER Section 3.0.3.1.16. Because the Supplementary Piping/Tank

Inspection is performed at very specific locations of air/water interface, and employs a

combination of volumetric and visual inspection techniques, the staff finds that the

Supplementary Piping/Tank Inspection Program will adequately manage the aging effects of

loss of material in this aggressive environment.

In Table 3.3.2-31, the LRA states that for butyl rubber accumulators that are exposed internally

to a nitrogen air gas environment and externally to treated water, there are no aging effects

requiring management. In RAI 3.3.2.3-1, Part A by letter dated July 23, 2008, the staff asked

the applicant to justify why it had not identified any aging effects requiring management for

these system-material-environment combinations.

In its letter dated August 27, 2008, in response to RAI 3.3.2.3-1 part A, the applicant stated that

the applicable aging effects for elastomers (including butyl rubber, synthetic rubber, neoprene,

and silicone) are changes in material properties and cracking, which may be due to ionizing

radiation, thermal exposure, or exposure to ultraviolet radiation or ozone. The applicant

provided the threshold level for ionizing radiation as 10E6 rads, for temperature as greater than

950F, and for ultraviolet radiation and ozone as prolonged exposure. The applicant further

stated that, except for certain areas in the Reactor Building, where ionizing radiation could be

more than the threshold limit, the other buildings are all in an environment that is within the

threshold limits. Therefore, the applicant concluded that there are no aging effects requiring

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management for butyl rubber accumulators that are exposed internally to a nitrogen air gas

environment and externally to treated water in the standby liquid control system.

The staff reviewed the applicant response to RAI 3.3.2.3-1, part A, and finds the applicant

response acceptable because the applicant defined the stressors that could cause the aging

effects in various structures. The applicant response is consistent with the GALL Report

definitions of the threshold limits of the stressors as recommended in the GALL Report Section

IX. On the basis of its review, the staff finds for butyl rubber accumulators that are exposed

internally to a nitrogen air gas environment and externally to treated water in the standby liquid

control system, there are no aging effects requiring management.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.32 Aging Management Review Results - Turbine Building Closed Cooling Water

System - LRA Table 3.3.2-32

The staff reviewed LRA Table 3.3.2-32, which summarizes the results of AMR evaluations for

the turbine building closed cooling water system component groups.

The staff reviewed LRA Table 3.3.2-32, which summarizes the results of AMR evaluations for

the turbine building closed cooling water system component groups. The staff determined that

all AMR evaluation results in LRA Table 3.3.2-32 are consistent with the GALL Report.

3.3.2.3.33 Aging Management Review Results - Reactor Recirculation System (NSAS

Portions) - LRA Table 3.3.2-33

The staff reviewed LRA Table 3.3.2-33, which summarizes the results of AMR evaluations for

the reactor recirculation system (NSAS) component groups. The staff determined that all AMR

evaluation results in LRA Table 3.3.2-33 are consistent with the GALL Report.

3.3.2.3.34 Aging Management Review Results - Reactor Vessel and Auxiliaries System (NSAS

Portions) - LRA Table 3.3.2-34

The staff reviewed LRA Table 3.3.2-34, which summarizes the results of AMR evaluations for

the RV and auxiliaries system (NSAS portions) component groups. The staff determined that

all AMR evaluation results in LRA Table 3.3.2-33 are consistent with the GALL Report.

3.3.3 Conclusion

The staff concludes that the applicant has provided sufficient information to demonstrate that

the effects of aging for the auxiliary systems components within the scope of license renewal

and subject to an AMR will be adequately managed so that the intended function(s) will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21(a)(3).

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3.4 Aging Management of Steam and Power Conversion Systems

This section of the SER documents the staff's review of the applicant's AMR results for the

steam and power conversion systems components and component groups of:

* Auxiliary Boiler System

* Bypass Steam System

* Condensate Transfer and Storage System

• Condenser and Air Removal System

* Feedwater System

* Main Steam System

* Main Turbine System

* Makeup Demineralizer System

* Makeup Transfer and Storage System

* Refueling Water Transfer and Storage System

3.4.1 Summary of Technical Information in the Application

LRA Section 3.4 provides AMR results for the steam and power conversion systems

components and component groups. LRA Table 3.4.1, "Summary of Aging Management

Programs for Steam and Power Conversion Systems Evaluated in Chapter VIII of the GALL

Report," is a summary comparison of the applicant's AMRs with those evaluated in the GALL

Report for the steam and power conversion systems components and component groups.

The applicant's AMRs evaluated and incorporated applicable plant-specific and industry OE in

the determination of AERMs. The plant-specific evaluation included condition reports and

discussions with appropriate site personnel to identify AERMs. The applicant's review of

industry OE included a review of the GALL Report and OE issues identified since the issuance

of the GALL Report.

3.4.2 Staff Evaluation

The staff reviewed LRA Section 3.4 to determine whether the applicant provided sufficient

information to demonstrate that the effects of aging for the steam and power conversion

systems components within the scope of license renewal and subject to an AMR, will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

The staff conducted an onsite audit of AMRs to ensure the applicant's claim that certain AMRs

were consistent with the GALL Report. The staff did not repeat its review of the matters

described in the GALL Report; however, the staff did verify that the material presented in the

LRA was applicable and that the applicant identified the appropriate GALL Report AMRs. The

staff's evaluations of the AMPs are documented in SER Section 3.0.3. Details of the staff's

audit evaluation are documented in SER Section 3.4.2.1.

In the onsite audit, the staff also selected AMRs consistent with the GALL Report and for which

further evaluation is recommended. The staff confirmed that the applicant's further evaluations

were consistent with the SRP-LR Section 3.4.2.2 acceptance criteria. The staff's audit

evaluations are documented in SER Section 3.4.2.2.

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The staff also conducted a technical review of the remaining AMRs not consistent with or not

addressed in the GALL Report. The technical review evaluated whether all plausible aging

effects have been identified and whether the aging effects listed were appropriate for the

material-environment combinations specified. The staff's evaluations are documented in SER

Section 3.4.2.3.

For SSCs which the applicant claimed were not applicable or required no aging management,

the staff reviewed the AMR line items and the plant's operating experience to verify the

applicant's claims.

Table 3.4-1 summarizes the staff's evaluation of components, aging effects or mechanisms,

and AMPs listed in LRA Section 3.4 and addressed in the GALL Report.

Table 3.4-1 Staff Evaluation for Steam and Power Conversion Systems Components in

the GALL Report

Componenint GruIp'. Aging, IEffect/ AMP Ino GALLL , Further .AMP'in LRA- i1 Staff Evaluation

.(GALL Reportý. --Mechanism,... Report'., Evaluation Supplements,

item No;.)2i ALo _____ __ _ ___'Rep ýAmend ments

Steel piping, piping Cumulative TLAA, evaluated in Yes TLAA Consistent with

components, and fatigue damage accordance with GALL Report, which

piping elements 10 CFR 54.21(c) recommends further

exposed to steam or evaluation (See SER

treated water Section 3.4.2.2.1)

(3.4.1-1)

Steel piping, piping Loss of material Water Chemistry and Yes Not applicable Not applicable. The

components, and due to general, One-Time Inspection applicant addresses

piping elements pitting and these components

exposed to steam crevice under GALL Report

(3.4.1-2) corrosion Item number 3.4.1-4.

(See SER

Section 3.4.2.2.2.1)

Steel heat exchanger Loss of material Water Chemistry and Yes Not applicable Not applicable to

components exposed due to general, One-Time Inspection BWRs (See SER

to treated water pitting and Section 3.4.2.2.2.1)

(3.4.1-3) crevice

corrosion

Steel piping, piping Loss of material Water Chemistry and Yes BWR Water Consistent with

components, and due to general, One-Time Inspection Chemistry GALL Report

piping elements pitting and Program (8.2.2)

exposed to treated crevice and Chemistry (See SER

water corrosion Program Section 3.4.2.2.2.1)

(3.4.1-4) Effectiveness

Inspection

(B.2.22)

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Component Group Aging Effect/ AMP in GALL Further AMP in LRA, Staff Evaluation

(GALL Report, Mechanism Report Evaluation Supplements,

Item No.) in GALL or

________________ ____________ _________, _____! Report, Amendments. A 

Steel heat exchanger Loss of material Water Chemistry and Yes Not applicable Not Applicable.

components exposed due to general, One-Time Inspection There are no steel

to treated water pitting, crevice, heat exchanger

(3.4.1-5) and galvanic components in-scope

corrosion for license renewal in

the steam and power

conversion system.

(See SER

Section 3.4.2.2.9)

Steel and stainless Loss of material Water Chemistry and Yes BWR Water Consistent with

steel tanks exposed due to general One-Time Inspection Chemistry GALL Report

to treated water (steel only) Program (B.2.2)

(3.4.1-6) pitting and and Chemistry (See SER

crevice Program Section 3.4.2.2.2.1,

corrosion Effectiveness and SER

Inspection Section 3.4.2.2.7.1)

(B.2.22)

Steel piping, piping Loss of material Lubricating Oil Yes Not applicable Not applicable

components, and due to general, Analysis and (See SER

piping elements pitting and One-Time Inspection See 3ER

exposed to crevice Section 3.4.2.2.2.2)

lubricating oil corrosion

(3.4.1-7)

Steel piping, piping Loss of material Plant-specific Yes Not applicable Not applicable (See

components, and due to general, SER Section

piping elements pitting, crevice, 3.4.2.2.3)

exposed to raw water and

(3.4.1-8) microbiologically

-influenced

corrosion, and

fouling

Stainless steel and Reduction of Water Chemistry and Yes Not applicable Not Applicable

copper alloy heat heat transfer One-Time Inspection(

exchanger tubes due to fouling (See SER

exposed to treated Section 3.4.2.2.4.1)

water

(3.4.1-9)

Steel, stainless steel, Reduction of Lubricating Oil Yes Not applicable Not applicable

and copper alloy heat transfer Analysis and

heat exchanger due to fouling One-Time Inspection (See SER Section

tubes exposed to 3.4.2.2.4.2)

lubricating oil

(3.4.1-10)

Buried steel piping, Loss of material Buried Piping and No Not applicable Not applicable

piping components, due to general, Tanks Surveillance

piping elements, and pitting, crevice, (See SER

tanks (with or without and or section 3.4.2.2.5.1)

coating or wrapping) microbiologically

exposed to soil -influenced Buried Piping and Yes

1(3.4.1-11) corrosion Tanks Inspection

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Componentn Group, Aging Effec GLA LRA, Staff Evaluation

(GALL Report, Mcnism ••Report -.Evaluation Supplements,

IteMN0.), inGALL or

________,_ ."Report Amendments

Steel heat exchanger Loss of material Lubricating Oil Yes Not applicable Not Applicable

components exposed due to general, Analysis and

to lubricating oil pitting, crevice, One-Time Inspection (See SER

(3.4.1-12) and Section 3.4.2.2.5.2)

microbiologically

-influenced

corrosion

Stainless steel Cracking due to Water Chemistry and Yes BWR Water Consistent with

piping, piping stress corrosion One-Time Inspection Chemistry GALL Report

components, piping cracking Program (B.2.2)

elements exposed to and Chemistry (See SER

steam Program Section 3.4.2.2.6)

(3.4.1-13) Effectiveness

Inspection

(B.2.22)

Stainless steel Cracking due to Water Chemistry and Yes Not applicable Not applicable. The

piping, piping stress corrosion One-Time Inspection applicant addresses

components, piping cracking these components

elements, tanks, and under GALL Report

heat exchanger Item number

components exposed 3.4.1-13.

to treated water

> 600C (> 1401F) (See SER

(3.4.1-14) Section 3.4.2.2.6)

Aluminum and Loss of material Water Chemistry and Yes BWR Water Consistent with the

copper alloy piping, due to pitting One-Time Inspection Chemistry GALL Report

piping components, and crevice Program (B.2.2)

and piping elements corrosion and Chemistry (See SER

exposed to treated Program Section 3.4.2.2.7.1)

water Effectiveness

(3.4.1-15) Inspection

(B.2.22)

Stainless steel Loss of material Water Chemistry and Yes BWR Water Consistent with

piping, piping due to pitting One-Time Inspection Chemistry GALL Report

components, and and crevice Program (B.2.2)

piping elements; corrosion and Chemistry (See SER

tanks, and heat Program Section 3.4.2.2.7.1)

exchanger Effectiveness

components exposed Inspection

to treated water (B.2.22)

(3.4.1-16)

Stainless steel Loss of material Plant-specific Yes Buried Piping See SER

piping, piping due to pitting and Tanks Section 3.4.2.2.7.2

components, and and crevice Inspection

piping elements corrosion Program

exposed to soil

(3.4.1-17)

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C po nent Gru Aging g Effict -AMP in GALL ýFuiKrther AMP in LRAI Staff Evaluation

(GALL Report - Mechanism.., Repot Evaluationp Supplements,

Iem ,No.) - in GALL o

. Reort Amend-mentsCopper alloy piping, Loss of material Lubricating Oil Yes Not applicable Not applicable

piping components, due to pitting Analysis and

and piping elements and crevice One-Time Inspection (See SER

exposed to corrosion Section 3.4.2.2.7.3)

lubricating oil

(3.4.1-18)

Stainless steel Loss of material Lubricating Oil Yes Not applicable Not applicable

piping, piping due to pitting, Analysis and

components, piping crevice, and One-Time Inspection (See SER

elements, and heat microbiologically Section 3.4.2.2.8)

exchanger -influenced

components exposed corrosion

to lubricating oil

(3.4.1-19)

Steel tanks exposed Loss of material, Aboveground Steel No System Consistent with

to air - outdoor general, pitting, Tanks Walkdown GALL Report

(external) and crevice Program

(3.4.1-20) corrosion (B.2.32) and

Condensate and

Refueling Water

Storage Tank

Inspection

(B.2.19)

High-strength steel Cracking due to Bolting Integrity No Bolting Integrity Consistent with

closure bolting cyclic loading, Program GALL Report

exposed to air with stress corrosion (B.2.12)

steam or water cracking

leakage

(3.4.1-21)

Steel bolting and Loss of material Bolting Integrity No Bolting Integrity Consistent with

closure bolting due to general, Program GALL Report

exposed to air with pitting and (B.2.12)

steam or water crevice

leakage, air - outdoor corrosion; loss

(external), or air - of preload due to

indoor uncontrolled thermal effects,

(external); gasket creep,

(3.4.1-22) and selfloosening

Stainless steel Cracking due to Closed-Cycle No BWR Water Evaluated in line item

piping, piping stress corrosion Cooling Water Chemistry 3.4.1-13 (See SER

components, and cracking System Program (B.2.2) Section 3.4.2.1.1)

piping elements. and Chemistry

exposed to closed- Program

cycle cooling water Effectiveness

> 60Ci (> 14011) Inspection

(3.4.1-23) Program

(B.2.22)

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Compoent Grou•p Aging Effecl . AMP in GALL• Further, AMP in LRA,- S-Staff Evaluation

A(GALL Report Mechanism Report Evaluationj Supplementsi

Item No.) .in.GALL o r

Report Amendments.

Steel heat exchanger Loss of material Closed-Cycle No Not applicable Not applicable to

components exposed due to general, Cooling Water SSES (See SER

to closed cycle pitting, crevice, System Section 3.4.2.1.1)

cooling water and galvanic

(3.4.1-24) corrosion

Stainless steel Loss of material Closed-Cycle No Not applicable Not applicable to

piping, piping due to pitting Cooling Water SSES (See SER

components, piping and crevice System Section 3.4.2.1.1)

elements, and heat. corrosion

exchanger

components exposed

to closed cycle

cooling water

(3.4.1-25) ....

Copper alloy piping, Loss of material Closed-Cycle No Not applicable Not applicable to

piping components, due to pitting, Cooling Water SSES (See SER

and piping elements crevice, and System Section 3.4.2.1.1)

exposed to closed galvanic

cycle cooling water corrosion

(3.4.1-26)

Steel, stainless steel, Reduction of Closed-Cycle No Not applicable Not applicable to

and copper alloy heat transfer Cooling Water SSES (See SER

heat exchanger due to fouling System Section 3.4.2.1.1)

tubes exposed to

closed cycle cooling

water

(3.4.1-27)

Steel external Loss of material External Surfaces No System Consistent with

surfaces exposed to due to general Monitoring Walkdown GALL Report

air - indoor corrosion Program

uncontrolled- (B.2.32); and (See SER.

(external), Supplementary Section 3.4.2.1.2)

condensation Piping/Tank

(external), or air Inspection

outdoor (external) (B.2.28)

.(3.4.1-28)

Steel piping, piping Wall thinning Flow-Accelerated. No Flow- Consistent with

components, and due to flow- Corrosion Accelerated GALL Report

piping elements accelerated. Corrosion

exposed to steam or corrosion (B.2.11), and (See SER

treated water Preventive Section 3.4.2.1.3)

(3.4.1-29) Maintenance

Activities - Main

Turbine (B.2.49)

Steel piping, piping Loss of material Inspection of Internal No Supplemental Consistent with

components, and due to general, Surfaces in Piping and GALL Report (See

piping elements pitting, and Miscellaneous Piping Tanks SER Section

exposed to air crevice and Ducting Inspection 3.4.2.1.4)

outdoor (internal) or corrosion Components Program

condensation (B.2.28)

(internal)

(3.4.1-30)

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Component Group Aging Effectl AMIP in GALL Further AMP in LRA, Staff Evaluation,

(GALL Report Mechanism.. Report Evaluation. Supplements,

Item, No).WnGALL or,

Rp ort. Amendments:

Steel heat exchanger Loss of material Open-Cycle Cooling No Not applicable Not applicable (See

components exposed due to general, Water System SER Section

to raw water pitting, crevice, 3.4.2.1.1)

(3.4.1-31) galvanic, and

microbiologically

-influenced

corrosion, and

fouling

Stainless steel and Loss of material Open-Cycle Cooling No Not applicable Not applicable to

copper alloy piping, due to pitting, Water System SSES (See SER

piping components, crevice, and Section 3.4.2.1.1)

and piping elements microbiologically

exposed to raw water -influenced

(3.4.1-32) corrosion

Stainless steel heat Loss of material Open-Cycle Cooling No Not applicable Not applicable to

exchanger due to pitting, Water System SSES (See SER

components exposed crevice, and Section 3.4.2.1.1)

to raw water microbiologically

(3.4.1-33) -influenced

corrosion, and

fouling

Steel, stainless steel, Reduction of Open-Cycle Cooling No Not applicable Not applicable to

and copper alloy heat transfer Water System SSES (See SER

heat exchanger due to fouling Section 3.4.2.1.1)

tubes exposed to raw

water

(3.4.1-34)

Copper alloy Loss of material SelectiveLeaching of No Selective Consistent with

> 15% Zn piping, due to selective Materials Leaching GALL Report

piping components, leaching Inspection

and piping elements Program

exposed to closed (B.2.29)

cycle cooling water,

raw water, or treated

water

(3.4.1-35)

Gray cast iron piping, Loss of material Selective Leaching of No Not applicable Not applicable to

piping components, due to selective Materials SSES (See SER

and piping elements leaching Section 3.4.2.1.1)

exposed to soil,

treated water, or raw

water

(3.4.1-36)

Steel, stainless steel, Loss of material Water Chemistry No BWR Water Consistent with

and nickel-based due to pitting Chemistry GALL Report

alloy piping, piping and crevice Program (B.2.2)

components, and corrosion (See SER

piping elements Section 3.4.2.1)

exposed to steam

(3.4.1-37)

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ComponentGroup, Aging Effect/ AMP in GALL Further AMP In LRA, Staff Evaluation

(GALL Report Mechanism Report Evaluation Supplements,

Item NO.). in GALL or

_______________i ________ Rprt Amendments

Steel bolting and Loss of material Boric Acid Corrosion No Not applicable Not applicable to

external surfaces due to boric acid BWRs

exposed to air with corrosion

borated water

leakage

(3.4.1-38)

Stainless steel Cracking due to Water Chemistry No Not applicable Not applicable to

piping, piping stress corrosion BWRs

components, and cracking

piping elements

exposed to steam

(3.4.1-39)

Glass piping None None No Not applicable Not applicable to

elements exposed to SSES (See SER

air, lubricating oil, Section 3.4.2.1.1)

raw water, and

treated water

(3.4.1-40)

Stainless steel, None None No None Consistent with

copper alloy, and GALL Report

nickel alloy piping,

piping components,

and piping elements

exposed to air -

indoor uncontrolled

(external)

(3.4.1-41)

Steel piping, piping None None No Not applicable Not applicable to

components, and SSES (See SER

piping elements Section 3.4.2.1 1)

exposed toair -

indoor controlled

(external)

(3.4.1-42)

Steel and stainless None None No Not applicable Not applicable to

steel piping, piping SSES (See SER

components,* and Section 3.4.2.1.1)

piping elements in

concrete

(3.4.1-43)

Steel, stainless steel, None None No None Consistent with

aluminum, and GALL Report

copper alloy piping,

piping components,

and piping elements

exposed to gas

(3.4.1-44) 1

The staff's review of the steam and power conversion systems component groups followed any

one of several approaches. One approach, documented in SER Section 3.4.2.1, reviewed AMR

results for components that the applicant indicated are consistent with the GALL Report and

3-429
require no further evaluation. Another approach, documented in SER Section 3.4.2.2, reviewed

AMR results for components that the applicant indicated are consistent with the GALL Report

and for which further evaluation is recommended. A third approach, documented in SER

Section 3.4.2.3, reviewed AMR results for components that the applicant indicated are not

consistent with, or not addressed in, the GALL Report. The staff's review of AMPs credited to

manage or monitor aging effects of the steam and power conversion systems components is

documented in SER Section 3.0.3.

3.4.2.1 AMR Results Consistent with the GALL Report

LRA Section 3.4.2.1 identifies the materials, environments, AERMs, and the following programs

that manage aging effects for the steam and power conversion systems components:

* BWR Water Chemistry Program

* Flow-Accelerated Corrosion (FAC) Program

* Bolting Integrity Program

* Condensate and Refueling Water Storage Tanks Inspection

" Chemistry Program Effectiveness Inspection

" Supplemental Piping/Tank Inspection

* Selective Leaching Inspection

" Buried Piping and Tanks Inspection Program

" System Walkdown Program

LRA Tables 3.4.2-1 through 3.4.2-10 summarizes AMRs for the steam and power conversion

systems components and indicate AMRs claimed to be consistent with the GALL Report.

For component groups evaluated in the GALL Report for which the applicant claimed

consistency with the report and for which, it does not recommend further evaluation, the staff's

audit and review determined whether the plant-specific components of these GALL Report

component groups were bounded by the GALL Report evaluation.

The applicant noted for each AMR line item how the information in the tables aligns with the

information in the GALL Report. The staff audited those AMRs with notes A through E

indicating how the AMR is consistent with the GALL Report.

Note A indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP is consistent with the GALL

Report AMP. The staff audited these line items to verify consistency with the GALL Report and

validity of the AMR for the site-specific conditions.

Note B indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP takes some exceptions to the

GALL Report AMP. The staff audited these line items to verify consistency with the GALL

Report and verified that the identified exceptions to the GALL Report AMPs have been

reviewed and accepted. The staff also determined whether the applicant's AMP was consistent

with the GALL Report AMP and whether the AMR was valid for the site-specific conditions.

Note C indicates that the component for the AMR line item, although different from, is

consistent with the GALL Report for material, environment, and aging effect. In addition, the

AMP is consistent with the GALL Report AMP. This note indicates that the applicant was unable

3-430
to find a listing of some system components in the GALL Report; however, the applicant

identified in the GALL Report a different component with the same material, environment, aging

effect, and AMP as the component under review. The staff audited these line items to verify

consistency with the GALL Report. The staff also determined whether the AMR line item of the

different component was applicable to the component under review and whether the AMR was

valid for the site-specific conditions.

Note D indicates that the component for the AMR line item, although different from, is

consistent with the GALL Report for material, environment, and aging effect. In addition, the

AMP takes some exceptions to the GALL Report AMP. The staff audited these line items to

verify consistency with the GALL Report. The staff verified whether the AMR line item of the

different component was applicable to the component under review and whether the identified

exceptions to the GALL Report AMPs have been reviewed and accepted. The staff also

determined whether the applicant's AMP was consistent with the GALL Report AMP and

whether the AMR was valid for the site-specific conditions.

Note E indicates that the AMR line item is consistent with the GALL Report for material,

environment, and aging effect, but credits a different AMP. The staff audited these line items to

verify consistency with the GALL Report. The staff also determined whether the credited

AMP would manage the aging effect consistently with the GALL Report AMP and whether the

AMR was valid for the site-specific conditions.

The staff audited and reviewed the information in the LRA. The staff did not repeat its review of

the matters described in the GALL Report; however, the staff did verify that the material

presented in the LRA was applicable and that the applicant identified the appropriate GALL

Report AMRs,

The staff reviewed the LRA to confirm that the applicant: (a) provided a brief description of the

system, components, materials, and environments; (b) stated that the applicable aging effects

were reviewed and evaluated in the GALL Report; and (c) identified those aging effects for the

engineered safety features ESF components that are subject to an AMR. On the basis of its

audit and review, the staff determines that, for AMRs not requiring further evaluation, as

identified in LRA Table 3.2.1, the applicant's references to the GALL Report are acceptable and

no further staff review is required, with the exception of the following AMRs that the applicant

had identified were consistent with the AMRs of the GALL Report and for which the staff felt

were in need of additional clarification and assessment. The staff's evaluations of these AMRs

are provided in the subsections that follow.

3.4.2.1.1 AMR Results Identified as Not Applicable

In LRA Table 3.4.1, item 23, the applicant states for this line item cracking of stainless steel

piping, piping components, and piping elements is addressed under the treated water

environment in table item 3.4.1-13. The staff reviewed the documentation supporting the

applicant's AMR evaluation and confirmed that the components under the this commodity

group: stainless steel piping, piping components, and piping elements, are evaluated as

exposed to treated water under line item 3.4.1-13. On the basis that this commodity group has

been evaluated, the staff agreed with the applicant's treatment of this line item.

In LRA Table 3.4.1, items 24 and 25, the applicant states that there are no steel heat

exchanger components and stainless steel components that are subject to AMR and exposed

to treated (closed cycle cooling) water in the steam and power conversion system for SSES.

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The staff reviewed the documentation supporting the applicant's AMR evaluation and confirmed

that no components under this commodity group exist in the Steam and Power Conversion

System. Therefore, the staff agrees with the applicant's determination that the corresponding

AMR result lines in the GALL Report is not applicable to SSES.

In LRA Table 3.4.1, items 26 and 27, the applicant states that there are no copper alloy

components and heat exchanger tubes exposed to closed cycle cooling water in the steam and

power system for SSES that are subject to AMR. The staff reviewed the documentation

supporting the applicant's AMR evaluation and confirmed that no components under this

commodity group exist in the Steam and Power Conversion System. Therefore, the staff

agrees with the applicant's determination that the corresponding AMR result lines in the GALL

Report is not applicable to SSES.

In LRA Table 3.4.1, items 31, 32, 33, and 34, the applicant states that the corresponding AMR

result line in the GALL Report is not applicable because only the main condenser in the steam

and power conversion system contains steel or stainless steel components that are subject to

AMR and exposed to raw water. The applicant further stated that no aging effects were

identified that could affect the intended function of Isolated Condenser Treatment Method

(ICTM) volume for these components. The staff reviewed the system intended function provided

in LRA Section 2.3.4.4 and noted that the intended function is to support the MSIV leakage

ICTM by providing hold-up and plate-out of fission products.

The staff found that, to maintain the intended function of plateout and holdup during postaccident conditions, the main condenser and main condenser complex components must

remain intact. The staff noted that normal plant operations monitor condenser vacuum

continuously to verify its integrity, and that the acceptable performance of the main condenser

during normal plant operation is adequate assurance that it will perform the plateout and holdup

post-accident function. Therefore, the staff agrees with the applicant's conclusion that no AMP

is required to assure the post-accident intended function and that this aging effect is not

applicable, and the staff finds that the corresponding AMR result line in the GALL Report is not

applicable to SSES.

In LRA Table 3.4.1, item 36, the applicant states for this line item there are no gray cast iron

piping, piping, components or piping elements that are subject to AMR and exposed to soil,

treated water or raw water in the steam and power conversion system for SSES. The staff

reviewed the documentation supporting the applicant's AMR evaluation and confirmed that no

components under this commodity group exist in the Steam and Power Conversion System.

Therefore, the staff agrees with the applicant's determination that the corresponding AMR result

lines in the GALL Report is not applicable to SSES.

In LRA Table 3.4.1, item 40, the applicant states for this line item, there are no glass piping

elements in the steam and power conversion system for SSES. The staff reviewed the

documentation supporting the applicant's AMR evaluation and confirmed that no components

under this commodity group exist in the Steam and Power Conversion System. Therefore, the

staff agrees with the applicant's determination that the corresponding AMR result lines in the

GALL Report is not applicable to SSES.

In LRA Table 3.4.1, item 42, the applicant states for this line item, indoor environments are

considered to be uncontrolled. The staff reviewed the documentation supporting the applicant's

AMR evaluation and confirmed that the components under the this commodity group: steel

piping, piping components, and piping elements, are evaluated as exposed to uncontrolled air

3-432
under line item 3.4.1-28. On the basis that this commodity group has been evaluated, the staff

agreed with the applicant's statement that this line item is not applicable.

In LRA Table 3.4.1, item 43, the applicant states for this line item, there are no components in

the steam and power conversion system for SSES embedded in concrete. The staff reviewed

the documentation supporting the applicant's AMR evaluation and confirmed that no

components under this commodity group exist in the Steam and Power Conversion System.

Therefore, the staff agrees with the applicant's determination that the corresponding AMR result

lines in the GALL Report is not applicable to SSES.

3.4.2.1.2 Loss of material due to general corrosion

In Table 3.4.2-6, the LRA states that loss of material of MS system steel piping in an external

environment of indoor air is managed by the Supplementary Piping/Tank Inspection Program.

During the audit, the staff noted that the applicant applied Note E to this item and referenced

LRA Table 3.4-1, item 3.4.1-28 and GALL Report Volume 2, item VII.H-7. The staff reviewed

the AMR results lines that reference Note E and determines that the component type, material,

environment, and aging effect are consistent with the GALL Report. However, the staff noted

that where the GALL Report recommends AMP XI.M36, "External Surface Monitoring", the

applicant proposed using the Supplementary Piping/Tank Inspection Program. The LRA also

references footnote 0401, which states that the environment is an aggressive air/water interface

in the suppression pool. The staff determined that in this environment, loss of material is due to

crevice and pitting corrosion on the inside surface of SRV discharge piping at air/water interface

in the suppression pool, and also, on the outside surface of SRV discharge piping at air/water

interface in the suppression pool.

However, the discussion column of Table 3.4.1, line item 3.4.1-28 only credits the System

Walkdown Program, and does not address the Supplementary Piping/Tank Inspection

Program. The staff issued RAI 3.4.2.1-1 by letter dated July 23, 2008, to request the applicant

to clarify this discrepancy.

Furthermore, for the same air/water interface environment, in some cases the LRA tables

reference footnote "G" or "H" and in some cases, they reference footnote "E." RAI 3.4.2-1 also

requested to clarify this discrepancy.

In its letter dated August 22, 2008, the applicant responded to RAI 3.4.2.1-1 by amending the

LRA to include the following paragraph in the discussion column of Table 3.4.1, item 3.4.1-28:

This item also includes loss of material due to pitting and crevice corrosion at

air/water interfaces for carbon steel piping components in an indoor air

environment. The Supplemental Piping/Tank Inspection is credited to detect and

characterize loss of material for these components. A Note E is used.

On the basis that the applicant amended the LRA to resolve the discrepancy between

Table 3.4.1, item 3.4.1-28 discussion column and Table 3.4.2-6, the staff finds the response

acceptable.

Furthermore, the applicant stated that the footnote H was used incorrectly and that Note E

should have been used as per the response provided in RAI 3.2.2.3.1-1 and documented in

SER Section 3.2.2.3.1.

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The staff reviewed the Supplementary Piping/Tank Inspection Program, which uses a

combination of volumetric and visual examination techniques to identify evidence of loss of

material or lack thereof. The staff's evaluation of the Supplementary Piping/Tank Inspection

Program is documented in SER Section 3.0.3.1.16. Because the Supplementary Piping/Tank

Inspection is performed at very specific locations of air/water interface, and employs more

conservative inspection techniques than the visual inspection of External Surfaces Monitoring

Program, the staff finds that the Supplementary Piping/Tank Inspection Program will adequately

manage the aging effects of loss of material in this aggressive environment.

3.4.2.1.3 Wall Thinning due to Flow-Accelerated Corrosion

In its letter dated June 30, 2008, in response to RAI B2.1 1-1, the applicant stated that wall

thinning due to flow-accelerated corrosion of steel main turbine casings in a treated water

environment is managed by the Preventive Maintenance Activities - Main Turbine.

The staff noted that the applicant applied Note E to this item and referenced Table 3.4-1, item

3.4.1-29 and GALL Report Volume 2, item VIII.B2-4. The staff reviewed the AMR results lines

that reference Note E and determines that the component type, material, environment, and

aging effect are consistent with the GALL Report. However, the staff noted that where the

GALL Report recommends AMP XI.M17, "Flow-Accelerated Corrosion", the applicant proposed

using the Preventive Maintenance Activities - Main Turbine Program.

The staff reviewed the Preventive Maintenance Activities - Main Turbine Program, which is an

existing plant-specific program that will be enhanced to include the inspection of the high

pressure turbine shell using visual inspection (VT-3 or equivalent) techniques and an ultrasonic

examination for wall thickness. The staff evaluated the Preventive Maintenance Activities - Main Turbine Program and its evaluation is documented in SER Section 3.0.3.3.4. The staff

finds the Preventive Maintenance Activities - Main Turbine acceptable to manage the aging

effects of loss of material due to flow-accelerated corrosion because the turbine shell will be

visually and volumetrically inspected in the presence of the turbine manufacturer representative,

and the operating experience review did not indicate any wear on the turbine outer casing

during significant modification work performed on these turbines over the last five years. On this

basis, the staff finds that the Preventive Maintenance Activities - Main Turbine will adequately

manage loss of material of steel turbine casing in a treated water environment during the period

of extended operation.

3.4.2.1.4 Loss of material due to general, pitting and crevice corrosion

In Table 3.4.2-3, the LRA states that loss of material of condensate transfer and storage

system steel valve bodies in an internal environment of ventilation is managed by the

Supplementary Piping/Tank Inspection Program.

During the audit, the staff noted that the applicant applied Note E to this item and referenced

LRA Table 3.4-1, item 3.4.1-30 and GALL Report Volume 2, item VIII.B1-6. The staff reviewed

the AMR results lines that reference Note E and determines that the component type, material,

environment, and aging effect are consistent with the GALL Report. However, the staff noted

that where the GALL Report recommends AMP XI.M38, "Inspection of Internal Surfaces in

Miscellaneous Piping and Ducting Components", the applicant proposed using the

Supplementary Piping/Tank Inspection Program.

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The staff reviewed the Supplementary Piping/Tank Inspection Program, which uses a

combination of volumetric and visual examination techniques to identify evidence of loss of

material or lack thereof. The staff's evaluation of the Supplementary Piping/Tank Inspection

Program is documented in SER Section 3.0.3.1.16. Because the Supplementary Piping/Tank

Inspection employs more conservative inspection techniques than only the visual inspection of

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program, the

staff finds that the Supplementary Piping/Tank Inspection Program will adequately manage the

aging effects of loss of material in an internal environment of ventilation.

SER Section 3.4.2.1 Conclusion. The staff evaluated the applicant's claim of consistency with

the GALL Report. The staff also reviewed information pertaining to the applicant's consideration

of recent operating experience and proposals for managing aging effects. On the basis of its

review, the staff concludes that the AMR results, which the applicant claimed to be consistent

with the GALL Report, are indeed consistent with its AMRs. Therefore, the staff concludes that

the applicant has demonstrated that the effects of aging for these components will be

adequately managed so that their intended function(s) will be maintained consistent with the

CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.4.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation is

Recommended

In LRA Section 3.4.2.2, the applicant further evaluates aging management, as recommended

by the GALL Report, for the steam and power conversion systems components and provides

information concerning how it will manage the following aging effects:

" cumulative fatigue damage

" loss of material due to general, pitting, and crevice corrosion

* loss of material due to general, pitting, crevice, and microbiologically-influenced

corrosion, and fouling

* reduction of heat transfer due to fouling

* loss of material due to general, pitting, crevice, and microbiologically-influenced

corrosion

" cracking due to SCC

" loss of material due to pitting and crevice corrosion

" loss of material due to pitting, crevice, and microbiologically-influenced corrosion

" loss of material due to general, pitting, crevice, and galvanic corrosion

* QA for aging management of nonsafety-related components

For component groups evaluated in the GALL Report, for which the applicant claimed

consistency with the report and for which the report recommends further evaluation, the staff

audited and reviewed the applicant's evaluation to determine whether it adequately addressed

the issues further evaluated. In addition, the staff reviewed the applicant's further evaluations

against the criteria contained in SRP-LR Section 3.4.2.2. The staff's review of the applicant's

further evaluation follows.

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3.4.2.2.1 Cumulative Fatigue Damage

LRA Section 3.4.2.2.1 states that fatigue is a TLAA, as defined in 10 CFR 54.3. Applicants must

evaluate TLAAs in accordance with 10 CFR 54.21 (c)(1 ). SER Section 4.3 documents the staff's

review of the applicant's evaluation of this TLAA.

3.4.2.2.2 Loss of Material Due to General, Pitting, and Crevice Corrosion

The staff reviewed LRA Section 3.4.2.2.2 against the following criteria in SRP-LR

Section 3.4.2.2.2:

(1) LRA Section 3.4.2.2.2 addresses loss of material due to general, pitting, and crevice

corrosion in piping, piping components, piping elements, tanks, and heat exchangers.

The applicant stated that loss of material due to general, pitting, and crevice corrosion

for steel piping components and tanks exposed to treated water in the Steam and Power

Conversion System is managed by the BWR Water Chemistry Program. The BWR

Water Chemistry Program manages aging effects through periodic monitoring and

control of contaminants. The Chemistry Program Effectiveness Inspection will provide a

verification of the effectiveness of the BWR Water Chemistry Program to manage loss

of material due to general, pitting, and crevice corrosion through examination of steel

piping components and tanks exposed to treated water.

SRP-LR Section 3.4.2.2.2 states that loss of material due to general, pitting, and crevice

corrosion may occur in steel piping, piping components, piping elements, tanks, and

heat exchanger components exposed to treated water and for steel piping, piping

components, and piping elements exposed to steam. The existing AMP monitors and

controls water chemistry to manage the effects of loss of material due to general, pitting,

and crevice corrosion. However, control of water chemistry does not preclude loss of

material due to general, pitting, and crevice corrosion at locations with stagnant flow

conditions; therefore, the effectiveness of water chemistry control programs should be

verified to ensure that corrosion does not occur. The GALL Report recommends further

evaluation of programs to verify the effectiveness of water chemistry control programs.

A one-time inspection of selected components and susceptible locations is an

acceptable method to ensure that corrosion does not occur and that component

intended functions will be maintained during the period of extended operation.

The staff noted that the applicant combined components from LRA Table 3.4.1, item 2

with components in LRA Table 3.4.1, item 4 for the purpose of AMR. The staff finds this

acceptable because the material, environment and aging effect for item 3.4.1-2 is the

same as for item 3.4.2 4 except that the environment in item 3.4.1-2 is steam and in

item 3.4.1-4 is liquid, and with regard to loss of material due to corrosion, the aging

effects in a liquid and in a steam environment are identical for steel components. On this

basis, the staff finds the application treatment of LRA Table item 3.4.1-2 as acceptable

The staff reviewed the applicant's BWR Water Chemistry Program. The staff's

evaluation of this program, which is documented in SER Section 3.0.3.1.1, determined

that the BWR Water Chemistry Program is consistent with the GALL Report's

recommendations for AMP XI.M2, "Water Chemistry," and provides mitigation for the

aging effect of loss of material due to general, pitting, crevice, and galvanic corrosion.

The staff reviewed the applicant's Chemistry Program Effectiveness Inspection. The

staffs evaluation of this program, which is documented in SER Section 3.0.3.1.10, found

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that the Chemistry Program Effectiveness Inspection is a one-time inspection that is

consistent with the GALL Report's recommendations for AMP XI.M32, "One-Time

Inspection." The CPEI includes provisions for inspecting selected components in areas

of low or stagnant flow and is capable of detecting loss of material due to general, pitting

crevice, and galvanic corrosion, if it should occur in the selected components. Based on

the applicant's use of a water chemistry program that provides mitigation of the aging

effect and use of a one-time inspection to confirm effectiveness of the water chemistry

program consistent with the recommendations of the GALL Report, the staff finds the

applicant's proposed AMPs for managing the potential aging effect of loss of material

due to general, pitting, crevice, and galvanic corrosion, in steel piping, piping

components, piping elements, and tanks exposed to treated water or to steam in the

feedwater system, the condensate storage and transfer system, the makeup

demineralizer system, the makeup transfer and storage system, and the refueling water

transfer and storage system to be acceptable.

The staff noted that the applicant designated line 3.4.1-3 of LRA Table 3.4.1 as "not

applicable" because the AMR result applies only for PWRs. The staff reviewed the

SRP-LR and confirmed that the corresponding AMR result in SRP-LR, Table 3.4-1,

item 3, is applicable only for PWRs. On the basis that Susquehanna is a BWR, not a

PWR, the staff finds the applicant's determination that LRA Table 3.4.1, item 3.4.1-3, is

not applicable to be acceptable.

(2) LRA Section 3.4.2.2.2 addresses loss of material due to general, pitting, and crevice

corrosion in piping, piping components, and piping elements exposed to lubricating oil.

The applicant stated that this aging effect is not applicable because there are no steel

components that are exposed to lubricating oil in the steam and power conversion

system.

SRP-LR Section 3.4.2.2.2 states that loss of material due to general, pitting, and crevice

corrosion may occur in steel piping, piping components, and piping elements exposed to

lubricating oil. The existing AMP periodically samples and analyzes lubricating oil to

maintain contaminants within acceptable limits, thereby preserving an environment not

conducive to corrosion. However, control of lube oil contaminants may not always be

fully effective in precluding corrosion; therefore, the effectiveness of lubricating oil

contaminant control should be verified to ensure that corrosion does not occur. The

GALL Report recommends further evaluation of programs to manage corrosion to verify

the effectiveness of lube oil chemistry control programs. A one-time inspection of

selected components at susceptible locations is an acceptable method to ensure that

corrosion does not occur and that component intended functions will be maintained

during the period of extended operation.

The staff reviewed LRA Section 2.3.4 and verified that SSES does not have support

systems within the scope of license renewal that contain the piping, piping components

and piping elements fabricated from steel exposed to lubricating oil.

Based on the staff's review as described above and of LRA Section 3.4 found that there

were no steel piping, piping components and piping elements exposed to lubricating oil

internally or externally. On the basis of this review, the staff finds that SRP-LR

Section 3.4.2.2.2 item 2 is not applicable to SSES.

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Based on the programs identified above, the staff concludes that the applicant's programs meet

SRP-LR Section 3.4.2.2.2 criteria. For those line items that apply to LRA Section 3.4.2.2.2, the

staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21(a)(3).

3.4.2.2.3 Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced

Corrosion, and Fouling

The staff reviewed LRA Section 3.4.2.2.3 against the criteria in SRP-LR Section 3.4.2.2.3.

LRA Section 3.4.2.2.3 addresses loss of material due to general, pitting, crevice, and

microbiologically influenced corrosion (MIC), and fouling. The applicant stated that this aging

effect is not applicable because the only steam and power conversion components exposed to

raw water are the stainless steel tubes inside the main condenser.

SRP-LR Section 3.4.2.2.3 states that loss of material due to general, pitting, and crevice

corrosion, and MIC and fouling may occur in steel piping, piping components, and piping

elements exposed to raw water. The GALL Report recommends further evaluation of a plantspecific AMP to ensure that the aging effect is adequately managed.

The staff reviewed the documentation supporting the applicant's AMR evaluation and confirmed

the applicant's claim that SSES has no steel piping, piping components, and piping elements

exposed to raw water. Therefore, the staff agrees with the applicant's determination that the

corresponding AMR result line in the GALL Report is not applicable to SSES.

Based on the above, the staff concludes SRP-LR Section 3.4.2.2.3 criteria is not applicable.

3.4.2.2.4 Reduction of Heat Transfer Due to Fouling

The staff reviewed LRA Section 3.4.2.2.4 against the following criteria in SRP-LR

Section 3.4.2.2.4:

(1) LRA Section 3.4.2.2.4 addresses reduction of heat transfer due to fouling in heat

exchanger tubes exposed to treated water. The applicant stated that this aging effect is

not applicable because there are no heat exchanger tubes exposed to treated water in

the steam and power conversion system that perform an intended function of heat

transfer.

SRP-LR Section 3.4.2.2.4 states that reduction of heat transfer due to fouling may occur

in stainless steel and copper alloy heat exchanger tubes exposed to treated water. The

existing AMP controls water chemistry to manage reduction of heat transfer due to

fouling. However, control of water chemistry may not always be fully effective in

precluding fouling; therefore, the GALL Report recommends that the effectiveness of

water chemistry control programs should be verified to ensure that reduction of heat

transfer due to fouling does not occur. A one-time inspection is an acceptable method to

ensure that reduction of heat transfer does not occur and that component intended

functions will be maintained during the period of extended operation.

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The staff reviewed the AMR Tables in LRA Section 3.4 and plant basis documents and

found that there were no stainless steel and copper alloy heat exchanger components

identified with a heat transfer function exposed to treated water. On the basis of this

review, the staff finds that this SRP-LR Section is not applicable to SSES.

(2) LRA Section 3.4.2.2.4 addresses reduction of heat transfer due to fouling in heat

exchanger tubes exposed to lubricating oil. The applicant stated that this aging effect is

not applicable because there are no heat exchanger tubes exposed to lubricating oil in

the steam and power conversion system.

SRP-LR Section 3.4.2.2.4 states that reduction of heat transfer due to fouling may occur

in steel, stainless steel, and copper alloy heat exchanger tubes exposed to lubricating

oil. The existing AMP monitors and controls lube oil chemistry to mitigate reduction of

heat transfer due to fouling. However, control of lube oil chemistry may not always be

fully effective in precluding corrosion; therefore, the effectiveness of lubricating oil

contaminant control should be verified to ensure that fouling does not occur. The GALL

Report recommends further evaluation of programs to verify the effectiveness of lube oil

chemistry control programs. A one-time inspection of selected components at

susceptible locations is an acceptable method to determine whether an aging effect is

occurring or is slowly progressing such that the component's intended functions will be

maintained during the period of extended operation.

The staff reviewed the AMR Tables in LRA Section 3.4 and plant basis documents and

found that there were no steel, stainless steel and copper alloy heat exchanger

components identified with a heat transfer function exposed to lubricating oil. On the

basis of this review, the staff finds that this SRP-LR Section is not applicable to SSES.

Based on the above, the staff concludes SRP-LR Section 3.4.2.2.4 criteria are not applicable.

3.4.2.2.5 Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced

Corrosion

The staff reviewed LRA Section 3.4.2.2.5 against the following criteria in SRP-LR

Section 3.4.2.2.5:

(1) LRA Section 3.4.2.2.5 addresses loss of material due to general, pitting, crevice, and

microbiologically-influenced corrosion in piping, piping components, and piping elements

exposed to soil. The applicant stated that this aging effect is not applicable because

there are no steel piping components or tanks exposed to soil in the steam and power

conversion system.

SRP-LR Section 3.4.2.2.5 states that loss of material due to general, pitting, and crevice

corrosion, and MIC may occur in steel (with or without coating or wrapping) piping,

piping components, piping elements, and tanks exposed to soil. The buried piping and

tanks inspection program relies on industry practice, frequency of pipe excavation, and

operating experience to manage the effects of loss of material from general, pitting, and

crevice corrosion, and MIC.

The effectiveness of the buried piping and tanks inspection program should be verified

to evaluate an applicant's inspection frequency and operating experience with buried

components to ensure that loss of material does not occur.

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The staff reviewed LRA Section 2.3.4 and verified that SSES does not have support

systems within the scope of license renewal that contain steel (with or without coating or

wrapping) piping, piping components, piping elements and tanks exposed to soil. The

only steam and power conversion system components exposed to soil are stainless

steel piping.

Based on the staff's review as described above and of LRA Section 3.4, the staff found

that there were no steel piping, piping components, piping elements and tanks exposed

to soil. On the basis of this review, the staff finds that SRP-LR Section 3.4.2.2.5.1 is not

applicable to SSES.

(2) LRA Section 3.4.2.2.5 addresses loss of material due to general, pitting, crevice, and

microbiologically-influenced corrosion in heat exchanger components exposed to

lubricating oil. The applicant stated that this aging effect is not applicable because there

are no steel heat exchanger components exposed to lubricating oil in the steam and

power conversion system.

SRP-LR Section 3.4.2.2.5 states that loss of material due to general, pitting, and crevice

corrosion, and MIC may occur in steel heat exchanger components exposed to

lubricating oil. The existing AMP periodically samples and analyzes lubricating oil to

maintain contaminants within acceptable limits, thereby preserving an environment not

conducive to corrosion. However, control of lube oil contaminants may not always be

fully effective in precluding corrosion; therefore, the effectiveness of lubricating oil

contaminant control should be verified to ensure that corrosion does not occur. The

GALL Report recommends further evaluation of programs to manage corrosion to verify

the effectiveness of the lube oil chemistry control program. A one-time inspection of

selected components at susceptible locations is an acceptable method to ensure that

corrosion does not occur and that component intended functions will be maintained

during the period of extended operation.

The staff reviewed the AMR Tables in LRA Section 3.4 and plant basis documents and

found that there were no steel heat exchanger components identified with a heat

transfer function exposed to lubricating oil. On the basis of this review, the staff finds

that this SRP-LR Section is not applicable to SSES.

Based on the above, the staff concludes SRP-LR Section 3.4.2.2.5 criteria are not applicable.

3.4.2.2.6 Cracking Due to Stress Corrosion Cracking

The staff reviewed LRA Section 3.4.2.2.6 against the criteria in SRP-LR Section 3.4.2.2.6.

LRA Section 3.4.2.2.6 addresses cracking due to stress corrosion cracking (SCC). The

applicant states that cracking due to SCC for stainless steel piping components exposed to

treated water or steam in the Steam and Power Conversion Systems is managed by the BWR

Water Chemistry Program. The BWR Water Chemistry Program manages aging effects

through periodic monitoring and control of contaminants. The CPEI will provide a verification of

the effectiveness of the BWR Water Chemistry Program to manage cracking due to SCC

through examination of stainless steel piping components exposed to treated water or steam.

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SRP-LR Section 3.4.2.2.6 states that cracking due to SCC may occur in stainless steel piping,

piping components, piping elements, tanks, and heat exchanger components exposed to

treated water greater than 600C (140 0F) and in stainless steel piping, piping components, and

piping elements exposed to steam. The existing AMP monitors and controls water chemistry to

manage the effects of cracking due to SCC. However, high concentrations of impurities in

crevices and with stagnant flow conditions may cause SCC; therefore, the GALL Report

recommends that the effectiveness of water chemistry control programs should be verified to

ensure that SCC does not occur. A one-time inspection of selected components at susceptible

locations is an acceptable method to ensure that SCC does not occur and that component

intended functions will be maintained during the period of extended operation.

The staff noted that the applicant combined components from LRA Table 3.4.1, item 3.4.1-14

with components in LRA Table 3.4.1, item 3.4.1-13, for the purpose of AMR. The applicant

described this in the discussion column for LRA Table 3.4.1, item 3.4.1-14. The staff noted that

the material, environment, aging effect and recommended AMPs for item 3.4.1-14 are the same

as for item 3.4.1-13, except that the environment in item 3.4.1-13 is steam (vaporized treated

water) and in item 3.4.1-14 is liquid (treated water) at temperature >600C (>1400 F). On the

basis that the material, environment, aging effect and recommended AMPs are the the identical

in LRA Table 3.4.1, items 3.4.1-13 and 3.4.1-14 (except for difference in liquid/vapor phase),

the staff finds it acceptable for the applicant to address all components associated with these

two lines under Table 3.4.1, item 3.4.1-13.

The staff reviewed the applicant's BWR Water Chemistry Program. The staff's evaluation of

this program, which is documented in SER Section 3.0.3.1.1, determined that the BWR Water

Chemistry Program is consistent with the GALL Report's recommendations for AMP XI.M2,

"Water Chemistry," and provides mitigation for the aging effect of cracking due to SCC. The

staff reviewed the applicant's Chemistry Program Effectiveness Inspection. The staff's

evaluation of this program, which is documented in SER Section 3.0.3.1.10, found that the

CPEl is a one-time inspection that is consistent with the GALL Report's recommendations for

AMP XI.M32, "One-Time Inspection." The applicant's CPEI includes provisions for inspecting

selected components in areas of low or stagnant flow and uses inspection techniques that are

capable of detecting cracking due to SCC, if it should occur in the selected components. Based

on the applicant's use of a chemistry program that provides mitigation of the aging effect and a

one-time inspection consistent with the recommendations of the GALL Report, the staff finds

the applicant's proposed AMPs for managing the aging effect of cracking due to SCC in

stainless steel piping components exposed to treated water >60 0C (>1401F) or to steam in the

steam and power conversion system to be acceptable.

Based on the programs identified above, the staff concludes that the applicant's programs meet

SRP-LR Section 3.4.2.2.6 criteria. For those line items that apply to LRA Section 3.4.2.2.6, the

staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21(a)(3).

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3.4.2.2.7 Loss of Material Due to Pitting and Crevice Corrosion

The staff reviewed LRA Section 3.4.2.2.7 against the following criteria in SRP-LR

Section 3.4.2.2.7:

(1) LRA Section 3.4.2.2.7 addresses loss of material due to pitting and crevice corrosion in

piping, piping components, piping elements, tanks, and heat exchanger components.

The applicant states that there are no aging effects identified for aluminum piping

components subject to AMR in the Steam and Power Conversion System. Loss of

material due to pitting and crevice corrosion for stainless steel piping components and

tanks, and copper alloy piping components, exposed to treated water in the Steam and

Power Conversion System is managed by the BWR Water Chemistry Program. The

BWR Water Chemistry Program manages aging effects through periodic monitoring and

control of contaminants. The CPEI will provide a verification of the effectiveness of the

BWR Water Chemistry Program to manage loss of material due to pitting and crevice

corrosion through examination of stainless steel piping components and tanks, and

copper alloy piping components, exposed to treated water.

SRP-LR Section 3.4.2.2.7 states that loss of material due to pitting and crevice

corrosion may occur in stainless steel, aluminum, and copper alloy piping, piping

components, and piping elements and in stainless steel tanks and heat exchanger

components exposed to treated water. The existing AMP monitors and controls water

chemistry to manage the effects of loss of material due to pitting, and crevice corrosion.

However, control of water chemistry may not preclude corrosion at locations with

stagnant flow conditions; therefore, the GALL Report recommends that the

effectiveness of water chemistry programs should be verified to ensure that corrosion

does not occur. A one-time inspection of selected components at susceptible locations

is an acceptable method to ensure that corrosion does not occur and that component

intended functions will be maintained during the period of extended operation.

The staff noted the applicant's statement that there are no aging effects identified for

aluminum piping components subject to AMR in the steam and power conversion

system. The staff issued RAI 3.4.2.2.7.1-1 by letter dated July 15, 2008, asking the

applicant to clarify whether this statement means that there are no aluminum

components in a treated water environment in the steam and power conversion system

or that there are such components but no aging effects are identified for those

components.

In a letter dated August 15, 2008, the applicant responded to RAI 3.4.2.2.7.1-1 by

providing the following response:

There are no aluminum piping components that are in-scope for license renewal and

that are exposed to a treated water environment in the steam and power conversion

system. The only aluminum piping components that are in-scope for license renewal and

that are in the steam and power conversion system are valve bodies in the MS system.

These valve bodies are exposed internally to a dry air-gas environment and externally to

indoor air environment as indicated in LRA Table 3.4.2-6.

The staff reviewed the applicant's response and the AMR results for the aluminum valve

bodies in LRA Table 3.4.2-6. The staff's evaluation of these components is documented

SER Table 3.4.1, item 3.4.1-44, and in SER Section 3.4.2.3. Because there are no

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aluminum piping components in the steam and power conversion system that are inscope for license renewal and in a treated water environment, the staff finds the

applicant's response to be acceptable. The staff finds the applicant's response

acceptable to have resolved the issue raised in RAI 3.4.2.2.7.1-1.

The staff reviewed the applicant's BWR Water Chemistry Program. The staff's

evaluation of this program., which is documented in SER Section 3.0.3.1.1, determined

that the BWR Water Chemistry Program is consistent with the GALL Report's

recommendations for AMP XI.M2, "Water Chemistry," and provides mitigation for the

aging effect of loss of material due to pitting and crevice corrosion. The staff reviewed

the applicant's Chemistry Program Effectiveness Inspection. The staff's evaluation of

this program, which is documented in SER Section 3.0.3.1.10, found that the CPEI is a

one-time inspection that is consistent with the GALL Report's recommendations for

AMP XI.M32, "One-Time Inspection." The CPEl includes provisions for inspecting

selected components in areas of low or stagnant flow and is capable of detecting loss of

material due to pitting or crevice corrosion, if it should occur in the selected components.

Based on the applicant's use of a water chemistry program that provides mitigation of

the aging effect and use of a one-time inspection consistent with the recommendations

of the GALL Report, the staff finds the applicant's proposed AMPs for managing the

potential aging effect of loss of material due to pitting or crevice corrosion in stainless

steel piping components and tanks and copper alloy piping components exposed to

treated water in the steam and power conversion system to be acceptable.

(2) LRA Section 3.4.2.2.7 addresses loss of material due to pitting and crevice corrosion in

piping, piping components, piping elements exposed to soil. The applicant states that

loss of material due to pitting and crevice corrosion for stainless steel piping

components exposed to soil is managed by the Buried Piping and Tanks Inspection

Program.

SRP-LR Section 3.4.2.2.7 states that loss of material due to pitting and crevice

corrosion may occur in stainless steel piping, piping components, and piping elements

exposed to soil. The GALL Report recommends further evaluation of a plant-specific

AMP to ensure that the aging effect is adequately managed.

The applicant has indicated generic Note E for this line item which is "Consistent with

NUREG-1801 item for material, environment, and aging effect, but a different aging

management program is credited or NUREG-1801 identifies a plant-specific aging

management program." Because the GALL XI.M34, "Buried Piping and Tanks

Inspection" Program does not discuss piping and tanks constructed from materials

besides carbon steel, GALL calls out a plant-specific aging management program for

this buried stainless steel program and specifies further evaluation. The staff reviewed

the applicant's Buried Piping and Inspection Program. The staff's evaluation of this

program, which is documented in SER Section 3.0.3.2.13 found that the Buried Piping

Inspection Program is based on the applicant's plant-specific operating experience that

uncoated stainless steel buried piping has not experienced degradation. However the

applicant has conservatively added the buried stainless steel piping within the scope of

this program to ensure that degradation has not occurred. The staff noted that a visual

inspection that will be performed by the applicant on the buried stainless steel piping

within 10 years of entering the period of extended operation will be capable of detecting

age-related degradation as a result of loss of material, consistent with the GALL

recommendations. The American Water Works Association standard for stainless steel

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piping is AWWA C220, "Stainless Steel Piping." On the basis of its review, the staff finds

the applicant has conservatively included stainless steel piping in the scope of this

program to be inspected within 10 years of entering the period of extended operation

and that a visual inspection of the external surface will be capable of detecting loss of

material.

(3) LRA Section 3.4.2.2.7 addresses loss of material due to pitting and crevice corrosion in

piping, piping components, and piping elements exposed to lubricating oil. The applicant

stated that this aging effect is not applicable because there is no copper alloy piping,

piping components, or piping elements that are exposed to lubricating oil in the steam

and power conversion system.

SRP-LR Section 3.4.2.2.7 states that loss of material due to pitting and crevice

corrosion may occur in copper alloy piping, piping components, and piping elements

exposed to lubricating oil. The existing AMP periodically samples and analyzes

lubricating oil to maintain contaminants within acceptable limits, thereby preserving an

environment not conducive to corrosion. However, control of lube oil contaminants may

not always be fully effective in precluding corrosion; therefore, the effectiveness of

lubricating oil contaminant control should be verified to ensure that corrosion does not

occur. The GALL Report recommends further evaluation of programs to manage

corrosion to verify the effectiveness of the lube oil chemistry control program. A onetime inspection of selected components at susceptible locations is an acceptable

method to ensure that corrosion does not occur and that component intended functions

will be maintained during the period of extended operation.

The staff reviewed LRA Section 2.3.4 and verified that SSES does not have support

systems within the scope of license renewal that contain the piping, piping components

and piping elements fabricated from copper alloy exposed to lubricating oil.

Based on the staff's review of LRA Section 3.4 there were no copper alloy piping, piping

components and piping elements exposed to lubricating oil internally or externally. On

the basis of this review, the staff finds that SRP-LR Section 3.4.2.2.7 Item 3 is not

applicable to SSES.

Based on the programs identified above, the staff concludes that the applicant's programs meet

SRP-LR Section 3.4.2.2.7 criteria. For those line items that apply to LRA Section 3.4.2.2.7, the

staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

3.4.2.2.8 Loss of Material Due to Pitting, Crevice, and Microbiologically-Influenced Corrosion

The staff reviewed LRA Section 3.4.2.2.8 against the criteria in SRP-LR Section 3.4.2.2.8.

LRA Section 3.4.2.2.8 addresses loss of material due to pitting, crevice, and microbiologically

influenced corrosion. The applicant stated that this aging effect is not applicable because there

are no stainless steel piping, piping components, piping elements, or heat exchanger

components exposed to lubricating oil in the steam and power conversion system.

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SRP-LR Section 3.4.2.2.8 states that loss of material due to pitting and crevice corrosion, and

MIC may occur in stainless steel piping, piping components, piping elements, and heat

exchanger components exposed to lubricating oil. The existing AMP periodically samples and

analyzes lubricating oil to maintain contaminants within acceptable limits, thereby preserving an

environment not conducive to corrosion. However, control of lube oil contaminants may not

always be fully effective in precluding corrosion; therefore, the effectiveness of lubricating oil

contaminant control should be verified to ensure that corrosion does not occur. The GALL

Report recommends further evaluation of programs to manage corrosion to verify the

effectiveness of the lube oil chemistry control program. A one-time inspection of selected

components at susceptible locations is an acceptable method to ensure that corrosion does not

occur and that component intended functions will be maintained during the period of extended

operation.

The staff reviewed LRA Section 2.3.4 and verified that SSES does not have support systems

with-in the scope of license renewal that contain the piping, piping components and elements

and heat exchanger components fabricated from stainless steel exposed to lubricating oil.

Based on the staff's review as described above and of LRA Section 3.4 and found that there

were no stainless steel piping, piping components and elements and heat exchanger

components exposed to lubricating oil internally or externally. On the basis of this review, the

staff finds that SRP-LR Section 3.4.2.2.8 is not applicable to SSES.

Based on the above, the staff concludes SRP-LR Section 3.4.2.2.8 criteria are not applicable.

3.4.2.2.9 Loss of Material Due to General, Pitting, Crevice, and Galvanic Corrosion

The staff reviewed LRA Section 3.4.2.2.9 against the criteria in SRP-LR Section 3.4.2.2.9.

LRA Section 3.4.2.2.9 addresses loss of material due to general, pitting, crevice, and galvanic

corrosion. The applicant stated that this aging effect is not applicable because there are no

steel heat exchanger components exposed to treated water in the steam and power conversion

system.

SRP-LR Section 3.4.2.2.9 states that loss of material due to general, pitting, crevice, and

galvanic corrosion may occur in steel heat exchanger components exposed to treated water.

The existing AMP monitors and controls water chemistry to manage the effects of loss of

material due to general, pitting, and crevice corrosion. However, control of water chemistry

does not preclude loss of material due to general, pitting, and crevice corrosion at locations with

stagnant flow conditions; therefore, the effectiveness of water chemistry control programs

should be verified to ensure that corrosion does not occur. The GALL Report recommends that

the effectiveness of water chemistry should be verified to confirm that corrosion does not occur.

A one-time inspection of selected components and susceptible locations is an acceptable

method to ensure that corrosion does not occur and that component intended functions will be

maintained during the period of extended operation.

The staff reviewed the AMR Tables in LRA Section 3.4 and found that there were no heat

exchanger components exposed to treated water. On the basis of this review, the staff finds

that this SRP-LR Section is not applicable to SSES.

Based on the above, the staff concludes SRP-LR Section 3.4.2.2.9 criteria are not applicable.

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3.4.2.2.10 Quality Assurance for Aging Management of Nonsafety-Related Components

SER Section 3.0.4 documents the staff's evaluation of the applicant's QA program.

3.4.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report

In LRA Tables 3.4.2-1 through 3.4.2-10, the staff reviewed additional details of the AMR results

for material, environment, AERM, and AMP combinations not consistent with or not addressed

in the GALL Report.

In LRA Tables 3.4.2-1 through 3.4.2-10, the applicant indicated, via notes F through J, which

the combination of component type, material, environment, and AERM does not correspond to

a line item in the GALL Report. The applicant provided further information about how it will

manage the aging effects. Specifically, note F indicates that the material for the AMR line item

component is not evaluated in the GALL Report. Note G indicates that the environment for the

AMR line item component and material is not evaluated in the GALL Report. Note H indicates

that the aging effect for the AMR line item component, material, and environment combination

is not evaluated in the GALL Report. Note I indicates that the aging effect identified in the GALL

Report for the line item component, material, and environment combination is not applicable.

Note J indicates that neither the component nor the material and environment combination for

the line item is evaluated in the GALL Report.

For component type, material, and environment combinations not evaluated in the GALL

Report, the staff reviewed the applicant's evaluation to determine whether the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB for the period of extended operation. The

staff's evaluation is documented in the following sections.

3.4.2.3.1 Aging Management Review Results - Auxiliary Boiler System - LRA Table 3.4.2-1

The staff reviewed LRA Table 3.4.2-1, which summarizes the results of AMR evaluations for the

auxiliary boiler system component groups. The staff determined that all AMR evaluation

results in LRA Table 3.4.2-1 are consistent with the GALL Report.

3.4.2.3.2 Aging Management Review Results - Bypass Steam System - LRA Table 3.4.2-2

The staff reviewed LRA Table 3.4.2-2, which summarizes the results of AMR evaluations for the

bypass steam system component groups.

LRA Table 3.4.2-2 summarizes the results of AMRs for bypass steam valve bodies constructed

from carbon steel and exposed to indoor air (internal) and treated water (internal) for which the

applicant proposed no aging effect and therefore no AMP is required.

The applicant has indicated that generic Note I is applicable for these items. Generic Note I is

"Aging effect in NUREG-1 801 for this component, material, and environment is not applicable."

The applicant explains in plant-specific Note 0406 why there are no aging effects requiring

management. Plant-specific Note 0406 states "The assumption is made for license renewal that

the occurrence of any aging effects results in minimal impact to the overall volume and surface

area associated with the MSIV Leakage ICTM functions of hold-up and plate-out (ICTM

Volume), and does not adversely affect the successful performance of this component intended

function. This assumption is supported by the fact that vacuum is maintained on the condenser

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during normal plant operation, and any leakage that enters the condenser post-accident is

subsequently released to the atmosphere. Any age-related degradation that impacts normal

plant operations would be indicated by a loss of vacuum and be resolved well before any

significant impact to the available volume and surface area is experienced (For example,

Condenser leakage is typically tracked and reported as Off-gas Flow Rate in support of normal

plant operation). Therefore, since the successful performance of the ICTM function will not be

realistically prevented by any age-related degradation, there are no aging effects requiring

management for any components of the steam systems if the only component intended function

is ICTM Volume." The staff agrees that there will not be an aging mechanism for this

material/environment combination because the materials of interest will not be exposed to the

environment of indoor air except for brief periods of time.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.4.2.3.3 Aging Management Review Results - Condensate Transfer and Storage System -

LRA Table 3.4.2-3

The staff reviewed LRA Table 3.4.2-3, which summarizes the results of AMR evaluations for the

condensate transfer and storage system component groups.

In LRA Table 3.4.2-3, the applicant proposed to manage loss of material due to crevice and

pitting corrosion of stainless steel tanks in an internal environment of ventilation at air/water

interfaces by using the Supplementary Piping/Tank Inspection Program. The applicant

referenced footnote "G" for this line item indicating that the environment is not in the GALL

Report for this component and material combination.

The staff reviewed the Supplementary Piping/Tank Inspection Program, which uses a

combination of volumetric and visual examination techniques to identify evidence of loss of

material or lack thereof. The staff's evaluation of the Supplementary Piping/Tank Inspection

Program is documented in SER Section 3.0.3.1.16. Because the Supplementary Piping/Tank

Inspection is performed at very specific locations of air/water interface, and employs a

combination of volumetric and visual inspection techniques, the staff finds that the

Supplementary Piping/Tank Inspection Program will adequately manage the aging effects of

loss of material in this aggressive environment.

In LRA Tables 3.4.2-3, the applicant proposed to manage cracking in copper alloy piping and

piping components in an environment of treated water by using the BWR Water Chemistry

Program, alone. The applicant cited generic Note G for these AMR results, indicating that the

aging effect is not in the GALL Report for this component, material and environment

combination. The staff issued RAI 3.2-3 by letter dated July 15, 2008, applicable for these AMR

results and for similar AMR results in LRA Tables 3.2.2-1, 3.2.2-3, 3.3.2-3, and 3.3.2-25. The

RAI asked the applicant to provide a technical justification as to why an inspection program,

such as the CPEI is not needed to confirm that the BWR Water Chemistry Program is effective

in preventing the aging effect.

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In a letter dated August 15, 2008, the applicant responded to RAI 3.2-3 by providing the

following response:

For the five AMR results lines listed in LRA Tables 3.2.2-1, 3.2.2-3, 3.3.2-3,

3.3.2-25, and 3.4.2-3, where the material is copper alloy, the environment is

treated water (internal), and the aging effect is cracking, verification of the

effectiveness of the BWR Water Chemistry Program is needed. The CPEI will

provide confirmation of the effectiveness of this program in managing the effects

of aging, including cracking in susceptible materials.

LRA Tables 3.2.2-1, 3.2.2-3, 3.3.2-3, 3.3.2-25, and 3.4.2-3 are revised to reflect

these results.

The staff reviewed the applicant's response and the associated LRA changes. The staff

reviewed the applicant's BWR Water Chemistry Program. The staff's evaluation of this

program, which is documented in SER Section 3.0.3.1.1, found that the BWR Water Chemistry

Program provides mitigation for the aging effect of cracking due to stress corrosion cracking.

The staff reviewed the applicant's Chemistry Program Effectiveness Inspection. The staff's

evaluation of this program, which is documented in SER Section 3.0.3.1.10, found that the

CPEI is a one-time inspection that is consistent with the GALL Report's recommendations for

AMP XI.M32, "One-Time Inspection." The CPEI includes provisions for inspecting selected

components in areas of low or stagnant flow and uses examination techniques that are capable

of detecting cracking, if it should occur in the selected components. Because the BWR Water

Chemistry Program provides mitigation and the CPEI provides detection of the aging effect if it

should occur, the staff finds the applicant's proposed AMPs for managing the potential aging

effect of cracking due to stress corrosion cracking in copper alloy piping and piping components

exposed to treated water in the condensate transfer and storage system to be acceptable. On

this basis, the staff finds that the issue raised in RAI 3.2-3 is resolved by the applicant's LRA

changes.

LRA Table 3.4.2-3 summarizes the results of AMRs for the Condensate Transfer and Storage

System for valve bodies tubing, and piping constructed from stainless steel and exposed to

outdoor air (external) and ventilation (interior) and proposed no aging effect and therefore that

no AMP is required.

The applicant has indicated that generic Note G is applicable for these items. Generic Note G is

"Environment not in NUREG-1801 for this component and material." The staff confirmed that

this environment is not in GALL for this component and material. The staff also agrees that

there will not be aging mechanism for this material/environment combination and that no AMP

is required. The staff noted that stainless steel is highly resistant to corrosion in dry

atmospheres in the absence of corrosive species (which would be reflective of indoor

uncontrolled air), as cited in Metals Handbook, Volumes 3 (p. 65) and 13 (p.555) (Ninth Edition,

American Society for Metals International, 1980 and 1987). Components are not subject to

moisture in a dry air environment (and indoor uncontrolled air would have limited humidity and

condensation). Therefore, the staff finds that stainless steel in an indoor, uncontrolled air

environment exhibits no aging effect, and the component or structure will remain capable of

performing intended functions consistent with the CLB for the period of extended operation.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

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adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.4.2.3.4 Aging Management Review Results - Condenser and Air Removal System -

LRA Table 3.4.2-4

The staff reviewed LRA Table 3.4.2-4, which summarizes the results of AMR evaluations for the

condenser and air removal system component groups.

In Table 3.4.2-4, the LRA states that for synthetic rubber flexible connections in treated water

internal and indoor air external environments in the condenser and air removal system, there

are no aging effects requiring management. In RAI 3.4.2.3-1 Part A, by letter dated

July 23, 2008, the staff asked the applicant to justify why it had not identified any aging effects

requiring management for these system-material-environment combinations. In RAI 3.4.2.3-1,

Part B, the staff asked the applicant to identify the rubber material that is used to fabricate the

flexible expansion joints in the CAR systems and to identify those material properties and aging

effects that could be impacted by exposure of these rubber materials to the treated water and

indoor air environments.

In its letter dated August 27, 2008, the applicant responded to the RAI 3.4.2.3-1 Part A, and

stated that there were no aging effects identified as requiring management because no aging

effects were considered to be of significance that would prevent the intended function in this

application of maintaining the ICTM volume (isolated condenser treatment method) as defined

in LRA Table 2.0-1 and discussed in LRA Section 2.3.4.4.

In its response to RAI Part B, the applicant stated that the materials that are used to fabricate

acceptable replacements for the flexible expansion joints (condenser boots) in the Condenser

and Air Removal System are neoprene-impregnated nylon, or nitrile-impregnated nylon. The

applicant also stated that the material properties that could be impacted include hardening (loss

of flexibility) and loss of strength. As a result of a further evaluation of the AMR for the

Condenser and Air Removal System, the applicant determined that the rubber expansion joints

(condenser boots) are subject to replacement on a specified time period in accordance with

plant preventive maintenance activities. The applicant further stated that the expansion joints

are, therefore, short-lived components and are not subject to AMR. The applicant amended the

LRA to revise Section 3.4.2.1.4 to delete rubber material from the list of materials; and revised

Table 3.4.2.1-4, to delete the commodity type rubber flexible connections (expansion joints) in

treated water and air-indoor environments.

The staff reviewed the applicant response and noted that the expansion joints are replaced on a

specified time period. SRP-LR Section 2.1.3.2.2, "Long-Lived", identifies long-lived passive

structures and components as those that are not subject to periodic replacement based on

specified time period. Therefore, staff finds that the rubber expansion joints that are replaced

on a specified time period are considered short-lived components and are not subject to AMR

and can be deleted from LRA Table 3.4.2.1-4. On this basis, the staff finds the applicant

response acceptable and considers this issue closed.

LRA Table 3.4.2-4 summarizes the results of AMRs for the Condenser and Air Removal System

carbon steel piping exposed to treated water (internal), condensers (inlet/outlet water boxes)

condensers (tubesheet) and condensers (shell) exposed to indoor air (external) and

condensers (inlet/outlet water boxes) condensers (tubesheet), condensers (tubes) and

condensers (shell) exposed to raw water (internal) and condensers (tubesheet) and (tubes)

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exposed to raw water (internal) and condensers (tubesheet) exposed to treated water (external)

and stainless steel condensers tube plugs exposed to raw water and treated water (external)

and exposed to indoor air (external) and treated water (internal). The applicant proposed that

this material-environment combination has no aging effects requiring management and that no

AMR is required.

The applicant has indicated that generic Note I is applicable for these items. Generic Note I

0406 is "Aging effect in NUREG-1801 for this component, material, and environment is not

applicable." Note 0406 states: "The assumption is made for license renewal that the

occurrence of any aging effects results in minimal impact to the overall volume and surface

area associated with the MSIV Leakage ICTM functions of hold-up and plate-out (ICTM

Volume), and does not adversely affect the successful performance of this component intended

function. This assumption is supported by the fact that vacuum is maintained on the condenser

during normal plant operation, and any leakage that enters the condenser post-accident is

subsequently released to the atmosphere. Any age-related degradation that impacts normal

plant operations would be indicated by a loss of vacuum and be resolved well before any

significant impact to the available volume and surface area is experienced (For example,

condenser in leakage is typically tracked and reported as Off-gas Flow Rate in support of

normal plant operation). Therefore, since the successful performance of the ICTM function will

not be realistically prevented by any age-related degradation, there are no aging effects

requiring management for any components of the steam systems if the only component

intended function is ICTM Volume."

The staff agrees that there will not be an aging mechanism for this material/environment

combination because the materials of interest will not be exposed to the environment of indoor

air except for brief periods of time and any degradation that would occur would be insignificant.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.4.2.3.5 Aging Management Review Results - Feedwater System - LRA Table 3.4.2-5

The staff reviewed LRA Table 3.4.2-5, which summarizes the results of AMR evaluations for the

feedwater system component groups.

In LRA Table 3.4.2-5, the applicant stated that for steel piping and valve bodies in an

environment of air-indoor external, there are no aging effects and no aging management

program is required. The applicant has indicated that generic Note I and specific Note 413 are

applicable for these items. Generic Note I is "Aging effect in NUREG-1 801 for this component,

material, and environment is not applicable." Note 0413 states: "External surface temperature

for this component type is > 1000C (212 0 F), therefore no moisture is present to promote aging."

As noted from Corrosion Handbook by H.H.Uhlig, general corrosion is the result of a chemical

or electrochemical reaction between a material and an aggressive environment. The staff

further noted that at ordinary temperatures, oxygen and moisture are the primary factors for

corrosion to form. Also, both oxygen and moisture must be present because oxygen alone or

water free of oxygen does not corrode steel to any extent. The staff noted that the feedwater

piping operating temperature is usually above 212'F, which is significantly above the ambient

temperature inside the plant. The staff determined that at this temperature, moisture will not

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collect on the external surfaces, but will evaporate and leave the surface dry. Based on this

review, the staff finds that for feedwater system steel piping and valve bodies in an environment

of indoor-air external, there are no aging effects because for corrosion to occur moisture must

be present, and for piping external surface temperatures above 212 0F, moisture will evaporate

and leave the surface dry. Therefore, the staff finds that steel piping and valve bodies in the

feedwater system, in an environment of air-indoor external, there are no aging effects and no

aging management program is required.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.4.2.3.6 Aging Management Review Results - Main Steam System - LRA Table 3.4.2-6

The staff reviewed LRA Table 3.4.2-6, which summarizes the results of AMR evaluations for the

MS system component groups.

In LRA Table 3.4.2-6, the applicant proposed to manage loss of material of carbon steel piping

and valves in an internal environment of ventilation at air/water interfaces by using the

Supplementary Piping/Tank Inspection Program. The applicant referenced footnote "G" for this

line item indicating that the environment is not in the GALL Report for this component and

material combination. The applicant also referenced footnote 0401 which indicates that loss of

material is due to crevice and/or pitting corrosion on the inside surface of SRV discharge piping

at air/water interface in the suppression pool, and also, on the outside surface of SRV

discharge piping at air/water interface in the suppression pool.

The staff reviewed the Supplementary Piping/Tank Inspection Program, which uses a

combination of volumetric and visual examination techniques to identify evidence of loss of

material or lack thereof. The staff's evaluation of the Supplementary Piping/Tank Inspection

Program is documented in SER Section 3.0.3.1.6. Because the Supplementary Piping/Tank

Inspection is performed at very specific locations of air/water interface, and employs a

combination of volumetric and visual inspection techniques, the staff finds that the

Supplementary Piping/Tank Inspection Program will adequately manage the aging effects of

loss of material in this aggressive environment.

LRA Table 3.4.2-6 summarizes the results of AMRs for the MS System line valve bodies and

piping constructed from carbon steel and exposed to indoor air (external) and treated water

(internal) and the applicant proposed that this material-environment combination has no aging

effects requiring management and no AMR is required.

The applicant has indicated that generic Note I is applicable for these items. Generic Note I

0406 is "Aging effect in NUREG-1 801 for this component, material, and environment is not

applicable." Note 0406 states: "The assumption is made for license renewal that the

occurrence of any aging effects results in minimal impact to the overall volume and surface

area associated with the MSIV Leakage ICTM functions of hold-up and plate-out (ICTM

Volume), and does not adversely affect the successful performance of this component intended

function. This assumption is supported by the fact that vacuum is maintained on the condenser

during normal plant operation, and any leakage that enters the condenser post-accident is

subsequently released to the atmosphere. Any age-related degradation that impacts normal

plant operations would be indicated by a loss of vacuum and be resolved well before any

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significant impact to the available volume and surface area is experienced (For example,

Condenser in leakage is typically tracked and reported as Off-gas Flow Rate in support of

normal plant operation).

Therefore, since the successful performance of the ICTM function will not be realistically

prevented by any age-related degradation, there are no aging effects requiring management for

any components of the steam systems if the only component intended function is ICTM

Volume.

The staff agrees that there will not be an aging mechanism for this material/environment

combination because the materials of interest will not be exposed to the environment of indoor

air except for brief periods of time and any degradation that would occur would be insignificant.

LRA Table 3.4.2-6 summarizes the results of AMRs for MS valve bodies constructed from

aluminum and exposed to indoor air (external) and for which the applicant proposed no aging

effect and therefore no AMP is required.

The applicant has indicated that generic Note G is applicable for these items. Generic Note G is

"Environment not in NUREG-1801 for this component and material." However, the staff noted

that GALL Report Item VII.J-1 addresses this component, material and environment and states

that for aluminum piping, piping components, and piping elements in an environment of airindoor controlled (external), there are no aging effects and no aging management program

required. Since the applicant is consistent with the GALL Report, the staff finds that for MS

valve bodies constructed from aluminum and exposed to indoor air (external), there are no

aging effects and therefore no AMP is required.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.4.2.3.7 Aging Management Review Results - Main Turbine System - LRA Table 3.4.2-7

The staff reviewed LRA Table,3.4.2-7, which summarizes the results of AMR evaluations for the

main turbine system component groups.

LRA Table 3.4.2-7 summarizes the results of AMRs for the Main Turbine System turbine

casings (low pressure) constructed from carbon steel and exposed to indoor air (external) and

treated water (internal) and the applicant proposed that this material-environment combination

has no aging effects requiring management and that no AMR is required.

The applicant has indicated that generic Note I 0406 is applicable for these items. Generic Note

I is "Aging effect in NUREG-1801 for this component, material, and environment is not

applicable." Note 0406 states: "The assumption is made for license renewal that the

occurrence of any aging effects results in minimal impact to the overall volume and surface

area associated with the MSIV Leakage ICTM functions of hold-up and plate-out (ICTM

Volume), and does not adversely affect the successful performance of this component intended

function. This assumption is supported by the fact that vacuum is maintained on the condenser

during normal plant operation, and any leakage that enters the condenser post-accident is

subsequently released to the atmosphere. Any age-related degradation that impacts normal

plant operations would be indicated by a loss of vacuum and be resolved well before any

I

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significant impact to the available volume and surface area is experienced (For example,

Condenser in leakage is typically tracked and reported as Off-gas Flow Rate in support of

normal plant operation).

Therefore, since the successful performance of the ICTM function will not be realistically

prevented by any age-related degradation, there are no aging effects requiring management for

any components of the steam systems if the only component intended function is ICTM

Volume."

The staff agrees that there will not be an aging mechanism for this material/environment

combination because the materials of interest will not be exposed to the environment of indoor

air except for brief periods of time and any degradation that would occur would be insignificant.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.4.2.3.8 Aging Management Review Results - Makeup Demineralizer System -

LRA Table 3.4.2-8

The staff reviewed LRA Table 3.4.2-8, which summarizes the results of AMR evaluations for the

makeup demineralizer system component groups. The staff determined that all AMR evaluation

results in LRA Table 3.4.2-8 are consistent with the GALL Report.

3.4.2.3.9 Aging Management Review Results -Makeup Transfer and Storage System -

LRA Table 3.4.2-9

The staff reviewed LRA Table 3.4.2-9, which summarizes the results of AMR evaluations for the

makeup transfer and storage system component groups. The staff determined that all AMR

evaluation results in LRA Table 3.4.2-9 are consistent with the GALL Report.

3.4.2.3.10 Aging Management Review Results - Refueling Water Transfer and Storage System

- LRA Table 3.4.2-10

The staff reviewed LRA Table 3.4.2-10, which summarizes the results of AMR evaluations for

the refueling water transfer and storage system component groups. The staff determined that

all AMR evaluation results in LRA Table 3.4.2-10 are consistent with the GALL Report.

3.4.3 Conclusion

The staff concludes that the applicant has provided sufficient information to demonstrate that

the effects of aging for the steam and power conversion systems components within the scope

of license renewal and subject to an AMR will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21(a)(3).

3-453
3.5 Aging Management of Containments. Structures, and Component Supports

This section of the SER documents the staff's review of the applicant's AMR results for the

containments, structures, and components supports components and component groups of:

* Primary Containment

* Reactor Building

* Engineered Safeguards Service Water Pumphouse and Spray Pond

* Circulating Water Pumphouse and Water Treatment Building

* Control Structure

* Diesel Generator 'A, B, C, And D' Building

* Diesel Generator 'E' Building

* Turbine Building

* Yard Structures

* Bulk Commodities

3.5.1 Summary of Technical Information in the Application

LRA Section 3.5 provides AMR results for the containments, structures, and components

supports components and component groups. LRA Table 3.5.1, "Summary of Aging

Management Programs for Structures and Component Supports Evaluated in Chapters II and

III of the GALL Report," is a summary comparison of the applicant's AMRs with those evaluated

in the GALL Report for the containments, structures, and components supports components

and component groups.

The applicant's AMRs evaluated and incorporated applicable plant-specific and industry OE in

the determination of AERMs. The plant-specific evaluation included condition reports and

discussions with appropriate site personnel to identify AERMs. The applicant's review of

industry OE included a review of the GALL Report and OE issues identified since the issuance

of the GALL Report.

3.5.2 Staff Evaluation

The staff reviewed LRA Section 3.5 to determine whether the applicant provided sufficient

information to demonstrate that the effects of aging for the containments, structures, and

components supports components within the scope of license renewal and subject to an AMR,

will be adequately managed so that the intended function(s) will be maintained consistent with

the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).

The staff conducted an onsite audit of AMRs to ensure the applicant's claim that certain AMRs

were consistent with the GALL Report. The staff did not repeat its review of the matters

described in the GALL Report; however, the staff did verify that the material presented in the

LRA was applicable and that the applicant identified the appropriate GALL Report AMRs. The

staff's evaluations of the AMPs are documented in SER Section 3.0.3. Details of the staff's

audit evaluation are documented in SER Section 3.5.2.1.

In the onsite audit, the staff also selected AMRs consistent with the GALL Report and for which

further evaluation is recommended. The staff confirmed that the applicant's further evaluations

were consistent with the SRP-LR Section 3.5.2.2 acceptance criteria. The staff's audit

evaluations are documented in SER Section 3.5.2.2.

3-454
The staff also conducted a technical review of the remaining AMRs not consistent with or not

addressed in the GALL Report. The technical review evaluated whether all plausible aging

effects have been identified and whether the aging effects listed were appropriate for the

material-environment combinations specified. The staff's evaluations are documented in SER

Section 3.5.2.3.

For SSCs which the applicant claimed were not applicable or required no aging management,

the staff reviewed the AMR line items and the plant's OE to verify the applicant's claims.

Table 3.5-1 summarizes the staff's evaluation of components, aging effects or mechanisms,

and AMPs listed in LRA Section 3.5 and addressed in the GALL Report.

Table 3.5-1 Staff Evaluation for Containments, Structures, and Component Supports in

the GALL Report

Component, 'Aging Effect/ AMP In GALL., Further AMP in LRA, Staff Evaluation

Grou'op ::Mechanism Report Evaluation Supplements,

(GALL Report in GALL., or

Item No.):' ____ - __" "________________ Report, Amendments.

BWR Concrete and Steel (Mark 1, 11, and Ill) Containments

Concrete Aging of accessible ISI (!WL) and for Yes ISI (IWL) Consistent with

elements: walls, and inaccessible inaccessible concrete, Program GALL Report, which

dome, basemat, concrete areas due an examination of (B.2.35) recommends further

ring girder, to aggressive representative evaluation (See

buttresses, chemical attack, and samples of below- SER Section

containment corrosion of grade concrete, and 3.5.2.2.1.1)

(as applicable) embedded steel periodic monitoring of

(3.5.1-1) groundwater if

environment is nonaggressive.. A plantspecific program is to

be evaluated if

environment is

aggressive.

Concrete Cracks and Structures Monitoring Yes Not applicable Not applicable to

elements; All distortion due to Program. If a SSES for further

(3.5.1-2) increased stress de-watering system is evaluation (See

levels from relied upon for control SER Section

settlement of settlement, then the 3.5.2.2.1.2)

licensee is to ensure

proper functioning of

the de-watering

system through the

period of extended

operation.

3-455
SComponentC Aý•'rgAging Effectl, '..AMP ,in GALL Further, AMP in LRA, Staff Evaluation •Group/ •Mechanism Report Evaluation Supplements,

(GALL Report in.GALLL or

ItemNo.)' r '.Report'-,- Amendments

Concrete Reduction in Structures Monitoring Yes Not applicable Not applicable to

elements: foundation strength, Program If a de- SSES for further

foundation, cracking, differential watering system is evaluation (See

sub-foundation settlement due to relied upon to control SER Section

(3.5.1-3) erosion of porous erosion of cement 3.5.2.2.1.2)

concrete from porous concrete

subfoundation subfoundations, then

the licensee is to

ensure proper

functioning of the dewatering system

through the period of

extended operation.

Concrete Reduction of A plant-specific aging Yes Not applicable Not applicable to

elements: dome, strength and management program SSES (See SER

wall, basemat, modulus of concrete is to be evaluated. Section 3.5.2.2.1.3)

ring girder, due to elevated

buttresses, temperature

containment,

concrete fill-in

annulus

(as applicable)

(3.5.1-4)

Steel elements: Loss of material due ISI (IWE) and Yes ISI (IWE) Consistent with

drywell; torus; to general, pitting 10 CFR Part 50, Program GALL Report, which

drywell head; and crevice Appendix J (B.2.34), and recommends further

embedded shell corrosion Containment evaluation (See

and sand pocket Leakage Rate SER Section

regions; drywell Test Program 3.5.2.2.1.4)

support skirt; (B.2.37)

torus ring girder;

downcomers;

liner plate, ECCS

suction header,

support skirt,

region shielded

by diaphragm

floor, suppression

chamber

(as applicable)

(3.5.1-5)

Steel elements: Loss of material due ISI (IWE) and Yes ISI (IWE) Consistent with

steel liner, liner to general, pitting 10 CFR Part 50, Program GALL Report, which

anchors, integral and crevice Appendix J (B.2.34), and recommends further

attachments corrosion Containment evaluation (See

(3.5.1-6) Leakage Rate SER Section

Test Program 3.5.2.2.1.4)

(B.2.37)

Prestressed Loss of prestress TLAA, evaluated in Yes Not applicable Not applicable to

containment due to relaxation, accordance with SSES (See SER

tendons shrinkage, creep, 10 CFR 54.21(c) Section 3.5.2.1.1

(3.5.1-7) and elevated and 3.5.2.2.1.5)

temperature

3-456
Component• ' Aging Effect-r AMP in GALL iFurther , AMP in LRA, staff Evaluation

Group IMehanism Report Evaluation Supplements,,

(GALL-Report. inGALL or,

Item No.) _________ ,_ Report Amendments.

Steel and Cumulative fatigue TLAA, evaluated in Yes TLAA Consistent with

stainless steel damage (CLB accordance with GALL Report, which

elements: vent fatigue analysis 10 CFR 54.21(c) recommends further

line, vent header, exists) evaluation (See

vent line bellows; SER Section 4.6

downcomers; and 3.5.2.2.1.6

(3.5.1-8)

Steel, stainless Cumulative fatigue TLAA, evaluated in Yes TLAA Consistent with

steel elements, damage (CLB accordance with GALL Report, which

dissimilar metal fatigue analysis 10 CFR 54.21(c) recommends further

welds: exists) evaluation (See

penetration SER Section

sleeves, 3.5.2.2.1.6 and

penetration section 4.6)

bellows;

suppression pool

shell, unbraced

downcomers

(3.5.1-9)

Stainless steel Cracking due to SCC ISI (IWE) and Yes Not applicable Not applicable to

penetration 10 CFR Part 50, SSES for further

sleeves, Appendix J, and evaluation (See

penetration additional appropriate SER Section

bellows, examinations/ 3.5.2.2.1.7)

dissimilar metal evaluations for

welds bellows assemblies

(3.5.1-10) and dissimilar metal

welds.

Stainless steel Cracking due to SCC ISI (IWE) and Yes Not applicable Not applicable to

vent line bellows, 10 CFR Part 50, SSES (See SER

(3.5.1-11) Appendix J, and Section 3.5.2.2.1.7)

additional appropriate

examination/

evaluation for bellows

assemblies and

dissimilar metal

welds.

Steel, stainless Cracking due to ISI (IWE) and Yes Not applicable Not Applicable for

steel elements, cyclic loading 10 CFR Part 50, further evaluation

dissimilar metal - Appendix J, and (See SER Section

welds: supplemented to 3.5.2.2.1.8)

penetration detect fine cracks

sleeves,

penetration

bellows;

suppression pool

shell,.unbraced

downcomers

(3.5.1-12)

3-457
Component AgingEffect !:AMP in GALL Further AMP in LRA, Staff Evaluation

Group Mechanism ýýReport: Evaluation. Supplements,

(GALL RepOort L on r~

Ite No) ___________ ReOrt AmendmentsSteel, stainless Cracking due to ISI (IWE) and Yes Not applicable Not Applicable for

steel elements, cyclic loading 10 CFR Part 50, further evaluation

dissimilar metal Appendix J, and (See SER Section

welds: torus; vent supplemented to 3.5.2.2.1.8)

line; vent header; detect fine cracks

vent line bellows;

downcomers

(3.5.1-13)

Concrete Loss of material ISI (IWL). Evaluation Yes Not applicable Not applicable to

elements: dome, (scaling, cracking, is needed for plants SSES for further

wall, basemat and spalling) due to that are located in evaluation (See

ring girder, freeze-thaw moderate to severe SER Section

buttresses, weathering conditions 3.5.2.2.1.9)

containment (weathering

(as applicable) index> 100 day-

(3.5.1-14) inch/yr)

(NUREG-1557).

Concrete Cracking due to ISI (IWL) for Yes Not applicable Not applicable to

elements: walls, expansion and accessible areas. SSES for further

dome, basemat, reaction with None for inaccessible evaluation (See

ring girder, aggregate; increase areas if concrete was SER Section

buttresses, in porosity, constructed in 3.5.2.2.1.10)

containment, permeability due to accordance with the

concrete fill-in leaching of calcium recommendations in

annulus hydroxide ACI 201.2R.

(as applicable).

(3.5.1-15)

Seals, gaskets, Loss of sealing and ISI (IWE) and No ISI (IWE) Consistent with

and moisture leakage through 10 CFR Part 50, Program GALL Report, (See

barriers containment due to Appendix J (B.2.34) SER Section

(3.5.1-16) deterioration of joint 3.5.2.1)

seals, gaskets, and

moisture barriers

(caulking, flashing,

and other sealants)

Personnel Loss of leak 10 CFR Part 50, No ISI Program (IWE) Consistent with

airlock, tightness in closed Appendix J and plant (B.2.34), GALL Report, (See

equipment hatch due to Technical Cosition SER Section

and CRD hatch mechanical wear of Specifications Leakage Rate 3.5.2.1)

locks, hinges, locks, hinges and Lest PR ate

and closure closure mechanisms Test Program

mechanisms (B.2.37)

(3.5.1-17)

Steel penetration Loss of material due ISI (IWE) and No ISI (IWE) Consistent with

sleeves and to general, pitting, 10 CFR Part 50, Program GALL Report, (See

dissimilar metal and crevice Appendix J (B.2.34), and SER Section

welds; personnel corrosion Containment 3.5.2.1)

airlock, Leakage Rate

equipment hatch Test Program

and CRD hatch (B.2.37)

(3.5.1-18)

3-458
Component Aging Effect/ AMP in GALL Further AMP in LRA, Staff Evaluation

Group Mechanism Report Evaluation Supplements,

(GALL Report in GALL or

Item No.) Report Amendments

Steel elements: Cracking due to SCC ISI (IWE) and No Not applicable Not applicable (See

stainless steel 10 CFR Part 50, SER Section

suppression Appendix J 3.5.2.2.1.7)

chamber shell

(inner surface)

(3.5.1-19)

Steel elements: Loss of material due ISI (IWE) and No ISI (IWE) Consistent with the

suppression to general, pitting, 10 CFR Part 50, Program GALL Report, (See

chamber liner and crevice Appendix J (B.2.34), SER Section

(interior surface) corrosion Containment 3.5.2.1)

(3.5.1-20) Leakage Rate

Test Program

(B.2.37), and

BWR Water

Chemistry

Program (B.2.2)

Steel elements: Fretting or lock up ISI (IWE) No ISI (IWE) Consistent with the

drywell head and due to mechanical Program GALL Report, (See

downcomer pipes wear (B.2.34) SER Section

(3.5.1-21) 3.5.2.1)

Prestressed Loss of material due ISI (IWL) No Not applicable Not applicable to

containment: to corrosion SSES (See SER

tendons and Section 3.5.2.1.1)

anchorage

components

(3.5.1-22)

Safety-Related and Other Structures; and Component

Supports

All Groups except Cracking, loss of Structures Monitoring Yes Structures Consistent with

Group 6: interior bond, and loss of Program Monitoring GALL Report, which

and above grade material (spalling, Program recommends further

exterior concrete scaling) due to (B12.39) evaluation (See

(3.5.1-23) corrosion of SER Section

embedded steel 3.5.2.2.2.1)

All Groups except Increase in porosity Structures Monitoring Yes Structures Consistent with

Group 6: interior and permeability, Program Monitoring GALL Report, which

and above grade cracking, loss of Program recommends further

exterior concrete material (spalling, (B.2.39) evaluation (See

(3.5.1-24) scaling) due to SER Section

aggressive chemical 3.5.2.2.2.1)

attack

3-459
C" mponent-,, Aging Effect/. AMP in, GALL -Further -, .A AMP in LRA, Staff Evaluation

Grup MeChanism : Report .. Evaluation Supplements,

(GALL Report, i-n.GALL or.

ItemNo.~ ___________ ____________ Rport Amiendments

All Groups except Loss of material due Structures Monitoring Yes Structures Consistent with

Group 6: steel to corrosion Program. If protective Monitoring GALL Report, which

components: all coatings are relied Program recommends further

structural steel upon to manage the (B.2.39) evaluation (See

(3.5.1-25) effects of aging, the SER Section

Structures Monitoring 3.5.2.2.2.1)

Program is to include

provisions to address

protective coating

monitoring and

maintenance.

All Groups except Loss of material Structures Monitoring Yes Structures Consistent with

Group 6: (spalling, scaling) Program. Evaluation Monitoring GALL Report, which

accessible and and cracking due to is needed for plants Program recommends further

inaccessible freeze-thaw that are located in (B.2.39) evaluation (See

concrete: moderate to severe SER Sections

foundation weathering conditions 3.5.2.2.2.1 and

(3.5.1-26) (weathering index 3.5.2.2.2.2.1)

> 100 day-inch/yr)

(NUREG-1557).

All Groups except Cracking due to Structures Monitoring Yes Structures Consistent with

Group 6: expansion due to Program. None for Monitoring GALL Report, which

accessible and reaction with inaccessible areas if Program recommends further

inaccessible aggregates concrete was (B.2.39) evaluation (See

interior/exterior constructed in SER Sections

concrete accordance with the 3.5.2.2.2.1 and

(3.5.1-27) recommendations in 3.5.2.2.2.2.2)

ACI 201.2R-77.

Groups 1-3, 5-9: Cracks and Structures Monitoring Yes Structures Consistent with

All distortion due to Program. If a Monitoring GALL Report, which

(3.5.1-28) increased stress de-watering system is Program recommends further

levels from relied upon for control (B.2.39) evaluation (See

settlement of settlement, then the SER Sections

licensee is to ensure 3.5.2.2.2.1 and

proper functioning of 3.5.2.2.2.2.3)

the de-watering

system through the

period of extended

operation.

Groups 1-3, 5-9: Reduction in Structures Monitoring Yes Structures Consistent with

foundation foundation strength, Program. If a Monitoring GALL Report, which

(3.5.1-29) cracking, differential de-watering system is Program recommends further

settlement due to relied upon for control (B.2.39) evaluation (See

erosion of porous of settlement, then the SER Sections

concrete licensee is to ensure 3.5.2.2.2.1 and

subfoundation proper functioning of 3.5.2.2.2.2.3)

the de-watering

system through the

period of extended

operation.

3-460
Component. -Aging Effect/. AMP in GALL. Further AMP in LRA, Staff Evaluation

Group Mechanism Report Evaluation Supplements,

(GALL Report in GALL, or

Item No.) ____:_"__ -_Report Amendments

Group 4: radial Lock-up due to wear ISI (IWF) or Yes ISI (IWF) Consistent with

beam seats in Structures Monitoring Program GALL Report, which

BWR drywell; Program (B.2.36) and/or recommends further

RPV support Structures evaluation (See

shoes for PWR Monitoring SER Section

with nozzle Program 3.5.2.2.2.1)

supports; steam (B.2.39)

generator

supports

(3.5.1-30)

Groups 1-3, 5, 7- Increase in porosity Structures Monitoring Yes Structures Consistent with

9: below-grade and permeability, Program; examination Monitoring GALL Report, which

concrete cracking, loss of of representative Program recommends further

components, material (spalling, samples of below- (B.2.39) evaluation (See

such as exterior scaling), aggressive grade concrete, and SER Section

walls below grade chemical attack; periodic monitoring of 3.5.2.2.2.2.4)

and foundation cracking, loss of groundwater, if the

(3 .5.1-31) bond, and loss of environment is nonmaterial (spalling, aggressive. A plantscaling), corrosion of specific program is to

embedded steel be evaluated if

environment is

aggressive.

Groups 1-3, 5, 7- Increase in porosity Structures Monitoring Yes Structures Not applicable to

9: exterior above and permeability, Program for Monitoring SSES for further

and below grade and loss of strength accessible areas. Program evaluation (See

reinforced due to leaching of None for inaccessible (8.2.39) SER Section

concrete calcium hydroxide areas if concrete was 3.5.2.2.2.2.5)

foundations constructed in

(3.5,1-32) accordance with the

recommendations in

ACI 201..2R-77.

Groups 1-5: Reduction of A plant-specific aging Yes Not applicable Not applicable to

concrete strength and management program SSES for further

(3.5.1-33) modulus due to is to be evaluated evaluation (See

elevated SER Section

temperature 3.5.2.2.2.3)

3-461
Component Aging Effect .- AMP in GALL Further -AMP in LRA, Staff Evaluation

Group Mechanism :;-Report. !Evaluation Supplements,

(GALL Report~ i6 GALL, or:- ~ ItemNNo.) Report, Amendments

Group 6: Increase in porosity Inspection of Water- Yes Water-Control Consistent with

Concrete; all and permeability, Control Structures or Structures GALL Report, which

(3.5.1-34) cracking, loss of FERO/US Army Corps Inspection recommends further

material due to of Engineers dam Program evaluation (See

aggressive chemical inspections and (B.2.40) SER Section

attack; cracking, loss maintenance 3.5.2.2.2.4.1)

of bond, loss of programs and for

material due to inaccessible concrete,

corrosion of an examination of

embedded steel representative

samples of belowgrade concrete, and

periodic monitoring of

groundwater, if the

environment is nonaggressive. A plantspecific program is to

be evaluated if

environment is

aggressive.

Group 6: exterior Loss of material Inspection of Water- Yes Water-Control Consistent with

above and below. (spalling, scaling) Control Structures or Structures GALL Report, (See

grade concrete and cracking due to FERC/US Army Corps Inspection SER Sections

foundation freeze-thaw of Engineers dam Program 3.5.2.1.5 and

(3.5.1-35) inspections and (B.2.40), and 3.5.2.2.2.4.2)

maintenance Structures

programs. Evaluation Monitoring

is needed for-plants Program

that are located in (B.2.39)

moderate to severe

weathering conditions

(weathering index

> 100 day-inch/yir)

(NUREG-1557).

Group 6: all Cracking due to Accessible areas: Yes Water-Control Consistent with

accessible and expansion/reaction Inspection of Water- Structures GALL Report, which

inaccessible with aggregates Control Structures or Inspection recommends further

reinforced FERC/US Army Corps Program evaluation.(See

concrete of Engineers dam (B.2.40) SER Section

(3.5.1-36) inspections and 3.5.2.2.2.4.3)

maintenance

programs. None for

inaccessible areas if

concrete was

constructed in

accordance with the

recommendations in

ACl 201.2R-77.

3-462
Component Aging Effectl AMP in GALL Further, AMP in LRA, Staff Evaluation

Group Mechanism Report Evaluation Supplements,

(GALL Report in GALL or

Item No.) Report Amendments

Group 6: exterior Increase in porosity For accessible areas, Yes Water-Control Consistent with

above and below and permeability, Inspection of Water- Structures GALL Report, which

grade reinforced loss of strength due Control Structures or Inspection recommends further

concrete to leaching of FERC/US Army Corps Program evaluation (See

foundation calcium hydroxide of Engineers dam (B.2.40) SER Section

interior slab inspections and 3.5.2.2.2.4.3)

(3.5.1-37) maintenance

programs. None for

inaccessible areas if

concrete was

constructed in

accordance with the

recommendations in

ACI 201.2R-77.

Groups 7, 8: tank Cracking due to A plant-specific aging Yes Not applicable Not Applicable,

liners SCC; loss of management program which recommends

(3.5.1-38) material due to is to be evaluated further evaluation

pitting and crevice (See SER Section

corrosion 3.5.2.2.2.5)

Support Loss of material due Structures Monitoring Yes Structures Consistent with

members; welds; to general and pitting Program Monitoring GALL Report, which

bolted corrosion Program recommends further

connections; (B.2.39) evaluation (See

support SER Section

anchorage to 3.5.2.2.2.6)

building structure

(3.5.1-39)

Building concrete Reduction in Structures Monitoring Yes Structures Consistent with

at locations of concrete anchor Program Monitoring GALL Report, which

expansion and capacity due to local Program recommends further

grouted anchors; concrete (B.2.39) evaluation (See

grout pads for degradation, service- SER Section

support base induced cracking or 3.5.2.2.2.6)

plates other concrete aging

(3.5.1-40) mechanisms

Vibration isolation Reduction or loss of Structures Monitoring Yes Structures Consistent with

elements isolation function, Program. Monitoring GALL Report, which

(3.5.1-41) radiation hardening, Program recommends further

temperature, (B.2.39) evaluation (See

humidity, sustained SER Section

vibratory loading 3.5.2.2.2.6)

Groups B1.1, Cumulative fatigue TLAA, evaluated in Yes None Not applicable (See

B1.2, and B1.3: damage (CLB accordance with SER

support fatigue analysis 10 CFR 54.21(c) Section 3.5.2.2.2.7)

members: anchor exists)

bolts, welds

(3.5.1-42)

Groups 1-3, 5, 6: Cracking due to Masonry Wall No Masonry Wall Consistent with

all. masonry block restraint shrinkage, Program (B.2.38) and GALL Report,

walls creep, and Fire Protection (See SER Section

(3.5.1-43) aggressive (B.2.16) 3.5.2.1.2)

environment Programs

3-463
Component Aging Effect/ AMP in GALL Fi rther AMP in LRA, Staff Evaluation

Group . Mechanism Reprt Evaluation- Supplements,

(GAILL- Report -iný GALL ýor

~itm N.) . eport'. :Amendmehntý -

Group 6: Loss of sealing due Structures Monitoring No Structures Consistent with

elastomer seals, to deterioration of Program Monitoring GALL Report, (See

gaskets, and seals, gaskets, and Program SER Section

moisture barriers moisture barriers (B.2.39) and/or 3.5.2.1)

(3.5.1-44) (caulking, flashing, Fire Protection

and other sealants) Program

(B.2.16)

Group 6: exterior Loss of material due Inspection of Water- No Water Control Consistent with

above and below to abrasion, Control Structures or Structures GALL Report

grade concrete cavitation FERC/US Army Corps Inspection

foundation; of Engineers dam Program

interior slab inspections and (B.2.40)

(3.5.1-45) maintenance

Group 5: fuel Cracking due to Water Chemistry and No BWR Water Consistent with

pool liners SCC; loss of monitoring of spent Chemistry GALL Report,

(3.5.1-46) material due to fuel pool water level in Program (B.2.2) (See SER Section

pitting and crevice accordance with and monitoring 3.5.2.1)

corrosion technical of spent fuel

specifications and pool water level

leakage from the leak in accordance

chase channels. with Technical

Specifications

and Leak Chase

Channels

Monitoring

Activities

(B.2.47).

Group 6: all metal Loss of material due Inspection of Water- No Water Control Consistent with

structural to general (steel Control Structures or Structures GALL Report, (See

members only), pitting and FERC/US Army Corps Inspection SER Section

(3.5.1-47) crevice corrosion of Engineers dam Program 3.5.2.1.3)

inspections and (B.2.40)

maintenance. If

protective coatings

are relied upon to

manage aging,

protective coating

monitoring and

maintenance

provisions should be

included.

Group 6: earthen Loss of material, Inspection of Water- No Water-Control Consistent with

water control loss of form due to Control Structures or Structures GALL Report, (See

structures - erosion, settlement, FERC/US Army Corps Inspection SER Section

dams, sedimentation, frost of Engineers dam Program 3.5.2.1)

embankments, action, waves, inspections and (B.2.40)

reservoirs, currents, surface maintenance

channels, canals, runoff, seepage programs

and ponds

(3.5.1-48)

3-464
Component Aging Effect/ AMP in GALL Further AMP in LRA, Staff Evaluation

Group Mechanism Report Evaluation Supplements,

(GALL Report " in GALL.,:;, or.

SItem No.) . Report'., Amendments

Support Loss of material due Water Chemistry and No BWR Water Consistent with

members; welds; to general, pitting, ISI (IWF) Chemistry GALL Report, (See

bolted and crevice Program (B.2.2) SER Section

connections; corrosion and IWF 3.5.2.1)

support Program

anchorage to (B.2.36)

building structure

(3.5.1-49)

Groups B2, and Loss of material due Structures Monitoring No Structures Consistent with

B4: galvanized to pitting and crevice Program Monitoring GALL Report, (See

steel, aluminum, corrosion Program SER Section

stainless steel (B.2.39) 3.5.2.1.4)

support

members; welds;

bolted

connections;

support

anchorage to

building structure

(3.5.1-50)

Group B1.1: high Cracking due to Bolting Integrity No Bolting Integrity Not applicable to

strength low-alloy SCC; loss of Program SSES (See SER

bolts material due to (B.2.12) Section 3.5.2.1.1)

(3.5.1-51) general corrosion

Groups B2, and Loss of mechanical Structures Monitoring No Not applicable Not applicable to

B4: sliding function due to Program SSES (See SER

support bearings corrosion, distortion, Section 3.5.2.1.1)

and sliding dirt, overload, fatigue

support surfaces due to vibratory and

(3.5.1-52) cyclic thermal loads

Groups B1.1, Loss of material due ISI (IWF) No IWF Program Consistent with

B1.2, and B1.3: to general and pitting (B.2.36) GALL Report,

support corrosion (See SER Section

members: welds; 3.5.2.1)

bolted

connections;

support

anchorage to

building structure

(3.5.1-53)

Groups B1.1, Loss of mechanical ISI (IWF) No ISI (IWF) Consistent with

B1.2, and B1.3: function due to Program GALL Report

constant and corrosion, distortion, (B.2.36)

variable load dirt, overload, fatigue

spring hangers; due to vibratory and

guides; stops; cyclic thermal loads

(3.5.1-54) _ _ 1 1 1

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Component . ,Aging Effect/ AMP InGALL Further- AMP inLRA,, Staff Evaluation

Group Mechanism ~eport EValuation Supplements,

(GALLReport IniGALL or-

~.ItmN6)~ ~ ~ -Report Amendments

Steel, galvanized Loss of material due Boric Acid Corrosion No Not applicable Not applicable to

steel, and to boric acid BWRs

aluminum corrosion

support

members; welds;

bolted

connections;

support

anchorage to

building structure

(3.5.1-55)

Groups B1.1, Loss of mechanical ISI (IWF) No Not applicable Not applicable to

B1.2, and B1.3: function due to SSES (See SER

sliding surfaces corrosion, distortion, Section 3.5.2.1.1)

(3.5.1-56) dirt, overload, fatigue

due to vibratory and

cyclic thermal loads

Groups B1.1, Reduction or loss of ISI (IWF) No Not applicable Not applicable to

B1.2, and B1.3: isolation function, SSES (See SER

vibration isolation radiation hardening, Section 3.5.2.1.1)

elements temperature,

(3.5.1-57) humidity, sustained

vibratory loading

Galvanized steel None None No None Consistent with

and aluminum GALL Report

support

members; welds;

bolted

connections;

support

anchorage to

building structure

exposed to air -

indoor

uncontrolled

(3.5.1-58)

Stainless steel None None No None Consistent with

support GALL Report

members; welds;

bolted

connections;

support

anchorage to

building structure

(3.5.1-59)

The staff's review of the containments, structures, and components supports component

groups followed any one of several approaches. One approach, documented in SER

Section 3.5.2.1, reviewed AMR results for components that the applicant indicated are

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consistent with the GALL Report and require no further evaluation. Another approach,

documented in SER Section 3.5.2.2, reviewed AMR results for components that the applicant

indicated are consistent with the GALL Report and for which further evaluation is

recommended. A third approach, documented in SER Section 3.5.2.3, reviewed AMR results

for components that the applicant indicated are not consistent with, or not addressed in, the

GALL Report. The staff's review of AMPs credited to manage or monitor aging effects of the

containments, structures, and components supports components is documented in SER

Section 3.0.3.

3.5.2.1 AMR Results Consistent with the GALL Report

LRA Section 3.5.2.1 identifies the materials, environments, AERMs, and the following programs

that manage aging effects for the containments, structures, and component supports

components:

* BWR Water Chemistry Program

* Crane Inspection Program

* Fire Protection Program

* Inservice Inspection (ISI) Program - IWE

* Inservice Inspection (ISI) Program - IWL

* Inservice Inspection (ISI) Program - IWF

" Containment Leakage Rate Test Program

* Masonry Wall Program

* Structures Monitoring Program

* RG 1.127 Water-Control Structures Inspection

* Leak Chase Channel Monitoring Activities

LRA Tables 3.5.2-1 through 3.5.2-10 summarize AMRs for the containments, structures, and

components supports components and indicate AMRs claimed to be consistent with the GALL

Report.

For component groups evaluated in the GALL Report for which the applicant claimed

consistency with the report and for which it does not recommend further evaluation, the staff's

audit and review determined whether the plant-specific components of these GALL Report

component groups were bounded by the GALL Report evaluation.

The applicant noted for each AMR line item how the information in the tables aligns with the

information in the GALL Report. The staff audited those AMRs with notes A through E

indicating how the AMR is consistent with the GALL Report.

Note A indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP is consistent with the GALL

Report AMP. The staff audited these line items to verify consistency with the GALL Report and

validity of the AMR for the site-specific conditions.

Note B indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP takes some exceptions to the

GALL Report AMP. The staff audited these line items to verify consistency with the GALL

Report and verified that the identified exceptions to the GALL Report AMPs have been

reviewed and accepted. The staff also determined whether the applicant's AMP was consistent

with the GALL Report AMP and whether the AMR was valid for the site-specific conditions.

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Note C indicates that the component for the AMR line item, although different from, is

consistent with the GALL Report for material, environment, and aging effect. In addition, the

AMP is consistent with the GALL Report AMP. This note indicates that the applicant was unable

to find a listing of some system components in the GALL Report; however, the applicant

identified in the GALL Report a different component with the same material, environment, aging

effect, and AMP as the component under review. The staff audited these line items to verify

consistency with the GALL Report. The staff also determined whether the AMR line item of the

different component was applicable to the component under review and whether the AMR was

valid for the site-specific conditions.

Note D indicates that the component for the AMR line item, although different from, is

consistent with the GALL Report for material, environment, and aging effect. In addition, the

AMP takes some exceptions to the GALL Report AMP. The staff audited these line items to

verify consistency with the GALL Report. The staff verified whether the AMR line item of the

different component was applicable to the component under review and whether the identified

exceptions to the GALL Report AMPs have been reviewed and accepted. The staff also

determined whether the applicant's AMP was consistent with the GALL Report AMP and

whether the AMR was valid for the site-specific conditions.

Note E indicates that the AMR line item is consistent with the GALL Report for material,

environment, and aging effect, but credits a different AMP or plant-specific AMP. The staff

audited these line items to verify consistency with the GALL Report. The staff also determined

whether the credited AMP would manage the aging effect consistently with the GALL Report

AMP and whether the AMR was valid for the site-specific conditions.

The staff audited and reviewed the information in the LRA. The staff did not repeat its review of

the matters described in the GALL Report; however, the staff did verify that the material

presented in the LRA was applicable and that the applicant identified the appropriate GALL

Report AMRs. The staff's evaluation follows.

3.5.2.1.1 AMR Results Identified as Not Applicable

LRA Table 3.5.1, items 22, 51, 52, 56, and 57 are identified as "Not Applicable" since the

component, material, and environment combination does not exist at SSES. For each of these

line items, the staff reviewed the LRA and the applicant's supporting documents, and confirmed

the applicant's claim that the component, material, and environment combination does not exist

at SSES. Because SSES does not have the component, material, and environment combination

for these Table 1 line items, the staff finds that these AMRs are not applicable to SSES.

3.5.2.1.2 Cracking due to restraint shrinkage, creep, and aggressive environment.

In the discussion section of LRA Table 3.5.1, item 3.5.1-43, the applicant stated that cracking

due to restraint shrinkage, creep, and aggressive environment is managed by the Masonry Wall

Program. During the review, the staff noted that aging management program for the AMR

results line that points to LRA Table 3.5.1, item 3.5.1-43, for five groups the applicant included

a reference to Note E and plant-specific Note 516, which states "masonry walls with a fire

barrier intended function receive additional inspection as part of the fire protection program."

The staff reviewed the AMR results lines referenced to Note E, plant-specific Note 516, and

determined that the component type, material, environment, and aging effect are consistent

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with the corresponding line of the GALL Report; however, where the GALL Report recommends

AMP XI.S5, "Masonry Wall Program," the applicant has proposed using the Fire Protection

Program. The applicant stated that the AMR result line items that reference LRA Table 3.5.1

item 3.5.1-43, are also listed as fire barriers that are in the scope for 10 CFR 54.4(a)(2)

criterion, and therefore, the Fire Protection Program was also credited. The Fire Protection

Program and Masonry Wall Program are performing visual inspections on a periodic basis to

manage cracking due to restraint shrinkage, creep, and aggressive environments. On the basis

that periodic visual inspections are performed, the staff finds the applicant's use of the Fire

Protection Program in conjunction with the Masonry Wall Program to be acceptable.

On the basis of its review of AMR result lines as described in the preceding paragraphs and its

comparison of the applicant's results to corresponding recommendations in the GALL Report,

the staff finds that the applicant addressed the AERMs adequately, as recommended by the

GALL Report.

3.5.2.1.3 Loss of material due to general (steel only), pitting and crevice corrosion

In the discussion section of LRA Table 3.5.1, item 3.5.1-47, the applicant stated that loss of

material due to general, pitting, and crevice corrosion is managed by the Structures Monitoring

Program. During the review, the staff noted that for the AMR results line pointing to Table 3.5.1,

item 3.5.1-47, for 16 groups the applicant included a reference to Note E and plant-specific

Note 526, which states "component is different, but consistent with NUREG-1 801 item for

material, environment, and aging effect, SSES operating experience has shown of water

accumulating in manholes. Therefore, aging mechanisms pertaining to raw water environments

are also applicable within manholes, valve vaults, and instrument pits."

The staff reviewed the AMR results lines referenced to Note E, plant-specific Note 526, and

determined that the component type, material, environment, and aging effect are consistent

with the corresponding line of the GALL Report; however, where the GALL Report recommends

AMP XI.S7, "Regulatory Guide 1.127, Inspection of Water-Control Structures Associated with

Nuclear Power Plants," the applicant has proposed using the Structures Monitoring Program

(SER Section 3.0.3.2.17). However, the AMR result line items that reference LRA Table 3.5.1,

item 3.5.1-47, are structural steel members in the Water-Control Structure. However, the

Water-Control Structure is in the scope for Structures Monitoring Program and the Structures

Monitoring Program performs visual inspections to manage loss of material due to general,

pitting, and crevice corrosion. On the basis that periodic visual inspections are performed, the

staff finds the applicant's use of the Structures Monitoring Program to be acceptable.

On the basis of its review of AMR result lines as described in the preceding paragraphs and its

comparison of the applicant's results to corresponding recommendations in the GALL Report,

the staff finds that the applicant addressed the AERMs adequately, as recommended by the

GALL Report.

3.5.2.1.4 Loss of Material Due to General and Pitting Corrosion

In the discussion section of LRA Table 3.5.1, item 3.5.1-50, the applicant stated that loss of

material due to pitting, and crevice corrosion is managed by the Structures Monitoring Program.

During the review, the staff noted that for the AMR results line pointing to Table 3.5.1, item

3.5.1-50, for two groups the applicant included a reference to Note E.

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The staff reviewed the AMR results lines referenced to Note E and determined that the

component type, material, environment, and aging effect are consistent with the corresponding

line of the GALL Report; however, where the GALL Report recommends AMP XI.S6,

"Structures Monitoring Program," the applicant has proposed using the ASME Section XI,

Subsection IWF. However, the AMR result line items that reference LRA Table 3.5.1, item

3.5.1-50, are galvanized steels in the component and piping support members, which are in the

scope for ASME Section XI, Subsection IWF and not in the Structures Monitoring Program. The

ASME Section XI, Subsection IWF and the Structures Monitoring Program perform visual

inspections to manage loss of material due to pitting, and crevice corrosion. On the basis that

periodic visual inspections are performed, the staff finds the applicant's use of the ASME

Section Xl, Subsection IWF to be acceptable.

On the basis of its review of AMR result lines as described in the preceding paragraphs and its

comparison of the applicant's results to corresponding recommendations in the GALL Report,

the staff finds that the applicant addressed the AEM adequately, as recommended by the GALL

Report.

3.5.2.1.5 Loss of material (spalling, scaling) and cracking due to freeze-thaw

In the discussion section of LRA Table 3.5.1, item 3.5.1-35, the applicant stated: loss of

material (spalling, scalling) and cracking due to freeze-thaw of group 6 exposed to raw water is

managed by Regulatory Guide 1.127, Inspection of Water-Control Structures Associated with

Nuclear Power Plants. During the review, the staff noted that for the AMR results line pointing to

Table 3.5.1, item 3.5.1-35, for three groups the applicant included a reference to Note E and

plant-specific Note 503, which states "the GALL item for freeze-thaw does not list exposed to

raw water environment for water control structures. Freeze-thaw may be possible near the

water line. This environment is both exposed to raw water; therefore environment is considered

a match. The identified AMP is used to manage aging effects for the period of extended

operation."

The staff reviewed the AMR results lines referenced to Note E, plant-specific Note 503, and

determined that the component type, material, environment, and aging effect are consistent

with the corresponding line of the GALL Report; however, where the GALL Report recommends

AMP XI.S7, "Regulatory Guide 1.127, Inspection of Water-Control Structures Associated with

Nuclear Power Plants" the applicant has proposed using the Structures Monitoring Program for

Table 3.5.1, item 3.5.1-35, which is concrete exposed to raw water environment. Since, the

Water-Control Structure is in the scope for Structures Monitoring Program and the Structures

Monitoring Program performs visual inspections to manage loss of material (spalling, scalling)

and cracking due to freeze-thaw, the staff finds the applicant's use of the Structures Monitoring

Program to be acceptable.

On the basis of its review of AMR result lines as described in the preceding paragraphs and its

comparison of the applicant's results to corresponding recommendations in the GALL Report,

the staff finds that the applicant addressed the AEM adequately, as recommended by the GALL

Report.

SER Section 3.5.2.1 Conclusion. The staff evaluated the applicant's claim of consistency with

the GALL Report. The staff also reviewed information pertaining to the applicant's consideration

of recent operating experience and proposals for managing aging effects. On the basis of its

review, the staff concludes that the AMR results, which the applicant claimed to be consistent

with the GALL Report, are indeed consistent with the AMRs Therefore, the staff concludes that

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the applicant has demonstrated that the effects of aging for these components will be

adequately managed so that their intended function(s) will be maintained consistent with the

CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.5.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation is

Recommended

3.5.2.2.1 PWR and BWR Containments

Aging of Inaccessible Concrete Areas. The applicant stated in LRA Section 3.5.2.2.1.1 that the

loss of material and change in material properties due to aggressive chemical attack, and

cracking, loss of bond, and loss of material (spalling, scaling) due to corrosion of embedded

steel in inaccessible areas of concrete and steel containments are not aging effects requiring

management at SSES because (1) groundwater analyses confirm that the SSES site

groundwater is not aggressive, and (2) the design of the SSES containment concrete in

accordance with ACI 318-71 and construction in accordance with ACI 301-72 enhance the

resistance to chemical attack through the use of dense concrete with low permeability, and

generally prevent corrosion of embedded steel from occurring.

The staff reviewed LRA Section 3.5.2.2.1.1 against the criteria in SRP-LR Section 3.5.2.2.1.1,

which states that increases in porosity and permeability, cracking, loss of material (spalling,

scaling) due to aggressive chemical attack, and cracking, loss of bond, and loss of material

(spalling, scaling) due to corrosion of embedded steel could occur in inaccessible areas of

concrete and steel containments. The existing program relies on ASME Section XI, Subsection

IWL to manage these aging effects. The SSES ISI Program - IWL described in LRA Section

B.2.35 is an existing program that is consistent with all elements of GALL AMP XI.S2, "ASME

Section Xl, Subsection IWL". The staff's review of the applicant's ISI Program - IWL is

documented in SER Section 3.0.3.1.20.

SRP-LR Section 3.5.2.2.1.1 also states that the GALL Report recommends further evaluation of

plant-specific programs to manage the aging effects for inaccessible areas if the environment is

aggressive. To ensure non-aggressive groundwater chemistries, the GALL Report suggests the

periodic groundwater inspection for chlorides, sulfates, and pH. The staff noted that the

applicant's groundwater inspections are performed by the applicant's Structures Monitoring

Program described in LRA Section B.2.39. The staff's review of the applicant's Structures

Monitoring Program is documented in SER Section 3.0.3.2.17.

The staff has reviewed the LRA and some associated on-site documents. In addition to the

sampling results from 2004 and 2005 presented in the LRA, which indicated groundwater pH

minimum value of 5.9, chloride content maximum value of 26 ppm, and sulfate content

maximum value of 96 ppm, the staff also checked SSES chemical analysis of groundwater at

WW-2 (outside of the Emergency Diesel Generator Building) performed in 2006 and 2007, and

found average values for pH 6.11 and 6.13, chloride 23.1 ppm and 40.4 ppm, and sulfate 43.2

ppm and 54.6 ppm, respectively. The staff confirmed that the below-grade environment at

SSES is non-aggressive (Chlorides < 500 ppm, Sulfates <1500 ppm, and pH > 5.5).

The staff noticed that SSES concrete is designed in accordance with American Concrete

Institute (ACI) 318-71 and constructed in accordance with ACI 301-72. The staff confirmed that

concrete constructed to these criteria has a low water-to-cement ratio of less than 0.50 and an

adequate air entrainment between 3 and 6%, which is equivalent to ACI 201.2R-77

recommendation on water-to-cement ratio for protecting concrete from chemical attack and

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recommendation on air contents for resisting freezing and thawing. Therefore, the staff agreed

that SSES concrete provides a good quality dense concrete with a low permeability, which

meets the intent of ACI 201.2R-77.

The staff also noted that visual examinations in 2000 revealed surface cracking on the

containment exterior and discussed it with the applicant's technical personnel. The applicant

provided documentation showing that the cracking is less than the allowable values per ACI

224R "Control of Cracking in Concrete Structures", Table 4.1 and acceptable per its appropriate

plant-specification. The staff further noted that the plant-specific operating experience did not

reveal any significant degradation requiring further evaluation. The absence of concrete aging

effects is confirmed under the applicant's ISI Program - IWL.

On the basis of its review, the staff finds that the increases in porosity and permeability,

cracking, loss of material (spalling, scaling) due to aggressive chemical attack, and cracking,

loss of bond, and loss of material (spalling, scaling) due to corrosion of embedded steel are not

plausible aging effects at SSES because (1) the plant-specific operating experience did not

reveal any degradation not bounded by industry experience, (2) the concrete being constructed

meets the intent of ACI 201.2R for durability with a high cement, low water/cement ratio, and (3)

the inspection frequency of groundwater chemistries under the applicant's Structures

Monitoring Program agrees with the recommendation of the GALL Report for groundwater

monitoring. Therefore, the staff finds that no further evaluation is required.

Based on the programs identified above, the staff concluded that the applicant has met the

criteria of SRP-LR Section 3.5.2.2.1.1. For those line items that apply to LRA Section

3.5.2.2.1.1, the staff determined that the LRA is consistent with the GALL Report and the

applicant has demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB during the period of extended

operation, as required by 10 CFR 54.21(a)(3).

Cracks and Distortion due to Increased Stress Levels from Settlement; Reduction

of Foundation Strength, Cracking and Differential Settlement due to Erosion of Porous

Concrete Subfoundations, if Not Covered by Structures Monitoring Program. The applicant

stated in LRA Section 3.5.2.2.1.2 that the cracks and distortion due to increased stress levels

from settlement, reduction of foundation strength, cracking, and differential settlement due to

erosion of porous concrete subfoundations are not aging effects requiring management at

SSES because (1) SSES does not employ a de-watering system in any of the site structures for

control of settlement, (2) the primary containment base foundation slabs rest on competent

bedrock and no settlement has been experienced, and (3) the primary containment base

foundation slabs are not constructed of porous concrete below-grade and are not subject to

flowing water.

The staff reviewed LRA Section 3.5.2.2.1.2 against the criteria in SRP-LR Section 3.5.2.2.1.2,

which states that the cracks and distortion due to increased stress levels from settlement could

occur in concrete and steel containments. Also, reduction of foundation strength, cracking, and

differential settlement due to erosion of porous concrete subfoundations could occur in all types

of containments. The existing program relies on the structures monitoring program to manage

these aging effects. SRP-LR Section 3.5.2.2.1.2 also states that the GALL Report recommends

no further evaluation if this activity is within the scope of the applicant's structures monitoring

program.

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The SSES Structures Monitoring Program described in LRA Section B.2.39 is an existing

program that is consistent, with enhancements, with GALL AMP XI.S6, "Structures Monitoring

Program." The staff's review of the applicant's Structures Monitoring Program is documented in

SER Section 3.0.3.2.17. The staff noted that the applicant conservatively elected to use the

Structural Monitoring Program to monitor the above-grade exposed containment concrete for

the aging effect of cracking and distortion due to settlement.

On the basis of its review, the staff finds that cracks and distortion due to increased stress

levels from settlement, reduction of foundation strength, cracking, and differential settlement

due to erosion of porous concrete subfoundations are not plausible aging effects to SSES

because the conditions necessary for the aging effects, such as soil environment and flowing

water environment, do not exist. The staff also finds that the Structures Monitoring Program

includes activities that are consistent with the recommendations in the GALL Report, and are

adequate to manage cracks and distortion due to increased stress levels from settlement,

reduction of foundation strength, cracking, and differential settlement due to erosion of porous

concrete subfoundations. Therefore, the staff finds that no further evaluation is required.

Based on the programs identified above, the staff concluded that the applicant has met the

criteria of SRP-LR Section 3.5.2.2.1.2. For those line items that apply to LRA Section

3.5.2.2.1.2, the staff determined that the LRA is consistent with the GALL Report and the

applicant has demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB during the period of extended

operation, as required by 10 CFR 54.21 (a)(3).

Reduction of Strength and Modulus of Concrete Structures due to Elevated Temperature.

The applicant stated in LRA Section 3.5.2.2.1.3 that during normal operation, containment

concrete general area temperatures do not exceed 150°F and local area temperatures do not

exceed 200°F.

The staff reviewed LRA Section 3.5.2.2.1.3 against the criteria in SRP-LR Section 3.5.2.2.1.3,

which states that reduction of strength and modulus of concrete due to elevated temperatures

could occur in PWR and BWR concrete and steel containments. The GALL Report

recommends further evaluation of a plant-specific aging management program if any portion of

the concrete containment components exceeds specified temperature limits, i.e., general area

temperature greater than 66°C (150 0F) and local area temperature greater than 93°C (2000 F).

The staff reviewed the LRA and noted that no portion of the concrete containment components

at SSES exceeds the specified temperature limits, which are 150°F for general area and 200 *F

for local area. On the basis of its review, the staff finds that reduction of strength and modulus

of concrete due to elevated temperatures are not applicable aging effects to SSES because the

conditions necessary for the aging effects, such as elevated temperatures, do not exist.

Therefore, the staff finds that no further evaluation is required.

Loss of Material due to General, Pitting and Crevice Corrosion. The applicant stated in LRA

Section 3.5.2.2.1.4 that the loss of material due to general, pitting and crevice corrosion is not a

significant aging effect at SSES because (1) the design of the SSES containment concrete in

accordance with ACI 318-71 and construction in accordance with ACI 301-72 provide a good

quality dense concrete with a low permeability, (2) the SSES concrete containments are located

within the Reactor Buildings and are protected from weather, and (3) the design of containment

liner is not conducive for capturing moisture between the carbon steel liner and concrete

containment wall, as well as between the liner and drywell floor.

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The staff reviewed LRA Section 3.5.2.2.1.4 against the criteria in SRP-LR Section 3.5.2.2.1.4,

which states that loss of material due to general, pitting and crevice corrosion could occur in

steel elements of accessible and inaccessible areas for all types of PWR and BWR

containments, SRP-LR Section 3.5.2.2.1.4 further states that the existing program relies on

ASME Section Xl, Subsection IWE, and 10 CFR Part 50, Appendix J, to manage this aging

effect. The SSES ISI Program - IWE, described in LRA Section B.3.34, and the Containment

Leakage Rate Test Program, described in LRA Section B.3.37, are existing programs that are

consistent with all elements of GALL AMP XI.S1, "ASME Section Xl, Subsection IWE", and

GALL AMP XI.S4, "10 CFR Part 50, Appendix J", respectively. The staff's reviews of the ISI

Program - IWE and Containment Leakage Rate Test Program are documented in SER Section

3.0.3.1.19 and SER Section 3.0.3.1.22, respectively. SRP-LR Section 3.5.2.2.1.4 also states

that the GALL Report recommends further evaluation of plant-specific programs to manage this

aging effect for inaccessible areas if corrosion is significant.

The staff reviewed the LRA and some associated on-site documents and interviewed the

applicant's technical staff. During the on-site review, the staff noticed that general visual

examinations of containment liners and penetrations have revealed flaking, discoloration, light

to heavy pitting and corrosion. The applicant provided documentation showing that deficiencies

were evaluated and corrected if necessary in accordance with the ISI Program - IWE. The staff

noted that there were no instances of Appendix J test failures due to causes other than valve or

flange seat leakage. For these failures, all conditions were evaluated and corrected in

accordance with the Containment Leakage Rate Test Program. The plant-specific operating

experience did not reveal or indicate any significant degradation in inaccessible areas. The

aging effect of loss of material due to general pitting and crevice corrosion for containment steel

elements is monitored and managed under the ISI Program - IWE and Containment Leakage

Rate Test Program.

On the basis of its review, the staff determines that loss of material due to general pitting and

crevice corrosion is an aging effect for steel elements of accessible and inaccessible areas of

containments. The staff finds that applicant's inspections and tests in accordance with the ISI

Program - IWE and Containment Leakage Rate Test Program to manage loss of material due

to general pitting and crevice corrosion are adequate because (1) the plant-specific operating

experience did not reveal any degradation not bounded by industry experience, (2) the aging

effect has been effectively monitored and managed under the aforementioned programs, and

(3) the containment concrete in contact with the embedded containment liner at SSES was

designed, constructed, and inspected in accordance with applicable ACI and ASTM standards,

which provide for a good quality, dense, well cured, and low permeability concrete; hence

corrosion for inaccessible areas is not expected to be significant for SSES. Therefore, the staff

agrees that no additional plant-specific program is required.

Based on the programs identified above, the staff concluded that the applicant has met the

criteria of SRP-LR Section 3.5.2.2.1.4. For those line items that apply to LRA Section

3.5.2.2.1.4, the staff determined that the LRA is consistent with the GALL Report and the

applicant has demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB during the period of extended

operation, as required by 10 CFR 54.21(a)(3).

Loss of Prestress due to Relaxation, Shrinkage, Creep, and Elevated Temperature. The staff

reviewed LRA Section 3.5.2.2.1.5 against the criteria in SRP-LR Section 3.5.2.2.1.5

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SSES Containments are designed and constructed as reinforced concrete structures, not

prestressed concrete structures. Therefore, loss of prestress forces due to relaxation,

shrinkage, creep and elevated temperature is not an aging effect applicable to SSES

Containments.

Cumulative Fatique Damage. The applicant stated in LRA Section 3.5.2.2.1.6 that fatigue

analyses of penetrations, hatches, drywell head, downcomer vents, safety relief valve (SRV)

discharge piping, and SRV quenchers are TLAAs as defined in 10 CFR 54.3. Fatigue TLAA are

evaluated as documented in LRA Section 4.6.

The staff reviewed LRA Section 3.5.2.2.1.6 against the criteria in SRP-LR Section 3.5.2.2.1.6,

which states that if included in the current licensing basis, fatigue analyses of suppression pool

steel shells (including welded joints) and penetrations (including penetration sleeves, dissimilar

metal welds, and penetration bellows) for all types of PWR and BWR containments and BWR

vent header, vent line bellows, and downcomers are TLAAs as defined in 10 CFR 54.3. TLAAs

are required to be evaluated in accordance with 10 CFR 54.21(c).

SER Section 4.6 documents the staffs review of the applicant's evaluation of this TLAA.

Cracking due to Stress Corrosion Cracking (SCC). The applicant stated in LRA Section

3.5.2.2.1.7 that (1) SCC is not an applicable aging effect primary containment penetration

sleeves, vent line headers, and downcomers because they are carbon steel components not

susceptible to SCC, and (2) SCC is not an applicable aging effect for dissimilar metal welds in

the SSES primary containment penetration sleeves since the welds are not subject to an

aggressive chemical environment.

The staff reviewed LRA Section 3.5.2.2.1.7 against the criteria in SRP-LR Section 3.5.2.2.1.7,

which states that cracking due to stress corrosion cracking of stainless steel penetration

sleeves, penetration bellows, and dissimilar metal welds could occur in all types of PWR and

BWR containments. Cracking due to SCC could also occur in stainless steel vent line bellows

for BWR containments. The existing program relies on ASME Section Xl, Subsection IWE and

10 CFR Part 50, Appendix J to manage this aging effect. The GALL Report recommends

further evaluation of additional appropriate examinations/evaluations implemented to detect

these aging effects for stainless steel penetration sleeves, penetration bellows and dissimilar

metal welds, and stainless steel vent line bellows.

The staff noted that the penetration sleeves, vent line headers, and downcomers are carbon

steel components. The staff acknowledged that stainless steel must be subject to both high

temperature (>1400 F) and an aggressive chemical environment to be susceptible to SCC. The

staff also noted that the dissimilar metal welds in the penetration sleeves located inside and/or

outside the primary containment drywell are within the Reactor Building, and are not subject to

an aggressive chemical environment.

On the basis of its review, the staff finds that SCC is not a susceptible aging effect for SSES

primary containment penetration sleeves, vent line headers, and downcomers because they are

carbon steel components, not stainless steel components. The staff also agrees that cracking

due to SCC for dissimilar metal welds in the SSES Primary Containment penetration sleeves is

not applicable to SSES since the conditions necessary for SCC, both high temperature

(>140 OF ) and exposure to an aggressive environment, do not simultaneously exist.

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Cracking due to Cyclic Loading. The applicant stated in LRA Section 3.5.2.2.1.8 that SSES

penetrations do not use expansion bellows, and penetration sleeves are fabricated of carbon

steel. The applicant also addressed cracking due to cyclic loading in shells and penetrations,

stating that the SSES AMR results conclude that cracking due to cyclic loading for containment

components is not an aging effect requiring management. The applicant explained in the LRA

that cyclic loading from plant heatups and cooldowns, containment testing, and from system

vibration is very low or limited in numbers of cycles. The SSES analyzed fatigue of cyclic

loading for steel elements as a TLAA in LRA Section 4.6.

The staff reviewed LRA Section 3.5.2.2.1.8 against the criteria in SRP-LR Section 3.5.2.2.1.8,

which states that cracking due to cyclic loading of suppression pool steel and stainless steel

shells (including welded joints) and penetrations (including penetration sleeves, dissimilar metal

welds, and penetration bellows) could occur for all types of containments and BWR vent

header, vent line bellows and downcomers. SRP-LR Section 3.5.2.2.1.8 also states that the

existing program relies on ASME Section XI, Subsection IWE and 10 CFR Part 50, Appendix J

to manage this aging effect. The SSES ISI Program - IWE and Containment Leakage Rate

Test Program are existing programs that are consistent with all elements of GALL AMP XI.S1,

"ASME Section Xl, Subsection IWE", and GALL AMP XI.S4, "10 CFR Part 50, Appendix J",

respectively. The staff's reviews of the ISI Program - IWE and Containment Leakage Rate Test

Program are documented in SER Section 3.0.3.1.19 and SER Section 3.0.3.1.22, respectively.

The GALL Report recommends further evaluation for detection of this aging effect.

The staff reviewed the AMR and its associated AMPs in the LRA. During the on-site review of

the associated AMPs, the staff also interviewed applicant's technical personnel. The staff

confirmed that SSES operating experience did not identify any events related to cyclic loading

induced cracking of containment components, and the number of loading cycles is very low or

limited. For steel elements, fatigue of cyclic loading for steel elements has been analyzed as a

TLAA. The staff's review of the TLAA is documented in SER Section 4.6.

On the basis of its review, the staff finds that cracking due to cyclic loading is not an applicable

aging effect for penetration bellows and penetration sleeves because SSES penetrations do not

use expansion bellows, and penetration sleeves are fabricated of carbon steel. The staff also

agrees that cracking due to cyclic loading for steel and stainless steel elements of containments

and vent header, vent line bellows and downcomers is not a plausible aging effect at SSES

because the conditions necessary for cracking, the number of loading cycles, is not sufficient to

initiate cracking. Therefore, the staff determines that no further evaluation is required.

Loss of Material (Scaling., Cracking, and Spalling) due to Freeze-Thaw. The staff reviewed LRA

Section 3.5.2.2.1.9 against the criteria in SRP-LR Section 3.5.2.2.1.9.

SSES primary containments are located within the reactor buildings. The staff finds that loss of

material (scaling, cracking, and spalling) due to freeze-thaw is not an aging effect applicable to

containments because loss of material (scaling, cracking, and spalling) due to freeze-thaw is

applicable only to concrete containments exposed to weather.

Cracking due to Expansion and Reaction with Aggregate, and Increase in Porosity and

Permeability due to Leaching of Calcium Hydroxide. The applicant stated in LRA Section

3.5.2.2.1.10 that cracking due to expansion and reaction with aggregate, and increase in

porosity and permeability due to leaching of calcium hydroxide are not aging effects requiring

management at SSES because (1) aggregates used in SSES containment concrete structures

were selected based on testing per ASTM C-289 "Potential Reactivity of Aggregate" and C-295

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"Petrographic Examination", (2) SSES specification for concrete prohibits the use of calcium

chloride in the concrete mix design, (3) the SSES Primary Containment concrete is not exposed

to flowing water, and (4) resistance to leaching is enhanced by using a dense, well-cured, low

permeable concrete in accordance with accepted ACI Standards.

The staff reviewed LRA Section 3.5.2.2.1.10 against the criteria in SRP-LR Section

3.5.2.2.1.10, which states that cracking due to expansion and reaction with aggregate, and

increase in porosity and permeability due to leaching of calcium hydroxide could occur in

concrete elements of concrete and steel containments. SRP-LR Section 3.5.2.2.1.10 also

states that the existing program relies on ASME Section Xl, Subsection IWL to manage these

aging effects. The SSES ISI Program - IWL described in LRA B.2.35 is an existing program

that is consistent with all elements of GALL AMP XI.S2, "ASME Section XI, Subsection IWL".

The staff's review of the applicant's ISI Program - IWL is documented in SER Section

3.0.3.1.20. SRP-LR Section 3.5.2.2.1.10 further states that the GALL Report recommends

further evaluation if concrete was not constructed in accordance with the recommendations in

ACI 201.2R-77.

The staff reviewed the LRA including the AMR and the associated AMP, and the UFSAR.

During the on-site review of the associated AMP, the staff also interviewed applicant's technical

personnel. The staff confirmed that the containment concrete structures are designed in

accordance with ACI 318-71 and constructed in accordance with ACI 301-72, which meets the

intent of ACl 201.2R-77 as discussed in SER Section 3.5.2.2.1.1, and the SSES containment

concrete aggregates are selected in accordance with ASTM standards, which meets the GALL

recommendation of investigations, tests, and petrographic examinations of aggregates

performed in accordance with ASTM C295-54 or ASTM C227-50 as described in NUREG-1 557.

The staff also noted that leaching of calcium hydroxide from reinforced concrete becomes

significant only if the concrete is exposed to flowing water; however the SSES containment

concrete is not exposed to flowing water.

On the basis of its review, the staff agrees that cracking due to expansion and reaction with

aggregate, increase in porosity and permeability due to leaching of calcium hydroxide are not

plausible aging effects for concrete elements of containments because (1) the absence of the

aging effects is confirmed under the ISI Program - IWL, (2) the material selection in

accordance with ASTM standards ensures nonreactive concrete aggregates (3) the design and

construction of containment concrete structures in accordance with ACI codes enhances

resistance to leaching, and (4) SSES containment concrete is not exposed to flowing water.

Therefore, the staff determines that no further evaluation is required.

3.5.2.2.2 Safety-Related and Other Structures and Component Supports

Aging of Structures Not Covered by Structures Monitoring Program. The applicant stated in

LRA Section 3.5.2.2.2.1 that the Structures Monitoring Program is credited for aging

management of these effects/mechanisms for the affected concrete structures and structural

components even if the AMR did not identify aging effects requiring management.

The staff reviewed LRA Section 3.5.2.2.2.1 against the criteria in SRP-LR Section 3.5.2.2.2.1,

which states that the GALL Report recommends further evaluation of certain structure/aging

effect combinations if they are not covered by the structures monitoring program. This includes

(1) cracking, loss of bond, and loss of material (spalling, scaling) due to corrosion of embedded

steel for Groups 1-5, 7, 9 structures; (2) increase in porosity and permeability, cracking, loss of

material (spalling, scaling) due to aggressive chemical attack for Groups 1-5, 7, 9 structures;

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(3) loss of material due to corrosion for Groups 1-5, 7, 8 structures; (4) loss of material

(spalling, scaling) and cracking due to freeze-thaw for Groups 1-3, 5, 7-9 structures; (5)

cracking due to expansion and reaction with aggregates for Groups 1-5, 7-9 structures; (6)

cracks and distortion due to increased stress levels from settlement for Groups 1-3, 5-9

structures; and (7) reduction in foundation strength, cracking, differential settlement due to

erosion of porous concrete subfoundation for Groups 1-3, 5-9 structures. The GALL Report

recommends further evaluation only for structure/aging effect combinations that are not within

the structures monitoring program. In addition, SRP-LR Section 3.5.2.2.2.1 also states that lock

up due to wear could occur for Lubrite® radial beam seats in BWR drywell, RPV support shoes

for PWR with nozzle supports, steam generator supports, and other sliding support bearings

and sliding support surfaces. The existing program relies on the structures monitoring program

or ASME Section XI, Subsection IWF to manage this aging effect. The GALL Report

recommends further evaluation only for structure/aging effect combinations that are not within

the ISl (IWF) or structures monitoring program.

The staff noted that the applicant's Structures Monitoring Program described in LRA Section

B.2.39 is credited for aging management of these effects/mechanisms for the affected concrete

structures and structural components even if the AMR did not identify aging effects requiring

management. The staff's review of the applicant's Structures Monitoring Program is

documented in SER Section 3.0.3.2.17. Additional reviews of specific aging

effects/mechanisms are discussed below.

1. Cracking, Loss of Bond, and Loss of Material (Spalling, Scaling) Due to Corrosion of

Embedded Steel for Groups 1-5, 7, and 9 Structures

The applicant stated in the LRA that the aging mechanisms associated with cracking,

loss of bond, and loss of material (spalling, scaling) due to corrosion of embedded steel

are not aging effects requiring management for SSES concrete structures components

because the below-grade environment for SSES is not aggressive, and concrete is

designed in accordance with specification ACI 318-71, and constructed in accordance

with ACI 301-72. The applicant also stated that concrete constructed to these criteria

has a low-water/cement ratio 0.50 or less, adequate air entrainment between 3% and

6% and provides a good quality dense concrete with a low permeability, which meets

the intent of ACI 201.2R-77. The applicant further stated that the below-grade

environment at SSES is non-aggressive and has been confirmed by water chemistry

analysis results. Sampling results from 2004 and 2005 indicated ground water pH

minimum value at 5.9, chloride content maximum value of 26 ppm, and sulfate content

maximum value of 96 ppm. Therefore, cracking, loss of bond, and loss of material

(spalling, scaling) due to corrosion of embedded steel are not AERMs for SSES

Groups 1-5, 7, and 9 structures.

Through a review of the LRA, the staff determined that the cracking, loss of bond, and

loss of material (spalling, scaling) due to corrosion of embedded steel for Groups 1-5, 7,

and 9 structures are not plausible aging effects at SSES because of (1) the lack of

aggressive groundwater. (2) SSES concrete is designed in accordance with

specification ACI 318-71 with a high-cement, low-water/cement ratio, which meets the

intent of ACI 201.2R-77 as discussed in SER Section 3.5.2.2.1.1 (3) proper curing, and

adequate air content between 3 and 6 percent. The above aging effects for these

groups are included within the Structures Monitoring Program by the applicant.

Therefore, the staff agrees that the criteria of SRP-LR Section 3.5.2.2.2.1 have been

met, and no further evaluation is required.

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2. Increase in Porosity and Permeability, Cracking, Loss of Material (Spalling, Scaling) Due

to Aggressive Chemical Attack for Groups 1-5, 7, and 9 Structures

The applicant stated in the LRA that the SSES concrete is designed in accordance with

ACl 318-71, and constructed in accordance with ACI 301-72. Concrete constructed to

these criteria has a low-water/cement ratio 0.50 or less, adequate air entrainment

between 3% and 6% and provides a good quality dense concrete with a low

permeability, which meets the intent of ACI 201.2R-77. The applicant further stated that

the below-grade environment is not aggressive. Therefore, the applicant concluded that

the increase in porosity and permeability cracking and loss of material (spalling, scaling)

due to aggressive chemical attack are not AERMs for SSES Groups 1-5, 7, and 9

concrete structures.

Through a review of the LRA, the staff determined that the increase in porosity and

permeability, cracking, and loss of material (spalling, scaling) due to aggressive

chemical attack for Groups 1-5, 7, and 9 structures are not plausible aging effects at

SSES because of the lack of aggressive groundwater and the concrete being

constructed for durability in accordance with the recommendations that meet the intent

of ACI 201.2R-77 as discussed in SER Section 3.5.2.2.1.1. The above aging effects for

these groups are included within the Structures Monitoring Program by the applicant.

Therefore, the staff agrees that the criteria of SRP-LR Section 3.5.2.2.2.1 have been

met, and no further evaluation is required.

3. Loss of Material Due to Corrosion for Groups 1-5, 7, and 8 Structures

The applicant stated in the LRA that SSES Structures Monitoring program is credited for

aging management of loss of material due to corrosion for SSES Group 1-5, 7, and 8

structures.

Through a review of the LRA, the staff determined that the loss of material due to

corrosion for Groups 1-5, 7, and 8 structures is an aging effect which will be managed

by the applicant's Structures Monitoring Program. Therefore, the staff agrees that the

criteria of SRP-LR Section 3.5.2.2.2.1 have been met, and no further evaluation is

required.

4. Loss of Material (Spalling, Scaling) and Cracking Due to Freeze-Thaw for Groups 1-3, 5,

and 7-9 Structures

The applicant stated in the LRA that the SSES concrete is designed in accordance with

ACI 318-71, and constructed in accordance with ACI 301-72. Concrete constructed to

these criteria has a low-water/cement ratio 0.50 or less, adequate air entrainment

between 3% and 6% and provides a good quality dense concrete with a low

permeability, which meets the intent of ACl 201.2R-77 standards that preclude the

freeze-thaw aging mechanism. Therefore, the applicant concluded that loss of material

(spalling, scaling) and cracking due to freeze-thaw are not AERMs for SSES Groups 1-

3, 5, and 7-9 structures.

Through a review of the LRA, the staff determined that the loss of material (spalling,

scaling) and cracking due to freeze-thaw for Groups 1-3, 5, and 7-9 structures are not

plausible aging effects at SSES because of concrete being constructed in accordance

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with ACI standards. The above aging effects for these groups are included within the

Structures Monitoring Program by the applicant. Therefore, the staff agrees that the

criteria of SRP-LR Section 3.5.2.2.2.1 have been met, and no further evaluation is

required.

5. Cracking Due to Expansion and Reaction with Aggregates for Groups 1-5 and 7-9

Structures

The applicant stated in the LRA that the SSES concrete is designed in accordance with

ACI 318-71, and constructed in accordance with ACI 301-72. Concrete constructed to

these criteria has a low-water/cement ratio 0.50 or less, adequate air entrainment

between 3% and 6% and provides a good quality dense concrete with a low

permeability, which meets the intent of ACI 201.2R. The applicant also stated that the

SSES specification requires that the potential reactivity of aggregates be acceptable

based on testing in accordance with ASTM C-289 "Potential Reactivity of Aggregate"

and C-295 "Petrographic Examination" and the SSES specification for concrete prohibits

the use of calcium chloride in the concrete mix design. Therefore, the applicant

concluded that cracking due to expansion and reaction with aggregates for Groups 1-3,

5, and 7-9 structures is not an AERM.

Through a review of the LRA, the staff determined that the cracking due to expansion

and reaction with aggregates for Groups 1-5 and 7-9 structures are not plausible aging

effects at SSES because (1) the material selection in accordance with ASTM standards

ensures nonreactive concrete aggregates, and (2) the SSES concrete design in

accordance with ACI 318-71 and construction in accordance with ACI 301-72 meet the

intent of ACI 201.2R-77 as discussed in SER Section 3.5.2.2.1.1. The staff finds that

Groups 1-5, 7-9 structures subject to this AMR are all in-scope of the Structures

Monitoring Program. Therefore, the staff agrees that the criteria of SRP-LR Section

3.5.2.2.2.1 have been met, and no further evaluation is required.

6. Cracks and Distortion Due to Increased Stress Levels from Settlement for Groups 1-3

and 5-9 Structures

The applicant stated in the LRA that reinforced concrete mat foundations have been

provided for all structures at SSES and their foundations rest on competent bedrock

except for the ESSW Pumphouse, which is supported by natural soil. The applicant also

stated that for the past 20 years, the ESSW Pumphouse total differential settlement is

well within the permissible limits for this type of structure and no settlement has

manifested itself via cracked walls or cracked foundations. Survey readings were carried

out for four years and the ESSW Pumphouse had not experienced any significant

settlement. No settlement has been experienced for other SSES in-scope structures.

SSES does not employ a de-watering system in any of the site structures for control of

settlement. Therefore, the applicant concluded that cracks and distortion due to

increased stress levels from settlement are not aging effects requiring management for

SSES concrete structure components.

Through a review of the LRA, UFSAR Section 2.5.4 "Stability of Subsurface Materials

and Foundations" and UFSAR Section 2.5.5" Stability of Slops", the staff determined

that the cracks and distortion due to increased stress levels from settlement for Groups

1-3 and 5-9 structures are not plausible aging effects at SSES because of the

nonexistence of these aging mechanisms. The SSES structures are founded on sound

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bedrock except for the ESSW Pumphouse, which is supported by natural soil. The total

differential settlement of ESSW Pumphouse is well below the allowable limits as

discussed in UFSAR Sections 2.5.4 and 2.5. The staff finds that Groups 1-5, 7- 9

structures subject to this AMR are all in-scope of the Structures Monitoring Program.

Therefore, the staff agrees that the criteria of SRP-LR Section 3.5.2.2.2.1 have been

met, and no further evaluation is required.

7. Reduction in Foundation Strength, Cracking, and Differential Settlement Due to Erosion

of Porous Concrete Subfoundation for Groups 1-3 and 5-9 Structures

In the LRA, the applicant stated that reduction in foundation strength, cracking, and

differential settlement due to erosion of porous concrete subfoundations are not aging

effects requiring management. The applicant also stated that for SSES concrete

foundations the concrete foundations at SSES are not constructed with porous concrete

and are not subject to flowing water. The applicant further stated that SSES does not

employ a de-watering system at any of the site structures for control of settlement.

Through a review of the LRA and UFSAR Appendix 3.8B "Concrete, Concrete Materials,

Quallity Control, and Special Construction Techniques", the staff determined that

reduction in foundation strength, cracking, and differential settlement due to erosion of

porous concrete subfoundation for Groups 1-3 and 5-9 structures are not plausible

aging effects because of the nonexistence of these aging mechanisms. The staff

confirmed from UFSAR Appendix 3.8B that there are no porous concrete

subfoundations for these structures. Therefore, the staff finds these aging effects are

not applicable to SSES.

8. Lockup Due to Wear for Lubrite® Radial Beam Seats in BWR Drywell and Other Sliding

Support Surfaces

In the LRA the applicant stated that Lubrite® plates are not used in SSES in-scope

structural components. The applicant also stated that lock-up due to wear is not an

aging effect requiring management at SSES. Aging degradations of supports designed

with or without sliding connections are managed by the ISI Program - IWF and/or the

Structures Monitoring Program.

Through a review of the LRA, the staff determined that the applicant has credited its

Inservice Inspection (ISI - IWF) Program and/or the Structures Monitoring Program to

manage aging of Lubrite® and Other Sliding Support Surfaces. The staff finds the

applicable AMP(s) acceptable for inspection of Lubrite® and Other Sliding Support

Surfaces because the GALL Report recommendation described by the associated

tables in GALL Volume 2 "Tabulation of Results" is followed. Therefore, the staff finds

that the criteria of SRP-LR Section 3.5.2.2.2.1 have been met, and no further evaluation

is required.

On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LR

Section 3.5.2.2.2.1. For those line items that apply to LRA Section 3.5.2.2.2.1, the staff

determined that the LRA is consistent with the GALL Report and the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB during the period of extended operation, as

required by 10 CFR 54.21(a)(3).

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Aging Management of Inaccessible Areas.

Below-Grade Inaccessible Concrete Areas - Freeze-Thaw. SSES is located in an area in which

weathering conditions are considered severe. The applicant stated in LRA Section 3.5.2.2.2.2.1

that loss of material (spalling, scaling) and cracking due to freeze-thaw in below-grade

inaccessible concrete areas of Groups 1-3, 5 and 7-9 structures are not aging effects requiring

management at SSES because (1) SSES structures are designed with proper drainage and

slope such that ponding or prolonged exposure to standing water on concrete surfaces is not

significant, and (2) the SSES concrete design in accordance with ACI 318-71 and construction

in accordance with ACI 301-72, which provided a good quality dense concrete with a low

permeability, meet the intent of ACI 201.2R-77.

The staff reviewed LRA Section 3.5.2.2.2.2.1 against the criteria in SRP-LR Section

3.5.2.2.2.2.1, which states that loss of material (spalling, scaling) and cracking due to freezethaw could occur in below grade inaccessible concrete areas of Groups 1-3, 5 and 7-9

structures. The GALL Report recommends further evaluation of this aging effect for

inaccessible areas of these Groups of structures for plants located in moderate to severe

weathering conditions.

The staff reviewed the LRA. The staff confirmed that the SSES Structures Monitoring Program

described in LRA Section B.2.39 is credited for aging management of these

effects/mechanisms for the affected concrete structures and structural components. The staff

noted that the Structures Monitoring Program will include examination of exposed concrete for

age-related degradation when a below-grade concrete component becomes accessible through

excavation. The staff found that the SSES concrete air content of 3% to 6%, which follows the

GALL recommendation, is documented. The staff determined that the SSES concrete mix

design addresses freeze-thaw damage potential by using sufficient air content, which creates a

large number of closely spaced, small air bubbles in the hardened concrete. The air bubbles

relieve the pressure build-up caused by ice formation by acting as expansion chambers.

On the basis of its review, the staff determines that for SSES, loss of material and cracking due

to freeze-thaw are aging effects requiring management for below-grade inaccessible concrete

areas of Groups 1-3, 5, and 7-9 structures since they are located in an area in which

weathering conditions are considered severe. However, the staff finds that the applicant's

evaluation acceptable because (1) the applicant's Structures Monitoring Program is credited for

aging management of these effects/mechanisms for the affected concrete structures and

structural components, which includes examination of exposed concrete for age-related

degradation when a below-grade concrete component becomes accessible through excavation,

and (2) air content of 3% to 6% at SSES conforms to the recommendation in ACl 201.2R-77 for

moderate to severe exposure.

Based on the programs identified above, the staff concluded that the applicant has met the

criteria of SRP-LR Section 3.5.2.2.2.2.1. For those line items that apply to LRA Section

3.5.2.2.2.2.1, the staff determined that the LRA is consistent with the GALL Report and the

applicant has demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB during the period of extended

operation, as required by 10 CFR 54.21(a)(3).

Below-Grade Inaccessible Concrete Areas - Expansion and Reaction with

AQgre-gates. The applicant stated in LRA Section 3.5.2.2.2.2. that cracking due to expansion

and reaction with aggregate is not an aging effect requiring management at SSES because (1)

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the SSES concrete structures are designed in accordance with ACI 318-71 and constructed in

accordance with ACl 301-72, (2) aggregates used in SSES concrete structures were selected

based on testing per ASTM C-289 "Potential Reactivity of Aggregate" and C-295 "Petrographic

Examination", and (3) the applicant's Structures Monitoring Program is credited for aging

management of these effects/mechanisms for the affected concrete structures and structural

components, and the Structures Monitoring Program includes examination of exposed concrete

for age-related degradation when a below-grade concrete component becomes accessible

through excavation.

The staff reviewed LRA Section 3.5.2.2.2.2.2 against the criteria in SRP-LR Section

3.5.2.2.2.2.2, which states that cracking due to expansion and reaction with aggregates could

occur in below-grade inaccessible concrete areas for Groups 1-5 and 7-9 structures. The GALL

Report recommends further evaluation of inaccessible areas of these Groups of structures if

concrete was not constructed in accordance with the recommendations in ACl 201.2R-77.

The staff has reviewed the LRA and UFSAR. The staff confirmed that the SSES concrete

structures are designed and constructed in accordance with accepted ACl codes, which meets

the intent of ACl 201.2R-77 as discussed in SER Section 3.5.2.2.1.1, and the SSES concrete

aggregates are selected in accordance with ASTM standards, which meets the GALL

recommendation of investigations, tests, and petrographic examinations of aggregates

performed in accordance with ASTM C295-54 or ASTM C227-50 as described in NUREG-1557.

The staff further noted that the Structures Monitoring Program will include examination of

exposed concrete for age-related degradation when a below-grade concrete component

becomes accessible through excavation.

On the basis of its review, the staff agrees that cracking due to expansion and reaction with

aggregate is not a plausible aging effect in below-grade inaccessible concrete areas for Groups

1-5 and 7-9 structures because (1) the material selection in accordance with ASTM standards

ensures nonreactive concrete aggregates, (2) the SSES concrete design in accordance with

ACI 318-71 and construction in accordance with ACl 301-72 meet the intent of ACI 201.2R-77,

and (3) the applicant's Structures Monitoring Program is credited for aging management of

these effects/mechanisms for the affected concrete structures and structural components,

which includes examination of exposed concrete for age-related degradation when a belowgrade concrete component becomes accessible through excavation. Therefore, the staff

determines that no further evaluation is required.

Based on the programs identified above, the staff concluded that the applicant has met the

criteria of SRP-LR Section 3.5.2.2.2.2.2. For those line items that apply to LRA Section

3.5.2.2.2.2.2, the staff determined that the LRA is consistent with the GALL Report and the

applicant has demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB during the period of extended

operation, as required by 10 CFR 54.21(a)(3).

Below-Grade Inaccessible Concrete Areas - Settlement and Erosion. The applicant stated in

LRA Section 3.5.2.2.2.2.3 that cracks and distortion due to increased stress levels from

settlement and reduction of foundation strength, cracking, and differential settlement due to

erosion of porous concrete subfoundations are not aging effects requiring management for

SSES below-grade inaccessible concrete components of Groups 1-3, 5 and 7-9 structures

because (1) SSES does not employ a de-watering system in any of the site structures for

control of settlement, (2) reinforced concrete mat foundations of all SSES structures, except the

ESSW pumphouse, rest on competent bedrock and no settlement has been experienced, (3)

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the differential settlement of the ESSW pumphouse is well within the permissible limits and wall

or foundation crack due to settlement has not been indentified, and (4) SSES base foundation

slabs are not constructed of porous concrete below grade.

The staff reviewed LRA Section 3.5.2.2.2.2.3 against the criteria in SRP-LR Section

3.5.2.2.2.2.3, which states that cracks and distortion due to increased stress levels from

settlement and reduction of foundation strength, cracking, and differential settlement due to

erosion of porous concrete subfoundations could occur in below-grade inaccessible concrete

areas of Groups 1-3, 5 and 7-9 structures. SRP-LR Section 3.5.2.2.2.2.3 also states that the

existing program relies on the Structures Monitoring Program to manage these aging effects.

The SSES Structures Monitoring Program described in LRA Section B.2.39 is an existing

program that is consistent, with enhancements, with GALL AMP XI.S6, "Structures Monitoring

Program." The staff's review of the applicant's Structures Monitoring Program is documented in

SER Section 3.0.3.2.17. SRP-LR Section 3.5.2.2.2.2.2 further states that the GALL Report

recommends no further evaluation if this activity is included in the scope of the applicant's

Structures Monitoring Program.

The staff reviewed the LRA including the AMR and its associated AMP. The staff noted that the

SSES base foundation slabs are not constructed of porous concrete below grade. The staff

also verified that the differential settlement of the ESSW pumphouse is well within the

permissible limits during the on-site review of its associated AMP. The staff further noted that

the associated AMP Structures Monitoring Program is credited for aging management of these

effects for the affected concrete structures and structural components, and will include

examination of exposed concrete for age-related degradation when a below-grade concrete

component becomes accessible through excavation.

On the basis of its review, the staff finds that cracks and distortion due to increased stress

levels from settlement; reduction of foundation strength, cracking and differential settlement

due to erosion of porous concrete subfoundations are not plausible aging effects in belowgrade inaccessible concrete areas of Groups 1-3, 5 and 7-9 structures because the conditions

necessary for aging effects, such as porous concrete material, flowing water environment,

and/or soil environment, do not exist. The Structures Monitoring Program is credited for aging

management of these effects for the affected concrete structures and structural components.

Therefore, the staff finds that no further evaluation is required.

Based on the programs identified above, the staff concluded that the applicant has met the

criteria of SRP-LR Section 3.5.2.2.2.2.3. For those line items that apply to LRA Section

3.5.2.2.2.2.3, the staff determined that the LRA is consistent with the GALL Report and the

applicant has demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB during the period of extended

operation, as required by 10 CFR 54.21 (a)(3).

Below-Grade Inaccessible Concrete Areas - Aggressive ChemicalAttack and

Corrosion of Embedded Steel. The applicant stated in LRA Section 3.5.2.2.2.2.4 that the loss of

material and change in material properties due to aggressive chemical attack, and cracking,

loss of bond, and loss of material (spalling, scaling) due to corrosion of embedded steel are not

aging effects requiring management at SSES because (1) groundwater analyses confirm that

the SSES site groundwater is not aggressive, and (2) the design of the SSES concrete in

accordance with ACI 318-71 and construction in accordance with ACI 301-72 enhance the

resistance to chemical attack through the use of dense concrete with low permeability, and

generally prevent corrosion of embedded steel from occurring.

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The staff reviewed LRA Section 3.5.2.2.2.2.4 against the criteria in SRP-LR Section

3.5.2.2.2.2.4, which states that increase in porosity and permeability, cracking, loss of material

(spalling, scaling) due to aggressive chemical attack; and cracking, loss of bond, and loss of

material (spalling, scaling) due to corrosion of embedded steel could occur in below-grade

inaccessible concrete areas of Groups 1-3, 5 and 7-9 structures. The GALL Report

recommends further evaluation of plant - specific programs to manage the aging effects for

inaccessible areas if the environment is aggressive.

To ensure non-aggressive groundwater chemistries, the GALL Report suggests the periodic

groundwater inspection for chlorides, sulfates, and pH. The staff noted that the applicant's

groundwater inspection program is performed by the applicant's Structures Monitoring Program

described in LRA Section B.2.39. The staff's review of the applicant's Structures Monitoring

Program is documented in SER Section 3.0.3.2.17.

The staff reviewed the LRA including the AMR and the associated AMP. During on-site review

of the associated AMP, the staff reviewed some related on-site documents. The staff noted the

plant-specific operating experience did not reveal any significant degradation. The absence of

concrete aging effects in below-grade inaccessible concrete areas of Groups 1-3, 5 and 7-9

structures is confirmed under the Structures Monitoring Program. The staff confirmed that the

below-grade environment at SSES is non-aggressive (Chlorides < 500 ppm, Sulfates <1500

ppm, and pH > 5.5). The staff further validated that the Structures Monitoring Program is

credited for management of the aging effects, will include review of site ground water and raw

water pH, chlorides, and sulfates during the period of extended operation, and will include

examination of exposed concrete for age-related degradation when a below-grade concrete

component becomes accessible through excavation.

On the basis of its review, the staff finds that the increases in porosity and permeability,

cracking, loss of material (spalling, scaling) due to aggressive chemical attack, and cracking,

loss of bond, and loss of material (spalling, scaling) due to corrosion of embedded steel are not

plausible aging effects in below-grade inaccessible concrete areas of Groups 1-3, 5 and 7-9

structures because (1) the plant-specific operating experience did not reveal any degradation

not bounded by industry experience, (2) the concrete being constructed meets the intent of

ACI 201.2R as discussed in SER Section 3.5.2.2.1.1 for durability with a high cement, low

water/cement ratio, and (3) the inspection frequency of groundwater chemistries under the

applicant's Structures Monitoring Program agrees with the recommendation of the GALL Report

for groundwater monitoring, and to date, the applicant's inspection results show the

groundwater is not aggressive. Therefore, the staff finds that no further evaluation is required.

Based on the programs identified above, the staff concluded that the applicant has met the

criteria of SRP-LR Section 3.5.2.2.2.2.4. For those line items that apply to LRA Section

3.5.2.2.2.2.4, the staff determined that the LRA is consistent with the GALL Report and the

applicant has demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB during the period of extended

operation, as required by 10 CFR 54.21 (a)(3).

Below-Grade Inaccessible Concrete Areas - Leachinq of Calcium Hydroxide. The applicant

stated in the LRA Section 3.5.2.2.2.2.5 that cracking increase in porosity and permeability due

to leaching of calcium hydroxide is not an aging effect requiring management in below-grade

inaccessible concrete areas of Groups 1-3, 5 and 7-9 structures because (1) the concrete

components below grade are not exposed to flowing water, and (2) resistance to leaching is

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enhanced by using a dense, well-cured, low permeable concrete in accordance with accepted

ACI Standards.

The staff reviewed LRA Section 3.5.2.2.2.2.5 against the criteria in SRP-LR Section

3.5.2.2.2.2.5, which states that increase in porosity and permeability, and loss of strength due

to leaching of calcium hydroxide could occur in below-grade inaccessible concrete areas of

Groups 1-3, 5 and 7-9 structures. SRP-LR Section 3.5.2.2.2.2.5 further states the GALL Report

recommends further evaluation of this aging effect for inaccessible areas of these Groups of

structures if concrete was not constructed in accordance with the recommendations in

ACI 201.2R-77.

The GALL Report states that an aging management program is not necessary for inaccessible

areas, even if reinforced concrete is exposed to flowing water, if there is documented evidence

that confirms the in-place concrete was constructed in accordance with the recommendations in

ACI 201.2R-77.

The staff reviewed the LRA. The staff noted that the concrete structures are designed in

accordance with ACl 318-71 and constructed in accordance with ACI 301-72. The staff also

noted that leaching of calcium hydroxide from reinforced concrete becomes significant only if

the concrete is exposed to flowing water; however, the concrete components below grade are

not exposed to flowing water.

On the basis of its review, the staff finds that cracking increase in porosity and permeability due

to leaching of calcium hydroxide is not an applicable aging effect in below-grade inaccessible

concrete areas of Groups 1-3, 5 and 7-9 structures because concrete components below grade

are not exposed to flowing water, and the design and construction of concrete in accordance

with accepted ACI codes meet the intent of ACl 201.2R-77 as discussed in SER Section

3.5.2.2.1.1.

Reduction of Strenqth and Modulus of Concrete Structures due to Elevated

Temperature. The staff reviewed LRA Section 3.5.2.2.2.3 against the criteria in SRP-LR

Section 3.5.2.2.2.3.

The applicant stated in LRA Section 3.5.2.2.2.3 that SSES in-scope concrete structures and

concrete components are maintained below the 150OF threshold for general areas and under

200°F for local areas.

SRP-LR Section 3.5.2.2.2.3 states that reduction of strength and modulus of concrete due to

elevated temperatures could occur in PWR and BWR Group 1-5 concrete structures. For any

concrete elements that exceed specified temperature limits, further evaluations are

recommended. SRP-LR Section 3.5.2.2.2.3 also states the GALL Report recommends further

evaluation of a plant-specific program if any portion of the safety-related and other concrete

structures exceeds specified temperature limits, i.e., general area temperature greater than

66°C (150'F) and local area temperature greater than 93°C (200'F).

The staff reviewed the LRA and noted that no portion of the concrete components at SSES

exceeds specified temperature limits, which are 150°F for general areas and 200°F for local

areas.

On the basis of its review, the staff finds that reduction of strength and modulus of concrete due

to elevated temperatures are not applicable aging effects to SSES because the conditions

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necessary for the aging effects, elevated temperatures, do not exist. Therefore, the staff finds

that no further evaluation is required

Aging Management of Inaccessible Areas for Group 6 Structures. The staff reviewed LRA

Section 3.5.2.2.2.4 against the criteria in SRP-LR Section 3.5.2.2.2.4

SRP-LR Section 3.5.2.2.2.4 states that the GALL Report recommends further evaluation for

inaccessible areas of certain Group 6 structure/aging effect combinations as identified below,

whether or not they are covered by inspections in accordance with the GALL Report, Chapter

XI.S7, "Regulatory Guide 1.127, Inspection of Water-Control Structures Associated with

Nuclear Power Plants" or the FERC / US Army Corp of Engineers dam inspections and

maintenance.

The staff's review and evaluation of aging management of inaccessible areas for Group 6

structures are addressed as follows.

Below-Grade Inaccessible Concrete Areas. The applicant stated in the LRA Section

3.5.2.2.2.4.1 that increase in porosity and permeability, cracking, loss of material (spalling,

scaling)/ aggressive chemical attack; and cracking, loss of bond, and loss of material (spalling,

scaling)/ corrosion of embedded steel in below-grade inaccessible concrete areas of Group 6

structures are not aging effects requiring management at SSES because (1) corrosion of

structural steel components is addressed by the Structures Monitoring Program. The RG1.127

Water-Control Structures Inspection is credited for aging management of rest of the aging

effects/mechanisms, even if the AMR did not identify aging effects requiring management, (2)

analyses confirm that the SSES site environment is not aggressive, and (3) the design of the

SSES concrete in accordance with ACI 318-71 and construction in accordance with ACI 301-72

enhance the resistance to chemical attack through the use of dense concrete with low

permeability, and generally prevent corrosion of embedded steel from occurring.

The staff reviewed LRA Section 3.5.2.2.2.4.1 against the criteria in SRP-LR Section

3.5.2.2.2.4.1, which states that increase in porosity and permeability, cracking, loss of material

(spalling, scaling)/ aggressive chemical attack; and cracking, loss of bond, and loss of material

(spalling, scaling)/ corrosion of embedded steel could occur in below-grade inaccessible

concrete areas of Group 6 structures. The GALL Report recommends further evaluation of

plant-specific programs to manage these aging effects in inaccessible areas if the environment

is aggressive.

The GALL Report recommends that the existing program relies on "Regulatory Guide 1.127,

Inspection of Water-Control Structures Associated with Nuclear Power Plants" for accessible

areas. The SSES RG 1.127 Water-Control Structures Inspection described in LRA Section

B.2.40 is an existing program that is consistent, with enhancements, with GALL AMP XI.S7,

"Regulatory Guide 1.127, Inspection of Water-Control Structures Associated with Nuclear

Power Plants." The staff's review of the applicant's RG 1.127 Water-Control Structures

Inspection is documented in SER Section 3.0.3.2.18. For inaccessible areas, the GALL Report

recommends an examination of representative samples of below-grade concrete, and periodic

monitoring of groundwater, if the environment is nonaggressive; and further evaluation of plantspecific programs to manage these aging effects, if the environment is aggressive.

The staff reviewed the LRA, including the AMR and associated AMPs. The staff noted that the

concrete structures are designed in accordance with ACI 318-71 and constructed in accordance

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with ACI 301-72. The staff also validated from applicant's inspection results that the chemistries

in groundwater and raw water at SSES are not aggressive.

On the basis of its review, the staff finds that the increase in porosity and permeability,

cracking, loss of material (spalling, scaling)/ aggressive chemical attack; and cracking, loss of

bond, and loss of material (spalling, scaling)/ corrosion of embedded steel in below-grade

inaccessible concrete areas of Group 6 structures are not plausible aging effects at SSES

because (1) the plant-specific operating experience did not reveal any degradation, (2) the

concrete being constructed meets the intent of ACI 201.2R as discussed in SER Section

3.5.2.2.1.1 for durability with a high cement, low water/cement ratio, (3) the applicant's

inspections of groundwater and raw water chemistries confirm that the environment is not

aggressive, and (4) the Structures Monitoring Program and the RG1.127 Water-Control

Structures Inspection are credited for aging management of these aging effects/mechanisms,

even if the AMR did not identify aging effects requiring management.

Based on the programs identified above, the staff concluded that the applicant has met the

criteria of SRP-LR Section 3.5.2.2.2.4.1. For those line items that apply to LRA Section

3.5.2.2.2.4.1 the staff determined that the LRA is consistent with the GALL Report and the

applicant has demonstrated that the.effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB during the period of extended

operation, as required by 10 CFR 54.21(a)(3).

Below-Grade Inaccessible Concrete Areas - Freeze-Thaw. The applicant stated in the LRA

Section 3.5.2.2.2.4.2 that SSES is located in an area in which weathering conditions are

considered severe. The loss of material (spalling, scaling) and cracking due to freeze-thaw in

below-grade inaccessible concrete areas of Group 6 structures are aging effects requiring

management at SSES because the concrete located in the ESSW Pumphouse, Spray Pond,

and the Cooling Tower Basins may become saturated and, therefore, could be susceptible to

freeze-thaw. The applicant further stated in LRA Section 3.5.2.2.2.4.2 that the RG 1.127 WaterControl Structures Inspection is credited to monitor for degradation of the Spray Pond and the

ESSW Pumphouse. The Structures Monitoring Program is credited to monitor for degradation

of the Cooling Tower Basins.

The staff reviewed LRA Section 3.5.2.2.2.4.2 against the criteria in SRP-LR Section

3.5.2.2.2.4.2, which states that loss of material (spalling, scaling) and cracking due to freezethaw could occur in below-grade inaccessible concrete areas of Group 6 structures. The GALL

Report recommends further evaluation of this aging effect for inaccessible areas for plants

located in moderate to severe weathering conditions.

The staff reviewed LRA Section 3.5.2.2.2.4.2. The staff noted that the RG1.127 Water-Control

Structures Inspection is credited to monitor for degradation of the Spray Pond and the ESSW

Pumphouse. The Structures Monitoring Program is credited to monitor for degradation of the

Cooling Tower Basins. The staff's review of the RG1.127 Water-Control Structures Inspection

and the Structures Monitoring Program are documented in SER Section 3.0.3.2.18 and

3.0.3.2.17, respectively. The staff verified that the SSES concrete design in accordance with

ACI 318-71 and construction in accordance with ACI 301-72, which provided a good quality

dense concrete with a low permeability, meet the intent of ACI 201.2R-77 as discussed in SER

Section 3.5.2.2.1.1. The staff particularly validated the SSES concrete air content of 3% to 6%,

which is consistent with the ACI 201.2R-77 as the GALL recommended.

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On the basis of its review, the staff finds that loss of material and cracking due to freeze-thaw

are aging effects in below-grade inaccessible concrete areas of Group 6 structures because

SSES is located in an area in which weathering conditions- are considered severe. Since the

design and construction of the SSES concrete is in accordance with the accepted ACl

Standards which prevents the freeze-thaw aging mechanism, the staff finds that applicant's

inspections in accordance with the RG1.127 Water-Control Structures Inspection, or the

Structures Monitoring Program to manage loss of material (spalling, scaling) and cracking due

to freeze-thaw in below grade inaccessible concrete areas of Group 6 structures is adequate

and no additional plant-specific program is required.

Based on the programs identified above, the staff concluded that the applicant has met the

criteria of SRP-LR Section 3.5.2.2.2.4.2. For those line items that apply to LRA Section

3.5.2.2.2.4.2 the staff determined that the LRA is consistent with the GALL Report and the

applicant has demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB during the period of extended

operation, as required by 10 CFR 54.21(a)(3).

Below-Grade Inaccessible Reinforced Concrete Areas. The applicant stated in LRA Section

3.5.2.2.2.4.3 that cracking due to expansion and reaction with aggregate and reaction with

aggregates and increase in porosity and permeability, and loss of strength due to leaching of

calcium hydroxide are not aging effects requiring management in below grade inaccessible

reinforced concrete areas of Group 6 structures because (1) aggregates used in SSES

concrete structures were selected based on testing per ASTM C-289 "Potential Reactivity of

Aggregate" and C-295 "Petrographic Examination", (2) SSES specification for concrete

prohibits the use of calcium chloride in the concrete mix design, (3) resistance to leaching is

enhanced by using a dense, well-cured, low permeable concrete in accordance with accepted

ACI Standards, and (4) the RG 1.127 Water-Control Structures Inspection is credited for aging

management of these effects/mechanisms for the affected concrete structures and structural

components, even if the AMR did not identify aging effects requiring management.

The staff reviewed LRA Section 3.5.2.2.2.4.3 against the criteria in SRP-LR Section

3.5.2.2.2.4.3, which states that cracking due to expansion and reaction with aggregates and

increase in porosity and permeability, and loss of strength due to leaching of calcium hydroxide

could occur in below grade inaccessible reinforced concrete areas of Group 6 structures. The

GALL Report recommends further evaluation of inaccessible areas if concrete was not

constructed in accordance with the recommendations in ACl 201.2R-77.

The GALL Report recommends that the existing program relies on "Regulatory Guide 1.127,

Inspection of Water-Control Structures Associated with Nuclear Power Plants" for accessible

areas. The SSES RG1.127 Water-Control Structures Inspection described in LRA Section

B.2.40 is an existing program that is consistent, with enhancements, with GALL AMP XI.S7,

"Regulatory Guide 1.127, Inspection of Water-Control Structures Associated with Nuclear

Power Plants." The staff's review of the applicant's RG1. 127 Water-Control Structures

Inspection is documented in SER Section 3.0.3.2.18. For inaccessible areas, the GALL Report

recommends that aging management is not necessary if the concrete was constructed in

accordance with ACl 201.2R.

The staff reviewed the LRA, including the AMR and the associated AMP. The staff noted that

the concrete structures were designed in accordance with ACI 318-71 and constructed in

accordance with ACI 301-72, which meets the intent of ACI 201.2R-77 as discussed in SER

Section 3.5.2.2.1.1. The staff also validated that aggregates were selected in accordance with

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ASTM C-289 and C-295 standards, which meets the GALL recommendation of investigations,

tests, and petrographic examinations of aggregates performed in accordance with ASTM C295-

54 or ASTM C227-50 as described in NUREG-1 557. The staff also noted that leaching of

calcium hydroxide from reinforced concrete is not significant even if the concrete exposed to

flowing water, if the concrete is constructed to ensure that it is dense, well-cured, and has low

permeability. Resistance to leaching is enhanced by using a dense, well-cured concrete with

low permeability.

On the basis of its review, the staff finds that cracking due to expansion and reaction with

aggregates and increase in porosity and permeability, and loss of strength due to leaching of

calcium hydroxide are not plausible aging effects in below-grade inaccessible reinforced

concrete areas of Group 6 structures because (1) the material selection in accordance with

ASTM standards ensures nonreactive concrete aggregates, (2) the design and construction of

SSES concrete structures in accordance with accepted ACI codes meet the intent of ACI

201.2R-77, and (3) the RG 1.127 Water-Control Structures Inspection is credited, and the

absence of concrete aging effects is confirmed under the program.

Based on the programs identified above, the staff concluded that the applicant has met the

criteria of SRP-LR Section 3.5.2.2.2.4.3. For those line items that apply to LRA Section

3.5.2.2.2.4.3 the staff determined that the LRA is consistent with the GALL Report and the

applicant has demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB during the period of extended

operation, as required by 10 CFR 54.21(a)(3).

Cracking due to Stress Corrosion Cracking and Loss of Material due to Pitting and Crevice

Corrosion. The applicant stated in LRA Section 3.5.2.2.2.5 that no tanks with stainless steel

liners are included in the structural AMRs.

The staff reviewed LRA Section 3.5.2.2.2.5 against the criteria in SRP-LR Section 3.5.2.2.2.5,

which states that cracking due to stress corrosion cracking and loss of material due to pitting

and crevice corrosion could occur for Group 7 and 8 stainless steel tank liners exposed to

standing water. The GALL Report recommends further evaluation of plant-specific programs to

manage these aging effects.

The staff reviewed the LRA. The staff noted that no tanks with stainless steel liners are included

in the structural AMRs. Tanks subject to AMR are evaluated with their respective mechanical

systems.

On the basis of its review, the staff finds that crackihg due to stress corrosion cracking and loss

of material due to pitting and crevice corrosion that could occur for Group 7 and 8 stainless

steel tank liners exposed to standing water are not applicable since there are no tanks with

stainless steel liners included in the structural AMRs. Tanks subject to an AMR are evaluated

with their respective mechanical systems.

A-ging of Supports Not Covered by Structures Monitoring Program. The applicant stated in LRA

Section 3.5.2.2.2.6 that the Structures Monitoring Program is credited for aging management of

the following effects/mechanisms: (1) loss of material due to general and pitting corrosion, for

Groups B2-B5 supports; (2) reduction in concrete anchor capacity due to degradation of the

surrounding concrete, for Groups B1-B5 supports; and (3) reduction/loss of isolation function

due to degradation of vibration isolation elements, for Group B4 supports.

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The staff reviewed LRA Section 3.5.2.2.2.6 against the criteria in SRP-LR Section 3.5.2.2.2.6,

which states that the GALL Report recommends further evaluation of certain component

support/aging effect combinations if they are not covered by the structures monitoring program.

This includes (1) loss of material due to general and pitting corrosion, for Groups B2-B5

supports; (2) reduction in concrete anchor capacity due to degradation of the surrounding

concrete, for Groups B1-B5 supports; and (3) reduction/loss of isolation function due to

degradation of vibration isolation elements, for Group B4 supports. Further evaluation is

necessary only for structure/aging effect combinations not covered by the structures monitoring

program.

The staff reviewed LRA 3.5.2.2.2.6. The staff noted that the component support/aging effect

combinations of (1) loss of material due to general and pitting corrosion, for Groups B2-B5

supports; (2) reduction in concrete anchor capacity due to degradation of the surrounding

concrete, for Groups B1-B5 supports; and (3) reduction/loss of isolation function due to

degradation of vibration isolation elements, for Group B4 supports are all covered by the

structures monitoring program. Therefore, the staff determined that no further evaluation is

required.

Based on the programs identified above, the staff concluded that the applicant has met the

criteria of SRP-LR Section 3.5.2.2.2.6. For those line items that apply to LRA Section

3.5.2.2.2.6 the staff determined that the LRA is consistent with the GALL Report and the

applicant has demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB during the period of extended

operation, as required by 10 CFR 54.21(a)(3).

Cumulative Fatigue Damage due to Cyclic Loading. The applicant stated in LRA

Section 3.5.2.2.2.7 that during the process of identifying TLAA in CLB, no fatigue analyses

were identified for component support members, anchor bolts, and welds for Groups B1.1,

B1.2, and B1.3.

The staff reviewed LRA Section 3.5.2.2.2.7 against the criteria in SRP-LR Section 3.5.2.2.2.7,

which states that fatigue of component support members, anchor bolts, and welds for Groups

B1.1, B1.2, and B1.3 component supports is a TLAA as defined in 10 CFR 54.3 only if a CLB

fatigue analysis exists. TLAAs are required to be evaluated in accordance with 10 CFR

54.21(c). The evaluation of this TLAA is addressed separately in Section 4.3, "Metal Fatigue

Analysis," of this SRP-LR.

The staff reviewed LRA Section 3.5.2.2.2.7. The staff confirmed that no fatigue analyses were

identified as TLAAs because no CLB fatigue analysis exists for component support members,

anchor bolts, and welds for Groups B1.1, B1.2, and B1.3. Therefore, cumulative fatigue

damage for Groups B1.1, B1.2, and B1.3 component supports is not a TLAA as defined in

10 CFR 54.3.

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3.5.2.2.3 Quality Assurance for Aging management of Nonsafety-Related Components

SER Section 3.0.4 documents the staff's evaluation of the applicatn's QA program.

3.5.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report

In the applicant LRA Tables 3.5.2-1 through 3.5.2-10, the staff reviewed additional details of the

AMR results for material, environment, AERM, and AMP combinations not consistent with or not

addressed in the GALL Report.

In LRA Tables 3.5.2-1 through 3.5.2-10, the applicant indicated, via notes F through J that the

combination of component type, material, environment, and AERM does not correspond to a

line item in the GALL Report. The applicant provided further information about how it will

manage the aging effects. Specifically, note F indicates that the material for the AMR line item

component is not evaluated in the GALL Report. Note G indicates that the environment for the

AMR line item component and material is not evaluated in the GALL Report. Note H indicates

that the aging effect for the AMR line item component, material, and environment combination

is not evaluated in the GALL Report. Note I indicate that the aging effect identified in the GALL

Report for the line item component, material, and environment combination is not applicable.

Note J indicates that neither the component nor the material and environment combination for

the line item is evaluated in the GALL Report.

For component type, material, and environment combinations not evaluated in the GALL

Report, the staff reviewed the applicant's evaluation to determine whether the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB for the period of extended operation. The

staff's evaluation is documented in the following sections.

3.5.2.3.1 Aging Management Review Results - Primary Containment - LRA Table 3.5.2-1

The staff reviewed LRA Table 3.5.2-1, which summarizes the results of AMR evaluations for the

primary containment component groups.

In LRA Table 3.5.2-1, the applicant identified 38 unique component/material/environment/aging

effect/AMP groups for the Primary Containment. Thirty have AMR results consistent with GALL,

as identified by reference to Notes A through E. The staff confirmed that the references to

Table 1 and GALL Volume II line items are appropriate.

For seven groups, the applicant proposed to manage concrete material, below grade and

protected from weather environment, aging affect none, by using the Structures Monitoring

Program and ISI-IWL Program. The staff's review of the Structures Monitoring Program is

documented in SER Section 3.0.3.2.17. These line items reference Note I and plant-specific

Note 501, which states "No applicable aging effects have been identified for the component.

However, the identified AMP will be used to confirm the absence of significant aging effects for

the period of extended operation." The staff disagrees with the applicant's AMR conclusion that

there are no aging effects requiring management for the period of extended operation for these

groups. However, the staff finds that the credited AMP is appropriate in each case. Because,

the applicant has committed under Structures Monitoring Program to perform ground-water

sampling to ensure that the ground-water is non-aggressive, as consistent with the GALL

Report recommendation. Since the applicant has committed to appropriate aging management

3-492
program for the period of extended operation, the staff finds these AMR results to be

acceptable. I

For one group, the applicant proposed to manage stainless steel material, aging affect none, by

using the ISI-IWE and Containment Leak Rate Test Program. The staffs review of the ISI-IWE

and Containment Leak Rate Test Program are documented in SER Section 3.0.3.1.19 and

3.0.3.1.22 respectively. This line item references Note I and plant-specific Note 501 and 506,

which states "No applicable aging effects have been identified for the component. However, the

identified AMP will be used to confirm the absence of significant aging effects for the period of

extended operation." And "The process line penetrations are of welded steel construction

without expansion bellows, gaskets or sealing compounds. Containment piping and mechanical

penetrations do not contain thermal insulation" respectively. The staff disagrees with the

applicant's AMR conclusion that there are no aging effects requiring management for the period

of extended operation for these groups. However, the staff finds that the credited AMPs are

appropriate in each case. Since the applicant has committed to appropriate AMPs for the period

of extended operation, the staff finds these AMR results to be acceptable.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations for the Primary Containment

not evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended function(s) will be maintained

consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21(a)(3).

3.5.2.3.2 Aging Management Review Results - Reactor Building - LRA Table 3.5.2-2

The staff reviewed LRA Table 3.5.2-2, which summarizes the results of AMR evaluations for the

reactor building component groups.

In LRA Table 3.5.2-2, the applicant identified 37 unique component/material/environment/aging

effect/AMP groups for the Reactor Building. Twenty-seven have AMR results consistent with

GALL, as identified by reference to Notes A through E. The staff confirmed that the references

to Table 1 and GALL Volume II line items are appropriate.

For ten groups, the applicant proposed to manage concrete material, aging affect none, by

using the Structures Monitoring Program. The staff's review of the Structures Monitoring

Program is documented in SER Section 3.0.3.2.17. These line items reference Note I and

plant-specific Note 501, which states "No applicable aging effects have been identified for the

component. However, the identified AMP will be used to confirm the absence of significant

aging effects for the period of extended operation." The staff disagrees with the applicant's

AMR conclusion that there are no aging effects requiring management for the period of

extended operation for these groups. However, the staff finds that the credited AMP is

appropriate in each case. Since the applicant has committed to appropriate AMPs for the period

of extended operation, the staff finds these AMR results to be acceptable.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations for the Reactor Building not

evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended function(s) will be maintained

consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3-493
3.5.2.3.3 Aging Management Review Results - Engineered Safeguards Service Water

Pumphouse and Spray Pond - LRA Table 3.5.2-3

The staff reviewed LRA Table 3.5.2-3, which summarizes the results of AMR evaluations for the

engineered safeguards service water pumphouse and spray pond component groups.

In LRA Table 3.5.2-3, the applicant identified 23 unique component/material/environment/aging

effect/AMP groups for the Engineered Safeguards Service Water Pumphouse and Spray Pond.

Thirteen have AMR results consistent with GALL, as identified by reference to Notes A through

E. The staff confirmed that the references to Table 1 and GALL Volume II line items are

appropriate.

For nine groups, the applicant proposed to manage concrete material, aging affect none, by

using the RG 1.127 Water Control Structures Inspection that is part of the Structures Monitoring

Program. The staff's review of the Structures Monitoring Program is documented in SER

Section 3.0.3.2.17. These line items reference Note I and plant-specific Note 501, which states

"No applicable aging effects have been identified for the component. However, the identified

AMP will be used to confirm the absence of significant aging effects for the period of extended

operation." The staff disagrees with the applicant's AMR conclusion that there are no aging

effects requiring management for the period of extended operation for these groups. However,

the staff finds that the credited AMP is appropriate in each case. Since the applicant has

committed to appropriate AMPs for the period of extended operation, the staff finds these AMR

results to be acceptable.

For one group, the applicant proposed to manage earthen material, aging affect loss of form, by

using the RG 1.127 Water Control Structures Inspection. The staff's review of the RG 1.127

Water Control Structures Inspection is documented in SER Section 3.0.3.2.18. The staff finds

that the credited AMP is appropriate in each case. Since the applicant has committed to

appropriate AMPs for the period of extended operation, the staff finds these AMR results to be

acceptable

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations for the Engineered Safeguards

Service Water Pumphouse and Spray Pond not evaluated in the GALL Report. The staff finds

that the applicant has demonstrated that the effects of aging will be adequately managed so

that the intended function(s) will be maintained consistent with the CLB for the period of

extended operation, as required by 10 CFR 54.21(a)(3).

3.5.2.3.4 Aging Management Review Results - Circulating Water Pumphouse and Water

Treatment Building - LRA Table 3.5.2-4

The staff reviewed LRA Table 3.5.2-4, which summarizes the results of AMR evaluations for the

circulating water pumphouse and water treatment building component groups.

In LRA Table 3.5.2-4, the applicant identified 20 unique component/material/environment/aging

effect/AMP groups for the Circulating Water Pumphouse and Water Treatment Building. Twelve

have AMR results consistent with GALL, as identified by reference to Notes A through E. The

staff confirmed that the references to Table 1 and GALL Volume II line items are appropriate.

3-494
For eight groups, the applicant proposed to manage concrete material, aging affect none, by

using the Structures Monitoring Program. The staff's review of the Structures Monitoring

Program is documented in SER Section 3.0.3.2.17. These line items reference Note I and

plant-specific Note 501, which states "No applicable aging effects have been identified for the

component. However, the identified AMP will be used to confirm the absence of significant

aging effects for the period of extended operation." The staff disagrees with the applicant's

AMR conclusion that there are no aging effects requiring management for the period of

extended operation for these groups. However, the staff finds that the credited AMP is

appropriate in each case. Since the applicant has committed to appropriate AMPs for the period

of extended operation, the staff finds these AMR results to be acceptable.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations for the Circulating Water

Pumphouse and Water Treatment Building not evaluated in the GALL Report. The staff finds

that the applicant has demonstrated that the effects of aging will be adequately managed so

that the intended function(s) will be maintained consistent with the CLB for the period of

extended operation, as required by 10 CFR 54.21(a)(3).

3.5.2.3.5 Aging Management Review Results - Control Structure - LRA Table 3.5.2-5

The staff reviewed LRA Table 3.5.2-5, which summarizes the results of AMR evaluations for the

control structure component groups.

In LRA Table 3.5.2-5, the applicant identified 17 unique component/material/environment/aging

effect/AMP groups for the Control Structure. Nine have AMR results consistent with GALL, as

identified by reference to Notes A through E. The staff confirmed that the references to Table 1

and GALL Volume II line items are appropriate.

For seven groups, the applicant proposed to manage concrete material, aging affect none, by

using the Structures Monitoring Program. The staff's review of the Structures Monitoring

Program is documented in SER Section 3.0.3.2.17. These line items reference Note I and

plant-specific Note 501, which states "No applicable aging effects have been identified for the

component. However, the identified AMP will be used to confirm the absence of significant

aging effects for the period of extended operation." The staff disagrees with the applicant's

AMR conclusion that there are no aging effects requiring management for the period of

extended operation for these groups. However, the staff finds that the credited AMP is

appropriate in each case. Since the applicant has committed to appropriate AMPs for the period

of extended operation, the staff finds these AMR results to be acceptable.

For the remaining one group, the applicant proposed to manage arboron laminate panels

material, aging affect none, and aging management program none. These line item reference

Note J and plant-specific Note 518, which states "The arboron flooring system panels consist of

cellulose based laminate impregnated with thermosetting resins. They are used as raised floor

and are located in a mild temperature and humidity controlled environment. SSES plant-specific

evaluation concluded no aging management is required for arboron flooring panels." The staff

reviewed the LRA, license design basis documents, EPRI 1002950 Structural Tools, Revision 1,

August 2003, and the GALL Report and found that these materials do not perform or support

any license renewal intended functions that satisfy the scoping criteria of 10 CFR 54.4(a).

Therefore, aging management for these materials is not required.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations for the Control Structure not

3-495
evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended function(s) will be maintained

consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21(a)(3).

3.5.2.3.6 Aging Management Review Results - Diesel Generator 'A, B, C, and D' Building -

LRA Table 3.5.2-6

The staff reviewed LRA Table 3.5.2-6, which summarizes the results of AMR evaluations for the

Diesel Generator 'A, B, C, and D' building component groups.

In LRA Table 3.5.2-6, the applicant identified 19 unique component/material/environment/aging

effect/AMP groups for the Diesel Generator 'A, B, C, and D' Building. Eight have AMR results

consistent with GALL, as identified by reference to Notes A through E. The staff confirmed that

the references to Table 1 and GALL Volume II line items are appropriate.

For eleven groups, the applicant proposed to manage concrete material, aging affect none, by

using the Structures Monitoring Program. The staff's review of the Structures Monitoring

Program is documented in SER Section 3.0.3.2.17. These line items reference Note I and

plant-specific Note 501, which states "No applicable aging effects have been identified for the

component. However, the identified AMP will be used to confirm the absence of significant

aging effects for the period of extended operation." The staff disagrees with the applicant's

AMR conclusion that there are no aging effects requiring management for the period of

extended operation for these groups. However, the staff finds that the credited AMP is

appropriate in each case. Since the applicant has committed to appropriate AMPs for the period

of extended operation, the staff finds these AMR results to be acceptable.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations for the Diesel Generator 'A, B,

C, and D' Building not evaluated in the GALL Report. The staff finds that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21(a)(3).

3.5.2.3.7 Aging Management Review Results - Diesel Generator 'E' Building -

LRA Table 3.5.2-7

The staff reviewed LRA Table 3.5.2-7, which summarizes the results of AMR evaluations for the

diesel generator 'E' building component groups.

In LRA Table 3.5.2-7, the applicant identified 13 unique component/material/environment/aging

effect/AMP groups for the Diesel Generator 'E' Building. Three have AMR results consistent

with GALL, as identified by reference to Notes A through E. The staff confirmed that the

references to Table 1 and GALL Volume II line items are appropriate.

For ten groups, the applicant proposed to manage concrete material, aging affect none, by

using the Structures Monitoring Program. The staff's review of the Structures Monitoring

Program is documented in SER Section 3.0.3.2.17. These line items reference Note I and

plant-specific Note 501, which states "No applicable aging effects have been identified for the

component. However, the identified AMP will be used to confirm the absence of significant

aging effects for the period of extended operation." The staff disagrees with the applicant's

3-496
AMR conclusion that there are no aging effects requiring management for the period of

extended operation-for these groups. However, the staff finds that the credited AMP is

appropriate in each case. Since the applicant has committed to appropriate AMPs for the period

of extended operation, the staff finds these AMR results to be acceptable.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations for the Diesel Generator 'E'

Building not evaluated in the GALL Report. The staff finds that the applicant has demonstrated

that the effects of aging will be adequately managed so that the intended function(s) will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21(a)(3).

3.5.2.3.8 Aging Management Review Results - Turbine Building - LRA Table 3.5.2-8

The staff reviewed LRA Table 3.5.2-8, which summarizes the results of AMR evaluations for the

turbine building component groups.

In LRA Table 3.5.2-8, the applicant identified 28 unique component/material/environment/aging

effect/AMP groups for the Turbine Building. Seventeen have AMR results consistent with GALL,

as identified by reference to Notes A through E. The staff confirmed that the references to

Table 1 and GALL Volume II line items are appropriate.

For eleven groups, the applicant proposed to manage concrete material, aging affect none, by

using the Structures Monitoring Program. The staff's review of the Structures Monitoring

Program is documented in SER Section 3.0.3.2.17. These line items reference Note I and

plant-specific Note 501, which states "No applicable aging effects have been identified for the

component. However, the identified AMP will be used to confirm the absence of significant

aging effects for the period of extended operation." The staff disagrees with the applicant's

AMR conclusion that there are no aging effects requiring management for the period of

extended operation for these groups. However, the staff finds that the credited AMP is

appropriate in each case. Since the applicant has committed to appropriate AMPs for the period

of extended operation, the staff finds these AMR results to be acceptable.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations for the Turbine Building not

evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended function(s) will be maintained

consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21(a)(3).

3.5.2.3.9 Aging Management Review Results - Yard Structures - LRA Table 3.5.2-9

The staff reviewed LRA Table 3.5.2-9, which summarizes the results of AMR evaluations for the

yard structures component groups.

In LRA Table 3.5.2-9, the applicant identified 51 unique component/material/environment/aging

effect/AMP groups for the Yard Structures. Twenty six have AMR results consistent with GALL,

as identified by reference to Notes A through E. The staff confirmed that the references to

Table 1 and GALL Volume II line items are appropriate.

3-497
For twenty two groups, the applicant proposed to manage concrete material, aging affect none,

by using the Structures Monitoring Program. The staff's review of the Structures Monitoring

Program is documented in SER Section 3.0.3.2.17. These line items reference Note I and

plant-specific Note 501, which states "No applicable aging effects have been identified for the

component. However, the identified AMP will be used to confirm the absence of significant

aging effects for the period of extended operation." The staff disagrees with the applicant's

AMR conclusion that there are no aging effects requiring management for the period of

extended operation for these groups. However, the staff finds that the credited AMP is

appropriate in each case. Since the applicant has committed to appropriate AMPs for the period

of extended operation, the staff finds these AMR results to be acceptable.

For the remaining three groups, the applicant proposed to manage concrete material, aging

affect loss of material cracking, by using the Structures Monitoring Program. The staff's review

of the Structures Monitoring Program is documented in SER Section 3.0.3.2.17. These line

items reference Note G and plant-specific Note 521, which states "The GALL does not list

exposed to raw water environment for this component type. SSES OE has shown cases of

water accumulating in manholes, trenches (SBO cables). Therefore, aging mechanisms

pertaining to raw water environments are also applicable within manholes, valve vaults, and

instrument pits. The identified AMP is used to manage aging effects for the period of extended

operation." The staff finds that the credited AMP is appropriate in each case. Since the

applicant has committed to appropriate AMPs for the period of extended operation, the staff

finds these AMR results to be acceptable.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations for the Yard Structures not

evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended function(s) will be maintained

consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21(a)(3).

3.5.2.3.10 Aging Management Review Results - Bulk Commodities - LRA Table 3.5.2-10

The staff reviewed LRA Table 3.5.2-10, which summarizes the results of AMR evaluations for

the bulk commodities component groups.

In LRA Table 3.5.2-10, the applicant identified 153 unique component, material, environment

and aging effect AMP groups for the Bulk Commodities. One hundred twenty eight have AMR

results consistent with GALL, as identified by reference to Notes A through E. The staff

confirmed that the references to Table 1 and GALL Volume II line items are appropriate.

For eight groups, the applicant proposed to manage concrete material, aging affect none, by

using the Structures Monitoring Program. The staff's review of the Structures Monitoring

Program is documented in SER Section 3.0.3.2.17. These line items reference Note I and

plant-specific Note 501, which states "No applicable aging effects have been identified for the

component. However, the identified AMP will be used to confirm the absence of significant

aging effects for the period of extended operation." The staff disagrees with the applicant's

AMR conclusion that there are no aging effects requiring management for the period of

extended operation for these groups. However, the staff finds that the credited AMP is

appropriate in each case. Since the applicant has committed to appropriate AMPs for the period

of extended operation, the staff finds these AMR results to be acceptable.

3-498
For ten groups, the applicant has none for aging management program to manage stainless

steel and aluminum materials (Table 3.5.1 item 3.5.1-50), aging affect none, During the review,

the staff noted that the GALL Report recommends the Structures Monitoring Program to

manage aging effects of loss of material/pitting and crevice corrosion. These SSES items have

the same component, material, and environment combination as in the GALL Report. On

May 30, 2008, the staff asked the applicant to provide the technical basis for not following the

GALL Report recommendation (RAI 3.5-1). In the letter dated July 08, 2008, the applicant

stated that line items (3.5.1-50) for stainless steel material exposed to a weather environment

are amended to align with the GALL Report recommendations and Structures Monitoring

Program or ISI-IWF AMPs. The staff reviewed the applicant responses and found them

acceptable because, after amending' LRA Table 1, line item 3.5.1-50 will be aligned with the

GALL Report recommendations.

For the remaining seven groups, the applicant has Note J for rubber, elastomer, gypsum board,

pryocrete grout, fiberglass, and insulation jacket and has none for aging management program

to manage an aging effects for these items. The staff reviewed the LRA, license design basis

documents, EPRI 1002950 Structural Tools, Revision 1, August 2003, and the GALL Report

and found that these materials do not perform or support any license renewal intended

functions that satisfy the scoping criteria of 10 CFR 54.4(a). Therefore, aging management for

these materials is not required.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations for the Bulk Commodities not

evaluated in the GALL Report. The staff finds that the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended function(s) will be maintained

consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21(a)(3).

3.5.3 Conclusion

The staff concludes that the applicant has provided sufficient information to demonstrate that

the effects of aging for containments, structures, and component supports within the scope of

license renewal and subject to an AMR will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21(a)(3).

3.6 Aging Management of Electrical and Instrumentation and Controls

The following information documents the staff's review of the applicant's AMR results for the

electrical and I&C components and component groups of:

" Non-EQ Insulated Cables and Connections

" Metal Enclosed Bus (Non-Segregated)

* High-Voltage Insulators

" Transmission Conductors and Connections

3.6.1 Summary of Technical Information in the Application

LRA Section 3.6 provides AMR results for the electrical and I&C components and component

groups. LRA Table 3.6.1, "Summary of Aging Management Programs for Electrical and I&C

Components Evaluated in Chapter VI of the GALL Report," is a summary comparison of the

3-499
applicant's AMRs with those evaluated in the GALL Report for the electrical and I&C

components and component groups.

3.6.2 Staff Evaluation

The staff reviewed LRA Section 3.6 to determine whether the applicant provided sufficient

information to demonstrate that the effects of aging for the electrical and I&C components

within the scope of, license renewal and subject to an AMR will be adequately managed so that

the intended function(s) will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21(a)(3).

The staff reviewed AMRs to ensure the applicant's claim that certain AMRs were consistent with

the GALL Report. The staff did not repeat its review of the matters described in the GALL

Report; however, the staff did verify that the material presented in the LRA was applicable and

that the applicant has identified the appropriate GALL Report AMPs. The staff's evaluations of

the AMPs are documented in SER Section 3.0.3. Details of the staff's evaluation are

documented in SER Section 3.6.2.1.

The staff also reviewed AMRs consistent with the GALL Report and for which further evaluation

is recommended. The staff confirmed that the applicant's further evaluations were consistent

with the SRP-LR Section 3.6.2.2 acceptance criteria. The staff's evaluations are documented in

SER Section 3.6.2.2.

The staff also reviewed the remaining AMRs that were not consistent with, or not addressed in,

the GALL Report. The technical review evaluated whether all plausible aging effects have been

identified and whether the aging effects listed were appropriate for the material-environment

combinations specified. The staff's evaluations are documented in SER Section 3.6.2.3.

Table 3.6-1 summarizes the staff's evaluation of components, aging effects or mechanisms,

and AMPs listed in LRA Section 3.6 and addressed in the GALL Report.

Table 3.6-1 Staff Evaluation for Electrical and Instrumentation and Controls in the GALL

Report

ComponentGrou ,._Aging Effet/ AMP in GALL ".Frther• AMP in LRA, Staff Evaluation

(GALL t•odrt: Mechanism Report 'Evialuation Suplements,

Itm o. n GALL, Or,

Report Amendments

Electrical equipment Degradation due Environmental Yes TLAA Further evaluation,

subject to to various aging Qualification of Environmental (See

10 CFR 50.49 mechanisms Electric Components Qualification of Section 3.6.2.2.1)

environmental Electrical

qualification (EQ) Components

requirements

(3.6.1-1) (B.3.2)

3-500
Component GroMup-. AgingEffectl AMP in GALL. Further AMP in LRA, Staff Evaluation

,(GALL Report, Mechanism Report: Evaluation : Supplements,

Item N o:)> iniAL o

:Reo7 A mendments

Electrical cables, Reduced Electrical Cables and No Non-EQ Consistent with

connections and insulation Connections Not Electrical Cables GALL (See

fuse holders resistance and Subject to and Section 3.6.2.1)

(insulation) not electrical failure 10 CFR 50.49 Connections

subject to due to various EQ Requirements Visual

10 CFR 50.49 physical, Inspection

EQ requirements thermal, Program

(3.6.1-2) radiolytic, (B.2.41)

photolytic, and

chemical

mechanisms

Conductor insulation Reduced Electrical Cables No Non-EQ Cables Consistent with

for electrical cables insulation And Connections and GALL (See

and connections resistance and Used In Connections Section 3.6.2.1)

used in electrical failure Instrumentation Used in Lowinstrumentation due to various Circuits Not Subject Current

circuits not subject to physical, to 10 CFR 50.49 Instrumentation

10 CFR 50.49 thermal, EQ Requirements Circuits Program

EQ requirements radiolytic, (B.2.42)

that are sensitive to photolytic, andreduction in chemical

conductor insulation mechanisms

resistance

(3.6.1-3)

Conductor insulation Localized Inaccessible Medium No Non-EQ Consistent with

for inaccessible damage and Voltage Cables Not Inaccessible GALL (See

medium Voltage breakdown of Subject to Medium-Voltage Section 3.6.2.1)

(2 kV to 35 kV) insulation 10 CFR 50.49 Cables Program

cables (e.g., installed leading to EQ Requirements (B.2,43)

in conduit or direct electrical failure

buried) not-subject'to due to moisture-'

10 CFR 50.49' intrusion, water

EQ requirements trees

(316.1-4)

Connector contacts Corrosion of Boric Acid Corrosion No Not applicable Not applicable to

for electrical connector BWR

connectorsexposed contact surfaces

to borated water due to intrusion

leakage of borated water

(3.6.1-5)

Fuse Holders Fatigue due to Fuse Holders No Fuse Holders Not Consistent with

(Not Part of a Larger ohmic heating, Program GALL (See

Assembly): Fuse thermal cycling, (B.2.50) Section 3.6.2.3)

holders - metallic electrical

clamp transients,

(3.6.1-6) frequent

manipulation,

vibration,

chemical

contamination,

corrosion, and

oxidation

3-501
!.ComponentGOroUp Aging AAMP Eff-ct inGALL -:`.Further AMP in LRA,.- Staff Evaluation

S(GALL Report MechIanism, ,, Report Evaluation Supplements,

Item No.) In GALL or' ____________________ Rport' "Ame-ndments'--

Metal enclosed bus - Loosening of Metal Enclosed Bus No Metal Enclosed Consistent with

bus, connections bolted Bus Inspection GALL (See

(3.6.1-7) connections due Program Section 3.6.2.1)

to thermal (B.2.44)

cycling and

ohmic heating

Metal enclosed bus - Reduced Metal Enclosed Bus No Metal Enclosed Consistent with

insulation, insulators insulation Bus Inspection GALL (See

(3.6.1-8) resistance and Program Section 3.6.2.1)

electrical failure (B.2.44)

due to various

physical,

thermal,

radiolytic,

photolytic, and

chemical

mechanisms

Metal enclosed bus - Loss of material Structures No Structures Consistent with

enclosure due to general Monitoring Program Monitoring GALL (See

assemblies corrosion Program Section 3.6.2.1)

(3.6.1-9) (B.2.39)

Metal enclosed bus - Hardening and Structures No Metal Enclosed Consistent with

enclosure loss of strength Monitoring Program Bus Inspection GALL (See

assemblies due to Program Section 3.6.2.1.1)

(3.6.1-10) elastomers (B.2.44)

degradation

High-voltage Degradation of A plant-specific Yes None Further evaluation

insulators insulation quality aging management (See SER

(3.6.1-11) due to presence program is to be Section 3.6.2.2.2)

of any salt evaluated

deposits and

surface

contamination;

loss of material

caused by

mechanical

wear due to

wind blowing on

transmission

conductors

3-502
Component Group. A.'ging:Effecdtl AMP in.GALL :Further AMP In LRA,.. Staff Evaluation

(GALL Repo ' .Mechanism Report :EValuation Supplements,

Item No.), ' in GALL : or

•__________ Report Amendments,

Transmission Loss of material A plant-specific Yes None Further evaluation

conductors and due to wind aging management (See SER Section

connections; induced program is to be 3.6.2.2.3)

switchyard bus and abrasion and evaluated

connections fatigue; loss of

(3.6.1-12) conductor

strength due to

corrosion;

increased

resistance of

connection due

to oxidation or

loss of preload

Cable Connections - Loosening of Electrical Cable No Non-EQ Consistent with

metallic parts bolted Connections Not Electrical Cable GALL (See

(3.6.1-13) connections due Subject to Connections Section 3.6.2.1)

to thermal 10 CFR 50.49 Program

cycling, ohmic Environmental

heating, Qualification

electrical Requirements

transients,

vibration,

chemical

contamination,

corrosion, and

oxidation

Fuse Holders None None No Not applicable Consistent with

(Not Part of a Larger GALL (See Section

Assembly) - 3.6.2.1)

insulation material

(3.6.1-14)

The staffs review of the electrical and I&C component groups followed any one of several

approaches: (1) as documented in SER Section 3.6.2.1, the staff reviewed AMR results for

components that the applicant indicated are consistent with the GALL Report and require no

further evaluation, (2) as documented in SER Section 3.6.2.2, the staff reviewed AMR results

for components that the applicant indicated are consistent with the GALL Report and for which

further evaluation is recommended, or (3) as documented in SER Section 3.6.2.3, the staff

reviewed AMR results for components that the applicant indicated are not consistent with or not

addressed in the GALL Report. The staff's review of AMPs credited to manage or monitor aging

effects of the electrical and I&C components is documented in SER Section 3.0.3.

3.6.2.1 AMR Results Consistent with the GALL Report

LRA Section 3.6.2.1 identifies the materials, environments, aging effects requiring

management, and the following programs that manage aging effects for the electrical and I&C

components:

• Non-EQ Insulated Cables and Connections Visual Inspection Program

* Non-EQ Cables and Connections Used in Low-Current Instrumentation Circuits Program

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" Non-EQ Inaccessible Medium Voltage Cables Program

* Non-EQ Electrical Cable Connections Program

* Metal Enclosed Bus Inspection Program

In LRA Table 3.6.2-1, the applicant summarizes AMRs for the electrical and instrumentation

and controls components and claimed that these AMRs are consistent with the GALL Report.

For component groups evaluated in the GALL Report for which the applicant claimed

consistency with the report and for which the GALL Report does not recommend further

evaluation, the staff's review determined whether the plant-specific components of these GALL

Report component groups were bounded by the GALL Report evaluation.

The applicant noted for each AMR line item how the information in the tables aligns with the

information in the GALL Report. The staff reviewed those AMRs with notes A through E

indicating how the AMR is consistent with the GALL Report.

The staff reviewed the information in the LRA. The staff did not repeat its review of the matters

described in the GALL Report; however, the staff did verify that the material presented in the

LRA was applicable and that the applicant identified the appropriate GALL Report AMRs.

The staff reviewed the LRA to confirm that the applicant: (a) provided a brief description of the

system, components, materials, and environments; (b) stated that the applicable aging effects

were reviewed and evaluated in the GALL Report; and (c) identified those aging effects for the

electrical and I&C components that are subject to an AMR. On the basis of its audit and review,

the staff determines that, for AMRs not requiring further evaluation, as identified in LRA

Table 3.6.1, the applicant's references to the GALL Report are acceptable and no further staff

review is required.

3.6.2.1.1 Hardening and loss of strength due to elastomer degradation

In the discussion section in LRA Table 3.6.2-1, Note 606, the applicant stated that the

inspection of the metal-enclosed bus enclosure assembly elastomers will be performed as part

of the metal enclosed bus inspection program. The elastomers will be inspected when the

covers of various bus enclosure sections are removed.

The staff noted that in the AMR results line that points to Table 3.6.1, Item 3.6.1-10, the

applicant included a reference to Note E.

The staff reviewed the AMR results lines referenced to Note E and determined that the

component type, material, environment, and aging effect are consistent with the corresponding

line of the GALL Report; however, where the GALL Report recommends the AMP XI.S6,

"Structures Monitoring Program", the applicant has proposed the Metal-Enclosed Bus

Inspection Program. As discussed in Section 3.0.3.1, the staff found the Metal-Enclosed Bus

Inspection Program acceptable to inspect the metal enclosed bus elastomer degradation.

The staff evaluated the applicant's claim of consistency with the GALL Report. The staff also

reviewed information pertaining to the applicant proposals for managing aging effects. On the

basis of its review, the staff concludes that the AMR results, which the applicant claimed to be

consistent with the GALL Report, are indeed consistent with its AMRs. Therefore, the staff

concludes that the applicant has demonstrated that the effects of aging for these components

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will be adequately managed so that the intended function(s) will be maintained consistent with

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.6.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation is

Recommended

In LRA Section 3.6.2.2, the applicant further evaluates aging management, as recommended

by the GALL Report, for the electrical and I&C components and provides information

concerning how it will manage the following aging effects:

• Electrical equipment subject to EQ

" Degradation of insulator quality due to salt deposits or surface contamination, loss of

material due to mechanical wear

" Loss of material due to wind induced abrasion and fatigue, loss of conductor strength

due to corrosion, and increased resistance of connection due to oxidation or loss of preload

* QA for aging management of nonsafety-related components

For component groups evaluated in the GALL Report, for which the applicant claimed

consistency with the report and for which the GALL Report recommends further evaluation, the

staff reviewed the corresponding AMR line items 3.6.1-11 and 3.6.1-12 in LRA Table 3.6.1. The

staff also reviewed applicant's evaluation to determine whether it adequately addressed the

issues further evaluated. In addition, the staff reviewed the applicant's further evaluations

against the criteria contained in SRP-LR Section 3.6.2.2. The staff's evaluation of items which

require further evaluation is discussed below.

3.6.2.2.1 Electrical Equipment Subject to Environmental Qualification

LRA Section 3.6.2.2.1 states that EQ is a TLAA, as defined in 10 CFR 54.3. Applicants must

evaluate TLAAs in accordance with 10 CFR 54.21(c)(1). SER Section 4.4 documents the staff's

review of the applicant's evaluation of this TLAA.

3.6.2.2.2 Degradation of Insulator Quality Due to Salt Deposits or Surface Contamination, Loss

of Material Due to Mechanical Wear

The staff reviewed LRA Section 3.6.2.2.2 against the criteria in SRP-LR Section 3.6.2.2.2. In

LRA Section 3.6.2.2.2, the applicant states that there are no aging effects identified that require

aging management for the high-voltage insulators subject to AMR for SSES. Due to its inland

location, salt spray from the ocean is not of concern at SSES. The applicant also states that the

rural location of SSES provides for minimal contamination from industrial effluents. The buildup

of surface contamination is gradual and is periodically washed away by rainfall. The highvoltage insulator within the scope of license renewal are connected to rigid components, such

that significant movement is not considered as a stressor, and wear is not identified as an aging

mechanism.

The staff reviewed LRA Section 3.6.2.2.2 against the criteria in SRP-LR Section 3.6.2.2.2 which

states that degradation of insulator quality due to salt deposits or surface contamination may

occur in high-voltage insulators. The GALL Report recommends further evaluation of plantspecific AMPs for plants at locations of potential salt deposits or surface contamination (e.g., in

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the vicinity of salt water bodies or industrial pollution). Loss of material due to mechanical wear

caused by wind on transmission conductors may occur in high-voltage insulators. The GALL

Report recommends further evaluation of a plant-specific AMP to ensure that these aging

effects are adequately managed.

The staff noted that various airborne material such as dust, salt and industrial effluent can

contaminate insulator surfaces. The buildup of surface contamination is gradual and in most

areas such contamination is washed away by rain; the glazed insulator surface aids this

contamination removal. A large buildup of contamination could enable the conductor voltage to

track along the surface more easily and can lead to insulator flashover. Surface contamination

can be a problem in areas where there are greater concentrations of airborne particles such as

near facilities that discharge soot or near the sea coast where salt spray is prevalent. Since

SSES is not located near facilities that discharge soot or near the sea coast, the rate of

contamination buildup on the insulators is not significant and is periodically washed away by

rainfall. Therefore, the staff found that degradation of insulator due to salt deposit or surface

contamination is not an aging effect requiring management for high-voltage insulators.

The staff noted that mechanical wear could be an aging effect for strain and suspension

insulators in that they are subject to movement. Movement of the insulators can be caused by

wind blowing the supported transmission conductor, causing it to swing from side to side. If this

swinging is frequent enough, it could cause wear in the metal contact points of the insulator

string and between an insulator and supporting hardware. In LRA Section 3.6.2.2.2, the

applicant states that the high-voltage insulators within the scope of license renewal for SSES

are connected to rigid components, such that significant movement is not considered as a

stressor and wear is not identified as an aging mechanism. However, the applicant did not

describe which components are connected to high-voltage insulators for which wear is not an

aging mechanism. In a letter dated July 3, 2008, the staff issued RAI 3.6-5 to request the

applicant describe components that are connected to high-voltage insulators and explain why

wear is not an aging mechanism for these high-voltage insulators. In a letter dated

August 5, 2008, the applicant stated that LRA Section 3.6.2.2.2 was revised in response to the

staffs RAI 2.5-1 as documented in Reference 3. The amended LRA includes high-voltage

insulators in addition to those connected to rigid components. Based on the amended LRA, the

components connected to the SSES high-voltage insulators within the scope of license renewal

are transmission conductors, transmission towers, dead end structures, switchyard disconnect

switches, motor-operated disconnect switches in the transformer yard, and structural supports.

The applicant further stated, in essence, that wear is not identified as an aging mechanism for

station post-insulators used to support short lengths of switchyard transmission cable and

components such as disconnect switches, because there is not movement involved, and

consequently no wear. All connections to station post-insulators are solid bolted connections,

such that there is no movement. The applicant also stated that a review of the SSES OE did not

reveal any failures of high-voltage insulators due to wear, or any significant issues associated

with wear.

The staff finds the applicant response acceptable. The staff noted that all connectors to

insulators are solid bolted connections and there is no movement involved. The transmission

conductors within the scope of license renewal at SSES are in short spans and the surface

areas exposed to wind loads are not significant. Furthermore, the applicant has confirmed that

it has not identified any loss of material of insulators due to mechanical wear or any significant

issues associated with wear. Therefore, the staff determined that loss of material due to wear is

not considered an aging effect and will cause a loss of intended functions of the insulators at

SSES.

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Based on the program identified, the staff concludes that the applicant's programs meet SRPLR 3.6.2.2.2 criteria. For those line items that apply to LRA Section 3.6.2.2.2, the staff

determines that surface contamination and loss of material due to wear is not an applicable

aging effect requiring management for high-voltage insulators at SSES and that the applicant

has demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21(a)(3).

3.6.2.2.3 Loss of Material Due to Wind-Induced Abrasion and Fatigue, Loss of Conductor

Strength Due to Corrosion, and Increased Resistance of Connection Due to Oxidation or Loss

of Pre-Load

In LRA Section 3.6.2.2.3, the applicant states that there is no switchyard bus within the scope of

license renewal. For transmission conductors and connections subject to AMR, there are no

aging effects identified that require aging management. The effects of wind do not require

aging management as the sections of transmission conductor in the scope of license renewal

are short in length, rigid, and connected to rigid components. The applicant also states that loss

of conductor strength due to corrosion of the transmission conductor is not identified as an

aging effect due to ample design and a minimal corrosion process at the rural location of SSES.

Connection resistance is not identified as a stressor based on the use of good bolting practices

and review of site OE.

In the LRA, the applicant further states that the most prevalent aging mechanism contributing to

loss of conductor strength of aluminum conductor steel reinforced (ACSR) transmission

conductors is corrosion. For ACSR conductors, degradation begins as a loss of zinc from the

galvanized steel core wires. Corrosion rate depend largely on air quality, which involves

suspended particles in the air, sulfur dioxide (S02) concentration, rain, fog, chemistry, and

other weather conditions. Corrosion of ACSR conductors is a very slow process that is even

slower in rural areas with less air pollution. The applicant also states that SSES is located in a

rural area in north-central Pennsylvania where airborne particle concentrations are

comparatively low.

The applicant also states that test performed by Ontario Hydroelectric showed a 30%

composite loss of conductor strength for an 80 year-old sample of an ACSR conductor (due to

corrosion). With respect to the Ontario Hydroelectric study, the National Electrical Safety Code

(NESC) requires that tension on installed conductors be a maximum of 60% of the ultimate

conductor strength and that consideration for ice, wind, and temperature be included in the

design. With a 30% loss of conductor strength, there is still margin between the NESC

requirements and the actual conductor strength. The applicant concluded that because the

SSES transmission conductor design and installation meet the NESC requirements, the Ontario

Hydroelectric study is considered to bound the SSES configuration.

In addition, the applicant states that increased connection resistance is not identified as an

aging effect requiring management. Bolted connections associated with transmission

conductors employ the use of good bolting practices consistent with the recommendations of

EPRI 1003471, "Electrical Connector Application Guideline." The applicant also states that

bolting hardware is selected to be compatible with the lugs used on the transmission

conductors and Belleville washers are used to compensate for temperature changes and to

maintain proper tightness. The applicant further states that its review of OE revealed no bolted

connection failures associated with transmission conductors at SSES.

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The applicant did not identify certain components within the scope of license renewal in

accordance with the requirements of 10 CFR 54.4(a)(3) for compliance with the SBO rule. In a

letter dated July 30, 2007, the staff asked RAI 2.5-1, and the applicant responsed by letter

dated August 23, 2007 with justification for why the switchyard circuit breakers were not

included in the scope of license renewal. In a letter dated May 7, 2008, the applicant amended

the LRA to include switchyard circuit breakers and high-voltage insulators within the scope of

license renewal. As a result of bringing high-voltage insulators into the scope, the applicant

revised LRA Section 3.6.2.2.3 to address aging effects of high-voltage insulators. The applicant

stated that loss of material due to mechanical wear is not an aging effect for certain strain

insulators if they are subject to significant movement. Movement of the insulator can be caused

by wind blowing the supported transmission conductor, causing it to swing from side to side. If

this swing is frequent enough, it could cause wear on the metallic contact points of the insulator

string and between an insulator and the supporting hardware. The applicant also stated that

although this aging mechanism is possible, industry experience has shown that transmission

conductors do not normally swing unless subjected to a substantial wind and they stop swinging

shortly after the wind subsides. Wind loading that can result in conductor sway is considered in

the transmission system design.

The staff reviewed LRA Section 3.6.2.2.3 against SRP-LR Section 3.6.2.2.3 which states that

loss of material due to wind induced abrasion and fatigue, loss of conductor strength due to

corrosion, and increased resistance of connection due to oxidation or loss of pre-load could

occur in transmission conductors and connections, and in switchyard bus and connections. The

GALL Report recommends further evaluation of a plant-specific AMP to ensure that this aging

effect is adequately managed.

The staff noted that transmission conductor vibration would be caused by wind loading. Industry

experience has shown that the transmission conductors do not normally swing and that when

they do, due to a substantial wind, do not continue to swing for very long once the wind has

subsided. Wind loading that can cause a transmission line and insulators to vibrate is

considered in the design and installation. The sections of transmission conductor in the scope

of license renewal are short spans, the surface area exposed to wind loads are not significant.

Based on this information, the staff determined that loss of material of transmission conductors

due to vibration is not an aging effect requiring management.

The staff also noted that corrosion of ACRS conductors is a slow acting aging effect that is

even slower for rural areas such as SSES, which generally has less suspended particles and

carbon dioxide concentration in the air than urban areas. The applicant states that a test

performed by Ontario Hydroelectric showed a 30% composite loss of conductor strength for an

80 year-old sample of an ACSR conductor (due to corrosion). However, the applicant did not

provide detailed information to substantiate the conclusion that the Ontario Hydroelectric Study

is valid for SSES. In a letter dated July 3, 2008, the staff issued RAI 3.6-2 to request the

applicant to explain the test performed by Ontario Hydroelectric and provide details as how

SSES's transmission conductors installed at SSES were bounded by the Ontario Hydro test and

will have adequate margin for 60 years.

In response to the staff's request, in a letter dated August 5, 2008, the applicant stated that the

tests for Ontario Hydro were conducted in the field and in the laboratory. A nondestructive

corrosion detector was modified for live line measurement of the loss of galvanizing from the

steel cores of the ACSR conductors. The field measurements were performed using a

motorized overhead line corrosion detector that traveled along the transmission line. Samples

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of the conductors tested in the field also were examined in the lab, through tests of fatigue,

tensile strength, torsional ductility, and electrical performance. The applicant also stated that

the fatigue and tensile strength testing involved the use of a dynamometer and an

electromagnetic shaker, with the conductor strung across a suspension assembly. The NESC

requires that the maximum tension of installed conductors shall not be more than 60% of the

rated breaking strength under NESC design conditions. NESC design conditions (known as

NESC Heavy for all of Pennsylvania) include simultaneous consideration of ice, wind, and

temperature. The applicant states that its design criteria for 230kV transmission lines are even

more demanding than NESC design criteria (1" radial ice versus 1/2" radial ice and a

simultaneous 8 psf wind versus 4 psf wind). The applicant further stated that this conductor

loading is higher than NESC and, like NESC, must not exceed 60% rated breaking strength. In

addition, the applicant stated that conductor loading requirements are reviewed below for the

startup transformer #10 230kv Tap and for the 230kV/5OOkV yard tie, which operates at 230kV.

Both of these lines utilize 1590 kcmil Lapwing 45/7 ACSR conductors. The 1590 describes the

cross-sectional area of the conductor in kcmils (1 kcmil = 1000 circular mils, and one circular

mil = the cross-sectional area of a circle 1 mil in diameter.). The 45/7 means the conductor has

45 outer strands of aluminum conductor around a two-layer core consisting of 7 strands of

galvanized steel wire. The ultimate strength (rated breaking strength) of Lapwing transmission

conductor is 42,200 lbs. The applicant also stated that based on a design maximum tension of

21,537 lbs for the startup transformer #10 230kV Tap, the margin between the maximum

conductor load and the ultimate conductor strength is 20,663 lbs.; therefore, the margin for

ultimate strength is 49%. The applicant further stated that Ontario Hydro study showed a 30%

loss of composite conductor strength in the typical 70 year-old conductor. In the case of the

Lapwing transmission conductors, a 30% loss of ultimate strength would mean that there would

still be adequate margin (46%) between the design maximum load of 21,537 pounds and the

eventual conductor strength of 33,085 pounds for the startup transformer #10 230kV Tap (1.12

x 42,200 x 0.7). As noted by Ontario Hydro, "new conductors show an average strength of

112% of rated tensile strength." The 230 kV / 500 kV Yard Tie line has a design maximum

conductor tension of 16,000 lbs., and thus, an even greater margin. Both transmission lines

exceed the design requirements set forth by the NESC. Therefore, the expected margin at 70

years of age is adequate for these installed transmission conductors at SSES. In addition, the

applicant stated that transmission conductor samples tested in the Ontario Hydro Test included

samples with 45 No. 7 strands and are representative of the installed conductors at SSES, so

the conclusions from the Ontario Hydroelectric Test Report for the remaining strength after 70

years of installation are both conservative and valid for SSES. Therefore, the applicant

concluded that loss of conductor strength due to corrosion of the transmission conductors is not

an aging effect requiring management for the period of extended operation.

The staff's review determined that the maximum tension of transmission conductors for start up

transformer #10 could be 65% of the rated breaking strength after losing 30% of conductor

breaking strength due to corrosion (21537 lbs./(1.12 x 42200 x 70% Ibs). NESC requires that

the maximum tension of installed conductors shall not be more than 60% of the rated breaking

strength. The ratio between the maximum tension and ultimate conductor strength would not

meet the NESC design requirements during the period of extended operation. The staff

expressed its concern during a conference with the applicant and requested the applicant to

explain why loss of conductor strength due to corrosion is not a significant aging effect when

these conductors would not meet the NESC design requirement after aging effect.

In a letter dated November 11, 2008, the applicant stated that using the PPL conservative

design criteria, the maximum design tension for the conductors in the Startup Transformer #10

Tap is 21,537 pounds. To put these loadings in perspective, the PPL design is compared to the

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NESC "Heavy" requirements. Based on a simulation using an industry standard sag-tension

computer program, the design maximum tension of 21,537 pounds under the PPL criteria of

1 inch radial ice simultaneously with an 8 psf wind and 0 degree F temperature corresponds to

an NESC "Heavy" design maximum tension of 16,195 pounds. The 16,195 pound maximum

tension is 38% of rated breaking strength under initial (newly installed conductor) conditions.

Therefore, the NESC criteria are met. The applicant further stated that based on the NESC

"Heavy" equivalent design maximum tension of 16,195 pounds for the Startup Transformer #10

230kV Tap conductors, the difference between the design maximum conductor load of 16,195

pounds and the ultimate conductor strength is 26,005 pounds, which produces a margin for

ultimate strength of 62% [26,005 / 42,200 = 62%]. In addition, the applicant stated that the

Ontario Hydro study showed a 30% loss of composite conductor strength in the typical 70 yearold conductor. In the case of the Lapwing transmission conductors, a 30% loss of ultimate

strength equates to an eventual conductor strength of 33,085 pounds for the Startup

Transformer #10 230kV Tap (1.12 x 42,200 x 0.7). As noted by Ontario Hydro, "new conductors

show an average strength of 112% of rated tensile strength." Based on the NESC "Heavy"

equivalent design maximum tension of 16,195 pounds for the Startup Transformer #10 230kV

Tap conductors, the difference between the design maximum conductor load of 16,195 pounds

and the eventual conductor strength of 33,085 is 16,890 pounds, which produces a margin for

ultimate strength of 51% [16,890 / 33,085 = 51%]. The applicant concluded that loss of

conductor strength due to corrosion of the transmission conductors is not an aging effect

requiring management for the period of extended operation.

The staff finds the applicant's response acceptable. The previously heavy loading of 21537 lbs.

was based on the heavy loading of 1 inch radial ice simultaneously with an 8 psf wind on a

transmission conductor. The calculated heavy loading of 16890 lbs. was based on NESC heavy

loading requirement of a 1/2" radial ice and a simultaneous 4 psf wind. The ratio between the

heavy loading and the ultimate conductor strength of a 70 year old transmission conductor

(after loosing 30% of conductor strength due to corrosion) is 49% (16890 lbs./1.12 x 42200 lbs.

x 0.7). The NESC requires that the maximum tension of installed conductors shall not be more

than 60% of the rated breaking strength under NESC design conditions. The ratio of maximum

heavy load and the ultimate conductor strength of installed conductors are below the 60%

NESC requirements. Furthermore, the length of transmission conductors in-scope of license

renewal is short span. These transmission conductors connecting the switchyard to the startup

transformer provide restoration of offsite power after a SBO event. The heavy loading of these

transmission conductors is much less than the calculated heavy loading of a transmission line.

Based on this information, the staff determined that loss of conductor strength due to corrosion

of transmission conductor is not a significant aging effect requiring management for the period

of extended operation. The staffs concern about loss of conductor strength due to corrosion is

resolved.

In LRA Section 3.6.2.2.3, the applicant stated that bolted connections associated with

transmission conductors employ the use of good bolting practices consistent with the

recommendations of EPRI 1003471, "Electrical Connector Application Guideline." However, the

applicant did not explain how its good bolting practices are consistent with EPRI 1003471. In a

letter dated July 3, 2008, the staff issued RAI 3.6-3 to request the applicant to describe how the

bolted connections associated with transmission conductors at SSES follow EPRI 1003471

recommendations. In their response dated August 5, 2008, the applicant stated that the

following bolted connection practices are used at SSES to ensure integrity of transmission

conductor bolted connections. These practices are consistent with the design and assembly

guidance in EPRI 1003471.

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Washers are used between the connector and bolt heads and nuts to protect the

surface of the connector when the bolt is turned.

* Belleville washers are used to keep the load on the connection as the connectors and

bolting materials respond to heat up and cool down.

The use of Belleville washers is predetermined for certain connector and bolting material

combinations and specified in the construction specifications.

Contact surfaces are cleaned, scoured (except plated surfaces) to remove any oxide

material coating, wiped with a dry clean cloth, and immediately coated with an oxide

inhibiting joint compound.

The applicant also stated that the bolting practices used for SSES transmission conductor

connections have been proven by reliable operation of the transmission system and the

switchyards associated with SSES.

The staff finds the applicant response acceptable because pre-load of bolted connections is

maintained by the use of lock and Belleville washers that absorb vibration and prevent loss of

pre-load. Contact surfaces are cleaned and coated with an oxide inhibiting joint compound (a

grease-type sealant) to prevent the formation of oxides on the metal surface and to prevent

moisture from entering these services, thus reducing changes of corrosion. Based on this

information, the staff determines that the design of transmission connections using Bellville

washers will eliminate the potential torque relaxation of bolted connections. This design is

consistent with the recommendation in EPRI document TR-1 04213, "Bolted Joint Maintenance

& Application Guide."

However, the staff noted that EPRI document TR-1 04213 identified a special problem with

Belleville washers. Hydrogen embrittlement is a recurring problem with Belleville washers and

other springs. When springs are electroplated, the plating process forces hydrogen into the

metal grain boundaries. If the hydrogen is not removed, the spring may spontaneously fail at

any time while in service. In a letter dated July 3, 2008, the staff issued RAI 3.6-3 (b) to request

the applicant to explain if electroplated Belleville washers are currently used at SSES. The staff

also requested the applicant to describe activities used to confirm the effectiveness of

switchyard bolted connections. In response dated August 5, 2008, the applicant stated that the

Belleville washers in use with the transmission conductors are stainless steel and are not

electroplated. Therefore, they are not subject to the hydrogen embrittlement aging effect. The

applicant also stated that switchyard bolted connections are routinely inspected using

thermography to confirm effectiveness of the connections. The staff found the applicant's

response acceptable because the special problem with hydrogen embrittlement is not a

concern at SSES since the Belleville washers in use with the transmission conductors are

stainless steel. The concern with hydrogen embrittlement aging effect is not applicable to

SSES. Furthermore, the applicant currently performs routine inspection using thermography to

confirm the effectiveness of switchyard connections.

The staff noted that increased resistance of connections due to oxidation could occur in

transmission conductors and connections, and in switchyard bus and connections. In LRA

Section 3.6.2.2.3, the applicant stated that increased connection resistance is not identified as

an aging effect requiring management. However, the applicant did not provide any basis for this

conclusion. In a letter dated July 3, 2008, the staff issued RAI 3.6-3.c to request the applicant to

explain why increased resistance of connections due to oxidation is not identified as an aging

effect requiring management. In a letter dated August 5, 2008, the applicant stated that

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increased connection resistance of switchyard connections due to oxidation is not identified as

an aging effect requiring management because of the use of good bolting practices that include

proper cleaning of contact surfaces, application of oxide inhibiting compound, and the use of

appropriate hardware to ensure the connection remain tight. These bolting practices minimize

the formation of an oxide layer directly at the contact point.

The staff found the applicant response acceptable. The staff noted that proper cleaning of

contact surface and using an anti-oxidant compound (grease-type sealant) prior to tightening

the connection prevent the formation of oxides on the metal surface and prevent moisture from

entering the connection, thus reducing the chances of oxidation. Industry OE has shown that

this method of installation provides a corrosion-resistance connection of low electrical

resistance. Furthermore, the applicant has stated that connections at the switchyard are

periodically evaluated via thermography as a preventive maintenance. On this basis, the staff

determined that aging mechanism of increased resistance of connections due to oxidation is

not a significant aging effect requiring management at SSES.

Based on the programs identified above, the staff concludes that the applicant's program meet

SRP-LR Section 3.6.2.2.3 criteria. For those line items that apply to LRA Section 3.6.2.2.3, the

staff determines that loss of material, loss of conductor strength, and increased resistance of

connections or loss of preload in transmission conductors and connections, and in switchyard

bus and connections, are not applicable to SSES. The applicant has demonstrated that the

effect of aging will be adequately managed so that the intended function(s) will be maintained

consistent with the CLB during the period of extended operation as required by 10 CFR

54.21 (a)(3).

3.6.2.2.4 Quality Assurance for Aging Management of Nonsafety-Related Components

SER Section 3.0.4 documents the staff's evaluation of the applicant's QA program for AMPs.

3.6.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report

In LRA Table 3.6.2-1, the staff reviewed additional details of the AMR results for material,

environment, AERM, and AMP combinations not consistent with or not addressed in the GALL

Report.

In LRA Table 3.6.2-1, the applicant indicated, via notes F through J that the combination of

component type, material, environment, and AERM does not correspond to a line item in the

GALL Report. The applicant provided further information about how it will manage the aging

effects.

For component type, material, and environment combinations not evaluated in the GALL

Report, the staff reviewed the applicant's evaluation to determine whether the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB for the period of extended operation. The

staff's evaluation is documented in the following sections.

3.6.2.3.1 Fuse Holders - Metallic Clamp

In LRA, Table 3.6.1, under Item 3.6.1-06, Fuse Holders (Not Part of a Large Assembly), the

applicant states that the aging effects detailed in NUREG-1 801 are not applicable for this item

at SSES. In LRA, Section 3.6.2.3.1, the applicant states that the fuse holders are located in

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metallic electrical boxes (terminal boxes) which have covers that protect the interior of the box

from the environment. The applicant further states that by design, these fuses are not removed

more than once per year, therefore, fatigue due to frequent manipulation does not apply. GALL

NUREG 1801, Rev. 1, Item VI.A-8 identifies corrosion and fatigue as one of aging

effect/mechanism for fuse holders (metallic clamp) and recommends fuse holder AMP XI.E5.

Condensation inside fuse panels could create a corrosive environment for fuse holders.

Manipulation (removing and inserting) of fuse elements during maintenance could weaken the

fuse holder clips and could create fatigue aging effects. In a letter dated July 3, 2008, the staff

issued RAI 3.6-1 to request the applicant to explain why corrosion of fuse holders inside fuse

panels due to condensation is not an aging effect requiring management. The staff also

requested the applicant to provide technical justification of how the manipulation of fuse holders

for maintenance activities will not create a fatigue aging effect.

In a letter dated August 5, 2008, the applicant responded that corrosion (due to condensation)

in the metallic electrical boxes housing for the fuses within the scope of license renewal and

subject to AMR is not expected because the boxes are located in a controlled indoor

environment and contain no components that experience temperatures less than ambient. The

applicant stated that its inspection of a sample of the 20 in-scope metal electric boxes

containing the fuse holders subject to AMR showed no corrosion or evidence of water intrusion

or collection. The metallic electrical boxes were clean and dry. The applicant also stated that

the additional 20 cycles of fuse removal and insertion in fuse holders, where the fuse is

removed once per year, is not expected to create a fatigue aging effect on the fuse holder clips.

This conclusion is based on engineering judgment when considering the threshold for low cycle

fatigue and the material properties of a typical fuse clip. As stated in EPRI, 1003056, "NonClass 1 Mechanical Implementation Guidelines and Mechanical Tools," Appendix H, Page 1-1,

"Low cycle fatigue failure might occur after fewer than 10,000 cycles but only if strains exceed

the yield strain." The applicant further stated that this statement suggests that absent of

excessive strain, low cycle fatigue would not be expected until after thousands of cycles, which

is many more than the number of cycles projected for the fuse clips in the scope of this AMP.

The fuse clip material properties determine what constitutes excessive strain, and because the

fuse clips are made from a spring material, it is expected that the alloys used to manufacture

the clips will have fairly high yield strengths. The applicant also stated that engineering

judgment indicates that the strain created during removal and insertion of the fuse is well below

the yield strain of the fuse clip material. A fatigue aging effect on the fuse holder clips is not

expected due to the additional 20 cycles of manipulation. The lack of excessive strain and the

fact that the total number of cycles on the spring clips is very low, as compared to thousands of

cycles expected for onset of low cycle fatigue, is the basis for the applicant's judgment.

The staff noted that NUREG 1801, Rev. 1, Item VI.A-8 identifies fatigue as one aging

effect/mechanism for fuse holder metallic clamps due to manipulation. In addition, OE as

discussed in NUREG-1 760, Aging Assessment of Safety-Related Fuses Used in Low- and

Medium-Voltage Applications in Nuclear Power Plants, documented OE with fuse holder

failures due to fatigue. Removal and inserting of fuse elements could weaken fuse holder clips.

These clips are made of copper alloy which have very low conductor strength. NUREG-1 760

recommends that field inspections should include examination of fuse holders since these

components account for a significant number of fuse failures due to loosening of the holder

clips or electrical connections. It also recommends that maintenance procedures should be

reviewed to minimize the removal and reinsertion of fuses to de-energize components since this

can lead to degradation of the fuse holders. Fuses that must be removed and inserted for

maintenance and surveillance should be included in periodic maintenance and inspection

programs to monitor and control the effects of these repetitive activities on the fuse and fuse

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holder. Furthermore, the GALL Report AMP XI.E5 recommends testing fuse holders so that the

component's intended function will be maintained within the CLB for the period of extended

operation. The staff disagreed with the applicant that the fatigue aging effect on the fuse holder

clips is not expected due to manipulation. Manipulation of fuse holders for maintenance could

create a fatigue aging effect on fuse holder clips.

In response to the staff's concern, in a letter dated November 11, 2008, the applicant stated

that twenty fuse boxes (containing only fuses and terminal blocks) were identified within the

license renewal scope. Sixteen contain power and control fuses in the plant direct current (DC)

power systems and four contain 6-amp fuses associated with the control room emergency

lighting system. Of these twenty, none contain fuses that are pulled from their metallic clamps

more than once per year. The applicant also stated that "an engineering evaluation concluded

that" none of these specified fuse holders has a metallic clamp that will exhibit the aging

mechanisms/effects of fatigue and/or frequent manipulation listed in NUREG-1 801,

Item VI.A-8.

However, to ensure the aging effect of increased connection resistance due to fatigue of the

fuse holder clamps is not occurring, SSES will implement a fuse holder program consistent with

the recommendations of NUREG-1801, Section XI.E5.

The staff finds the applicant response acceptable because for fuse holders that the applicant

periodically pulled fuse elements to de-energize circuits for preventive maintenance activities,

the applicant will implement a fuse holder program consistent with the GALL Report AMP XI.E5.

The staff evaluation of this program is SER Section 3.0.3. In a letter dated November 11, 2008,

the applicant amended LRA Sections 3.6.2.1, 3.6.2.3.1, Table 3.6-1, 3.6.2.1, A1.2.51, A.1.4,

B.2, and B.2.50 associated with fuse holder and to add fuse holder as a component type

requiring aging management. The staff's concern about fatigue aging effect of fuse holders due

to manipulation is resolved.

3.6.2.3.2 Tie Wraps

Tie wraps may be taken credit for in seismic analysis and in plant design specifications primary

for separation to preclude ampacity degrading. OE has identified issues with tie wraps. Tie

wraps were brittle, degraded, or missing and tie wraps failures affected safety functions of other

system/components. The LRA does not discuss tie wraps as a commodity type requiring AMRs.

In a letter dated July 3, 2008, the staff issued RAI 3.6-4 to request the applicant to explain why

tie wraps do not require an AMR. In particular, the staff requested the applicant to address if tie

wraps are given credit in the seismic analysis for the current licensing basis and the effects of

tie wraps for 10 CFR 54.4 (a)(2) over 10 CFR 54.4 (a)(1), non safety components whose failure

could affect safety-functions.

In response to the staff's request, in a letter dated August 5, 2008, the applicant stated that a

review of current licensing basis documentation revealed that SSES does not credit tie wraps in

the seismic qualification of cable trays. SSES considered the potential effect on safety-related

equipment caused by the failure of plastic cable tie-wraps due to age-related degradation and

concluded that the failure of tie wraps that could prevent satisfactory accomplishment of the

functions of structures, systems and components (SSCs) identified under 10 CFR 54.4(a)(1) is

not credible for the following reasons:

A review of the OE did not reveal any instances of equipment failures due to

degradation of electrical cable tie wraps.

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Sensitive components that could be impacted by a loose tie wrap are installed within

protective enclosures.

SSES employs good housekeeping and foreign material exclusion (FME) practices.

The applicant also stated that reviews of SSES and industry OE did not reveal any occurrences

of equipment failures caused by tie wraps outside of active components. Therefore, failure of tie

wraps resulting in impact to safety functions is considered a hypothetical failure and based on

current license renewal guidance does not need to be considered further for license renewal.

The applicant further stated that based on a review of CLB documentation, including the

UFSAR, Design Basis Documents, cable installation specifications, and design calculations,

electric cable ties are not credited for spacing of cables at SSES. Cable ampacity ratings are

based on cable tray fill, cable loading depth, cable diameters, and the number of conductors.

Cables are assumed to be organized randomly in the tray and spacing between cables is not a

consideration. Therefore, cable tie wraps are not credited in the SSES design for cable

ampacity ratings.

The staff found the applicant's response acceptable. Because tie wraps are not credited for

seismic analysis or design specifications at SSES, failures of tie wraps will not affect safetyrelated systems or components from perform their intended function. The applicant has

reviewed its OE and did not identify any instances of equipment failures due to degradation of

electrical cable tie wraps. Sensitive components that could be impacted by a loose tie wrap are

installed within protective enclosures at SSES. The applicant employs good housekeeping and

foreign material exclusion (FME) practices. Based on this information, the staff determines that

the applicant correctly determined that tie wraps are not within the scope of license renewal.

3.6.3 Conclusion

The staff concludes that, the applicant has provided sufficient information to demonstrate that

the effects of aging for the electrical and I&C components within the scope of license renewal

and subject to an AMR will be adequately managed so that the intended function(s) will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21(a)(3).

3.7 Conclusion for Aging Management Review Results

The staff reviewed the information in LRA Section 3, "Aging Management Review Results," and

LRA Appendix B, "Aging Management Programs." On the basis of its review of the AMR results

and AMPs, the staff concludes that the applicant has demonstrated that the aging effects will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also

reviewed the applicable UFSAR supplement program summaries and concludes that the

supplement adequately describes the AMPs credited for managing aging, as required by

10 CFR 54.21(d).

With regard to these matters, the staff concludes that there is reasonable assurance that the

applicant will continue to conduct the activities authorized by the renewed licenses will continue

to be conducted in accordance with the CLB, and any changes made to the CLB, in order to

comply with 10 CFR 54.21(a)(3), are in accordance with the Atomic Energy Act of 1954, as

amended, and NRC regulations.

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SECTION 4

TIME-LIMITED AGING ANALYSES

4.1 Identification of Time-Limited Aging Analyses

This section of the safety evaluation report (SER) addresses the identification of time-limited

aging analyses (TLAAs). In license renewal application (LRA) Sections 4.2 through 4.7, PPL

Susquehanna, LLC (PPL or the applicant) addressed the TLAAs for Susquehanna Steam

Electric Station (SSES), Units 1 and 2. SER Sections 4.2 through 4.8 documents the review of

the TLAAs conducted by the staff of the United States (US) Nuclear Regulatory Commission

(NRC) (the staff).

TLAAs are certain plant-specific safety analyses that involve time-limited assumptions defined

by the current operating term. Pursuant to Title 10, Section 54.21(c)(1), of the Code of Federal

Regulations (10 CFR 54.21(c)(1 )), applicants must list TLAAs in compliance with 10 CFR 54.3.

In addition, pursuant to 10 CFR 54.21(c)(2), applicants must list existing plant-specific

exemptions granted in accordance with 10 CFR 50.12, based on TLAAs. For any such

exemptions, the applicant must evaluate and justify the continuation of the exemptions for the

period of extended operation.

4.1.1 Summary of Technical Information in the Application

To identify the TLAAs, the applicant evaluated existing analyses and calculations for SSES

against the six criteria specified in 10 CFR 54.3. The applicant indicated that it has identified the

analyses and calculations that meet the six criteria by searching the current licensing basis

(CLB). The CLB includes the updated final safety analysis report (UFSAR), engineering

calculations, technical reports, engineering work requests, licensing correspondence, and

applicable vendor reports. In LRA Table 4.1-1, "Time-Limited Aging Analyses," the applicant

listed the applicable TLAAs:

" reactor vessel (RV) neutron embrittlement

" metal fatigue

" environmental qualification (EQ) of electrical equipment

" containment liner plate, metal containments, and penetrations fatigue analyses

* main steamline (MSL) flow restrictor erosion analyses

" high-energy line break (HELB) cumulative fatigue usage factors

" core plate rim hold-down bolts

As required by 10 CFR 54.21 (c)(2), the applicant must list all exemptions granted pursuant to

10 CFR 50.12, based on TLAAs, and evaluated and justified for continuation through the period

of extended operation. The LRA states that each active exemption was reviewed to determine

whether it was based on a TLAA. The applicant did not identify any exemptions for the CLB that

were dependent on and could change because of time-limited assumptions.

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4.1.2 Staff Evaluation

In LRA Section 4.1, the applicant listed the TLAAs for SSES. The staff reviewed the information

to determine whether the applicant has provided sufficient information pursuant to

10 CFR 54.21(c)(1) and 10 CFR 54.21(c)(2).

As defined in 10 CFR 54.3, TLAAs must meet the following six criteria:

(1) involve structures, systems, and components (SSCs) within the scope of license

renewal, as described in 10 CFR 54.4(a)

(2) consider the effects of aging

(3) involve time-limited assumptions defined by the current operating term (40 years)

(4) are determined to be relevant by the applicant in making a safety determination

(5) involve conclusions, or provide the basis for conclusions, related to the capability of the

system, structure, and component to perform its intended functions, as described in

10 CFR 54.4(b)

(6) are contained or incorporated by reference in the CLB

The applicant reviewed the list of common TLAAs in NUREG-1800, Revision 1, "Standard

Review Plan for Review of License Renewal Applications for Nuclear Power Plants" (SRP-LR),

dated September 2005. The applicant listed TLAAs applicable to SSES in LRA Table 4.1-1.

The staff confirmed that the applicant's LRA includes the TLAAs that are normally applicable to

boiling-water reactor (BWR) applications, including:

" TLAAs on neutron irradiation embrittlement: upper shelf energy (USE), adjusted

reference temperature, pressure temperature (P-T) limits, RV circumferential weld

probability of failure analyses, RV axial weld probability of failure analyses, and RV

reflood analyses.

" TLAAs on metal fatigue of American Society of Mechanical Engineers (ASME)

Code Class 1 components (RV and Class 1 piping components), metal fatigue of NonClass 1 components, and environmentally assisted fatigue.

* TLAAs on environmental qualification of electrical equipment.

* TLAAs on metal fatigue of the containment liner and containment penetrations, including

ASME MC structures, downcomer vents and safety/relief valve (SRV) discharge piping,

and SRV quenchers.

The staff finds the applicant's identification of these TLAAs acceptable because they are

consistent with the TLAAs identified in SRP-LR Sections 4.2, 4.3, 4.4, and 4.6 as being

applicable to BWR LRAs.

The staff also verified that the LRA included the following additional plant-specific TLAAs:

* MSL Flow Restrictor Erosion Analyses

* HELB Metal Fatigue Analysis

Core Plate Rim Hold-down Bolt Stress Relaxation Analysis

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The staff confirmed that applicant's identification of these additional TLAAs satisfies the

recommendation in SRP-LR Section 4.7 that the applicant identify any additional analyses for

the facilities that meet the definition of a TLAA, in accordance with the requirements of

10 CFR 54.3. The staff did not identify any omissions of TLAA for this LRA.

The staff noted that the LRA indicates the TLAA on containment prestressed tendons

discussed in SRP-LR Section 4.5 is not applicable to the LRA. The staff confirmed that the

design of SSES Units 1 and 2 do not include containment structures designed with pre-stressed

tendons. Therefore, based on this confirmation, the staff concludes that the applicant has

provided a basis for concluding that the TLAA on prestressed containment tendons is not

applicable to the LRA because the SSES containment designs do not include these design

features.

Based on its review, the staff concludes that the applicant has satisfied the requirements of

10 CFR 54.3 to identify the TLAAs that are applicable to the LRA because the applicant has

satisfied the TLAA identification guidance and recommendations in SRP-LR Sections 4.2, 4.3,

4.4, 4.6, and 4.7, and because the applicant has provided an acceptable basis for concluding

that the guidance in SRP-LR Section 4.5, on TLAAs for prestressed concrete tendons, is not

applicable to the LRA.

Pursuant to 10 CFR 54.21 (c)(1), each TLAA for an application must be found acceptable for the

period of extended operation, in accordance with one of the following acceptance criteria:

(i) the analysis remains valid for the period of extended operation

(ii) the analysis has been projected to the end of the period of extended operation

(iii) the effects of aging of the intended function will be managed for the period of

extended operation

The staff confirmed that the TLAAs identified by the applicant as being applicable to the LRA

have been evaluated by the applicant against the provisions and criteria of 10 CFR 54.21(c)(1).

The staff evaluates these TLAAs and provides its bases for accepting them, in accordance with

10 CFR 54.21(c)(1)(i), (ii), or (iii), in the staff evaluations provided in SER Sections 4.2, 4.3, 4.4,

4.6, or 4.7.

In request for additional information (RAI) 4.1.3, the staff requested that the applicant clarify

whether the following exemptions granted to PPL in lieu of meeting the fracture toughness

requirements of 10 CFR Part 50, Appendix G, and that were granted under the requirements of

10 CFR 50.60(b) and the exemption approval criteria pursuant to 10 CFR 50.12, should be

identified as exemptions based on the time-limited assumptions, as required by

10 CFR 54.21(c)(2):

t

(1) The exemption in Paragraph 2E of Operating License NPF-14 for Unit 1.

(2) The exemption granted in the staff letter of February 7, 2002, from D. S. Collins

(NRC) to R. G. Byram (PPL), granting PPL an exemption to use methods of

ASME Code Case N-640 in the generation of the P-T limits for Units 1 and 2.

In its response to RAI 4.1.3, dated June 12, 2007, the applicant clarified that the exemption

granted in Operating License NPF-14, Paragraph 2E for Unit 1 is based on the methods for

calculating the initial Upper Shelf Energy (USE) and reference nil-ductility temperature (RTNDT)

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values, pursuant to 10 CFR Part 50, Appendix G required USE and P-T limit calculations, and

that these values are based on TLAAs. The staff noted that in NUREG-0800, Chapter 3.5.2,

NRC Branch Position EMCB 5-2 states that the initial USE and initial RTNDT values used in USE

and P-T limit calculations are established from either drop weight or Charpy-V notch tests

performed on unirradiated RPV material .impact test specimens, and are not dependent upon

the influence of these values to an accumulated neutron irradiation time-limited parameter.

Thus, based on this assessment, the staff finds that the applicant has provided an acceptable

basis for concluding that the exemption mentioned in Operating License NPF-14,

Paragraph 2E, for Unit 1, is not based on a TLAA.

The applicant also clarified that the alternative P-T limit calculation methods discussed in ASME

Code Case N-640 have been approved by the staff in the latest version of Regulatory Guide

(RG) 1.147 and endorsed by reference in 10 CFR 50.55a. Thus, the exemption to use this code

case is no longer necessary and will not be needed for the period of extended operation. The

staff confirms the staff endorsed ASME Code Case N-640 for use in RG 1.147, Revision 15.

Based on this confirmation, the staff concludes that the exemption to use ASME Code Case

N-640 is no longer required and need not be identified as an applicable exemption for the LRA

based on a TLAA because: (a) the staff has endorsed the code case for use in RG 1.147,

Revision 15 and (b) the applicant may use the Code for the 10-year ISI intervals for the period

of extended operation. The applicant may use the Code without receiving prior staff approval, if

it identifies this code case for use when updating the ASME Code Section XI edition of record,

12 months prior to entering into these 10-year IS[ intervals.

Based on its review, as discussed above, the staff finds the applicant's response to RAI 4.1.3-1

acceptable. Therefore, the staff's concern described in RAI 4.1.3-1 is resolved.

Based on the information provided by the applicant as to the process it used to identify these

exemptions and its results, the staff concludes, in accordance with 10 CFR 54.21 (c)(2), that

there are no TLAA-based exemptions that the applicant must justify prior to entering into and

continuing through the period of extended operation.

4.1.3 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable list

of TLAAs, as required by 10 CFR 54.21(c)(1). The staff confirms, as required by

10 CFR 54.21(c)(2), that no exemption to 10 CFR 50.12 had been granted based on a TLAA.

4.2 Reactor Vessel Neutron Embrittlement

"Neutron embrittlement" is the term for changes in mechanical properties of RV materials

caused by exposure to fast neutron flux (E>1.0 MeV) within the vicinity of the reactor core,

called the beltline region. The most pronounced material change is a reduction in fracture

toughness. As fracture toughness decreases with cumulative fast neutron exposure, the

material's resistance to cleavage and ductile fracture decreases. Fracture toughness also

depends on temperature. The RTNDT, above which the material behaves in a ductile manner

and below which the material behaves in a brittle manner, increases as fluence increases and

requires higher temperatures for continued ductility. Regulations governing RV integrity are

found in 10 CFR Part 50. Specifically, 10 CFR 50.60 requires all light-water reactors to meet the

fracture toughness, P-T limits, and material surveillance program requirements for the reactor

coolant pressure boundary (RCPB) pursuant to 10 CFR Part 50 Appendices G and H.

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The CLB analyses evaluating reduction of fracture toughness of the reactor pressure vessel

(RPV) for 40 years are TLAAs. Neutron fluence, USE, adjusted reference temperature, and

vessel P-T limits are time-dependent items that must be investigated to evaluate vessel

embrittlement (i.e., fracture toughness of vessel materials). The following sections address

fluence, USE, adjusted reference temperature, P-T limits, circumferential welds, and axial welds

for RPV beltline materials for the period of extended operation.

4.2.1 Neutron Fluence

4.2.1.1 Summary of Technical Information in the Application

LRA Section 4.2.1 summarizes the evaluation of neutron fluence for the period of extended

operation. To evaluate the effects of radiation on RPV material embrittlement, analyses

determined neutron fluence for extended power uprate conditions and for extended operation

out to 54 effective full-power years (EFPY) (i.e., at the end of 60 years operation). Using actual

reactor core power histories to date and conservative estimates of future core designs for each

unit, extended operation to 60 years will be bounded by 54 EFPY. High energy (>1 MeV)

neutron fluence for the RPV beltline region welds and shells was calculated by the Radiation

Analysis Modeling Application (RAMA) fluence methodology developed for the Electric Power

Research Institute (EPRI) and the Boiling Water Reactor Vessel and Internals Project

(BWRVIP). Use of this methodology for evaluations of fluence was in accordance with

guidelines presented in Regulatory Guide (RG) 1.190, as recommended in SRP-LR Section 4.

The staff has reviewed and approved the RAMA for BWR RPV fluence predictions and

concluded that the RAMA methodology applies to SSES. Fluence was calculated at the inner

surface (0-T) of the vessel wall, at one-quarter (1/4-T) and three-quarters (3/4-T) of the vessel

wall thickness.

NUREG-1801 (The Generic Aging Lessons Learned (GALL) Report) indicates that ferritic

materials for RPV beltline shells, welds, and assembly components must be evaluated for

neutron irradiation embrittlement, if high-energy neutron fluence is greater than a threshold

value of 1.OE+17 n/cm2 (0-T location) at the end of the license renewal term. RPV shell

courses #1 and #2 and axial welds in these shell courses will experience neutron fluence

greater than the threshold value prior to the end of 54 EFPYs of operation. The circumferential

weld between shell courses #1 and #2 also will be exposed to neutron fluence exceeding the

threshold value during the extended lives of the plants. Shell course #3 and its welds will not

experience neutron fluence exceeding the threshold value during the extended lives of the

plants. The only RPV assembly items other than the shells and welds likely to experience

neutron fluence greater than 1.0E+1 7 n/cm2, during the period of extended operation, would be

instrumentation nozzles N16A and N16B. These nozzles are fabricated from Inconel SB-166, a

non-ferritic material which is not a limiting material in the vessel beltline region; therefore,

nozzles N16A and N16B are not subject to 10 CFR Part 50, Appendix G evaluation

requirements for irradiation effects. Within the beltline region, only shell courses #1 and #2,

their axial welds, and the circumferential weld between shell courses # 1 and #2, require

evaluation for neutron embrittlement for the period of extended operation.

4.2.1.2 Staff Evaluation

On four BWRVIP reports related to the RAMA fluence methodology, in the SER dated

May 13, 2005, the staff approved the use of the RAMA code for BWR RPV fluence predictions

and concluded that the RAMA methodology applies to SSES. The applicant provided fluence

values based on the RAMA methodology for the SSES RPV beltline materials in LRA

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Section 4.2.1. These fluence values were used throughout LRA Section 4.2 for the RPV

neutron embrittlement calculations. The staff confirmed that Units 1 and 2 are BWR-4 plants

and their fluence values were calculated in accordance with the guidance of RG 1.190, with no

bias in the calculations. Therefore, the staff finds the applicant's fluence values acceptable.

4.2.1.3 UFSAR Supplement

The applicant provided an UFSAR supplement summary description of its TLAA evaluation of

neutron fluence in LRA Section A.1.3.1. On the basis of its review of the UFSAR supplement,

the staff finds the summary description of the applicant's actions to address neutron fluence is

adequate.

4.2.1.4 Conclusion

On the basis of its review, the staff concludes that the fluence values for the SSES RPV beltline

materials in LRA Section 4.2.1 are acceptable for use for the RPV neutron embrittlement

calculations, throughout LRA Section 4.2. The staff also concludes that the UFSAR supplement

contains an appropriate summary description of the TLAA evaluation, as required by

10 CFR 54.21(d) and therefore is acceptable.

4.2.2 Upper Shelf Energy Evaluation

4.2.2.1 Summary of Technical Information in the Application

LRA Section 4.2.2 summarizes the evaluation of USE values for the period of extended

operation. Part 50 of 10 CFR, Appendix G requires that USE values for RPV materials include

the effects of neutron radiation and that USE for the beltline materials including plates and

welds be maintained at no less than 50 ft-lb for the life of the RV. Calculated neutron fluence

values considering both the units' extended power uprate and extended operation to 54 EFPY

exceed previously-determined neutron fluence values based on materials surveillance program

information for SSES Units 1 and 2. Therefore, projected changes in USE values for the period

of extended operation are required in accordance with 10 CFR Part 50, Appendix G. The

projected USE values at the end of 54 EFPY for the RPV beltline plates and welds for SSES,

Units 1 and 2 were determined in accordance with RG 1.99, Revision 2. For plates and welds

that do not meet the 50 ft-lb criterion, an equivalent-margins analysis documented in BWRVIP74-A, "BWR Vessel and Internals Project, BWR Reactor Pressure Vessel Inspection and Flaw

Evaluation Guidelines for License Renewal," was used instead to evaluate the acceptability of

the low USE RPV materials. The results of this evaluation demonstrated that all SSES, Units 1

and 2 plates and welds that do not meet the 50 ft-lb criterion are bounded by the BWRVIP-74-A

equivalent margins analysis. Therefore, the applicant concluded that the effects of neutron

radiation have been evaluated appropriately, and all RPV beltline materials for SSES, Units 1

and 2 have been demonstrated to remain in compliance with Appendix G of 10 CFR Part 50 for

the period of extended operation.

4.2.2.2 Staff Evaluation

The staff reviewed LRA Section 4.2.2 to verify, pursuant to 10 CFR 54.21(c)(1)(ii), that the

analyses have been projected to the end of the period of extended operation.

According to RG 1.99, Revision 2, the predicted decrease in USE values due to neutron

embrittlement during plant operation is dependent upon the amount of copper in the material

and the predicted neutron fluence for the material. This RG recommends a minimum of two

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credible data points for the use of surveillance data in the embrittlement evaluation. RG Position

1.2 specifies methods for calculating the predicted decrease in USE values for materials that do

not have sufficient credible surveillance data. Since each RPV for Units 1 and 2 has only one

set of surveillance data, the applicant used RG 1.99, Revision 2, Position 1.2, for calculating the

predicted USE decreases for each of the beltline welds and plates for the extended period of

operation.

For a conventional USE evaluation, the initial USE value is needed in addition to the USE

decrease, to calculate the USE value at 54 EFPY for a RPV material. LRA Tables 4.2-3 and

4.2-5, which the applicant completely revised in its RAI response dated October 18, 2007,

provide initial USE values for all Units 1 and 2 RPV beltline materials. This information is

consistent with that in the staff's Reactor Vessel Integrity Database (RVID), with two

exceptions: (1) the RVID does not record initial USE values for Units 1 and 2 beltline materials

having predicted 32 EFPY USE values lower than 50 ft-lb, and (2) the initial USE values for

Unit 1 weld Nos. 2 and 5 reported in the revised LRA Table 4.2-3 are 109 ft-lb, while the

corresponding values in the RVID are 126 ft-lb and 134 ft-lb, respectively. The staff found that

although the RVID values of 126 ft-lb and 134 ft-lb for weld Nos. 2 and 5 are consistent with

those in a Surveillance Report Table 7-4, dated May 19, 1994, and Attachment 2 to the

applicant's response to GL 92-01, Revision 1, dated June 23, 1994, the Charpy impact energy

plots from the May 19, 1994 surveillance report clearly indicated an initial USE value of 109 ft-lb

for these welds. Different initial USE values also exist between revised LRA Table 4.2-5 and the

RVID for Unit 2 weld Nos. 5 and 7. The staff evaluated the discrepancies and concluded that

the applicant's revised LRA Tables 4.2-3 and 4.2-5 represent the most accurate information as

to initial USE values for the Units 1 and 2 RPVs. Therefore, the applicant's revised LRA

Tables 4.2-3 and 4.2-5 represent the most accurate information as to initial USE values for the

Units 1 and 2 RPVs. Based on these initial USE values, the applicant used RG 1.99, Revision 2

to calculate the percent USE decrease and the 54 EFPY USE values at the 1/4-T location for all

Units 1 and 2 RPV beltline materials and presented the results in revised LRA Tables 4.2-3 and

4.2-5. The staff performed an independent evaluation and confirmed the applicant's 54 EFPY

USE values for all RPV beltline materials. Thus, pursuant to 10 CFR 54.21 (c)(1 )(ii), the staff

finds that the Units 1 and 2 RPV beltline materials which have 54 EFPY USE values at 1/4-T

greater than 50 ft-lb (see revised LRA Tables 4.2-3 and 4.2-5) meet the 10 CFR Part 50,

Appendix G USE requirement to the end of the period of extended operation.

The BWR Owners Group prepared an equivalent margins analysis in Topical Report BWRVIP74-A, to demonstrate that lower values of USE will provide margins of safety against fracture

equivalent to those required by ASME Code Section Xl, Appendix G. The equivalent margins

analysis from BWRVIP-74-A utilized the technique originally developed in GE Topical Report

NEDO-33205-A, "10 CFR Part 50, Appendix G, Equivalent Margin Analysis for Low Upper Shelf

Energy in BWR/2 through BWRI6 Vessels," Revision 1, February 1994. The staff reviewed and

accepted BWRVIP-74-A, as documented in the staff's SER dated October 18, 2001.

Consequently, a plant without initial USE data or having a projected USE value lower than

50 ft-lb may reference BWRVIP-74-A to confirm that equivalent margins of safety against

failure are maintained for its RPV beltline welds or plates by demonstrating that the percent

USE decrease in each weld or plate is less than the allowable USE decrease for welds or plates

established in BWRVIP-74-A.

For the RPV beltline materials in LRA Tables 4.2-3 and 4.2-5 that do not meet the 50 ft-lb

criterion through the end of the period of extended operation, the applicant performed

equivalent margins analysis evaluations and summarized the results in revised LRA

Tables 4.2-4 and 4.2-6. The staff confirms that the BWRVIP-74-A equivalent margins analysis

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was appropriately applied and the percent USE decreases for the RPV materials that did not

meet the 50 ft-lb criterion are less than the allowable USE decrease established in

BWRVIP-74-A for RPV welds and plates. Therefore, pursuant to 10 CFR 54.21(c)(1)(ii), the

staff finds the Units 1 and 2 RPV beltline materials which have 54 EFPY USE values at the

1/4-T location less than 50 ft-lb (see revised LRA Tables 4.2-3 and 4.2-5) also meet the

10 CFR Part 50, Appendix G USE requirement to the end of the period of extended operation.

4.2.2.3 UFSAR Supplement

The applicant provided an UFSAR supplement summary description of its TLAA evaluation of

USE in revised LRA Section A.1.3.1.2, LRA amendments, and LRA responses dated

November 25, 2008. On the basis of its review of the UFSAR supplement, the staff finds the

summary description of the applicant's actions to address USE is adequate.

4.2.2.4 Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to

10 CFR 54.21(c)(1)(ii), that for the Units 1 and 2 RPV beltline materials which have 54 EFPY

USE values at the 1/4-T location less than 50 ft-lb (see revised LRA Tables 4.2-3 and 4.2-5)

also meet the 10 CFR Part 50, Appendix G USE requirement to the end of the period of

extended operation. The staff also concludes that the UFSAR supplement contains an

appropriate summary description of the TLAA evaluation, as required by 10 CFR 54.21(d) and,

therefore, is acceptable.

4.2.3 Adjusted Reference Temperature Analysis

4.2.3.1 Summary of Technical Information in the Application

LRA Section 4.2.3 summarizes the evaluation of adjusted reference temperature for the period

of extended operation. In addition to USE, the key parameter which characterizes the fracture

toughness of a material is RTNDT, which changes as its exposure to neutron radiation increases.

The effects of neutron radiation on RTNDT are reflected in this reference temperature change

(ARTNDT), and the resulting adjusted reference temperature. Adjusted reference temperature,

is calculated by adding ARTNDT to RTNDT with appropriate margin for uncertainties. The

methodology for calculating adjusted reference temperature for the vessel beltline plates and

welds is in RG 1.99, Revision 2. Material properties and initial RTNDT values were from analyses

of RV surveillance materials. The applicant reviewed data from the staff RVID and the BWRVIP

Integrated Surveillance Program and used the highest limiting material property values in

computations of ARTNoT and adjusted reference temperature for conservative results.

4.2.3.2 Staff Evaluation

The staff reviewed LRA Section 4.2.3 to verify, pursuant to 10 CFR 54.21(c)(1 )(ii), that the

analyses have been projected to the end of the period of extended operation.

The applicant calculated the adjusted reference temperature values based on the 54 EFPY

fluences for the Units 1 and 2 RPV beltline materials. The applicant described the results, which

the staff accepts and are discussed in SER Section 4.2.1, in LRA Tables 4.2-1 and 4.2-2.

In reviewing the adjusted reference temperature values and the key parameters for their

determination, as described in LRA Tables 4.2-7 and 4.2-8, the staff found that the applicant's

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chemistry data and initial RTNDT values are identical to those established in the staff's RVID for

the Units 1 and 2 RPV beltline materials. The staff independently reviewed all adjusted

reference temperature calculations in LRA Tables 4.2-7 and 4.2-8, based on the approved

chemistry and fluence data, and determined that the applicant has appropriately followed the

guidance of RG 1.99, Revision 2 in determining the projected 54 EFPY adjusted reference

temperature values for the Units 1 and 2 RPV beltline materials. The staff's 54 EFPY adjusted

reference temperature value for the Unit 1 limiting material, the lower intermediate shell with

heat number C0776-1 is 71.5 0 F, as opposed to the applicant's 72.4 0 F. The staff's 54 EFPY

adjusted reference temperature value for the Unit 2 limiting material, the lower intermediate

shell with heat number C2421-3 is 61.9 0 F, as opposed to the applicant's 62.4°F. The

applicant's adjusted reference temperature values are more conservative than the staff's

values. LRA Section 4.2.3 further states, "[i]t may be noted that adjusted reference temperature

values are well below the 200°F suggested in Section 3 of Regulatory Guide 1.99 and are,

thus, acceptable for the period of extended operation." It should be noted that there are no

criteria, pursuant to 10 CFR Part 50, for accepting RPV adjusted reference temperatures. The

significance of adjusted reference temperatures is evaluated indirectly in another TLAA, in LRA

Section 4.2.4, "Pressure-Temperature (P-T) Limits."

In RAI 4.2.3-1, the staff requested that the applicant revise LRA Section 4.2.4 and its

associated UFSAR supplement summary description by removing the quoted statement: "[i]t

may be noted that adjusted reference temperature values are well below the 200'F suggested

in Section 3 of Regulatory Guide 1.99 and are, thus, acceptable for the period of extended

operation."

In its response to RAI 4.2.3-1, dated October 18, 2007, the applicant made the appropriate

revision.

Based on its review, the staff finds the applicant's response to RAI 4.2.3-1 acceptable because

the applicant has appropriately revised the LRA to remove the quote. Therefore, the staff's

concern described in RAI 4.2.3-1 is resolved.

4.2.3.3 UFSAR Supplement

The applicant provided an UFSAR supplement summary description of its TLAA evaluation of

adjusted reference temperature in LRA Section A.1.3.1. On the basis of its review of the revised

UFSAR supplement, the staff finds that the summary description of the applicant's actions to

address adjusted reference temperature is adequate.

4.2.3.4 Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to

10 CFR 54.21(c)(1)(ii), that for adjusted reference temperature, the analyses have been

projected to the end of the period of extended operation. The staff also concludes that the

UFSAR supplement contains an appropriate summary description of the TLAA evaluation, as

required by 10 CFR 54.21(d) and therefore is acceptable.

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4.2.4 Pressure-Temperature (P-T) Limits

4.2.4.1 Summary of Technical Information in the Application

LRA Section 4.2.4 summarizes the evaluation of P-T limits for the period of extended operation.

To assure that adequate margins of safety are maintained for various modes of reactor

operation, 10 CFR Part 50, Appendix G specifies material P-T requirements for the service life

of the RV. The basis for these fracture toughness requirements is in ASME Code Section XI,

Appendix G. The ASME Code requires P-T limits for hydrostatic pressure tests and leak tests,

for operation with the core not critical during heatup and cool-down, and for core critical

operation. Calculations were performed to develop P-T limit curves for Units 1 and 2 for 54

EFPY, but were not submitted as part of the application. The calculations, which were for the

bounding regions of the RV, account for the 54 EFPY fluence projections and include the

effects of extended power uprate conditions.

The P-T curves were developed in accordance with 10 CFR Part 50, Appendix G and the

methods of ASME Code Section XI, Appendix G, 1998 Edition, including the 2000 Addenda.

4.2.4.2 Staff Evaluation

The staff reviewed LRA Section 4.2.4 to verify, pursuant to 10 CFR 54.21(c)(1)(ii), that the

analyses have been projected to the end of the period of extended operation.

The current P-T limits were approved by the staff on March 30, 2006. These P-T limits are valid

for 35.7 EFPY for Unit 1 (Amendment 232) and 30.2 EFPY for Unit 2 (Amendment 209). LRA

Section 4.2.4 states that calculations were performed to develop P-T limits in accordance with

10 CFR Part 50, Appendix G and ASME Code Section Xl, Appendix G, 1998 Edition, including

the 2000 Addenda, for both Units for the extended period of operation, using the 54 EFPY

fluence values discussed in LRA Section 4.2.1. However, since the LRA did not include, for

staff review, the revised P-T limits valid for 54 EFPY, the staff determined that it is inappropriate

for the applicant to state in LRA Section 4.2.4 that, "[t]he 54 EFPY P-T curves for Units 1 and 2

demonstrate that there is sufficient operating margin for hydrostatic tests, heatup, cooldown,

and core critical operation to the end of the period of extended operation."

In RAI 4.2.4-1, the staff requested that the applicant revise LRA Section 4.2.4 and its

associated UFSAR supplement summary description, replacing the statement above with a

clarification that the applicant will submit P-T limit updates to the staff, in compliance with

10 CFR Part 50, Appendix G. The request will change this section of the LRA to comply with

10 CFR 54.21 (c)(1) (iii) instead of 10 CFR 54.21 (c)(1) (ii).

In its response to RAI 4.2.4-1, dated October 18, 2007, the applicant amended LRA

Section 4.2.4 to reflect the change requested by the staff.

Based on its review, the staff finds the applicant's response to RAI 4.2.4-1 acceptable because

the applicant has appropriately revised the LRA to clarify that it will submit P-T limit updates to

the staff, in compliance with 10 CFR Part 50, Appendix G. Therefore, the staff's concern

described in RAI 4.2.4-1 is resolved.

The applicant did not include its 54 EFPY P-T limits in the LRA. The staff does not require that

the applicant submit these P-T limit curves as part of the LRA for this TLAA. However, the staff

determines that the applicant is required to submit revised P-T limits (not necessarily the

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54 EFPY P-T limits) in accordance with 10 CFR Part 50, Appendix G, prior to the expiration of

the facility's current P-T limit curves, allowing adequate time for staff review and approval.

Therefore, the staff finds that the applicant's plan to manage the P-T limits in accordance with

10 CFR 54.21(c)(1)(iii) is acceptable, because the applicant will implement changes to the P-T

limit curves through the license amendment process (i.e., through revision of the plant

Technical Specifications) and; thus, meet the requirements of 10 CFR 50.60 and

10 CFR Part 50, Appendix G.

4.2.4.3 UFSAR Supplement

The applicant provided an UFSAR supplement summary description of its TLAA evaluation of

P-T limits in LRA Section A.1.3.1.

On the basis of its review of the revised UFSAR supplement, the staff finds the summary

description of the applicant's actions to address P-T limits is adequate.

4.2.4.4 Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to

10 CFR 54.21(c)(1)(iii), that, for P-T limits, the effects of aging on the intended function will be

adequately managed for the period of extended operation. The staff also concludes that the

UFSAR supplement contains an appropriate summary description of the TLAA evaluation, as

required by 10 CFR 54.21(d) and therefore is acceptable.

4.2.5 Reactor Vessel Circumferential Weld Examination Relief

4.2.5.1 Summary of Technical Information in the Application

LRA Section 4.2.5 summarizes the evaluation of RV circumferential weld examination relief for

the period of extended operation. BWRVIP-74-A reiterates the BWRVIP-05 recommendation

that RPV circumferential welds may be exempted from examination. The NRC BWRVIP-74-A

SER agreed, but required plants to request relief individually. The relief request should

demonstrate that at the expiration of the current license the circumferential welds satisfy the

BWRVIP-05 limiting conditional failure probability evaluation. This evaluation of circumferential

weld parameters is a TLAA. The applicant requested relief from circumferential vessel shell

weld volumetric examinations in November 2000. The relief-request was granted in

February 2001. The submittal included an analysis showing the RV parameters at 32 EFPY

within the bounding parameters for Chicago Bridge & Iron (CB&I) vessels from the BWRVIP-05

SER dated July 28, 1998, and with a lower conditional probability of failure for circumferential

welds than that stated in the BWRVIP-05 SER. The RPV circumferential weld parameters at

54 EFPY will remain within the bounding parameters for CB&I vessels at 64 EFPY from the

BWRVIP-05 SER and the conditional probability of failure for circumferential welds remains

below that stated in the BWRVIP-05 SER. The applicant's process for a relief request for

circumferential vessel shell weld volumetric examinations prior to the period of extended

operation will be the same as during the original licensing period.

4.2.5.2 Staff Evaluation

The staff reviewed LRA Section 4.2.5 to verify, pursuant to 10 CFR 54.21(c)(1)(ii), that the

analyses have been projected to the end of the period of extended operation.

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The technical basis for relief from the ASME Code, Section XI circumferential weld ISI

requirements is discussed in the BWRVIP-05 SER. In the BWRVIP-05 SER, the staff

concluded that since the failure frequency for circumferential welds in BWR plants is

significantly below the criterion specified in RG 1.154, "Format and Content of Plant-Specific

Pressurized Thermal Shock Safety Analysis Reports for Pressurized Water Reactors," and

below the core damage frequency of any BWR plant, the failure frequency for RPV

circumferential welds is sufficiently low to justify elimination of ISI. The BWRVIP-05 SER

indicated that BWR applicants may request relief from the ISI requirements of

10 CFR 50.55a(g) for volumetric examination of RPV circumferential welds by demonstrating

that: (1) at the expiration of the license, the circumferential welds satisfy the limiting conditional

failure probability for circumferential welds in the BWRVIP-05 SER, and (2) the applicant has

implemented operator training and established procedures that limit the frequency of cold overpressure events to the frequency specified in the BWRVIP-05 SER. The letter indicated that the

requirements for inspection of RPV circumferential welds during an additional 20-year license

renewal period require reassessment, on a plant-specific basis, as part of any BWR LRA. In

addition, the applicant must request relief from the ISI requirements for volumetric examination

of circumferential welds for the extended license term, in accordance with the requirements of

10 CFR 50.55a(g).

BWRVIP-74 Section A.4.5 indicates that the BWRVIP-05 SER conservatively evaluated the

BWR RPVs to 64 EFPY, which is 10 EFPY greater than what is realistically expected for the

end of the license renewal period. BWRVIP-74 Section A.4.5 also indicates that to obtain relief

from the ASME Code specified ISI requirements on RPV circumferential welds, each licensee

will submit a plant-specific relief request demonstrating that the two BWRVIP-05 SER

conditions are satisfied for the period of extended operation. But, BWRVIP-74 Section A.4.5

provides no guidance about the information that should be included in an LRA. Since meeting

the first BWRVIP-74 Section A.4.5 condition for a plant-specific relief request (i.e., the first

BWRVIP-05 SER condition for the extended period of operation) requires a TLAA, the staff

determined that this TLAA information should be included in the LRA. The staff used the mean

RTNDT value to evaluate the failure probability of BWR circumferential welds at 32 and 64 EFPY

in the BWRVIP-05 SER. The neutron fluence used in this evaluation was the neutron fluence at

the RPV inner diameter clad-weld interface.

Although LRA Section 4.2.5 does not provide a comparison of the applicant's plant-specific

information with the generic analysis information in the BWRVIP-05 SER to support its

conclusion that the Units 1 and 2 RPV beltline circumferential weld parameters at 54 EFPY

remain within the bounding parameters for CB&I RPVs at 64 EFPY from the BWRVIP-05 SER,

the essential plant-specific information needed for this comparison is available in LRA

Section 4.2.3. As a result, the staff performed a comparison in its evaluation. The staff notes

LRA Tables 4.2-7 and 4.2-8 show that the initial RTNDT and ARTNDT for the limiting

circumferential weld for Unit 2 at 54 EFPY (with heat No. 624263/E204A27A) are -20'F and

30.9 0 F, resulting in a mean RTNDT (without the margin term) of 10.9 0 F. The corresponding

Unit 1 mean RTNDT is -29.7 0F. The mean RTNDT from the BWRVIP-05 SER generic analysis for

CB&I RPV circumferential weld at 64 EFPY is 70.6 0 F. Since the 54 EFPY mean RTNDT value for

either Unit 1 or Unit 2 is less than the 64 EFPY value from the BWRVIP-05 SER, the staff

concludes that the RPV conditional failure probability for either unit at 54 EFPY is bounded by

the staff's generic analysis in the BWRVIP-05 SER. The staff also confirms that the copper and

nickel, chemistry factor, and initial RTNDT for the limiting weld for both units are consistent with

those in the staff's RVID. Therefore, the staff determines that the applicant's RPV

circumferential welds satisfy the limiting conditional failure probability for circumferential welds

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at the end of the period of extended operation (the first condition established in the BWRVIP-05

SER).

For the relief request mentioned in LRA Section 4.2.5, the staff reviewed and accepted the

applicant's implementation of operator training and establishment of procedures, limiting the

frequency of cold over-pressure events to the frequency specified in the BWRVIP-05 SER, for

the remaining licensed period of operation described in the 2001 SER. Further, the applicant

stated in LRA Section 4.2.5, "PPL will process a relief request for circumferential vessel shell

weld volumetric examinations prior to the period of extended operation in the same manner that

has been the practice during the original licensing period." With this commitment, the staff

determines that continued implementation of operator training and establishment of procedures

limiting the frequency of cold over-pressure events will be satisfied during the period of

extended operation (the second condition established in the BWRVIP-05 SER). The staff

determines that this condition concerns specific plant operation procedures, and is not

considered a TLAA.

In the BWRVIP-05 SER, the staff concluded that the applicant need not examine the RPV

circumferential shell welds, if the corresponding volumetric examinations of the RPV axial shell

welds revealed the presence of an age-related degradation mechanism.

In RAI 4.2.5-1, dated September 5, 2007, the staff requested that the applicant confirm whether

previous volumetric examinations of the RPV axial shell welds have shown any indication of

cracking or other age-related degradation mechanisms in the welds.

In its response to RAI 4.2.5-1, dated October 18, 2007, the applicant verified that previous

examinations of the Susquehanna RPV axial shell welds have not identified any relevant

indications or other age-related degradation mechanisms in the welds.

Based on its review, the staff finds the applicant's response to RAI 4.2.5-1 acceptable because

the applicant has verified that no relevant indications or other age-related degradation

mechanisms in the welds were identified as a result of its previous examinations of the axial

welds at Units 1 and 2. Therefore, the staff's concern described in RAI 4.2.5-1 is resolved.

The staff finds the applicant's conclusion for this TLAA acceptable because the staff's

evaluation, based on the LRA Sections 4.2.3 and 4.2.5 information, indicates that the 54 EFPY

conditional failure probability for the RPV circumferential welds for Units 1 and 2 is bounded by

the staff analysis in the BWRVIP-05 SER, and because the applicant will submit a relief request

addressing the continued use of procedures and training to limit cold over-pressure events

during the period of extended operation, prior to the period of extended operation.

4.2.5.3 UFSAR Supplement

The applicant provided an UFSAR supplement summary description of its TLAA evaluation of

RV circumferential weld examination relief in LRA Section A. 1.3.1. On the basis of its review of

the UFSAR supplement, the staff finds the summary description of the applicant's actions to

address RV circumferential weld examination relief is adequate.

4.2.5.4 Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to

10 CFR 54.21(c)(1)(ii), that for RV circumferential weld examination relief, the analyses have

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been projected to the end of the period of extended operation. The staff also concludes that the

UFSAR supplement contains an appropriate summary description of the TLAA evaluation, as

required by 10 CFR 54.21(d) and therefore is acceptable.

4.2.6 Reactor Vessel Axial Weld Failure Probability

4.2.6.1 Summary of Technical Information in the Application

LRA Section 4.2.6 summarizes the evaluation of RV axial weld failure probability for the period

of extended operation. The SER for BWRVIP-74-A evaluated the failure frequency of BWR

RPV axially-oriented welds and determined it to be below 5.OE-06 per reactor year for 40 years

of reactor operation. Applicants for license renewal must evaluate axially-oriented RPV welds to

show that their failure frequency remains below the 5.0E-06 calculated in the BWRVIP-74 SER.

The SER states that an acceptable justification is that the limiting axial beltline weld

mean-RTNDT at the end of the period of extended operation is less than the values specified in

the SER. The axial weld mean-RTNDT at 54 EFPY is projected to be well below that in the SER,

and thus the axial weld failure frequency is well below the acceptable limit of 5.OE-06.

4.2.6.2 Staff Evaluation

The staff reviewed LRA Section 4.2.6 to verify, pursuant to 10 CFR 54.21(c)(1)(ii), that the

analyses have been projected to the end of the period of extended operation.

In the BWRVIP-05 SER, the staff identified a concern regarding the failure frequency of axial

welds in BWR RPVs. In response to this concern, the BWRVIP supplied evaluations of axial

weld failure frequency in letters dated December 15, 1998, and November 12, 1999. The staff's

BWRVIP-05 supplemental SER on these analyses was issued on March 7, 2000. As discussed

in the BWRVIP-05 supplemental SER, the staff performed a generic analysis using the Clinton

RPV (a CB&I vessel) and established that a mean axial weld RTNDT of 91 'F would result in a

RPV failure frequency of 2.73 x 10-6, per reactor-year of operation. This information was

repeated in the BWRVIP-74-A SER.

The staff notes that LRA Section 4.2.6 does not provide a comparison of SSES plant-specific

information with the Clinton RPV information stated above to support the applicant's conclusion

that the Units 1 and 2 RPV beltline axial weld mean-RTNDT at 54 EFPY is projected to be well

below that in the BWRVIP-74-A SER. However, since the applicant provided essential plantspecific information needed for this comparison in LRA Section 4.2.3, the staff performed a

comparison in its evaluation. Based on LRA Tables 4.2-7 and 4.2-8, the staff finds the

mean-RTNDT for the most limiting axial and circumferential weld for both units at 54 EFPY is

10.9 0F, less than the mean-RTNDT of 91 OF from the BWRVIP-74-A SER.

The staff determines that this comparison supports its conclusion that the failure frequency for

the SSES RPV axial welds will be far less than 5 x 10- per reactor-year of operation at the end

of the period of extended operation. Therefore, the conclusion in LRA Section 4.2.6 is

acceptable.

4.2.6.3 UFSAR Supplement

The applicant provided an UFSAR supplement summary description of its TLAA evaluation of

RV axial weld failure probability in LRA Section A.1.3.1. On the basis of its review of the UFSAR

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supplement, the staff finds that the summary description of the applicant's actions to address

RV axial weld failure probability is adequate.

4.2.6.4 Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to

10 CFR 54.21(c)(1)(ii), that for RV axial weld failure probability, the analyses have been

projected to the end of the period of extended operation. The staff also concludes that the

UFSAR supplement contains an appropriate summary description of the TLAA evaluation, as

required by 10 CFR 54.21(d) and therefore is acceptable.

4.2.7 Reflood Thermal Shock

4.2.7.1 Summary of Technical Information in the Application

LRA Section 4.2.7 summarizes the evaluation of reflood thermal shock for the period of

extended operation. The UFSAR Section 3.13.1 documents a concern of possible brittle

fracture of the RV from reflooding following a postulated loss-of-coolant accident (LOCA). This

concern is addressed in NEDO-10029, "An Analytical Study on Brittle Fracture of GE-BWR

Vessels Subject to the Design Basis Accident", in which a very conservative analysis sets an

upper limit on brittle fracture failure for the materials and concludes that catastrophic failure is

not possible. The NEDO-1 0029 analysis assumes a neutron fluence of 1 E+18 neutrons per

square centimeter (n/cm2) throughout the vessel with a corresponding shift in the RTNDT of

50 0F. For SSES, the predicted maximum fluence at 1/4-T vessel wall thickness at 54 EFPY is

9.48E+17 n/cm2 for Unit 1 and 9.54E+17 n/cm2 for Unit 2 with an RTNDT shift of 35.9°F for Unit 1

and 38.4 0F for Unit 2. Therefore, as the 54 EFPY values are bounded by the values assumed in

the NEDO-10029 analysis, the analysis remains valid for the period of extended operation.

4.2.7.2 Staff Evaluation

The staff reviewed LRA Section 4.2.7 to verify, pursuant to 10 CFR 54.21(c)(1)(i), that the

analyses remain valid for the period of extended operation.

RPV. In LRA Section 4.2.7, the applicant stated that the SSES RPVs are bounded by the

NEDO-1 0029 analysis, because the RTNDT shifts at 54 EFPY (35.9 0F for Unit 1 and 38.40 F for

Unit 2) are less than the RTNDT shift of 50°F used in the NEDO-10029 analysis. The staff

determined that the applicant's assessment is not complete, because the fracture toughness of

the RPV material is determined by the RPV operating temperature and the RTNDT value (i.e.,

the sum of the initial RTNDT value, the shift, and the margin, of the limiting RPV material) and

not by RTNDT shifts, only. Further, the staff determined that the applicant must demonstrate that

the driving force based on the plant-specific design-basis accident (DBA) and SSES RPV

geometry is also bounded by the generic analysis.

In RAI 4.2.7-1 dated September 5, 2007, the staff requested that the applicant confirm that the

current licensing basis relies on the NEDO-10029 methodology and conclusions in addressing

the reflood thermal shock issue, and demonstrate that the driving force based on the plantspecific DBA and SSES RPV geometry is also bounded by the generic analysis.

In its response to RAI 4.2.7-1, dated October 18, 2007, the applicant stated that the CLB for

Units 1 and 2 credits the analysis documented in NEDO-1 0029 to address the concern for

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brittle fracture of the RPV due to reflood, following a postulated LOCA. For the period of

extended operation, however, instead of relying on NEDO-1 0029, the applicant has revised its

position by relying on more recent analysis results from the paper, "Fracture Mechanics

Evaluation of a Boiling Water Reactor Vessel Following a Postulated Loss of Coolant Accident,"

published in the Fifth International Conference on Structural Mechanics in Reactor Technology,

Berlin, Germany, in August 1979. This paper was among the submittals in support of the staff's

evaluation of the applicant's structural integrity analysis of the Unit 1 RPV, after an out-of-limit

cooldown event occurred on January 12, 1989 (NRC Enforcement Action EA 89-042). The staff

reconfirmed the acceptability of the 1989 analysis, since it appropriately: (a) selected the

controlling DBA LOCA - the steam line break, (b) used finite element analyses in both the

thermal and stress analyses, (c) calculated applied stress intensity factors using an influence

coefficient approach based on published finite element solutions, and (d) performed a fracture

toughness evaluation based on ASME Code, Section Xl.

Based on the 1989 analysis results, the applicant further responded that the peak stress

intensity factor at 1/4-T of the RPV wall is about 100 ksi•/in, which occurs at approximately 300

seconds after initiation of the bounding LOCA event (MSL break). At that instant, the crack tip

material temperature is 4000 F. On the fracture toughness side, the maximum adjusted

reference temperature at the end of the period of extended operation for the Units 1 and 2 RPV

beltline materials is 72.40 F (see SER Section 4.2.3.2). This yields a fracture toughness of 200

ksi4in for a crack tip material temperature of 4000 F, in accordance with ASME Code Section XI,

Appendix G, Figure G-221 0-1. Since the driving force (applied stress intensity factor) is much

less than the material resistance to fracture (fracture toughness), the staff concludes that brittle

fracture of the SSES RPVs due to vessel reflood, following a design basis LOCA during the

period of extended operation, is not a concern.

Based on its review, the staff finds the applicant's response to RAI 4.2.7-1 acceptable because

the applicant ceased to rely on the NEDO-1 0029 methodology that caused the staff to issue

RAI 4.2.7-1 in addressing the reflood thermal shock issue, and has demonstrated that the

driving force based on the plant-specific DBA and SSES RPV geometry is less than the fracture

toughness of the SSES RPV materials with a comfortable margin. Therefore, the staff's

concern described in RAI 4.2.7-1 is resolved.

The staff determines that the applicant's TLAA for reflood thermal shock of the RPVs meets the

regulatory requirements of 10 CFR 54.21(c)(1 )(ii) because it was projected to the end of the

period of extended operation.

RPV Core Shroud. In LRA 4.3.7, the applicant failed to note that other approved LRA

applications for plants such as Monticello, Brunswick, and Browns Ferry treated the reflood

thermal shock analysis of the RPV core shroud as a TLAA.

In RAI 4.2.7-2, dated September 5, 2007, the staff requested that the applicant clarify whether

the reflood thermal shock analysis of the RPV core shroud for SSES should be a TLAA and; if

not, provide a justification.

In its response to RAI 4.2.7-2 dated October 18, 2007, that applicant stated that the reflood

thermal shock analysis of RPV core shroud was never performed for either unit and is not part

of the CLB for Units 1 and 2.

Based on its review, the staff finds the applicant's response to RAI 4.2.7-2 acceptable because

the applicant has verified that the reflood thermal shock analysis of RPV core shroud was never

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performed for either SSES unit and is, therefore, not part of the CLB for Units 1 and 2. The staff

confirms that, pursuant to 10 CFR 54.3(a)(6), an applicant's calculations and analyses are

considered as TLAAs only if they are contained or incorporated by reference in the CLB.

Therefore, the staff's concern described in RAI 4.2.7-2 is resolved.

4.2.7.3 UFSAR Supplement

The applicant provided an UFSAR supplement summary description of its TLAA evaluation of

reflood thermal shock in LRA Section A.1.3.1. As discussed in SER Section 4.2.7.2, the

applicant revised its evaluation significantly. The revised UFSAR Supplement Section A. 1.3.1

was submitted as a supplement dated December 17, 2007, as part of the applicant's

RAI response. On the basis of its review of the revised UFSAR supplement, the staff finds that

the summary description of the applicant's actions to address reflood thermal shock is

adequate.

4.2.7.4 Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to

10 CFR 54.21 (c)(1)(ii), that for reflood thermal shock, the revised analyses have been projected

to the end of the period of extended operation. The staff also concludes that the revised

UFSAR supplement contains an appropriate summary description of the TLAA evaluation, as

required by 10 CFR 54.21(d) and therefore is acceptable.

4.3 Metal Fatigue

A metal component subjected to cyclic loading at loads less than the design load may fail due

to fatigue. Metal fatigue of components may have been evaluated based on an assumed

number of transients or cycles for the current operating term. The validity of such metal fatigue

analysis is reviewed for the period of extended operation. The applicant discussed the fatigue

design of SSES components in LRA Section 4.3. The staff reviewed the technical information in

LRA Section 4.3 according to the guidance provided in SRP-LR Section 4.3.

The staff review identified several areas where additional information was required to complete

the review of the applicant's metal fatigue TLAAs in LRA Section 4.3. Therefore, the staff

issued RAIs to the applicant. The following discussion describes the staff's RAIs and the

corresponding applicant responses.

4.3.1 Reactor Pressure Vessel Fatigue Analyses

4.3.1.1 Summary of Technical Information in the Application

LRA Section 4.3.1 describes the SSES evaluation of TLAAs for the RPV assembly within the

scope of license renewal. The applicant discussed the design basis for the RPV assembly and

indicated that some 60-year projections of the transients (for the assembly) may exceed the

number of cycles used for the design. Table 4.3-1 of the LRA contains the list of reactor design

transients and 60-year cycle projections. In addition, Table 4.3-2 of the LRA contains the list of

fatigue usage for limiting RCPB locations. These locations include the limiting RPV assembly

locations. The applicant stated that metal fatigue of the RPV assembly components is managed

by the SSES Fatigue Monitoring Program.

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4.3.1.2 Staff Evaluation

In LRA Section 4.3.1, the applicant indicated that the SSES RPV was designed in accordance

with the Class 1 requirements of ASME Code Section II1. The specific design criterion for

fatigue analysis of the ASME Code Class 1 components involves calculating the cumulative

usage factor (CUF). The fatigue damage in the component caused by each thermal or pressure

transient depends on the magnitude of the stresses caused by the transient. The CUF sums the

fatigue damage resulting from each transient. ASME Code Section III requires that the CUF be

less than 1.0. The staff reviewed the reactor design transients used in the fatigue analysis of

the RPV assembly components.

LRA Table 4.3-1 shows the design transients for the RPV assembly, including the design cycles

and 60-year projected cycles. LRA Table 4.3-2 shows the design CUF values and 60-year

projected CUF values for the limiting RPV assembly locations. The applicant indicates that the

CUFs were calculated based on the transients and cycles shown in LRA Table 4.3-1.

Based on the information in the LRA, the SSES Fatigue Monitoring Program (FMP) relies on

transient cycle monitoring to evaluate the fatigue usage described in the license renewal

application. The staff notes that to rely on this approach, it is essential that all thermal and

pressure activities are bounded by the design specifications and cycles of all significant thermal

events are captured and logged. To ensure effectiveness and validity of the fatigue monitoring

program, in letter dated April 27, 2009, the staff issued RAI 4.3.1-1, requesting the applicant to:

(a) Confirm that all monitored transient events were bounded by the design specifications.

(b) Specify the time (years) over which actual transient monitoring and cycle tracking

activities took place. If there have been periods in which transient data are not recorded

since the plant startup, for any type of transient, specify the affected time frame. For the

time periods for which transients were not monitored, provide justification to

demonstrate that the estimated cycles for this unmonitored period are conservative.

By letter dated May 26, 2009, the applicant responded to RAI 4.3.1-1 Part (a) by describing the

transient monitoring procedures in detail and concluded that all monitored transient events are

bounded by the design specifications and are conservatively factored into the fatigue usage

calculations for the ASME Class 1 reactor coolant pressure boundary components within the

FMP. For RAI 4.3.1-1 Part (b), the applicant response indicates that cycle tracking activities

have covered the entire operating history of SSES Units 1 and 2.

Based on its review, the staff found the applicants response to RAI 4.3.1-1 acceptable because

the applicant provided the information requested in detail and has demonstrated conservatism

of the SSES transient monitoring program.

LRA Table 4.3-1 shows that the 60-year projected cycles for a majority of transients are lower

than the respective design cycles, approximately by a factor between 2 and 3 for both units. For

startup and shutdown transients, the 60-year projected cycles are higher than the design

cycles, by approximately 30%. LRA Table 4.3-2 shows that for some of the limiting RCPB

locations, the 60-year projected CUF values are much lower than the 40-year design CUF

values, up to a factor of 10 and even greater. It appears that the CUF results and the number

of transients are out of proportion for certain locations. With this concern, in letter dated April

27, 2009, the staff issued RAI 4.3.1-2, requesting the applicant to justify the large reductions in

projected 60-year CUF values seen for some locations, with relatively minor reduction in cycle

projections, in spite of some transients having projected cycles higher than the design cycles.

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By letter dated May 26, 2009, the applicant provided its response to RAI 4.3.1-2 in detail. The

applicant states that for the vessel support skirt, the design CUF values of 0.913 for Unit 1 and

0.888 for Unit 2, were calculated based on a design adequacy evaluation performed to account

for new seismic, hydrodynamic, and annulus pressurization loads that were postulated following

the original plant design and construction. The applicant also states that when developing the

FMP, the design adequacy evaluation for the support skirt was reviewed, and it was determined

that a significant portion of the design CUF value was due to these new loads that result from

emergency and faulted plant conditions. The applicant further states that since these severe

conditions are not anticipated to occur, the 60-year CUF projection, based on the 60-year cycle

projections, is significantly lower than the design CUF.

The applicant states that for the core spray nozzle forging, and the recirculation inlet nozzle, the

design CUF value of 0.815, were calculated based on the design fatigue analysis for the

feedwater nozzle. The applicant also states that bounding these nozzles with the feedwater

nozzle analysis is conservative because the feedwater nozzle is a similar design and

experiences a higher number of more severe transients than either of the bounded nozzles.

The applicant further states that the design fatigue analysis for the feedwater nozzle was overly

conservative, because it had assumed cycle counts that are several times higher than the 60-

year cycle projections. The applicant concluded that the large reduction in the 60-year CUF

projection for these two locations is due to the application of the CBF (cycle-based fatigue

monitoring) methodology, combined with an overly conservative original design analysis.

For the FW Nozzle (N4) and the CRD Penetration locations, the applicant asserted that the 60-

year CUF values for these two locations were calculated using stress-based fatigue monitoring

(SBF) methodology in FatiguePro, and thus the fatigue usage is not totally dependent on the

number of cycles.

The staff evaluated the applicant response to RAI 4.3.1-2, as summarized below:

For the case of the vessel support skirt, the staff now realized that the design fatigue analysis

included loads from emergency and faulted plant conditions in the calculation, whereas in the

60-year CUF projection, the emergency and faulted loads were removed. In addition,

significantly fewer cycles are projected than were used for the design analysis for most of the

transients. Per the ASME guidance, emergency and faulted loading conditions do not need to

be included in the fatigue usage evaluation. With these changes in loads and cycles a

significant reduction in the 60-year CUF projection is expected. Based on this consideration,

the staff found the significant drop in CUF projection reasonable.

For the case of the core spray nozzle forging and the recirculation inlet nozzle, the staff now

realized that the design fatigue CUFs were in fact taken from the results calculated for the

feedwater nozzle. The staff found the bounding approximation for these two nozzles

acceptable because it is a conservative approach. But in evaluating 60-year CUF, the applicant

used the CBF (cycle-based fatigue monitoring) methodology, along with the 60-year projected

cycles applicable to these nozzles. Therefore, the 60-year CUF value shows a more significant

drop than the reduction in the number of cycles suggested. This net effect is compounded by

the fact that the design CUF for these two nozzles should have been lower than the values

taken from the feedwater nozzle results (the bounding approach). Based on this consideration,

the staff found the significant drop in the CUF projection reasonable.

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For the case of the FW Nozzle (N4) and the CRD Penetration locations where reduction in 60-

year projected CUFs are the greatest among the locations listed in LRA Table 4.3-2, the 60-

year CUF values as shown in LRA Table 4.3-2 are subject to change because they were

produced by the stress-based fatigue monitoring methodology in FatiguePro, nonconforming

software -- as documented in RIS 2008-30, titled "Fatigue Analysis of Nuclear Power Plant

Components," dated December 16, 2008. As a result, concern regarding the highly significant

drop in CUF is resolved. Reevaluations for these two locations, or confirmatory evaluations that

demonstrate acceptable results, and for any other cases which utilize the SBF monitoring, are

necessary. This effort is described in License Renewal Commitment No. 60.

Based on the discussions presented herein, the staff found the applicant response to

RAI 4.3.1-2 acceptable, and the concern as described in the RAI is resolved.

In RAI 4.3-1, dated June 12, 2008, the staff identified the following concerns regarding the

transients listed in LRA Table 4.3-1:

(a) LRA Table 4.3-1 provides the number of design cycles as well as 60-year cycle

projections. It was not clear from the table how the 60-year cycle projections were

calculated. Therefore, the staff requested that the applicant provide the cycles accrued

to date and explain how the 60-year projections values were calculated.

(b) The design transients for the RPV assembly are listed in UFSAR Table 3.9-1. The staff

reviewed UFSAR Table 3.9-1, and found a discrepancy between the UFSAR Table and

LRA Table 4.3.1. Therefore, the staff requested that the applicant explain the difference

in the number of design cycles for loss of feedwater heaters and pre-op blowdown

between the UFSAR and LRA tables.

(c) The applicant grouped certain transients together, and it was not clear to the staff the

basis for grouping these transients together and having a single cycle projection for

60 years. Therefore, the staff requested that the applicant explain why the turbine

generator trip transient and other scram transients were grouped and projected together

for 60 years. The staff also requested that the applicant explain how scram transient

conditions bound all scrams that may be experienced by the plant.

(d) Further, the staff requested that the applicant provide the basis for grouping loss of

feedwater heaters and partial feedwater heater bypass as a single transient and include

the effect on feedwater nozzle CUF analysis.

In its response to RAI 4.3-1a, dated August 1, 2008, the applicant provided the current cycle

counts for Units 1 and 2. The applicant stated that the average number of cycles per year for

the past ten-year period was used to estimate the number of additional cycles expected to

occur by the end of the period of extended operation. The staff finds the applicant's projections

provide a reasonable estimate of the number of transient cycles expected to occur by the end

of the period of extended operation. The staff notes that the SSES Fatigue Monitoring Program

will monitor the number of actual transients to ensure that they do not exceed the projected 60-

year cycles during the period of extended operation.

In its response to RAI 4.3-1 b, dated August 1, 2008, the applicant stated that UFSAR

Table 3.9-1 lists the total number of cycles for the loss of feedwater heater events as 80. The

applicant also stated that 10 of the loss of feedwater heater transients considered in the RPV

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fatigue analysis involved a turbine trip with 100 percent steam bypass. The applicant further

stated that the SSES bypass system is only capable of 25 percent steam bypass; therefore,

these 10 transients were not included in LRA Table 4.3-1. On June 25, 2009, through a

teleconference, SSES technical personnel provided additional information to supplement what

was presented in the August 1, 2008, response to RAI 4.3-1b. In the teleconference, the

applicant stated that SSES FMP will monitor the loss of feedwater heater events with a turbine

trip with 25 percent steam bypass flow, and the loss of feedwater heater events with partial

feedwater heater bypass as well. The applicant also stated that during the extended operation

period SSES will use stress-based fatigue (SBF) monitoring methodology pursuant to

Regulatory Issue Summary (RIS) 2008-30 and the actual thermal conditions will be used for the

fatigue evaluation. On the basis of its review, the staff found the applicant's explanation

reasonable because the applicant will actually count cycles and determine the fatigue usage for

the monitored locations.

The applicant stated that UFSAR Table 3.9-1 lists 10 pre-op blowdown events. Further, the

applicant stated that the SSES RPVs did not experience any of these events in the

pre-operational phase, and that the event is not applicable following the initial startup.

Therefore, the event was not included in LRA Table 4.3-1. The staff finds the applicant's

explanation acceptable since there will be no pre-op blowdown events for the SSES FMP to

monitor during the period of extended operation.

In its response to RAI 4.3-1c, dated August 1, 2008, the applicant stated that UFSAR Table 4.3-

1 separates reactor scrams into two categories; namely, 40 cycles of turbine trips and 140

cycles of other scrams. However, LRA Table 4.3-1 lists 180 cycles of reactor scram events. The

applicant also stated that the SSES FMP evaluates all reactor scrams using the most limiting

transient. The staff finds the applicant's explanation acceptable since the SSES FMP will track

the reactor scrams in a conservative manner by assuming the most conservative transient for

each scram event.

In its response to RAI 4.3-1d, dated August 1, 2008, the applicant stated that the response to

RAI 4.3-1b explains why only Partial Feedwater Heater Bypass events are counted by the

SSES Fatigue Monitoring Program. The applicant's response to RAI 4.3-1b is discussed above

and accepted. As for the second part of RAI 4.3-1d, the applicant responded that combining

the two transients indicated in the present RAI question has no effect on the feedwater nozzle

CUF analysis because the feedwater nozzle was evaluated by the stress-based fatigue (SBF)

methodology in FatiguePro, wherein fatigue usage were calculated based on the monitored

actual plant conditions instead of the design transients. The staff found that the second part of

RAI 4.3-1d no longer constitutes a concern because the feedwater nozzle must be reevaluated,

as discussed under the staff evaluation of applicant response to RAI 4.3.1-2. On the basis of

its review, the staff finds that the concern indicated in RAI 4.3-1d is resolved.

Based on its review, the staff finds the applicant's response to RAI 4.3-1 (a-d), dated August 1,

2008, acceptable because the applicant has (a) provided the cycles accrued to date and

explained how the 60-year projections values were calculated; (b) adequately explained the

difference in the number of design cycles for loss of feedwater heaters and pre-op blowdown

between the UFSAR and LRA tables; (c) satisfactorily explained how scram transient conditions

bound all scrams that may be experienced by the plant; and (d) provided a reasonable basis for

grouping loss of feedwater heaters and partial feedwater heater bypass as a single transient

and included the effect on feedwater nozzle CUF analysis. Therefore, the staff's concern

described. in RAI 4.3-1 is resolved.

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In RAI 4.3-2, dated June 12, 2008, the staff requested that the applicant provide a complete list

of design transients used to calculate the 60-year CUF projections for the limiting RCPB

locations, and describe, in detail, how they are monitored.

In its response to RAI 4.3-2, dated August 1, 2008, the applicant stated that it had provided a

complete list of transients in its response to RAI B.3.1-1. The applicant also stated that its FMP

automatically monitors a number of the design transients using plant-specific data. The

applicant went on to state that a number of design transients cannot be automatically counted

by the FMP and must be manually counted, based on the review of the plant data and operating

logs, and then entered into the Fatigue Monitoring Program.

Based on its review, the staff finds the applicant's response to RAI 4.3-2 acceptable because

the applicant has provided a complete list of design transients used to calculate the 60-year

CUF projections for the limiting RCPB locations, and adequately described how they are

monitored. The staff determines that the applicant's method of tracking the design transients is

reasonable and acceptable.

The applicant noted that some transients may exceed the number used for the design of the

RPV components and stated that the limiting components of the RPV will be monitored by the

SSES Fatigue Monitoring Program. The applicant committed (Commitment No. 43) to

implementing one or more of to the following actions to address locations where the CUFs

approach the allowable limit during the period of extended operation:

* Further refinement of the fatigue analyses to lower the CUFs to less than the allowable

* Repair of the affected components

* Replacement of the affected components

* Management by an inspection program that has been reviewed and approved by the

staff (e.g., periodic non-destructive examination (NDE) of the affected locations at the

intervals determined by a method acceptable to the staff)

As indicated by the applicant, the use of an inspection program to manage fatigue will require

prior staff review and approval. The SSES FMP will require that the applicant monitor the

fatigue usage of the limiting RPV components and to take corrective actions if the CUF of these

components is projected to exceed the allowable value of 1.0, during the period of extended

operation. The staff finds that the applicant's FMP provides an acceptable program to manage

the fatigue usage of the RPV components during the period of extended operation.

4.3.1.3 UFSAR Supplement

The applicant provided the UFSAR supplement summary description of its TLAA evaluation of

the SSES RPV assembly in LRA Section A. 1.3.2.1. On the basis of its review of the UFSAR

supplement, the staff finds that the applicant has provided an adequate summary description of

its actions to address the fatigue evaluation of the RPV assembly.

4.3.1.4 Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to

10 CFR 54.21(c)(1)(iii), that the effects of aging due to fatigue on the intended function(s) of the

RPV assembly will be adequately managed during the period of extended operation. The staff

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also concludes that the UFSAR supplement contains an appropriate summary description of the

TLAA evaluation, as required by 10 CFR 54.21(d) and therefore is acceptable.

4.3.2 Reactor Vessel Internals Fatigue Analyses

4.3.2.1 Summary of Technical Information in the Application

LRA Section 4.3.2 describes the SSES evaluation of TLAAs for RPV internals within the scope

of license renewal. The RPV internals are described in terms of two assemblies: core support

structures and reactor internals. These two assemblies were designed in accordance with

ASME Section III, Subsection NG, and were demonstrated to be within allowable limits for 40

years. The applicant performed additional structural evaluations to address operation under

extended power uprate conditions and determined that the CUF for all RPV internals remain

within the allowable limits for 60 years. Table 4.3-1 of the LRA contains the list of reactor design

transients and 60-year cycle projections. In addition, the applicant manages reactor vessel

internals by the SSES BWR Vessel Internals Program. The SSES BWR Vessel Internals

Program manages the RPV internals through inspections.

4.3.2.2 Staff Evaluation

In LRA Section 4.3.2 the applicant stated that its evaluation demonstrating that the fatigue

usage factors for all RPV internals remain within the ASME Code Section III, Subsection NG

limits, for the extended period of operation, included the effects of operation under extended

power uprate conditions.

In RAI 4.3-8, dated October 22, 2008, the staff requested that the applicant explain how the

number of reactor design transient cycles for 60 years of plant operation was determined for the

analysis of the RPV internals.

In its response to RAI 4.3-8, dated December 12, 2008, the applicant stated that the number of

reactor transient design cycles for 40 years of plant operation was multiplied by 1.5 to obtain

the number of cycles for 60 years of plant operation.

Based on its review, the staff finds the applicant's response to RAI 4.3-8 acceptable because

the applicant has provided a sufficient explanation for how it determined the number of reactor

design transient cycles for 60 years of plant operation for the analysis of the RPV internals. The

staff notes that the number of projected reactor transient cycles used in the evaluation of the

RPV internals is greater than the 60-year cycle projections provided in LRA Table 4.3-1.

Therefore, the staff's concern described in RAI 4.3-8 is resolved.

The staff finds the applicant's evaluation, which includes the effects of the extended power

uprate, acceptable and notes that the applicant also monitors the design transients using its

Fatigue Monitoring Program. The staff concludes that the FMP provides additional assurance

that the fatigue usage of the RPV internals will remain within acceptable limits, for the period of

extended operation.

In addition, the staff also reviewed the LRA Section B.2.9, "BWR Vessel Internals Program"

using the guidance provided in GALL Aging Management Program (AMP) XI.M9. During the

review, the staff noted that the BWR Vessel Internals Program only inspects the top guides for

the first 12 years of the period of extended operation. The staff noted that the top guide is

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subject to irradiation-assisted stress-corrosion cracking (IASCC), and that neutron fluence

increases with plant operation.

In RAI 4.3-4, dated June 12, 2008, the staff requested that the applicant clarify how the aging

effect of IASCC will be managed for the remainder for the period of extended operation.

In its response to RAI 4.3-4, dated August 1, 2008, the applicant stated that management of

IASCC has been incorporated into SSES BWR Vessel Internals Program. The staff is satisfied

with this response to RAI 4.3-4 which addresses how the IASCC will be managed during the

period of extended operation for the top guide. The staff evaluation of the SSES BWR Vessel

Internals Program is provided in SER Section 3.0.3.2.4.

4.3.2.3 UFSAR Supplement

The applicant provided the UFSAR supplement summary description of its TLAA evaluation of

RPV internals in LRA Section A.1.3.2.2. On the basis of its review of the UFSAR supplement,

the staff finds the applicant has provided an adequate summary description of its actions to

address the fatigue evaluation of the RPV internals.

4.3.2.4 Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to

10 CFR 54.21(c)(1 )(ii), that the fatigue TLAA for the RPV internals have been projected to the

end of the period of extended operation. In addition, the staff concludes that the applicant has

demonstrated, pursuant to 10 CFR 54.21(c)(1)(iii), that the effects of aging on the intended

function of the reactor vessel internals will be adequately managed for the period of extended

operation. The staff also concludes that the UFSAR supplement contains an appropriate

summary description of the TLAA evaluation, as required by 10 CFR 54.21(d) and therefore is

acceptable.

4.3.3 Effects of Reactor Coolant Environment on Fatigue Life of Components and Piping

4.3.3.1 Summary of Technical Information in the Application

LRA Section 4.3.3 describes the applicant's evaluation of the effects of the reactor coolant

environment on the fatigue life of components. The applicant evaluated locations identified in

NUREG/CR-6260 that are applicable to SSES. These components included: reactor vessel

shell and lower head, reactor vessel feedwater nozzle, reactor recirculation piping (including

inlet and outlet nozzles), core spray line reactor vessel nozzle and associated Class 1 piping,

RHR return line Class 1 piping, and feedwater line Class 1 piping. Of the 11 locations on these

components, 7 have environmentally adjusted CUFs greater than 1.0. The applicant indicated

that these locations would be managed by the SSES Fatigue Monitoring Program.

4.3.3.2 Staff Evaluation

The FMP at SSES tracks transients and cycles of reactor coolant system components that have

explicit design transient cycles, to assure that these components remain within their design

basis. Generic Safety Issue (GSI)-166, "Adequacy of the Fatigue Life of Metal Components,"

raised concerns as to whether the fatigue curves used in the design of the reactor coolant

system components were too conservative. Once GSI-1 66 was resolved for the initial 40 year

design life of operating components, the staff opened GSI-190, "Fatigue Evaluation of Metal

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Components for 60 year Plant Life," to address license renewal. The staff closed GSI-1 90 in

December, 1999, concluding:

The results of the probabilistic analyses, along with the sensitivity studies

performed, the iterations with industry (NEI and EPRI), and the different

approaches available to the licensees to manage the effects of aging, lead to the

conclusion that no generic regulatory action is required, and that GSI-190 is

closed. This conclusion is based primarily on the negligible calculated increases

in core damage frequency in going from 40 to 60 year lives. However, the

calculations supporting resolution of this issue, which included consideration of

environmental effects, and the nature of age-related degradation indicate the

potential for an increase in the frequency of pipe leaks as plants continue to

operate. Thus, the staff concludes that, consistent with existing requirements in

10 CFR 54.21, licensees should address the effects of coolant environment on

component fatigue life as aging management programs are formulated in

support of license renewal.

The staff reviewed the applicant's environmental fatigue CUFs in LRA Table 4.3-3. The staff

noted that the applicant's RPV (Shell at Shroud Support) CUF, including the environmental

effects, is projected to exceed 1.0 for 60-year operation. Based on its review of the BWR

evaluations in NUREG/CR-6260 and other LRA applications, the staff notes that the RPV shell

typically has a CUF (including environmental effects) of less than the allowable value.

In RAI 4.3-3, dated June 12, 2008, the staff requested that the applicant list the transients and

corresponding usage factors, and provide the environmental factors used in its evaluation.

In its response to RAI 4.3-3, dated August 1, 2008, the applicant stated that the transients used

for the evaluation were listed in its response to RAI B3.1-1. The staff confirmed that the

applicant's response to RAI B3.1-1 listed all transients monitored by the SSES Fatigue

Monitoring Program. The applicant's calculation indicated that the environmental usage factor

has considered the percentage of operating life with hydrogen water chemistry (HWC) and the

percentage of operating life with normal water chemistry (NWC). The staff notes that the

application of HWC would significantly reduce the environmental effect on fatigue of carbon and

low alloy steel components.

In RAI 4.3-10, dated October 22, 2008, the staff requested that the applicant provide a list of

transients at the RPV shell shroud support for both units, that are the most significant

contributors to the CUFs listed in LRA Table 4.3-2. The staff also requested that the applicant

provide a discussion of any conservative assumptions that may have been used in the

analyses.

In its response to RAI 4.3-10, dated December 12, 2008, the applicant stated that the shroud

support was analyzed for four design transients; natural circulation startup, pre-op blowdown,

shutdown, and loss of alternating current power.

The applicant stated that the analysis of these four transients yielded the most severe thermal

stresses for the shroud support. The applicant assumed that all transient cycles occurred at the

maximum thermal stress, when determining the number of allowable cycles from the fatigue

design curves.

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This procedure produces a very conservative estimate of the CUF, which explains the relatively

high environmental CUF reported for the RPV shell at the shroud support location. The staff

notes that the CUF can be significantly reduced by a detailed analysis which considers the

actual thermal stress associated with each individual load pair, as discussed in

NUREG/CR-6260 Section 4.3.

Based on its review, the staff finds the applicant's response to RAI 4.3-10 acceptable because

the applicant has provided a list of transients at the RPV shell shroud support that are the most

significant contributors to the CUFs and has adequately explained the assumptions used in its

CUF analysis. Therefore, the staff's concern described in RAI 4.3-10 is resolved.

The staff also noted that the environmental usage factors at several other locations in LRA

Table 4.3-3 were significantly different from those listed in NURE/CR-6260. The staff

determined that SSES is a BWR 4, which is comparable to the older BWR evaluated in

NUREG/CR-6260.

In RAI 4.3-9, dated October 22, 2008, the staff requested that the applicant provide a summary

of the environmental fatigue life correction factor (Fen) calculation for each component analyzed,

including values of oxygen level, temperature and strain rate used in the Fen calculations. The

staff also requested that the applicant provide the basis for the oxygen level, temperature and

strain rate values used in the Fen calculations.

In its response to RAI 4.3-9, dated December 12, 2008, the applicant stated that the Fen

multipliers were calculated assuming HWC conditions for 68% for Unit 1 and 70% for Unit 2 of

the plant operating life at 60 years. The evaluation of the BWR in NUREG/CR-6260 assumed

normal water chemistry (NWC) for the entire plant life. The staff noted that the applicant's

response indicated that the dissolved oxygen (DO) level in the feedwater line was low for both

NWC and HWC conditions at both units and that the applicant used a Fen of 1.74 for the carbon

steel components and a Fen of 2.45 for the low-alloy steel components of the feedwater nozzle.

The applicant's response also indicated that bounding fluid temperature and strain rates were

used to develop the remaining Fen multipliers. The NWC DO level for the core spray and

recirculation low alloy nozzles was relatively high. This accounted for the relatively high Fen

multiplier of approximately 13 for both units, even though DO level was low for the HWC

conditions which exist for the majority of the plant life. The staff finds the Fen values used in the

evaluation of the core spray and recirculation nozzles reasonable for the.DO levels reported by

the applicant.

The applicant also used a Fen of approximately 13 for the evaluation of the stainless steel

components of the recirculation loop piping for both units. The applicant assumed bounding

values for the fluid temperature and strain rate in the calculation of the Fen values, using the

NUREG/CR-5704 equation for stainless steel components. The staff finds the Fen value used

for these stainless steel components acceptable, based on the DO levels in the recirculation

reported for NWC and HWC.

The staff notes that applying a Fen value of 1.74 to carbon steel components and 2.45 to lowalloy steel components, as mentioned above, involves an assumption that the DO level is no

greater than 50 ppb during the entire operating time. This can be readily verified by reviewing

the applicable equations in NUREG/CR-6583. While the applicant has provided historic sample

DO data in the attachment to the response to RAI 4.3-9, the necessity of getting additional

information was prompted because that attachment only covers the time period from 1994 to

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2007. The DO data for the times prior to 1994, about a 10 year period since the plants' startup,

was not provided. Without evidence to show that 50 ppb DO level has been maintained the

entire time, bounding environmental conditions would have to be used to calculate Fen for the

affected periods. With this concern, on April 27, 2009, a follow-up RAI (RAI 4.3-9R) was

issued, requesting the applicant to provide additional information significant to the

environmental fatigue evaluations, as described below:

(a) Provide dissolved oxygen (DO) data for the SSES at full power for the three summer

months of each of the following years: 1985, 1988 and 1991, for both Units 1 and 2.

(b) Describe the methodology of Fen calculation which SSES used to deal with the situations

where DO content in the feedwater system, over certain periods, has been consistently

greater than 50 ppb.

(c) Describe how water samples were taken, including the sampling locations, and justify

that the DO data in the feedwater system shown in PLA-6464 are applicable to all

NUREG/CR-6260 components for Fen calculations.

In its response to RAI 4.3-9R(a), dated May 26, 2009, the applicant provided the DO data for

the time periods specified. For Unit 2, 1986 instead of 1985 data were provided because the

applicant indicated that Unit 2 had no three-month period of continuous operation in 1985. The

applicant also indicated that for Unit 2 the data period was extended beyond three months to

show the return to normal oxygen levels following the repair of a leaking condensate pump

suction line drain valve, which resulted in the higher than normal feedwater system oxygen

levels from July to mid-November 1988.

The staff found the applicant response to part (a) of this RAI acceptable because it provided the

information requested. Combining the data provided in the attachment to the response to RAI

4.3-9 and the attachment to the response to RAI 4.3-9R results in more than 20 years of

coverage on the DO levels experienced by SSES Units 1 and 2 RV and RCS components,

covering nearly the entire plant operating history.

Reviewing the dataset, the staff confirmed that for the reactor water, during the NWC period

(prior to 2000), the DO level was maintained in the range between 220 ppb to 320 ppb with a

norm of about 270 ppb. During the HWC period (2000 and forward), the reactor water DO level

was maintained below 2 ppb. This observation is true for both Unit 1 and Unit 2. For the

feedwater, the DO level in Unit 1 was maintained within 50 ppb for the entire plant operating

history with occasional insignificant overshooting. The feedwater DO level in Unit 2 was

similarly maintained except for a period from July 1988 through mid-November 1988, during

which the feedwater DO level stayed relatively high, at about 100 ppb. It is fair to say this is

approximately a 6-month time frame, slightly augmented for conservatism. The applicant

attributes this elevated DO level to condensate pump suction line drain valve leaking, as

described above. The staff found the applicant's reasoning acceptable because the DO of

feedwater had returned to below 50 ppb level after the valve was repaired.

In its response to RAI 4.3-9R(b), dated May 26, 2009, the applicant stated that NUREG/CR6583 and NUREG/CR-5704 do not discuss how to address variable DO levels during operation.

The applicant indicates that it had followed the industry guidance provided in EPRI Final Report

1012017 (MRP-47 Revision 1) to evaluate Fen based on a simple time-averaged DO level. The

staff deemed this approach non-conservative because the material will respond to the current

environmental conditions not the average conditions over the operating history. The timeaveraged conditions, especially over a lengthy period, will eliminate contributions from short4-27
lived but severe conditions. Therefore, more involved averaging method will be required to

weigh the effects for each period. Nevertheless, for the SSES case, a simple time-averaged

method is deemed adequate because the database shows that the period in which the

feedwater DO level has exceeded 50 ppb is estimated to be less than 6 months. This

represents approximately only 1/120 (i.e., 0.83%) of the intended plant life of 60 years so the

impact will be negligible. Based on this consideration, the staff found the applicant's handling

of the Fen calculations for the feedwater nozzle, feedwater nozzle safe end, and feedwater

piping locations reasonable.

In its response to RAI 4.3-9R(c), dated May 26, 2009, the applicant provided the following

statements:

The DO levels in the SSES Units 1 and 2 feedwater systems are normally

determined by in-line DO monitors, which continuously sample the feedwater

flowing to the Reactor Building Sample Station via the sample line. The

feedwater sample line ties into the main feedwater header pipe inside the reactor

building. Therefore, the feedwater being sampled is representative of the

feedwater flowing to the reactor vessel.

The DO levels in the SSES Units 1 and 2 reactor water are also normally

determined by in-line DO monitors, which continuously sample the reactor water

flowing to the Reactor Building Sample Station via the sample line. The reactor

water sample line ties into the reactor water cleanup line upstream of the filter

demineralized inlet. The reactor water cleanup system draws water from the

reactor vessel bottom head drain and from each of the recirculation pump

suction lines. Therefore, the reactor water being sampled is representative of a

mixture of the water in the reactor bottom head and of the water in the reactor

annulus region.

The staff found the applicant's response acceptable because it provided the information

requested, including presentation of the water sampling methods used and demonstration of

applicability of the data to all of the NUREG/CR-6260 locations considered. The applicant

presented two parts of DO sampling routines to address the chemical conditions in the

feedwater system and in the reactor recirculation water system to support the DO dataset

attached to the responses to RAI 4.3-9 and RAI 4.3-9R.

Based on the discussion and evaluation of the responses to all three parts of RAI 4.3-9R, the

staff's concern of the Fen calculations for the carbon steel and low-alloy steel components is

resolved. The Fen values used for the 60-year CUF calculations are shown in the applicant's

response to RAI 4.3-9, transmitted to NRC Document Control Desk on December 12, 2008,

designated as SSES LRA Supplement PLA-6464, where details of the Fen calculations for the

Recirculation System is also shown.

The applicant used a Fen of 1.49 for the evaluation of the Inconel (nickel-chromium-iron alloy)

core spray nozzle safe ends. The evaluation demonstrated acceptable fatigue usage for the

safe ends at both units. The license renewal guidance provided in NUREG/CR-5704 addresses

austenitic stainless steels and does not contain a specific equation that addresses Inconel

material. The Fen value used by the applicant was based on the equation reported in

NUREG/CR-6335, "Fatigue Strain-Life Behavior of Carbon and Low-Alloy Steels, Austenitic

Stainless Steels, and Alloy 600 in LWR Environments," August 1995. This Fen value is less

conservative than the calculated value using the latest equation provided in NUREG/CR-6909,

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"Effect of LWR Coolant Environments on the Fatigue Life of Reactor Materials," February 2007.

The staff notes that NUREG/CR-6909 is not listed in the staff license renewal guidance

documents. However, NUREG/CR-6909 does allow for the use of an average temperature in

conjunction with an integrated rate approach to determine Fen, which is not as conservative as

the procedure used by the applicant. Implementation of the NUREG/CR-6909 procedure would

probably result in a higher Fen value than was used by the applicant for the core spray nozzle

safe ends. However, the evaluation performed by the applicant demonstrates that the core

spray nozzle (forging) bounds the core spray nozzle safe end on both units. The staff concludes

that use of the NUREG/CR-6909 procedure would not result in environmental fatigue usages

that are larger in the core spray safe ends than the environmental fatigue usages listed by the

applicant for the core spray nozzles. Therefore, the staff finds that the core spray nozzles are

the bounding components for the evaluation. The staff further finds that demonstration of an

acceptable environmental fatigue usage of the core spray nozzles will provide adequate

assurance of acceptable fatigue usage of the core spray nozzle safe ends.

To address locations where the CUFs approach the allowable limit during the period of

extended operation the applicant committed to implementing one or more of the actions that are

specified in Commitment No. 43 and that are listed in the SER section 4.3.1.2.

Based on its review, the staff finds the applicant's response to RAI 4.3-9 acceptable because

that applicant has provided an adequate summary of the Fen calculation for each component

analyzed, including values of oxygen level, temperature and strain rate used in the Fen

calculations and has sufficiently explained the basis for the oxygen level, temperature and

strain rate values used in the Fe, calculations. Therefore, the staff's concerns described in

RAI 4.3-9 are resolved.

As indicated by the applicant, the use of an inspection program to manage fatigue will require

prior staff review and approval. The SSES FMP will require that the applicant monitor the

fatigue usage of the LRA Table 4.3-3 locations and take corrective actions if the CUF, including

environmental effects at these locations, is projected to exceed the allowable value of 1.0,

during the period of extended operation. The staff finds that the applicant's FMP provides an

acceptable program to manage the effects of the reactor coolant environment on the fatigue life

of the RCPB components, during the period of extended operation.

4.3.3.3 UFSAR Supplement

The applicant provided the UFSAR supplement summary description of its evaluation of effects

of reactor coolantenvironment on fatigue life of components in LRA Section A.1.3.2.3. On the

basis of its review of the UFSAR supplement, the staff finds that the applicant has provided an

adequate summary of its environmental fatigue evaluation of RCPB components.

4.3.3.4 Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to

10 CFR 54.21(c)(1)(iii), that the effects of reactor coolant environment on fatigue life of RCPB

components will be adequately managed during the period of extended operation. The staff

also concludes that the UFSAR supplement contains an appropriate summary description of the

TLAA evaluation, as required by 10 CFR 54.21(d) and therefore is acceptable.

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4.3.4 Reactor Coolant Pressure Boundary Piping and Component Fatigue Analyses

4.3.4.1 Summary of Technical Information in the Application

LRA Section 4.3.4 describes the SSES evaluation of reactor coolant pressure boundary piping

and component fatigue analyses. The piping and components are all within Class 1 boundary.

This includes all RCPB piping and in-line components subject to ASME Code Section XI,

Subsection IWB, inspection requirements. The components are listed in this section of the LRA

and are identified in the UFSAR as well. The SSES FMP monitors the design transients

(considered in RCPB components fatigue analyses) and ensures that the fatigue values of

selected RCPB components are within limits. In addition, the LRA stated that fatigue on the

Class 1 valves would be managed indirectly by monitoring fatigue on the piping.

4.3.4.2 Staff Evaluation

In LRA Section 4.3.4, the applicant stated that the RCPB components are generally designed in

compliance with ASME Code Section III, Subsection NB-3600. Subsection NB-3600 contains

rules for the design of Class 1 piping systems, which require that the CUF be less than 1.0. The

applicant provided the 60-year CUF projections for the limiting RCPB locations in LRA

Table 4.3-2. This LRA Table shows that the projected CUFs at all Unit 1 and Unit 2 locations

are less than 1.0. The staff finds these projected 60-year CUFs acceptable since they are within

the ASME Code Section III acceptance limit of 1.0.

In addition to the ASME Code Section III, Subsection NB-3600 criteria, the applicant's high

energy pipe break licensing basis criteria requires that the CUF be less than 0.1 in locations

between the containment isolation valves (typically designated as the no-break zone). LRA

Table 4.3-2 documents the projected 60-year CUF for the Unit 2 feedwater piping in the nobreak zone at greater than 0.1. The applicant has committed to monitor the limiting locations in

LRA Table 4.3-2, using the SSES Fatigue Monitoring Program. Further discussion of the pipe

break criteria is provided in SER Section 4.7.2. To address locations where the CUFs approach

the allowable limit during the period of extended operation the applicant committed to

implementing one or more of the actions that are specified in Commitment No. 43 and that are

listed in the SER section 4.3.1.2.

As indicated by the applicant, the use of an inspection program to manage fatigue will require

prior staff review and approval. The SSES FMP will require that the applicant monitor the

fatigue usage of the limiting RCPB components and take corrective actions, if the CUF of these

components is projected to exceed the allowable value of 1.0 (or 0.1 in the no-break zone),

during the period of extended operation. The staff finds the SSES FMP provides an acceptable

program to manage the fatigue usage of the RCPB components during the period of extended

operation.

The staff noted that applicant justified the monitoring of fatigue on piping as a way to monitor

associated valves, by asserting that fatigue usage is typically much higher on the associated

piping systems.

In RAI 4.3-5, dated July 3, 2008, the staff requested that the applicant provide the technical

basis for that statement. The applicant's response indicated that ASME Class 1 valves are

typically prepared by the valve manufacturer and are not analyzed as part of the piping system.

The applicant reviewed a representative sample of ASME Class 1 valve design reports and

found the fatigue usage factors of the valves were less than 0.1. These values were less than

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the fatigue usage factors at the limiting piping locations presented in LRA Table 4.3-2. The

staff finds the applicant's response, dated August 1, 2008, reasonable based on its review of

previous LRAs which identified that the limiting RCPB piping fatigue usage factors were in the

piping components at locations such as branch connection nozzles and piping material

transition regions.

4.3.4.3 UFSAR Supplement

The applicant provided the UFSAR supplement summary description of its fatigue TLAA

evaluation of the RCPB piping and components in LRA Section A.1.3.2.4. On the basis of its

review of the UFSAR supplement, the staff finds that the applicant has provided an adequate

summary description of the RCPB fatigue TLAA evaluation.

4.3.4.4 Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to

10 CFR 54.21(c)(1)(iii), that the effects of aging due to fatigue on the intended function(s) of

RCPB components will be adequately managed during the period of extended operation. The

staff also concludes that the UFSAR supplement contains an appropriate summary description

of the TLAA evaluation, as required by 10 CFR 54.21(d) and therefore is acceptable.

4.3.5 Non-Class 1 Component Fatigue Analyses

4.3.5.1 Summary of Technical Information in the Application

LRA Section 4.3.5 describes the SSES evaluation of non-Class 1 component fatigue analyses.

The components included within this section are: pipe, tubing, fittings, tanks, vessels, heat

exchangers, valve bodies and bonnets, pump casings, and miscellaneous process components.

The applicant reviewed non-Class 1 components with operating temperatures above the

specified threshold values. The applicant evaluated these components to determine the number

of projected cycles for 60 years was found to be less than 7000 for piping and in-line

components.

4.3.5.2 Staff Evaluation

In LRA Section 4.3.5, the applicant stated that explicit fatigue analyses were not required for

the evaluation of non-Class 1 components. Instead, the piping design code contained a limit of

7000 equivalent full range thermal cycles. The applicant also stated that all non-Class 1

components above the specified temperature thresholds are projected to have less 7000

cycles.

In RAI 4.3-6, the staff requested that the applicant verify whether any of the numbers of

projected cycles for piping and in-line components were derived for evaluation of "partial cycle"

transients, where partial cycles are transient cycles that do not experience the full-temperature

design cycles.

In its response to RAI 4.3-6, dated August 1, 2008, the applicant stated that the 60-year cycle

projections assumed each event occurred at full-temperature design range and no partial cycles

were used in the evaluation.

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Based on its review, the staff finds the applicant's response to RAI 4.3-6 acceptable because

the applicant has assumed the maximum range for each temperature cycle in its assessment.

The staff also finds that the applicant has performed an acceptable evaluation of the nonClass 1 components for the period of extended operation. Therefore, the staff's concern

described in RAI 4.3-6 is resolved.

4.3.5.3 UFSAR Supplement

The applicant provided the UFSAR supplement summary description of its fatigue TLAA

evaluation of Non-Class 1 Component Fatigue Analyses in LRA Section A.1.3.3. On the basis

of its review of the UFSAR supplement, the staff finds that the applicant has provided an

adequate summary description of the fatigue TLAA evaluation non-Class 1 components.

4.3.5.4 Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to

10 CFR 54.21(c)(1)(i), that the analyses of Non-Class 1 components will remain valid during the

period of extended operation. The staff also concludes that the UFSAR supplement contains an

appropriate summary description of the TLAA evaluation, as required by 10 CFR 54.21(d) and

therefore is acceptable.

4.4 Environmental Qualification of Electrical Equipment

The 10 CFR 50.49 EQ program is a TLAA for purposes of license renewal. The TLAA of the EQ

of electrical components includes all long-lived, passive, and active electrical and I&C

components that are important to safety and are located in a harsh environment. The harsh

environments of the plant are those areas subject to environmental effects by LOCAs or

HELBs. EQ equipment comprises safety-related and Q-list equipment, nonsafety-related

equipment the failure of which could prevent satisfactory accomplishment of any safety-related

function, and necessary post-accident monitoring equipment.

As required by 10 CFR 54.21(c)(1), the applicant must provide a list of EQ TLAAs. The

applicant shall demonstrate that for each type of EQ equipment, one of the following is true:

(1) the analyses remain valid for the period of extended operation, (2) the analyses have been

projected to the end of the period of extended operation, or (3) the effects of aging on the

intended function(s) will be adequately managed for the period of extended operation.

4.4.1 Summary of Technical Information in the Application

LRA Section 4.4 summarizes the evaluation of EQ of electrical equipment for the period of

extended operation. The applicant states that SSES EQ program is in compliance with the

requirement of 10 CFR 50.49, and is being used to manage the aging of equipment in the EQ

program during the current license term. The existing SSES EQ program will be used to

manage aging of equipment in the EQ program during the period of extended operation and

includes provision to ensure that the qualification bases are maintained and the components do

not exceed their qualified lives.

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4.4.2 Staff Evaluation

The staff reviewed LRA Section 4.4 to verify, pursuant to 10 CFR 54.21 (c)(1)(iii), that the

effects of aging on the intended function(s) will be adequately managed for the period of

extended operation.

The staff reviewed LRA Section 4.4 and plant basis documents to determine whether the

applicant provided adequate information to meet the requirement of 10 CFR 54.21(c)(1). For

the electrical equipments identified in the EQ master list, the applicant uses

10 CFR 54.21(c)(1)(iii) in its TLAA evaluation to demonstrate that the aging effects of EQ

equipment will be adequately managed during the period of extended operation. The staff

reviewed the applicant's EQ program to determine whether it will assure that the electrical and

I&C components covered under this program will continue to perform their intended functions,

consistent with the CLB, for the period of extended operation.

The staff's evaluation of the components qualification focused on how the EQ program

manages the aging effects to meet the requirements pursuant to in 10 CFR 50.49.

The staff conducted an audit of the information provided in LRA Section B 3.2 and program

basis documents. On the basis of its audit, the staff finds that the EQ program, which the

applicant claimed to be consistent with GALL AMP X.E1, "Environment Qualification of

Electrical Components," is consistent with the EQ program in the GALL Report. Therefore, the

staff finds that the EQ program is capable of programmatically managing the qualified life of

components within the scope of the program for license renewal. The continued implementation

of the EQ program provides assurance that the aging effects will be managed and that

components within the scope of the EQ program will continue to perform their intended

functions for the period of extended operation.

4.4.3 UFSAR Supplement

In LRA Section A.1.3.4, the applicant provided an updated final safety analysis report (UFSAR)

supplement of summary description of EQ of electrical equipment. This summary description is

not consistent with that in SRP-LR Table 4.4.2 as it does not contain reanalysis attributes.

Reanalysis must address attributes of the applicant's analytical methods; data collection and

reduction methods; underlying assumptions; acceptance criteria; corrective actions, if

acceptance criteria are not met; and the period of time, prior to the end of qualified life, when

the reanalysis will be completed.

In RAI B.3.2-1, the staff requested that the applicant revise the UFSAR supplement description

to include these reanalysis attributes.

In response to RAI B.3.2-1, dated August 5, 2008, the applicant stated that LRA Section A.1.3.4

is revised to include the reanalysis attributes as follows:

A.1.3.4 Environmental Qualification of Electric Equipment

Environmental Qualification.analyses for those components with a qualified life of

40 years or greater are identified as TLAA for SSES. NRC regulation

10 CFR 50.49, "Environmental Qualification of Electric Equipment Important to

Safety for Nuclear Power Plants" requires licensees to identify electrical

equipment covered under this regulation and to maintain a qualification file

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demonstrating that the equipment is qualified for its application and will perform

its safety function up to the end of its qualified life.

10 CFR 50.49 requires EQ components that are not qualified for the current

license term to be refurbished, replaced, or have their qualifications extended

prior to reaching the aging limits established in the aging evaluation. Reanalysis

of aging evaluations to extend the qualifications of components is performed on

a routine basis as part of the EQ Program. Important attributes for the reanalysis

of aging evaluations include analytical methods, data collection and reduction

methods, underlying assumptions, acceptance criteria, corrective actions (if

acceptance criteria are not met), and the time remaining to the end of qualified

life.

The SSES EQ Program is an existing program that implements the requirements

of 10 CFR 50.49 and will be used to manage the effects of aging on the intended

function(s) of the components associated with EQ TLAA for the period of

extended operation.

Based on its review, the staff finds the applicant's response to RAI B.3.2-1 acceptable because

the applicant has revised the UFSAR supplement description to include the reanalysis

attributes. Therefore, the staff's concern described in RAI B.3.2-1 is resolved.

With the amendment as described above, the applicant provides an adequate summary

description of TLAA evaluation. This description is consistent with the guidance found in

SRP-LR Table 4.4.2. On the basis of its review of the UFSAR supplement, the staff finds that

the summary description of the applicant's actions to address EQ of electrical equipment is

adequate, as required by 10 CFR 54.21(d).

4.4.4 Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to

10 CFR 54.21(c)(1)(iii), that, for EQ of electrical equipment, the effects of aging on the intended

function(s) will be adequately managed for the period of extended operation. The staff also

concludes that the UFSAR supplement contains an appropriate summary description of the

TLAA evaluation, as required by 10 CFR 54.21(d) and therefore is acceptable.

4.5 Concrete Containment Tendon Prestress

4.5.1 Summary of Technical Information in the Application

LRA Section 4.5 summarizes the evaluation of concrete containment tendon prestress for the

period of extended operation. Units 1 and 2 have Mark II primary containments with no prestressed tendons; therefore, tendon prestress evaluations are not applicable.

4.5.2 Staff Evaluation

Units 1 and 2 containment has no prestressed tendons; therefore, the staff finds that this TLAA

is not required.

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4.5.3 UFSAR Supplement

The staff concludes that no UFSAR supplement is required because Units 1 and 2 has no prestressed tendons in the containment building.

4.5.4 Conclusion

On the basis of its review, as discussed above, the staff concludes this TLAA is not required.

4.6 Containment Liner Plate. Metal Containments, and Penetrations Fatigue

Analyses

4.6.1 ASME Code Class MC Components

4.6.1.1 Summary of Technical Information in the Application

LRA Section 4.6.1 summarizes the applicant's evaluation of fatigue of ASME Code Class MC

components for the period of extended operation. Fatigue evaluations were required for

analyses qualifying as TLAAs for the containment penetrations, hatches, and drywell head. The

applicant states that it compared the design thermal cycles for those evaluations against the

maximum projected thermal cycles for extended life to 60 years and determined that the

penetration fatigue evaluations are adequate and require no updating for license renewal.

4.6.1.2 Staff Evaluation

The staff reviewed LRA Section 4.6.1, pursuant to 10 CFR 54.21(c)(1)(i), to verify that the

analyses remain valid for the period of extended operation.

In LRA Section 4.6.1, the applicant stated that the design thermal cycles for ASME

Code Class MC components are 500 cycles associated with plant startup and shutdown and

one cycle for a DBA. The staff examined UFSAR Section 3.8.2, "ASME Class MC Steel

Components of the Containment" and confirmed the design thermal cycles for the fatigue

evaluation of the containment ASME Code Class MC stainless steel components.

The staff reviewed LRA Section 4.6.1 and the relevant references cited in the TLAA. The staff

noted LRA states that the RPV assembly and internal components were designed for a

combined total of 228 events for startup and shutdown for 40 years, and projected for a total of

296 cycles for extended life to 60 years. The staff finds that the 500 design cycles for startups

and shutdowns remains well above the projected 60-year value, and the one cycle for DBA is

assumed in the design for the life of the plant, whether that is 40 years or 60 years. On this

basis, the staff agrees that the existing analysis of fatigue remains valid through the period of

extended operation. The staff finds this TLAA acceptable because the projected 60-year

thermal cycles are bounded by the design thermal cycles based on UFSAR Section 3.8.2.

4.6.1.3 UFSAR Supplement

The applicant provided a UFSAR supplement summary description of its TLAA evaluation of

fatigue for the containment ASME Code Class MC stainless steel components in LRA

Section A.1.3.5.1. On the basis of its review of the UFSAR supplement, the staff finds that the

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summary description of the applicant's actions to address fatigue of the containment ASME

Code Class MC stainless steel components is adequate because the applicant has provided

information equivalent to the guidance found in SRP-LR Table 4.6-1.

4.6.1.4 Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to

10 CFR 54.21(c)(1)(i), that, for the containment ASME Code Class MC components fatigue

TLAA, the analyses remain valid for the period of extended operation. The staff also concludes

that the UFSAR supplement contains an appropriate summary description of the TLAA

evaluation, as required by 10 CFR 54.21(d) and therefore is acceptable.

4.6.2 Downcomer Vents and Safety Relief Valve Discharge Piping

4.6.2.1 Summary of Technical Information in the Application

LRA Section 4.6.2 summarizes the applicant's evaluation of fatigue for downcomer vents and

SRV discharge piping for the period of extended operation. The applicant states that to ensure

the integrity of the downcomers and SRV discharge piping for the original 40-year life of the

plant, analyses were performed for the appropriate load combinations and their associated

number of cycles. Fatigue evaluations were required for analyses qualifying as TLAAs. The

applicant also states that it calculated the combined stress and corresponding equivalent stress

cycles to obtain the fatigue CUF in accordance with the ASME Section III, Subsection NB-3600.

In the SSES LRA, the applicant summarized the maximum CUF for the downcomers in

Table 4.6-1 and for the SRV discharge piping in LRA Table 4.6-2. The applicant compared the

number of events assumed in the 40-year design basis analyses against the projected 60-year

number and determined that the fatigue evaluations are adequate and require no updating for

license renewal.

4.6.2.2 Staff Evaluation

The staff reviewed LRA Section 4.6.2 pursuant to 10 CFR 54.21(c)(11)(i), to verify that the

analyses remain valid for the period of extended operation.

During the review, the staff reviewed the applicant's related onsite basis documents to confirm

the design cycles of downcomer vents and SRV discharge piping for the fatigue evaluation. In

LRA Table 4.6-1, the applicant summarized the maximum CUF for the downcomers. However,

the staff noted that Operational Cases Four and Six are identical, while the CUF values are

different.

In RAI 4.6.2-1, dated June 17, 2008, the staff requested that the applicant clarify the

discrepancy.

In its response to RAI 4.6.2-1, dated July 8, 2008, the applicant stated that the LRA Table 4.6-1

Maximum CUF for Downcomers described is incorrect and requires revision based on the

Design Assessment Report for Units 1 and 2 The applicant amended the LRA to correctly

identify Operational Case Six in Table 4.6-1 as "6-Emergency/Faulted - SBA:SRV+CHUG" to

"Emergency/Faulted - SBA: CHUG+SSE."

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Based on its review, the staff finds the applicant's response to RAI 4.6.2-1 acceptable because

the applicant has amended LRA Table 4.6-1 to clarify the maximum downcomer CUF

discrepancy. Therefore, the staff's concern described in RAI 4.6.2-1 is resolved.

The staff reviewed LRA Section 4.6.2, the related onsite basis documents, and the applicant's

response to RAI 4.6.2-1. The staff notes that the applicant has summarized the maximum

CUFs for downcomers with different operational cases in LRA Table 4.6-1, and the maximum

CUFs for SRV discharge piping in the suppression pool area in LRA Table 4.6-2. The staff finds

that all CUFs for both 40 years and 60 years are less than 1. The staff also finds that the

number of cycles assumed in the applicant's design basis (40-year) for the both downcomer

and SRV discharge piping remains above the projected 60-year number of events. On this

basis, the staff agrees with the applicant that the existing analysis of fatigue remains valid

through the period of extended operation.

The staff finds this TLAA acceptable because the 60-year anticipated number of events is

bounded by the number assumed in the design basis analysis.

4.6.2.3 UFSAR Supplement

The applicant provided a UFSAR supplement summary description of its TLAA evaluation of the

downcomer vents and SRV discharge piping in LRA Section A.1.3.5.2. On the basis of its

review of the UFSAR supplement, the staff finds that the summary description of the applicant's

actions to address fatigue for the downcomer vents and SRV discharge piping is adequate

because the applicant has provided information equivalent to the guidance found in SRP-LR

Table 4.6-1.

4.6.2.4 Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to

10 CFR 54.21(c)(1)(i), that, for the downcomer vents and SRV discharge piping fatigue TLAA,

the analyses remain valid for the period of extended operation. The staff also concludes that

the UFSAR supplement contains an appropriate summary description of the TLAA evaluation,

as required by 10 CFR 54.21(d) and therefore is acceptable.

4.6.3 Safety Relief Valve Quenchers

4.6.3.1 Summary of Technical Information in the Application

LRA Section 4.6.3 summarizes the applicant's evaluation of SRV quenchers fatigue for the

period of extended operation. The applicant states that to ensure the integrity of the SRV

quenchers for the original 40-year life of the plant, two analyses were performed based on the

number of allowable cycles, one using design loading, and the other using test loading data.

Seven thousand cycles were assumed as design cycles for the components. Fatigue

evaluations were required for analyses qualifying as TLAAs. The applicant calculated CUF for

each analysis, and summarized the CUF for the SRV quenchers in LRA Table 4.6-3. The

applicant further states that it compared the number of cycles assumed in the 40-year design

basis analyses against the projected 60-year number from FatiguePro software and determined

that the fatigue evaluations are adequate and require no updating for license renewal.

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4.6.3.2 Staff Evaluation

The staff reviewed LRA Section 4.6.3, pursuant to 10 CFR 54.21(c)(1)(i), to verify that the

analyses remain valid for the period of extended operation.

During the audit and review, the staff reviewed the applicant's related onsite basis documents

to confirm the design cycles of the SRV quenchers for the fatigue evaluation. The staff noted

that all components of the quenchers, except the base support which was designed as a

"Code Paragraph NE" component support, were designed and analyzed in accordance with

ASME Code Section III, Paragraph NC-3200, 1977 Edition with 1977 Summer Addenda. The

staff is not clear which Code Paragraph NF the applicant referred to. In RAI 4.6.3-1, dated

June 17, 2008, the staff requested that the applicant clarify which code was being referenced.

In its response to RAI 4.6.3-1, dated July 8, 2008, the applicant stated that LRA Section 4.6.3 is

incorrect and "Code Paragraph NF" will be revised to "Code Subsection NF." The staff

confirmed that that applicant has amended LRA Section 4.6.3 to reflect this change.

Based on its review, the staff finds the applicant's response to RAI 4.6.3-1 acceptable because

the applicant has amended LRA Section 4.6.3 to correct the code reference. The staff confirms

that Code Subsection NF is the correct reference. Therefore, the staff's concern described in

RAI 4.6.3-1 is resolved

The staff reviewed LRA Section 4.6.3, the related onsite basis documents, and the applicant's

response to RAI 4.6.3-1. The staff notes that the projected quencher cycles and CUFs are

displayed in LRA Table 4.6.3. The staff finds that the expected number of cycles for each

quencher component analyzed is 7000, and that all CUFs for both 40 years and 60 years are

less than 1. The staff also finds that the number of design cycles for the SRV quenchers

exceeds the number of projected 60-year cycles. On this basis, the staff agrees with the

applicant that the existing analysis of fatigue remains valid through the period of extended

operation. The staff finds this TLAA acceptable because the number of projected 60-year

cycles is bounded by the number assumed in the design basis analysis.

4.6.3.3 UFSAR Supplement

The applicant provided a UFSAR supplement summary description of its TLAA evaluation of the

SRV quenchers in LRA Section A.1.3.5.3. On the basis of its review of the UFSAR supplement,

the staff finds that the summary description of the applicant's actions' to address fatigue for the

SRV quenchers is adequate because the applicant has provided information equivalent to the

guidance found in SRP-LR Table 4.6-1.

4.6.3.4 Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to

10 CFR 54.21 (c)(1)(i), that, for the SRV quenchers fatigue TLAA, the analyses remain valid for

the period of extended operation. The staff also concludes that the UFSAR supplement

contains an appropriate summary description of the TLAA evaluation, as required by

10 CFR 54.21(d) and therefore is acceptable.

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4.7 Other Plant-Specific Time-Limited Aging Analyses

4.7.1 Main Steam Line Flow Restrictor Erosion Analyses

4.7.1.1 Summary of Technical Information in the Application

LRA Section 4.7.1 summarizes the evaluation of Main Steam Line (MSL) flow restrictor erosion

analyses for the period of extended operation. A flow restrictor is incorporated in each MSL to

limit flow to 200 percent of rated flow if a MSL ruptures outside containment. Flow restrictor

erosion is a safety concern because it could impair flow restrictor ability to limit vessel

blowdown following a MSL break. As erosion is a time-related phenomenon, analyses of its

effect on flow restrictors over the 40-year life of the plant are TLAAs. According to UFSAR

Section 5.4.4, flow restrictor cast stainless steel material has excellent resistance to erosion by

high-velocity steam. Only very slow erosion occurs and such a slight enlargement of the flow

restrictor opening has no safety significance. The UFSAR states that after 40 years of operation

the choke flow through the restrictor would increase by no more than 5% due to erosion,

implying a 5% increase in released radiological dose, insignificant for a postulated break in a

MSL outside containment.

Another 20 years of operation will result in further erosion of the MSL flow restrictor throats,

which can be extrapolated linearly from 40 to 60 years. This extrapolation is conservative

because the rate of erosion is expected to decrease as the restrictor throat area increases

(operation at extended power uprate conditions does not affect erosion rate significantly).

Therefore, erosion for the 20 years of extended operation will be approximately half the erosion

for the first 40 years, and the corresponding increase in steam flow will be approximately half of

the increase (5 percent) in steam flow due to erosion at the end of 40 years, meaning that by

the end of 60 years the increase in flow compared to flow at the beginning of life will be no

more than 7.5 percent. Therefore, the released dose for the accident case at 60 years would be

increased no more than 7.5 percent. Such an insignificant increase in dose over the analyzed

case remains within regulatory limits, as indicated in UFSAR Section 15.6.4.5.3. Hence, MSL

flow restrictor performance is not impacted significantly by additional erosion during the period

of extended operation, and the potential effect of the degraded performance is acceptable.

4.7.1.2 Staff Evaluation

The staff reviewed LRA Section 4.7.1, to verify pursuant to 10 CFR 54.21(c)(1)(ii), that the

analyses have been projected to the end of the period of extended operation.

The design safety function of the flow restrictors is to limit the radiological release outside of the

drywell following a MSL break and prior to MS isolation valve closure.

In LRA Section 4.7.1, the applicant stated that erosion of the MSL flow restrictors during

40 years of operation would increase steam flow rate by no more than 5 percent, and an

additional 20 years of operation could be linearly extrapolated for a total increase in steam flow

(and therefore dose) of 7.5 percent. The applicant based the 5 percent increase on an erosion

rate "as high as 0.004 inches per year" of the MS flow restrictor. In RAI 4.7.1-1a the staff

requested that the applicant explain the basis for assuming an erosion rate of 0.004 inches per

year and whether this rate was applicable for the term of extended operation. The staff also

requested that the applicant clarify whether this assumption was conservative, realistic, or nonconservative.

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In its response to RAI 4.7.1-1a dated October 16, 2007, the applicant provided its basis for an

additional 20 years of operation that included justification for the assumed erosion rate of the

MSL flow restrictors. In addition, the applicant submitted evidence verifying that there was

sufficient margin on the acceptable dose limits, in the event of a radiological release outside of

containment.

As justification for the assumed erosion rate over 20 years of extended operation, the applicant

cited EPRI Non-Class 1 Mechanical Implementation Guideline and Mechanical Tools (EPRI

Tools), Revision 4, Appendix A, Section 3.1.6, on treated water. This EPRI guideline states that

material loss due to erosion is possible only if the fluid stream contains particulate (or water

droplets in two phase flow) that impinges upon the surface of the metal. The applicant stated

that since the environment in the MSLs, at the location of the flow restrictors, is treated water in

the form of steam (with only 0.1 to 0.2 percent moisture), virtually no water droplets exist in the

steam to cause erosion. This assumption is supported by inspection results indicating no

significant erosion damage in the MSLs at Units 1 and 2. The staff reviewed EPRI report

TR-1 06611, "Flow Accelerated Corrosion in Power Plants," Revision 1 and notes that flowaccelerated corrosion (FAC) rates drop to essentially zero when the chromium content of the

alloy is above 0.5 percent and the temperature is greater than 4500F. The report also states

that type 304 stainless steel (which contains a minimum of 18 percent chromium) has more

than 250 times greater resistance to FAC than carbon steel. The MSL flow restrictors in

question are constructed of cast austenitic stainless steel (American Society for Testing of

Materials A351 Grade CF8), which contains a minimum of 18 percent chromium, and typically

operate at a steam temperature of 543°F. The staff determined that the applicant's FAC

program inspection of the carbon steel piping immediately downstream of the flow restrictors on

Unit 2, showed the highest wear rate to be 0.019 inches per year, which is only about five times

higher than the assumed wear rate of the stainless steel flow restrictors. When compared to the

nominal ratio of 250 times given in the EPRI report, the staff finds that there is sufficient margin

to assume that the 0.004 inches per year FAC rate is a very conservative value. Based on the

information provided by the applicant, the staff finds the justification for the assumed erosion

rate acceptable.

The staff performed an evaluation of the Control Room Habitability Envelope and of the offsite

radiological doses (at the exclusion area boundary and the low population zone) following a

MSL break, outside of containment, using the Alternative Source Term methodology described

in RG 1.183. This methodology assumed a mass release that was a 20 percent increase over

the original licensing value. This assumption provides additional margin for the extended power

uprate, for which the applicant had submitted a separate license amendment. The Alternative

Source Term methodology demonstrated that the highest ratio of any calculated dose to its

acceptance criteria is 18.6 percent. Therefore, even with the 20 percent flow increase, a safety

margin on the doses of at least 81.4 percent still remained. The staff determined that the

additional 20 percent margin was unnecessary, because documented results demonstrate that

a mass release following a MSL break will not increase (SSES PUSAR submittal, PLA-6076).

The staff determines that an increase of 7.8 percent in the mass release from a postulated

steam line break is acceptable because it is enveloped by the 20 percent increase considered

in the extended power uprate evaluation, which was subsequently determined to be

unnecessary.

In LRA Section 4.7.1, the applicant stated that any erosion that occurs will increase the throat

cross-sectional area, thereby decreasing flow velocity and, thus, decrease the actual wear rate.

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Therefore, the initial assumed wear rate of 0.004 inches per year will remain conservative for

the period of extended operation. In RAI 4.7.1-1b, the staff requested that the applicant provide

a copy of its calculation that demonstrated the acceptability of the MS flow restrictors for the

license renewal period. The staff also requested that the applicant provide descriptions of all

relevant parameters and, a basis and justification for all assumptions.

In its response to RAI 4.7.1-1b, dated October 16, 2007, the applicant stated that with an

erosion rate of 0.004 inches per year, the throat diameter of the MSL flow restrictor's venturi

section would increase by 0.480 inches (0.004 x 2 x 60) over the course of 60 years. Because

the flow restrictor had an original throat diameter of 12.580 inches, the final diameter would be

13.060 inches (12.580 + 0.480) after 60 years. This would increase the throat area of the flow

restrictor by 7.8 percent, and, because the flow is proportional to the throat area, the flow

through the restrictor following a MSL break would increase by 7.8 percent. The staff finds the

response to RAI 4.7.1-1b acceptable.

4.7.1.3 UFSAR Supplement

The applicant provided an UFSAR supplement summary description of its TLAA evaluation of

MSL flow restrictor erosion analyses in LRA Section A. 1.3.6. On the basis of its review of the

UFSAR supplement, the staff finds that the summary description of the applicant's actions to

address MSL flow restrictor erosion analyses is adequate.

4.7.1.4 Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to

10 CFR 54.21(c)(1)(ii), that, for the MSL flow restrictor erosion analyses, the analyses have

been projected to the end of the period of extended operation. The staff also concludes that the

UFSAR supplement contains an appropriate summary description of the TLAA evaluation, as

required by 10 CFR 54.21(d) and therefore is acceptable.

4.7.2 High Energy Line Break Cumulative Fatigue Usage Factors

4.7.2.1 Summary of Technical Information in the Application

LRA Section 4.7.2 discusses the evaluation of TLAAs associated with the postulation HELBs.

The SSES design criteria used to determine postulated HELB design locations included the

calculated fatigue CUF based on the number of design transients assumed for the original 40-

year life of the plant. Postulated pipe breaks were evaluated at locations where the design CUF

was greater than 0.1. The applicant indicated that additional locations could exceed the CUF

criteria in 60 years. The applicant will use the SSES FMP to monitor the fatigue usage of the

piping systems and to determine whether any additional locations exceed the pipe break criteria

during the period of extended operation.

4.7.2.2 Staff Evaluation

In LRA Section 4.7.2, the applicant stated that its FMP will be used to monitor the fatigue usage

of piping systems during the period of extended operation. The applicant also stated that

appropriate corrective actions would be taken to address any new locations where the CUF is

projected to exceed 0.1, during the period of extended operation.

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In RAI 4.7.2-1, dated September 5, 2007, the staff requested that the applicant clarify whether

any Class 1 high-energy piping locations with a CUF value of less than 0.1, by the current

design basis, may exceed 0.1 during the period of extended operation.

In its response to RAI 4.7.2-1, dated August 1, 2008, the applicant stated that there are

additional locations where the CUF may exceed 0.1 during the period of extended operation.

The applicant further stated that its FMP will be enhanced to ensure that high-energy piping

systems continue to meet the applicable pipe break criteria, as specified in UFSAR Section 3.6,

during the period of extended operation. The staff confirms that the applicant has revised

Commitment No. 43 to enhance the SSES FMP as part of its response to RAI B.3.1-4. The

revised commitment contains a provision to review HELB evaluations.

The staff finds the applicant's revised Commitment No. 43 to enhance the SSES FMP

adequately addresses the TLAA associated with high energy pipe breaks. Therefore, the staff's

concern described in RAI 4.7.2-1 is resolved.

4.7.2.3 UFSAR Supplement

The applicant provided the UFSAR supplement summary description of its TLAA evaluation of

HELB CUFs in LRA Section 1.3.6.2. On the basis of its review of the UFSAR supplement, the

staff finds the summary description of the applicant's actions to address the TLAA associated

with postulated piping rupture locations due to fatigue usage is adequate.

4.7.2.4 Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to

10 CFR 54.21(c)(1)(iii), that the fatigue analysis of RCPB components, including the fatigue

criteria for postulation of high-energy pipe breaks, will be adequately managed during the

period of extended operation. The staff also concludes that the UFSAR supplement contains an

appropriate summary description of the TLAA evaluation, as required by 10 CFR 54.21(d) and

therefore is acceptable.

4.7.3 Core Plate Rim Hold-Down Bolts

4.7.3.1 Summary of Technical Information in the Application

LRA Section 4.7.3 summarizes the evaluation of core plate rim hold-down bolts for the period of

extended operation. The SER that refers to BWRVIP-25, "BWR Core Plate Inspection and Flaw

Evaluation Guidelines," for license renewal indicates loss of preload on the core plate rim

hold-down bolts as one TLAA that must be addressed by applicants seeking license renewal.

BWRVIP-25, Appendix B states that the core plate bolts will have at least 81-percent preload

remaining at 54 EFPY. The applicant determined that loss of preload due to non-irradiation

effects was negligible.

GE extended power uprate analyses evaluated the core plate hold-down bolts and determined

that the preload at the end of 60 years would be adequate to prevent lateral motion of the core

plate.

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4.7.3.2 Staff Evaluation

The staff reviewed LRA Section 4.7.3, to verify pursuant to 10 CFR 54.21 (c)(1)(ii), that the

analyses have been projected to the end of the period of extended operation.

In LRA Section 4.7.3, the applicant stated that based on BWRVIP-25, the core plate bolts will

have at least 81 percent preload remaining at 54 EFPY. The applicant further stated that the

GE extended power uprate analyses, which evaluated the core plate hold-down bolts, showed

that the preload at the end of 60 years would be adequate to prevent lateral motion of the core

plate for the period of extended operation. The staff notes that this conclusion is not supported

by any SSES plant-specific evaluation.

In RAI 4.7.3-1, dated September 5, 2007, the staff requested that the applicant:

(1) Demonstrate the applicability of the BWRVIP-25 loss of preload analysis to the

Susquehanna units. Identify the temperature of the bolts during the normal

operation and the projected bolt neutron fluence at the end of the period of

extended operation for the Susquehanna units. Provide a plant-specific

evaluation demonstrating that the loss of preload due to stress relaxation for the

Susquehanna RPV core plate hold-down bolts is bounded by the value of

19 percent from BWRVIP-25 Appendix B.

(2) Perform a plant-specific core plate hold-down bolt analysis using the

BWRVIP-25 Appendix A methodology, demonstrating that the axial and bending

stresses for the mean and highest loaded hold-down bolts will not exceed the

ASME Code Section III allowable stresses for Pm (primary membrane) and Pm +

Pb (primary membrane plus bending) as a result of a plant-specific reduction in

the bolt preload at the end of the extended period of operation. State the

assumptions on which the plant-specific analysis was based.

(3) Provide sufficient information regarding the GE extended power uprate analyses

on the core plate hold-down bolts mentioned in LRA Section 4.7.3 so that the

staff can determine whether the Susquehanna hold-down bolts are adequate to

prevent lateral motion of the core plate for the period of extended operation.

In its response to RAI 4.7.3-1, dated October 18, 2007, items 1 and 2, dated October 18, 2007,

the applicant stated that it proposes to address the loss of preload on the core plate rim holddown bolts, prior to entering the period of extended operation, by one of the following two

actions:

(1) Perform an SSES plant-specific evaluation consistent with BWRVIP-25 to

demonstrate that the core plate rim hold-down bolts will be capable of preventing

lateral displacement of the core plate for the period of extended operation. The

evaluation will determine the maximum expected reduction in the bolt preload at

the end of the period of extended operation, considering all applicable

parameters (i.e., operating temperature, operating loads, and irradiation effects)

and demonstrate the acceptability of the final preload at the end of the period of

extended operation. Using the methodology of BWRVIP-25 Appendix A, the

evaluation will also determine the primary membrane and bending stresses for

the limiting bolt(s) to demonstrate that ASME Code allowables are not exceeded

4-43
as a result of the reduction in bolt preload at the end of the period of extended

operation. The evaluation will be submitted to the staff for review no less than

two years prior to the period of extended operation.

(2) Install core plate wedges to structurally replace the lateral load resistance

provided by the hold-down bolts. With wedges installed, any loss of preload on

the core plate rim hold-down bolts during the period of extended operation will

have no effect on the lateral stability of the core plate.

The applicant further stated that if the evaluation described as (1) above is unable to

demonstrate acceptable bolt preload or bolt stress values at the end of the period of extended

operation, appropriate corrective action will be taken prior to entering the period of extended

operation. These proposed measures are summarized in Disposition of LRA Section 4.7.3,

UFSAR Supplement Section A. 1.3.6.3, and a new commitment in LRA Table A-I.

Based on its review, the staff finds the applicant's response to RAI 4.7.3-1 acceptable because

the applicant has committed (Commitment No. 55) to address the loss of preload on the core

plate rim hold-down bolts, prior to entering the period of extended operation. The staff reviewed

the applicant's commitment and concludes that conducting the proposed plant-specific analysis,

consistent with BWRVIP-25 guidance, is an acceptable method of addressing the TLAA for the

core plate rim hold-down bolts, as described in the SER for compliance with the license renewal

rule, dated December 7, 2000. The staff also concludes that installation of core plate wedges is

considered an appropriate corrective action, consistent with BWRVIP-25, as described in the

SER for operating plants, dated December 19, 1999. Either action will provide adequate

assurance that the 60-year stress relaxation of the core plate hold-down bolts, due to neutron

exposure, will not compromise the structural integrity and operability of the core plate to the end

of the period of extended operation. The staff determines that since the plant-specific analysis

described by the applicant in action (1) will consider applicable irradiation effects not based on

the GE extended power uprate report, item (3) of the RAI is no longer a concern. Therefore, the

staff's concerns described in RAI 4.7.3-1 are resolved.

4.7.3.3 UFSAR Supplement

The applicant provided an UFSAR supplement summary description of its TLAA evaluation of

core plate rim hold-down bolts in LRA Section A.1.3.6. On the basis of its review of the revised

UFSAR supplement, the staff finds that the summary description of the applicant's actions to

address core plate rim hold-down bolts is adequate.

4.7.3.4 Conclusion

On the basis of its review, the staff concludes that the applicant's Commitment No. 55 to

provide a plant-specific TLAA analysis on the stress relaxation of the core plate rim hold-down

bolts for the period of extended operation, two years prior to the start of the period of extended

operation, in accordance with 10 CFR 54.21(c)(1)(iii), is acceptable. Further, the non-TLAA

alternative of installing core plate wedges as structural replacements for the lateral load

resistance, provided by the hold-down bolts, is considered acceptable. The staff also concludes

that the UFSAR supplement contains an appropriate summary description of the TLAA

evaluation, as required by 10 CFR 54.21(d) and therefore is acceptable.

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4.8 Conclusion for Time-Limited Aging Analyses

The staff reviewed the information in LRA Section 4, "Time-Limited Aging Analyses." On the

basis of its review, the staff concludes, that the applicant has provided a sufficient list of TLAAs,

as defined in 10 CFR 54.3 and that the applicant has demonstrated that: (1) the TLAAs will

remain valid for the period of extended operation, as required by 10 CFR 54.21 (c)(1)(i); (2) the

TLAAs have been projected to the end of the period of extended operation, as required by

10 CFR 54.21 (c)(1 )(ii); or (3) that the effects of aging on intended function(s) will be adequately

managed for the period of extended operation, as required by 10 CFR 54.21 (c)(1 )(iii). The staff

also reviewed the UFSAR supplement for the TLAAs and finds that the supplement contains

descriptions of the TLAAs sufficient to satisfy the requirements of 10 CFR 54.21(d). In addition,

the staff concludes, as required by 10 CFR 54.21(c)(2) that no plant-specific, TLAA-based

exemptions are in effect.

With regard to these matters, the staff concludes that there is reasonable assurance that the

activities authorized by the renewed licenses will continue to be conducted in accordance with

the CLB, and that any changes made to the CLB, in order to comply with 10 CFR 54.29(a), are

in accordance with the Atomic Energy Act of 1954, as amended, and NRC regulations.

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SECTION 5

REVIEW BY THE ADVISORY COMMITTEE ON REACTOR

SAFEGUARDS

The NRC staff issued its safety evaluation report (SER) with open items related to the renewal

of the operating license of Susquehanna Steam Electric Station (SSES), Units 1 and 2 on

March 13, 2009. On April 1, 2009, the applicant presented its license renewal application, and

the staff presented its review findings to the ACRS Plant License Renewal Subcommittee. The

staff reviewed the applicant's comments on the SER and completed its review of the license

renewal application. The staff's evaluation is documented in an SER that was issued by letter

dated August 27, 2009.

During the 566st meeting of the ACRS, October 8, 2009, the ACRS completed its review of the

SSES license renewal application and the NRC staff's SER. The ACRS documented its

findings in a letter to the Commission dated October 23, 2009. A copy of this letter is provided

on the following pages of this SER Section.

5-1
UNITED STATES

NUCLEAR REGULATORY COMMISSION

ADVISORY COMMITTEE ON REACTOR SAFEGUARDS

*- -WASHINGTON, DC 20555 - 0001

October 23, 2009

The Honorable Gregory B. Jaczko

Chairman

U. S. Nuclear Regulatory Commission

Washington, DC 20555-0001

SUBJECT: REPORT ON THE SAFETY ASPECTS OF THE LICENSE RENEWAL

APPLICATION FOR THE SUSQUEHANNA STEAM ELECTRIC STATION,

UNITS 1 AND 2

Dear Chairman Jaczko:

During the 5 6 6 th meeting of the Advisory Committee on Reactor Safeguards, October 8-10,

2009, we completed our review of the license renewal application for the Susquehanna Steam

Electric Station (SSES), Units 1 and 2, and the final Safety Evaluation Report (SER) prepared

by the NRC staff. Our Plant License Renewal Subcommittee also reviewed this matter during

its meeting on April 1, 2009. During these reviews, we had the benefit of discussions with

representatives of the NRC staff and the applicant, PPL Susquehanna, LLC (PPL). We also

had the benefit of the documents referenced. This report fulfills the requirement of 10 CFR

54.25 that the ACRS review and report on all license renewal applications.

CONCLUSION AND RECOMMENDATION

1. The programs established and committed to by the applicant to manage age-related

degradation provide reasonable assurance that SSES, Units 1 and 2 can be operated in

accordance with its current licensing basis for the period of extended operation without

undue risk to the health and safety of the public.

2. The PPL application for renewal of the operating licenses of SSES, Units 1 and 2 should

be approved.

BACKGROUND AND DISCUSSION

SSES consists of two General Electric Model 4 boiling water reactors (BWR-4) with Mark II

containments and is located approximately 5 miles northeast of Berwick, Pennsylvania. In

2008, the NRC authorized an extended power uprate to increase the maximum power level for

SSES, Units 1 and 2 from 3,489 MWt to 3,952 MWt. The gross electrical output of each

reactor is approximately 1,300 megawatts-electric. The relevant evaluations of the license

renewal application have been performed at the extended power conditions. PPL requested

renewal of the SSES, Units 1 and 2 operating licenses for 20 years beyond the current license

terms, which expire on July 17, 2022, for Unit 1, and on March 23, 2024, for Unit 2.

5-2
2

In the final SER, the staff documented its review of the license renewal application and other

information submitted by the applicant or obtained from the staff audits and inspections at the

plant site. The staff reviewed the completeness of the applicant's identification of the

structures, systems, and components (SSCs) that are within the scope of license renewal; the

integrated plant assessment process; the applicant's identification of the plausible aging

mechanisms associated with passive, long-lived components; the adequacy of the applicants

Aging Management Programs (AMPs); and the identification and assessment of time-limited

aging analyses (TLAAs) requiring review.

In the SSES license renewal application, PPL identified the SSCs that fall within the scope of

license renewal. For these SSCs, the applicant performed a comprehensive aging

management review. Based on this review, the applicant will implement 52 AMPs for license

renewal, which include existing, new, and enhanced programs. Thirteen programs have

exceptions to the corresponding programs described in the Generic Aging Lessons Learned

(GALL) Report. Four of the programs are plant specific programs that do not have counterparts

in the GALL Report.

The PPL application either demonstrates consistency with the GALL Report or documents

deviations to the approaches specified in that Report. As noted above, 13 of the AMPs include

exceptions to the corresponding programs in the GALL Report. We reviewed these exceptions

and agree with the staff that they are acceptable. The staff conducted two license renewal

audits and two inspections at the SSES site. The audits verified the appropriateness of the

scoping and screening methodology, AMPs, aging management review, and TLAAs. The

inspections verified that the license renewal requirements are appropriately implemented.

Based on the audits and inspections, the staff concluded in the final SER that the proposed

activities will adequately manage the effects of aging of SSCs identified in the application and

that the intended functions of these SSCs will be maintained during the period of extended

operation. We agree with this conclusion.

The staffs review of the applicant's operating experience revealed that inaccessible mediumvoltage cables in certain manholes at SSES have experienced significant exposure to water,

i.e., cable in standing water for more than a few days. In addition, during a walk down, the staff

found several feet of water in Manhole Numbers 2 and 16. The staff identified water in

manholes as a generic, current operating plant issue in Information Notice 2002-12,

"Submerged Safety-Related Electrical Cables," and Generic Letter 2007-01, "Inaccessible or

Underground Power Cable Failures That Disable Accident Mitigation Systems or Cause Plant

Transients." The staff will resolve the issue of water in manholes during the current period of

operation through the Reactor Oversight Process, in accordance with the requirements of

10 CFR Part 50.

PPL has committed to implement a Non-EQ Inaccessible Medium-Voltage Cables Program

involving two parts: first, inspection (and draining, if necessary) of the applicable manholes on

a periodic basis; and second, the development of a testing program to confirm that the

conductor insulation on the applicable cables is not degrading. This program applies to six

cables associated with the offsite power supply for SSES. These are the only inaccessible

medium-voltage cables at SSES that are within the scope of license renewal. These cables are

exposed to significant moisture and are energized more than 25% of the time. The Non-EQ

Inaccessible Medium-Voltage Cable Program is a new AMP which will require the applicant to

5-3
3

test the cables and to evaluate plant-specific operating experience to determine an appropriate

inspection frequency for the manholes.

The staff has determined that implementation of the Non-EQ Inaccessible Medium-Voltage

Cable Program will ensure that the aging effects on inaccessible medium-voltage cables will be

adequately managed during the period of extended operation. We agree with this conclusion.

The applicant identified the systems and components requiring TLAAs and reevaluated them

for the period of extended operation. The staff concluded that the applicant has provided an

adequate list of TLAAs. Further, the staff concluded that the applicant has met the

requirements of the License Renewal Rule by demonstrating that the TLAAs will remain valid

for the period of extended operation; or the TLAAs have been projected to the end of the period

of extended operation; or the aging effects will be adequately managed for the period of

extended operation.

We agree with the staff that there are no issues related to the matters described in 10 CFR

54.29(a)(1) and (a)(2) that preclude renewal of the operating licenses for SSES, Units 1. and 2.

The programs established and committed to by PPL provide reasonable assurance that the

SSES can be operated in accordance with its current licensing basis for the period of extended

operation without undue risk to the health and safety of the public. The PPL application for

renewal of the operating licenses for SSES, Units 1 and 2 should be approved.

Sincerely,

Mario V. Bonaca

Chairman

5-4
SECTION 6

CONCLUSION

The staff of the United States (US) Nuclear Regulatory Commission (NRC) (the staff) reviewed

the license renewal application (LRA) for Susquehanna Steam Electric Station, Units 1 and 2, in

accordance with NRC regulations and NUREG-1 800, Revision 1, "Standard Review Plan for

Review of License Renewal Applications for Nuclear Power Plants," dated September 2005.

Title 10, Section 54.29, of the Code of Federal Regulations (10 CFR 54.29) sets the standards

for issuance of a renewed license.

On the basis of its review of the LRA, the staff determines that the requirements of

10 CFR 54.29(a) have been met.

The staff noted that any requirements of 10 CFR Part 51, Subpart A, are documented in

NUREG-1437, "Generic Environmental Impact Statement for License Renewal of Nuclear

Plants (GELS)," Supplement 35 "Generic Environmental Impact Statement for License Renewal

of Nuclear Plants Regarding Susquehanna Steam Electric Station, Units 1 and 2, Final Report"

dated March 2009.

6-1

Appendix A

APPENDIX A

SSES UNITS I AND 2 LICENSE RENEWAL COMMITMENTS

During the review of the Susquehanna Steam Electric Station (SSES), Units 1 and 2, license

renewal application (LRA) by the staff of the United States (US) Nuclear Regulatory

Commission (NRC) (the staff), PPL Susquehanna, LLC (the applicant) made commitments

related to aging management programs (AMPs) to manage aging effects for structures and

components. The following table lists these commitments along with the implementation

schedules and sources for each commitment.

A-1
Table A-1

SSES License Renewal Commitments

UFSAR Enhancement

Item Number Commitment Supplement or

Location Implementation (LRA App. A) Schedule

1) Inservice Existing program is credited. A.1.2.23 Ongoing

Inspection (ISI)

Program

2) BWR Water Existing program is credited. A.1.2.11 Ongoing

Chemistry

Program

3) Reactor Head Existing program is credited. A.1.2.40 Ongoing

Closure Studs

Program

4) BWR Vessel ID Existing program is credited. A.1.2.9 Ongoing

Attachment

Welds Program

5) BWR Feedwater Existing program is credited. A.1.2.6 Ongoing

Nozzle Program

6) BWR CRD Existing program is credited. A.1.2.5 Ongoing Return Line NozzeturnoL PPL will implement weld overlay repairs in accordance with ASME Nozzle Program Section XI and NRC-approved Code Cases. If no NRC-approved Code

Case exists for the weld overlay, PPL will obtain NRC approval prior to

implementing the repair in accordance with 10 CFR 50.55a.

7) BWR Stress Existing program is credited. A.1.2.8 Ongoing

Corrosion

Cracking (SCC)

Program

A-2
Table A-1 SSES License Renewal Commitments

UFSAR Enhancement

Item Number Commitment Supplement or

Location Implementation

(LRA App. A) Schedule

8) BWR Existing program is credited. A.1.2.7 Ongoing Penetrations

Program

9) BWR Vessel Existing program is credited. A.1.2.10 Ongoing Internals Ieroral PPL will continue to perform inspections on at least 10% of the top guide grid beam cells containing control rod drives/blades every twelve

years during the period of extended operation. Inspections on at least

5% of the top guide locations will be performed within the first six years

of each twelve year interval. The top guide locations to be inspected

are those subject to neutron fluence levels that exceed the IASCC

threshold of 5.0E+20 n/cm 2. The inspections will be performed using

the enhanced visual inspection technique, EVT-1.

10) Thermal Aging Program is new. A. 1.2.48 Prior to the

and Neutron The new program for SSES will be consistent with the program described in period of

CasttAusent NUREG-1 801 Section XI.M 13, Thermal Aging and Neutron Embrittlement of operation.

Cast Austenitic Cast Austenitic Stainless Steel (CASS) Program. The SSES program will

Stainless Steel identify susceptible components, evaluate those components to determine (CASS) Program their susceptibility to loss of fracture toughness, and examine those

components that are evaluated to be susceptible.

11) Flow- Existing program is credited. A. 1.2.20 Ongoing

Accelerated

Corrosion (FAC)

Program

A-3
Table A-1

SSES License Renewal Commitments

UFSAR Enhancement

Item Number Commitment Supplement or

Location Implementation

(LRA App. A) Schedule

12) Bolting Integrity Existing program is credited with the following enhancement: Prior to the

Program * Include specific precautions against the use of sulfur (sulfide) containing A. 1.2.2 period of

extended

compounds as a lubricant for bolted connections. operation

13) Piping Corrosion Existing program is credited with the following enhancements: A.1.2.38 Prior to the

Program period of P Include the Standby Gas Treatment System loop seals within the scope extended

of the program. operation.

* Incorporate performance, documentation and trending of opportunistic

visual inspections (during normal maintenance/repair activities) in

addition to existing Piping Corrosion Program inspections.

14)Crane Inspection Existing program is credited. A.1.2.17 Ongoing

Program

15) Fire Protection Existing program is credited. A. 1.2.18 Ongoing

Program

16) Buried Piping Program is new. A. 1.2.4 Prior to the

Surveillance The scope of the Buried Piping Surveillance Program includes only the period of

Program portions of the buried piping in the Residual Heat Removal Service Water extended

(RHRSW) and Emergency Service Water (ESW) common return header operation.

known to have damaged coatings. The program is credited for managing

loss of material due to crevice, general, and pitting corrosion and

microbiologically influenced corrosion (MIC) for buried steel piping

components with damaged coatings.

A-4
Table A-1

SSES License Renewal Commitments

UFSAR Enhancement

Item Number Commitment Supplement or

Location Implementation

(LRA App. A) Schedule

17) Condensate and Program is a new one-time inspection. A. 1.2.14 Within the 10-

Refueling Water year period prior

Storage Tanks The scope of the Condensate and Refueling Water Storage Tanks to the period of

Inspection Inspection includes the base (bottom surface and foundation pad interface) extended of the Condensate Storage Tanks (CSTs) and Refueling Water Storage exten.

Tank (RWST) that are in the scope of license renewal and included in the operation.

Condensate Storage and Transfer and the Refueling Water Storage and

Transfer systems.

An appropriate combination of volumetric (including thickness

measurement) and visual examinations will be conducted, for a unit's CST

(or RWST), to detect evidence of a loss of material due to crevice, general,

or pitting corrosion or to confirm a lack thereof. Results will be applied to

the other unit's tank(s) based on engineering evaluation.

18) Reactor Vessel Existing program is credited with the following enhancement: A. 1.2.41 Prior to the

Surveillance Address the additional requirements specified in the NRC safety evaluation period of

Program dated March 1, 2006, for BWRVIP-1 16. The program will include a extended

requirement that, if a standby capsule is removed from either of the SSES operation.

Unit 1 or Unit 2 reactor vessels without the intent to test it, the capsule will

be stored in a manner which maintains it in a condition which would permit

its future use, including during the period of extended operation if

necessary.

A-5
Table A-1

SSES License Renewal Commitments

UFSAR Enhancement

Item Number Commitment Supplement or

Location Implementation

(LRA App. A) Schedule

19) Chemistry Program is a new one-time inspection. A. 1.2.12 Within the 10-

Program The Chemistry Program Effectiveness Inspection includes the internal year period prior

Inspection surfaces of aluminum, copper and copper alloy, carbon and low alloy steel, extended

cast iron, stainless steel, and nickel alloy components in systems that

contain treated water or fuel oil. A representative sample of components in operation.

low flow and stagnant areas (i.e., locations that are isolated from the flow

stream and possibly prone to gradual accumulation/concentration of

contaminants) will be examined for evidence of a loss of material (due to

crevice, galvanic, general, or pitting corrosion or to erosion, and to MIC in

fuel oil), or to confirm a lack thereof, and the results applied to the rest of

the system(s) based on engineering evaluation.

20) Cooling Units Program is a new one-time inspection. A. 1.2.16 Within the 10-

Inspection The Cooling Units Inspection activities focus on a representative sample year period prior

population of subject components at susceptible locations, to be defined in to the period of

the implementing documents. These inspection activities provide extended

symptomatic evidence of cracking, loss of material, or reduction in heat operation.

transfer at all other susceptible locations due to the similarities in materials

and environmental conditions.

21) Heat Exchanger Program is a new one-time inspection. A.1.2.22 Within the 10-

Inspection The Heat Exchanger Inspection detects and characterizes conditions to year period prior

determine whether, and to what extent a loss of heat transfer due to fouling to the period of

is occurring (or likely to occur) for heat exchangers within the scope of extended

license renewal. The Heat Exchanger Inspection is also credited for operation.

managing cracking due to stress corrosion cracking / inter-granular attack

in the treated water (internal) environment of the admiralty brass tubes.

A-6
Table A-1

SSES License Renewal Commitments

UFSAR Enhancement

Item Number Commitment Supplement or

Location Implementation

(LRA App. A) Schedule

22) This commitment for Main Steam Flow Restrictor Inspection was removed.

23) Monitoring and Program is a new one-time inspection. A.1.2.33 Within the 10-

Collection System The scope of the Monitoring and Collection System Inspection includes the year period prior Inspection internal surfaces of subject carbon steel (and low alloy steel) and cast iron to the period of

piping and valve bodies that are exposed to potentially radioactive drainage extended

water (untreated water) and potentially other contaminants/fluids during operation.

normal plant operations.

A representative sample of components in the system, to be defined in the

implementing documents, and to include containment isolation piping and/or

valve bodies, will be examined for evidence of a loss of material (due to

crevice, general, or pitting corrosion or to MIC), or to confirm a lack thereof,

and the results applied to the rest of the system based on engineering

evaluation.

A-7
Table A-1

SSES License Renewal Commitments

UFSAR Enhancement

Item Number Commitment Supplement or

Location Implementation

(LRA App. A) Schedule

24) Supplemental

Piping/Tank

Inspection

Program is a new one-time inspection.

The Supplemental Piping/Tank Inspection is credited for managing loss of

material due to crevice and pitting corrosion on carbon steel surfaces at

air-water interfaces. The inspection is also credited for managing loss of

material due to microbiologically influenced corrosion (MIC) at the air-water

interface with the mist eliminator loop seal, which is filled with raw water

from the Service Water System, and galvanic corrosion at points of contact

between the mist eliminator housing and the SGTS filter enclosure, where

condensation and water pooling may occur. Additionally, the Supplemental

Piping/Tank Inspection detects and characterizes whether, and to what

extent, a loss of material due to crevice and pitting corrosion is occurring

(or is likely to occur) for stainless steel surfaces at air-water interfaces.

The Supplemental Piping/Tank Inspection also detects and characterizes

loss of material due to crevice, galvanic, general, and pitting corrosion on

internal carbon steel surfaces within the scram discharge volume (piping

and valve bodies) of the Control Rod Drive Hydraulic System, within the air

space of the condensate storage tanks and within the Diesel Generator

starting air receiver tanks and E diesel compressor skid air receiver tanks

to determine whether, and to what extent, degradation is occurring (or is

likely to occur).

In addition, the Supplemental Piping/Tank Inspection is credited to detect

and characterize loss of material due to general, crevice, and pitting

corrosion on the internal surfaces of carbon steel and cast iron diesel

exhaust piping, piping components, and turbocharger casings.The

inspection is also credited to detect and characterize cracking and loss of

A.1.2.46 Within the 10-

year period prior

to the period of

extended

operation.

A-8
Table A-1

SSES License Renewal Commitments

UFSAR Enhancement

Item Number Commitment Supplement or

Location Implementation

(LRA App. A) Schedule

material due to crevice and pitting corrosion on the internal surfaces of

stainless steel diesel exhaust piping components.

25) Selective Program is a new one-time inspection. A. 1.2.43 Within the 10-

Leaching The Selective Leaching Inspection detects and characterizes conditions to year period prior

Inspection determine whether, and to what extent a loss of material due to selective to the period of

leaching is occurring (or likely to occur) for susceptible components extended

including piping and tubing, valve bodies, pump and turbocharger casings, operation.

heat exchanger, cooler, and chiller components, hydrants, sprinkler heads,

strainers, level gauges, orifices, and heater sheaths. The components

within the scope of the program are formed of cast iron, brass, bronze, and

copper alloy materials. The components are subject to raw water, treated

water, groundwater (buried), indoor air with condensation, outdoor air, and

fuel oil environments. The components within the scope of this program are

located in twenty-six different plant systems.

26) Buried Piping Program is new. A.1.2.3 Prior to the

and Tanks The scope of the Buried Piping and Tanks Inspection Program includes period of

Inspection buried components that are within the scope of license renewal for SSES. extended

Program The program is credited for managing loss of material due to crevice, operation.

general, and pitting corrosion and microbiologically influenced corrosion

(MIC) for buried steel piping components. In addition, the program is

credited with managing loss of material for buried stainless steel piping

components. The Buried Piping and Tanks Inspection Program is also

credited for managing loss of material due to crevice, general, and pitting

corrosion and microbiologically influenced corrosion (MIC) for buried steel

tanks in the Diesel Fuel Oil System.

A-9
Table A-1

SSES License Renewal Commitments

UFSAR Enhancement

Item Number Commitment Supplement or

Location Implementation

(LRA App. A) Schedule

27) Small-Bore Program is a new one-time inspection. A. 1.2.44 Within the 10-

Class 1 Piping The SSES program will include measures to verify that cracking is not year period prior

Inspection occurring in Class 1 small-bore piping, thereby validating the effectiveness to the period of

of the Chemistry Program to mitigate cracking and confirming that no extended

additional aging management programs are needed for the period of operation.

extended operation.

28) System Existing program is credited with the following enhancements: A.1.2.47 Prior to the Walkdownpeido Proga The governing procedure for the System Walkdown Program must be period of

revised to add the listing of systems crediting the program for license

renewal and to explicitly include inspection of other metals, copper alloy operation.

and stainless steel.

o It may be determined by engineering evaluation that these

components do not require monitoring every two weeks, and the

basis for a different walkdown frequency must be documented

on the appropriate procedure form.

The governing procedure for the System Walkdown Program must be

enhanced to address the license renewal requirement for opportunistic

inspections of normally inaccessible components (e.g., those that are

insulated), and those that are accessible only during refueling outages.

For underground vaults/pits/manholes, an initial sample of at least one

vault/pit/manhole from each grouping of components with identical

material and environment combinations will be inspected prior to

entering the period of extended operation. A representative sample of

the entire population will be inspected within the first 6 years of the

A-10
Table A-1

SSES License Renewal Commitments

UFSAR Enhancement

Item Number Commitment Supplement or

Location Implementation

(LRA App. A) Schedule

28) System

Walkdown Program

(cont'd)

period of extended operation. Results of the inspection activities that

require further engineering evaluation/resolution (e.g., sample

expansion and inspection frequency changes if degradation is

detected), if any, will be evaluated using the SSES corrective action

process.

The governing procedure for the System Walkdown Program will be

enhanced to include a visual and ultrasonic inspection of the external

surfaces of piping passing into structures through penetrations

(underground piping) for those penetrations with a history of leakage.

These inspections will be focused on penetrations that are leaking at

that time and will include a representative population of each material,

environment combination from those piping systems within the scope of

license renewal (which includes those for the RHRSW, ESW, and Fire

Protection systems) that enter structures below grade.

A routine activity to supplement the existing plant program will be

generated, and based at least in part on EPRI 1007933, "Aging

Assessment Field Guide," to inspect elastomers and polymers for

cracking and/or change in material properties.

Evidence of surface degradation, such as cracking or discoloration,

as well as physical manipulation and/or prodding, will be used as a

measure of the material condition.

A representative sample will be determined by engineering evaluation with a

focus on components considered to be most susceptible to aging, such as

due to their time in service, the severity of conditions during normal plant

operations, and any pertinent design margins.

A-11
Table A-1

SSES License Renewal Commitments

UFSAR Enhancement

Item Number Commitment Supplement or

Location Implementation

__(LRA App. A) Schedule

29) Inservice Existing program is credited. A.1.2.24 Ongoing

Inspection (ISI)

Program - IWE

30) Inservice Existing program is credited. A.1.2.25 Ongoing

Inspection (ISI)

Program - IWF

31) Inservice Existing program is credited. A.1.2.26 Ongoing

Inspection (ISI)

Program - IWL

32) Containment Existing program is credited. A.1.2.15 Ongoing

Leakage Rate

Test Program

33) Masonry Wall Existing program is credited with the following enhancement: A.1.2.31 Prior to the

Program Specify that for each masonry wall, the extent of observed masonry period of

cracking and/or degradation of steel edge supports/bracing is extended

evaluated to ensure that the current evaluation basis is still valid. operation.

Corrective action is required if the extent of masonry cracking and

steel degradation is sufficient to invalidate the evaluation basis.

34) Structures Existing program is credited with the following enhancements: A.1.2.45 Prior to the

Monitoring Include additional structures requiring aging management for license period of

Program renewal to the scope of the inspections. extended

I i Ioperation.

A-12
Table A-1

SSES License Renewal Commitments

UFSAR Enhancement

Item Number Commitment Supplement or

Location Implementation

(LRA App. A) Schedule

34) Structures

Monitoring

Program

(cont'd)

" Specify that if a below grade structural wall or structural component

becomes accessible through excavation; a follow-up action is

initiated for the responsible engineer to inspect the exposed surfaces

for age-related degradation.

* Clarify "structural component" for inspection includes each of the

component types identified as requiring aging management.

Include degradation mechanisms for elastomer and earthen

embankment inspection.

* Include RG 1.127 inspection elements for water-control structure.

* Specify that the responsible engineer shall review site groundwater

and raw water pH, chlorides, and sulfates results prior to inspection

to validate that the below-grade or raw water environment remain

non-aggressive during the period of extended operation.

" Specify that for each masonry wall, the extent of observed masonry

cracking and/or degradation of steel edge supports/bracing is

evaluated to ensure that the current evaluation basis is still valid.

Corrective action is required if the extent of masonry cracking and

steel degradation is sufficient to invalidate the evaluation basis.

* Include additional direction for quantifying, monitoring and trending

of inspection results; Include additional guidance for inspection

reporting, data collection and documentation; Specify acceptance

criteria and critical parameters to monitor degradation and to trigger

level of inspection and initiation of corrective action; and provide I I

A-13
Table A-1

SSES License Renewal Commitments

UFSAR Enhancement

Item Number Commitment Supplement or

Location Implementation

(LRA App. A) Schedule

better alignment with referenced Industry codes, standards and

guidelines.

* Include specific qualification requirements for the inspector.

35) RG 1.127 Existing program is credited with the following enhancements: A.1.2.42 Prior to the

Water-Control period of Structures 0 Add the Spray Pond (including concrete liner, emergency spillway, extended

Inspection riser encasements and earthen embankments) to its scope for operation.

inspection.

* Include RG 1.127, Revision 1, Section C.2 inspection elements and

degradation mechanisms for water-control structure inspection.

* Include acceptance criteria as delineated in NUREG-1801 Section

XI.S7 for water-control structures. Evaluation criteria provided in

Chapter 5 of ACI 349.3R-96 provides acceptance criteria (including

quantitative criteria) for determining the adequacy of observed aging

effects and specifies criteria for further evaluation.

36) Non-EQ Program is new. A.1.2.35 Prior to the

Electrical The Non-EQ Electrical Cables and Connections Visual Inspection Program period of

Connections is credited with detecting aging effects from adverse localized environments ertin.

Visual in non-EQ cables and connections at SSES. operation. Visual

Inspection The program is applicable to non-EQ cables and connections found in the

Program Reactor Buildings, Circulating Water Pumphouse and Water Treatment

Building, Control Structure, Diesel Generator Buildings, Turbine Building,

A-14
Table A-1 SSES License Renewal Commitments

UFSAR Enhancement

Item Number Commitment Supplement or

Location Implementation

(LRA App. A) Schedule

Engineered Safeguards Service Water Pumphouse, and various yard

structures (manholes, duct banks, valve vaults, instrument pits, etc.). This

program is also applicable to the cables and connections within the scope

of license renewal located in the yard areas and control cubicles of the T10

230 kV Switchyard, the 500 kV Switchyard, and the 230 kV Switchyard.

37) Non-EQ Cables Program is new. A.1.2.34 Prior to the

and The Non-EQ Cables and Connections Used in Low-Current Instrumentation period of

Used in Low- Circuits Program is credited with identifying aging effects for sensitive, high- operation.

Current voltage, low-current signal applications that are in-scope for license renewal

at SSES. These sensitive circuits are potentially subject to reduction in Instrumentation insulation resistance (IR) when found in adverse localized environments.

Circuits

Program

38) Non-EQ Program is new. A. 1.2.36 Prior to the Inaccessible Mediu period of le The Non-EQ Inaccessible Medium-Voltage Cables Program involves two extended

Medium-Voltage parts: first, the actions to inspect the applicable plant manholes (and to

Cables Program drain them, if necessary) on a periodic basis; and second, the development operation.

of a testing program to confirm that the conductor insulation on the

applicable cables is not degrading.

This program applies to six cables associated with the offsite power supply

for SSES. These are the only inaccessible medium-voltage cables at SSES

that are within the scope of license renewal and are exposed to significant

moisture simultaneously with significant voltage.

A-15
Table A-1

SSES License Renewal Commitments

UFSAR Enhancement

Item Number Commitment Supplement or

Location Implementation

(LRA App. A) Schedule

39) Metal-Enclosed Program is new. A.1.2.32 Prior to the

Bus Inspection The Metal-Enclosed Bus Inspection Program is credited with detecting period of

Program aging effects for in-scope metal-enclosed bus at SSES. The applicable extended

components for the metal-enclosed bus will be listed in the program operation.

implementing document(s), with their locations specified, as appropriate.

The in-scope bus is limited to non-segregated metal-enclosed bus in the

13.8 kV and 4 kV electrical systems associated with the off-site power

supply at SSES.

40) Area-Based Program is a new one-time inspection. A.1.2.1 Within the 10-

NSAS The Area-Based NSAS Inspection includes confirming the environmental year period prior

Inspection and/or internal surfaces conditions of subject nonsafety-related carbon extended

steel (includes low alloy steel), cast iron, copper alloy and stainless steel exte n .

components in systems that (frequently or continuously during normal plant operation.

operations) contain raw water, potable water, non-radioactive

equipment/area drainage water, or in some select cases, treated water.

The program is plant-specific.

41) Leak Chase The existing program is credited. A.1.2.27 Ongoing Channel Moningl The program is plant-specific. Monitoring

Activities

A-16
Table A-1

SSES License Renewal Commitments

UFSAR Enhancement

Item Number Commitment Supplement or

Location Implementation

(LRA App. A) Schedule

42) Maintenance 

Preventive Existing program is credited with the following enhancements: A.1.2.39 Prior to the

Mactiintienc period of - Include a specific step to perform a visual inspection of the RCIC erioded

Activities - triecsn.extended

RCIC/HPCI turbine casing. operation. Turbine • Add requirements to have inspections performed by qualified personnel

Casings using VT-3 or equivalent inspection methods, and to document and

trend inspection results.

0 Establish specific acceptance criteria for inspection results.

The program is plant-specific.

43) Fatigue Existing program is credited with the following enhancements: A.1.2.49 Prior to the

e Fatigue Mperiod of

Program Provisions will be made in the Fatigue MoniProgram rogram to validate extended

that components which have satisfied ASME Section III, Paragraph operation.

N-415.1 requirements (i.e., RPV nozzles N6A, N6B, and N7) continue

to satisfy these requirements prior to and during the period of extended

operation, thereby allowing fatigue to be continued to be addressed

under N-415.1.

The Fatigue Monitoring Program will be enhanced to ensure that the

fatigue usage at all monitored locations, including those locations that

account for the effect of the reactor water environment, is managed

such that an adequate margin against fatigue cracking is maintained.

PPL will implement one or more of the following actions, if fatigue

usage at a monitored location, including any location that accounts for

the effect of the reactor water environment, is projected to reach the I

A-17
Table A-1

SSES License Renewal Commitments

UFSAR Enhancement

Item Number Commitment Supplement or

Location Implementation

(LRA App. A) Schedule

43) Fatigue design basis limit prior to the end of the period of extended operation:

Monitoring 1. Further refinement of the fatigue analyses to lower the CUFs to

Program less than the allowable;

(cont'd)

2. Repair of the affected components;

3. Replacement of the affected components;

4. Management by an inspection program that has been reviewed and

approved by the NRC.

" The Fatigue Monitoring Program will be enhanced to include the review

of Class 1 valve fatigue analyses and other fatigue-related TLAA, such

as flued head analyses and high energy line break evaluations, when

sufficient fatigue accumulation has occurred, to determine if additional

actions are required to address fatigue-related concerns.

* The Fatigue Monitoring Program will be enhanced to include fatigue

monitoring of the additional locations required to bound the limiting

locations applicable to SSES, as identified in NUREG/CR-6260.

* The Fatigue Monitoring Program will be enhanced to establish

monitoring criteria to ensure that the fatigue usage at all monitored

locations, including those locations that account for the effect of the

reactor water environment, is managed such that design basis limits

are not exceeded during the period of extended operation.

The Fatigue Monitoring Program will define specific fatigue usage

values for all monitored locations that, if reached, will require further

action. These fatigue usage values shall be conservatively set to

A-18
Table A-1

SSES License Renewal Commitments

UFSAR Enhancement

Item Number Commitment Supplement or

Location Implementation

(LRA App. A) Schedule

values that will allow for not less than 4 years of additional plant

operation before the actual fatigue usage at any location would reach

the design basis limit. Upon reaching the defined usage at a location,

the Fatigue Monitoring Program will require an action request to be

generated. The action request will require further engineering

evaluation to resolve the issue.

44) Environmental Existing program is credited. A.1.3.4 Ongoing Qualification Qualification For those EQ components that do not show a minimum 60-year life, the EQ

(EQ) Program Program will ensure qualified life is not exceeded by directing

refurbishment, replacement, or reanalysis to extend the qualification.

45) Closed Cooling Existing program is credited. A.1.2.13 Ongoing.

Water

Chemistry

Program

46) Fire Water Existing program is credited with the following enhancements: A. 1.2.19 Prior to the

System 0 The Fire Water System Program will be revised to incorporate sprinkler period of

Program head sampling/replacements, in accordance with NFPA 25. extended

operation.

0 The Fire Water System Program will be revised to incorporate ultrasonic

testing of representative above ground portions of water suppression

piping that are exposed to water but which do not normally experience

flow, are associated with a dry-pipe sprinkler system and may contain

stagnant water, or is pre-action or deluge piping that is normally dry but

may have been wetted and not completely dried.

A-19
Table A-1

SSES License Renewal Commitments

UFSAR Enhancement

Item Number Commitment Supplement or

Location Implementation

(LRA App. A) Schedule

* Perform at least one visual inspection (opportunistic or focused) of the

internal surface of buried fire water piping, within the 10 year period

prior to the period of extended operation.

* Perform at least one inspection per year of 'wet' fire protection piping for

wall thickness and pipe blockage, if no opportunistic inspection has

been completed.

47) Fuel Oil Existing program is credited. A.1.2.21 Ongoing

Chemistry

Program

48) Lubricating Oil Existing program is credited with the following enhancements: A.1.2.28 Prior to the

ing Oil Aperiod of

Program The Lubricating Oil Analysis Program will be enhanced to includeed

sampling of the lubricating oil from the Control Structure Chiller and extend

Diesel Engine Driven Fire Pump when the oil is changed. The oil will be operation.

tested for water and for particle count.

The Lubricating Oil analysis Program will be revised to include sampling

of the lubricating oil from the Reactor Building Chiller when the oil is

changed. The oil will be tested for water and particle count.

49) Lubricating Oil Program is a new one-time inspection. A.1.2.29 Within the 10-

Inspection The Lubricating Oil Inspection detects and characterizes the condition of year period prior

materials in systems and components for which the Lubricating Oil Analysis to the period of

Program is credited with aging management. The inspection provides extended

I I Ioperation.

A-20
Table A-1

SSES License Renewal Commitments

UFSAR Enhancement

Item Number Commitment Supplement or

Location Implementation

(LRA App. A) Schedule

direct evidence as to whether, and to what extent, a loss of material or a

reduction in heat transfer due to fouling has occurred.

50) Non-EQ Program is new. A.1.2.37 Prior to the

Electrical Cable The non-EQ Electrical Cable Connections Program manages the aging for period of Connections extended Program the metallic parts of non-EQ electrical cable connections within the scope of operation.

license renewal. The program addresses cable connections that are used

to connect cable conductors to other cables or electrical devices. Aging

management for the metallic parts of the non-EQ electrical cable

connections that are subject to aging stressors will be provided by testing.

51) New P-T Revised Pressure-Temperature (P-T) limits will be submitted to the NRC for A.1.3.1.4 Ongoing

Curves approval when necessary to comply with 10 CFR 50 Appendix G.

52) OE Review at Perform an Operating Experience (OE) review for the period of operation at Prior to the

EPU Conditions EPU conditions and its impact on aging management programs for period of

systems, structures and components (SSCs). extended

operation.

53) Incorporate Incorporate FSAR Supplement into the SSES FSAR as required by 10 A.1.1 Following

FSAR CFR 54.21(d). issuance of the

Supplement renewed

operating

licenses.

54) Re-apply for PPL will process a relief request for circumferential vessel shell weld A. 1.3.1.5 Prior to the

relief request volumetric examinations for the period of extended operation. period of

extended

operation.

A-21
Table A-1

SSES License Renewal Commitments

UFSAR Enhancement

Item Number Commitment Supplement or

Location Implementation

(LRA App. A) Schedule

55) CorePlate Hold PPL will either (1) obtain NRC approval of a SSES plant-specific evaluation A.1.3.6.3 Prior to the

Down Bolts consistent with BWRVIP-25 to demonstrate that the core plate rim hold- period of

down bolts will be capable of preventing lateral displacement of the core extended

plate for the period of extended operation (the plant-specific evaluation will operation.

be submitted for NRC review no less than 2 years prior to the period of

extended operation and will address the inspection strategy for the holddown bolts) or (2) install core plate wedges to structurally replace lateral

load resistance provided by the bolts.

56) BWRVIP-76 PPL will address any future conditions, requirements, or limitations A. 1.3.6.4 Prior to the

imposed by the NRC's safety evaluation for license renewal for BWRVIP- period of

76. extended

operation.

57) Preventative Existing program is credited with the following enhancement: A.1.2.50 Prior to the Maintenance period of Activities-Main c Specify that the inspection of the high-pressure turbine shell will consist extended

Turbine Casing of a visual inspection (VT-3 or equivalent) of accessible surfaces and operation.

an ultrasonic examination of selected locations for wall thickness.

The program is plant-specific.

58) Activities in Activities credited in the SSES response to NRC Generic Letter 88-14 will Ongoing

Response to be continued throughout the period of extended operation.

NRC Generic

Letter 88-14

A-22
Table A-1

SSES License Renewal Commitments

UFSAR Enhancement

Item Number Commitment Supplement or

Location Implementation

(LRA App. A) Schedule

59) Fuse Holders Program is new. A.1.2.51 Prior to the

Program The Fuse Holders Program is credited with identifying increased connection period of

resistance between the fuse holder metallic clamp and fuse due to fatigue extended

of the metallic clamp. The program provides for periodic inspection of fuse operation.

holder clamps within the scope of license renewal that are not in enclosures

containing active components and whose fuses are scheduled for removal

once every 12 months, or more frequently.

60) Activities in PPL will either (1) implement fatigue monitoring software that satisfactorily Prior to the

Response to addresses all issues raised in the proposed Regulatory Information period of

NRC Concerns Summary (RIS 2008-30), "Fatigue Analysis of Nuclear Power Plant extended

Regarding Components,", or (2) perform a confirmatory ASME Code, Section III operation.

Fatigue fatigue evaluation for the SBF-monitored locations to justify the existing

Analyses FatiguePro methodology used at SSES Units 1 and 2.

61) Boral Coupon Spent fuel pool Boral coupon testing will be continued in the period of Revise the

Testing extended operation with one set of coupons being tested during the tenth FSAR prior to

or eleventh year after Unit 1 enters the period of extended operation. the period of

SSES FSAR section 9.1.2.3.3 Inservice Inspection will be revised to extended

identify the coupon testing schedule during the period of extended operation, with

operation. SSES FSAR section 9.1.2.3.3.2 Test Coupon Inspection will coupon testing

be revised to require neutron attenuation testing as part of the inspection ongoing as

of test coupons removed from the spent fuel pool. indicated.

A-23

Appendix B

APPENDIX B

CHRONOLOGY

This appendix lists chronologically the routine licensing correspondence between the staff of

the United States (US) Nuclear Regulatory Commission (NRC) (the staff) and PPL

Susquehanna, LLC (PPL). This appendix also lists other correspondence on the staff's review

of the Susquehanna Steam Electric Station (SSES), Units 1 and 2 license renewal application

(LRA) (under Docket Nos. 50-387 and 50-388).

APPENDIX B: CHRONOLOGY

Date Subject

09/13/2006 Letter from McKinney B T, PPL Susquehanna, LLC, NRC/Document

Control Desk

NRC/NRR, "Susquehanna Steam Electric Station, Units 1 and 2,

License Renewal Application ", (ML062620157)

09/20/2006 Press Release, NRC/OPA, "Press Release-06-115: NRC Announces

Availability of License Renewal Application for Susquehanna Steam

Electric Station, Units 1 and 2," (ML062630232)

09/26/2006 Federal Register Notice

Letter, from Gillespie F P, NRC/NRRIADRO/DLR, to McKinney B T,

PPL Susquehanna, LLC, "Receipt and Availability of the License

Renewal Application for the Susquehanna Steam Electric Station.,"

,(ML062690158)

10/11/2006 Letter

Technical Specification, Bases Change

Technical Specifications, from McKinney B T, PPL Susquehanna,

LLC, NRC/Document Control Desk

NRC/NRR, "Susquehanna, Proposed License Amendment Numbers

285 for Unit 1 And 253 for Unit 2, Constant Pressure Power Uprate,"

(ML062900160)

10/26/2006 Federal Register Notice

Letter, from Gillespie F P, NRC/NRR/ADRO/DLR, to McKinney B T,

PPL Susquehanna, LLC, "Determination of Acceptability and

Sufficiency for Docketing, Proposed Review Schedule, and Opportunity

for a Hearing Regarding the Application from PPL Susquehanna, LLC.,

for renewal of the Operating Licenses for the Susquehanna Steam

Electric Station," (ML062930293)

10/31/2006 Press Release, NRC/OPA, "Press Release-06-138: NRC Announces

Opportunity to Request a Hearing on License Renewal Application for

Susquehanna Nuclear Power Plant.," (ML063040604)

B-1
APPENDIX B: CHRONOLOGY

Date Subject

11/02/2006 Federal Register Notice, Meeting Agenda

Meeting Notice, from Mullins A, NRC/NRR/ADRO/DLR/REBB, to

Franovich R L, NRC/NRRIADRO/DLR/REBB, "11/15/2006 Notice of

Forthcoming Meeting to Discuss the License Renewal Process and

Environmental Scoping for Susquehanna Steam Electric Station,

License Renewal Application Review" (ML06299001 0)

11/02/2006 Letter, from McKinney B T, PPL Susquehanna, LLC, NRC/Document

Control Desk, NRC/NRR, "Susquehanna, Units 1 and 2, Acceptability

and Sufficiency for Docketing - Application for Renewed Operating

Licenses Numbers NPF-14 and NPF-22.," (ML063130413)

11/06/2006 Press Release, NRC/OPA/RGN-I/FO, "Press Release-l-06-058: NRC

To Discuss Process For Review of License Renewal Application For

Susquehanna Nuclear Plant, Seeks Environmental Input"

(ML063100410)

11/15/2006 Meeting Agenda, NRC/NRR, "Susquehanna Steam Electric Station

11/15/06 Environmental Scoping Meeting Agenda and Open House

Welcome" (ML063240148)

11/15/2006 Slides and Viewgraphs, NRC/NRR, "Susquehanna Steam Electric

Station 11/15/06 Environmental Scoping Meeting Slide Handouts"

_ML063240150)

01/02/2007 Legal-Intervention Petition, Responses and Contentions, from Epstein

E J, - No Known Affiliation, NRC/SECY/RAS, "2007/01/02-

Susquehanna- Legal-Intervention Petition Re: PPL Susquehanna LLC

Application for Susquehanna Steam Electric Station's Renewed

Operating Licenses " (ML070170485)

01/10/2007 Legal-Intervention Petition, Responses and Contentions, from Epstein

E J, - No Known Affiliation, NRC/SECY, "2007/01/10- SusquehannaEmail from Eric Epstein re: Service to Parties the supplemental filing

relating to SAMA requirements " (ML070310330)

01/12/2007 Legal-Hearing Request Referral Memorandum, from Vietti-Cook A L,

NRC/SECY, to Hawkens E R, NRC/ASLBP, "2007/01/12-

Memorandum fo the Secretary referring the intervention petition of Eric

Joseph Espstein submitted for intervention in the Susquehanna

License Renewal proceeding to the ASLBP," , (ML070170135)

01/13/2007 Rulemaking-Comment, from Epstein E, Three Mile Island Alert, Inc.,

NRC/SECY/RAS, "2007/01/13-Comment (1) submitted by Three Mile

Island AlertI Inc., Eric Epstein on Massachusetts Attorney General's

PRM-51-10 re to Amend 10 CFR Part 51 "(ML070180478)

01/23/2007 Legal-Order, from Young A M, NRC/ASLBP, "2007/01/23 -LB

ORDER (Regarding Schedule and Guidance for Proceedings),",

(ML070230569)

B-2
APPENDIX B:. CHRONOLOGY-.

Date, Subject

01/29/2007 Legal-Intervention Petition, Responses and Contentions, from

Barkman M L

Martin J C, NRC/OGC, NRC/ASLBP, "2007/01/29 - Susquehanna -

NRC Staff Response to Eric Joseph Epstein's Petition for Leave to

Intervene, Request for Hearing and Contentions" (ML070300052)

01/29/2007 Legal-Intervention Petition, Responses and Contentions, from Lewis D

R, Pillsbury, Winthrop, Shaw, Pittman, LLP

PPL Susquehanna, LLC, NRC/ASLBP, "2007/01/29 - Susquehanna -

PPL Susquehanna's Answer to Eric Epstein's Petition for Leave to

Intervene" (ML070360282)

01/31/2007 Legal-Report, from Epstein E J, Three Mile Island Alert, Inc,

NRC/ASLBP, "2007/01/31 - Susquehanna - Notice of Related Filing by

Three Mile Island Alert Incorporated, submitted by Eric Joseph Epstein

,, (ML070370621)

02/05/2007 Legal-Intervention Petition, Responses and Contentions, from Epstein

E J, - No Known Affiliation, NRC/ASLBP, "2007/02/05 - Susquehanna

- Eric Joseph Epstein's Response to PPL Susquehanna's Answer and

Petitioners Response to NRC Staffs Response for leave to Intervene,

Request for Hearing, and Contentions" (ML070510363)

02/05/2007 Legal-Motion, from Epstein E J, - No Known Affiliation, NRC/ASLBP,

"2007/02/05- Susquehanna - Eric Joseph Epstein's Motion to Compel

PPL Susquehanna, LLC to: (1) Apply for a Direct License Transfer (Or

Incorporate Modifications from an NRC Approved Transfer Into the

Relicensing Application)" (ML070470585)

02/13/2007 Legal-Motion, from Lewis D R, Pillsbury, Winthrop, Shaw, Pittman,

LLP

PPL Susquehanna, LLC, NRC/ASLBP, "2007/02/13- Susquehanna -

PPL Susquehanna's Motion to Strike Portions of Eric Epstein's

Response to Answers, to Petition to Intervene " (ML070520456)

02/15/2007 Legal-Motion, 'from Martin J C, NRC/OGC, "2007/02/15 -

Susquehanna - NRC Staff Response to Eric Joseph Epstein's Motion

to Compel and Request for Schedular Exemption,", (ML070510031)

02/23/2007 Legal-Intervention Petition, Responses and Contentions, from Epstein

E J, - No Known Affiliation, NRC/ASLBP, "2007/02/23- Susquehanna -

Eric Joseph Epstein's Response to PPL Susquehanna's Motion to

Strike Portions of Eric Epstein's Response to Answers to Petition to

Intervene" (ML070610194)

02/28/2007 Legal-Order, from Young A, NRC/ASLBP, "2007/02/28-LB Order

(Scheduling Telephone Conference)," (ML070590643)

03/02/2007 Inspection Plan

Letter, from Gray M, NRC/RGN-l/DRP/PB4, to McKinney B T, PPL

Susquehanna, LLC, "Annual Assessment Letter - Susquehanna Steam

Electric Station (Report 05000387/2007001 and 05000388/2007001),"

(ML070610580)

B-3
APPENDIX B: CHRONOLOGY

Date 'Subject

03/20/2007 Letter

Request for Additional Information (RAI), from Sanabria Y D,

NRC/NRR/ADRO/DLR/RLRA, to McKinney B T, PPL Susquehanna,

LLC, "Request for Additional Information for the Review of the

Susquehanna Steam Electric Station, Units 1 and 2, License Renewal

Application," (ML070720456)

03/20/2007 Legal-intervention Petition, Responses and Contentions, from Epstein

E J, - No Known Affiliation, NRC/ASLBP, "2007/03/20 - Susquehanna

- Eric Joseph Epstein's Response to the NRC Staff's Motion to Strikes

Portions of Eric Joseph Epstein Response to the Atomic Safety

Licensing Board Panel's Request for Information." (ML070930609)

03/22/2007 Legal-Memorandum and Order, from Lathrop H K

Sager W, Young A, NRC/ASLBP, "2007/03/22-LB Memorandum and

Order (Ruling on Standing and Contentions of Petitioner Eric Joseph

Epstein) (LBP-07-04)," (ML070820022)

04/17/2007 Press Release, NRC/OPA/RGN-I/FO, "Press Release-l-07-020: NRC

To Discuss 2006 Assessment For Susquehanna Nuclear Plant At

-Public Meeting Scheduled For April 24.," (ML071070494)

04/17/2007 Letter, from McKinney B T, PPL Susquehanna, LLC, NRC/Document

Control Desk

NRC/NRR, "Susquehanna Steam Electric Station - Application for

Renewed Operating Licenses in Response to Scoping and Screening

RAI's.," (ML071140385)

04/27/2007 Letter

Schedule and Calendars, from Diaz-Sanabria Y K,

NRC/NRRPADRO/DLRIRLRA, to McKinney B T, PPL Susquehanna,

LLC, "Revision of Schedule for the Conduct of the Review of the

Susquehanna Steam Electric Station, Units 1 and 2, License Renewal

Application," (ML071000062)

05/11/2007 Legal-Intervention Petition, Responses and Contentions, from Epstein

E J, - No Known Affiliation, NRC/SECY/RAS, "Petition to Intervene

with Respect to the Proposed Amendment Request for a Thermal

Power Increase for the Susquehanna Steam Electric Station, Units 1

and 2," , (ML071430580)

05/16/2007 Letter Request for Additional Information (RAI), from Sanabria Y K,

NRC/NRR/ADRO/DLRPRLRA, to McKinney B T, PPL Susquehanna,

LLC, "Requests for Additional Information (RAI 4.1.3) for the Review of

the Susquehanna Steam Electric Station, Units 1 and 2, License

Renewal Application" (ML071270018)

06/12/2007 Letter, from McKinney B T, PPL Susquehanna, LLC, NRC/Document

Control Desk

NRC/NRR, "Susquehanna Steam Electric Station, Application for

Renewed Operating Licenses Numbers NPF-14 and NPF-22,

Requests for Additional Information (RAI 4.1.3) " (ML071760100)

B-4
-APPENDIX1B: CHRONOLOGY

Dateb. Subject

06/15/2007 Meeting Summary Note to File, Telcon Record, Verbal Comm

Request for Additional Information (RAI), from Diaz-Sanabria Y,

NRC/NRR/ADRO/DLRIRLRA, PPL Susquehanna, LLC, "Summary of

Telephone Conference Call Held on, May 29, 2007, Between the U.S.

Nuclear Regulatory Commission and PPL Susquehanna, LLC,

Concerning Requests for Additional Information Pertaining to the

Susquehanna Steam Electric Station, Units 1 and 2, LRA"

(ML071510549)

06/15/2007 Letter, from McKinney B T, PPL Susquehanna, LLC, NRC/Document

Control Desk

NRC/NRR, "Susquehanna Steam Electric Station, Application for

Renewed Operating Licenses, Responses to Environmental Audit

Questions" (ML071790414)

06/22/2007 Letter Request for Additional Information (RAI), from Diaz-Sanabria Y

K, NRC/NRRIADRO/DLR/RLRA, to McKinney B T, PPL

Susquehanna, LLC, "Requests for Additional Information for the

Review of the Susquehanna Steam Electric Station, Units 1 and 2,

License Renewal Application "(ML071710542)

06/28/2007 Memoranda

Safety Evaluation Report, from Auluck R C,

NRC/NRRPADRO/DLR/RLRB, to Lund A L,

NRC/NRR/ADRO/DLR/RLRA, "Scoping and Screening Draft Safety

Evaluation Report Input Regarding the PPL Susquehanna, LLC,

Application for the Susquehanna Steam Electric Station, Units 1 and 2

Dated September 13, 2006" (ML071790336)

07/12/2007 Letter, from Lund A L, NRC/NRR/ADRO/DLRIRLRA, to McKinney B

T, PPL Susquehanna, LLC, "Project Manager Change for the License

Renewal Environmental Review for Susquehanna Steam Electric

Station, Units 1 and 2, (TAC Nos. MD3021 and MD3022)"

(ML071920034)

07/24/2007 Letter, from McKinney B T, PPL Susquehanna, LLC, NRC/Document

Control Desk

NRC/NRR, "Susquehanna, Response to Request for Additional

Information in Regard to Application for Renewed Operating Licenses

NPF-14 and NPF-22 " (ML072200268)

07/25/2007 Letter, from Gettys E H, NRC/NRR/ADRO/DLR/RLRA, to McKinney B

T, PPL Susquehanna, LLC, "Revision of Schedule for the Conduct of

Review of the Susquehanna Steam Electric Station, Units 1 and 2,

License Renewal Application,", (ML071920267)

07/25/2007 Letter

Request for Additional Information (RAI), from Gettys E H,

NRC/NRR/ADRO/DLR/RLRA, to McKinney B T, PPL Susquehanna,

LLC, "Requests for Additional Information for the Review of the

Susquehanna Steam Electric Station, Units 1 and 2, License Renewal

Application (RAI 2.2-1 - 2.3.2.6-5)" (ML071970085)

B-5
APENIXB: CHRONO1LOGY`-,

b ate... ubet

07/30/2007 Letter

Request for Additional Information (RAI), from Gettys E H,

NRC/NRR/ADRO/DLR/RLRA, to McKinney B T, PPL Susquehanna,

LLC, "Request for Additional Information for the Review of the

Susquehanna Steam Electric Station, Units 1 and 2, License Renewal

Application (RAI 2.5-1 to RAI 2.5-2),", (ML071970114)

08/03/2007 Letter

Request for Additional Information (RAI), from Gettys E,

NRC/NRR/ADRO/DLRIRLRA, to McKinney B T, PPL Susquehanna,

LLC, "Requests for Additional Information for the Review of the

Susquehanna Steam Electric Station, Units 1 and 2, License Renewal

Application RAI section 2.4" (ML072120507)

08/23/2007 Letter, Request for Additional Information (RAI), from McKinney B T,

PPL Susquehanna, LLC, NRC/Document Control Desk

NRC/NRR, "Susquehanna Steam Electric Station, Units 1 and 2,

Response to NRC Requests for Additional Information for Review of

License Renewal Application (LRA) Sections 2.2 & 2.3"

(ML072480272)

08/23/2007 Letter, from McKinney B T, PPL Susquehanna, LLC, NRC/Document

Control Desk

NRC/NRR, "Susquehanna, Units 1 & 2 - Request for Additional

Information (RAI) for the Review of the License Renewal Application

(LRA) Section 2.5 PLA-6261 "(ML072540680)

08/27/2007 Letter, Meeting Summary, from Gettys E,

NRC/NRRIADRO/DLRIRLRA, "Summary of Telephone Conference

Call Held on July 26, 2007, Between the U.S. Nuclear Regulatory

Commission and PPL Susquehanna, LLC, Concerning Draft Requests

for Additional Information Pertaining to the Susquehanna Steam

Electric Station, Units 1 and 2 " (ML072330167).

08/27/2007 Letter, Request for Additional Information (RAI), from Gettys E H,

NRC/NRRIADRO/DLR/RLRA, to McKinney B T, PPL Susquehanna,

LLC, "Requests for Additional Information for the Review of the

Susquehanna Steam Electric Station, Units 1 and 2, License Renewal

Application "(ML072330234)

08/27/2007 Memoranda, Request for Additional Information (RAI), from Gettys E

H, NRC/NRRJADRO/DLRPRLRA, PPL Susquehanna, LLC, "Summary

of Telephone Conference Call Held on August 16, 2007, Between the

US NRC and PPL Susquehanna, Concerning Request for Additional

Information Pertaining to the Susquehanna, Units 1 and 2, License

Renewal Application " (ML072330414)

08/28/2007 Letter, from McKinney B T, PPL Susquehanna, LLC, NRC/Document

Control Desk

NRC/NRR, "Requests for Additional Information for the Review of the

Susquehanna Steam Electric Station Units 1 & 2, License Renewal

Application (LRA) Section 2.4" (ML072490210)

B-6
APPENDIX B: -CHRONOLOGY-ý-

* bat~;S'ubject

09/05/2007 Letter, Request for Additional Information (RAI), from Gettys E H,

NRC/NRRIADRO/DLR/RLRA, to McKinney B T, PPL Susquehanna,

LLC, "Requests for Additional Information for the Review of the

Susquehanna Steam Electric Station, Units 1 and 2, License Renewal

Application " (ML072360229)

09/07/2007 Letter, Meeting Summary, from Gettys E,

NRC/NRRJADRO/DLR/RLRA, PPL Susquehanna, LLC, "Summary of

Telephone Conference Call Held on August 23, 2007, Between the •

U.S. Nuclear Regulatory Commission and PPL Susquehanna,. LLC,

Concerning Draft Requests for Additional Information Pertaining to the

Susquehanna Steam Electric Station, Units 1 & 2 " (ML072360232)

09/12/2007 Letter, from McKinney B T, PPL Susquehanna, LLC, NRC/Document

Control Desk

NRC/NRR, "Susquehanna, Units 1 and 2, Annual Amendment to the

Application for Renewed Operating License Numbers NPF-14 and

NPF-22 Pursuant to 10 CFR 54.21(b)" (ML072640347)

09/17/2007 Letter, Request for Additional Information (RAI), from Gettys E H,

NRC/NRRIADRO/DLRIRLRA, to McKinney B T, PPL Susquehanna,

LLC, "Requests for Additional Information for the Review of the

Susquehanna Steam Electric Station, Units 1 and 2, License Renewal

Application" (ML072490602)

09/18/2007 Meeting Summary, Request for Additional Information (RAI), from

Gettys E, NRC/NRR/ADRO/DLRIRLRA, PPL Susquehanna, LLC,

"08/28/2007 and .09/05/2007 Summary of Telephone Conference Calls

Between the U.S. Nuclear Regulatory Commission and PPL

Susquehanna, LLC, Concerning D-RAI "(ML072490046)

09/18/2007 Letter, Request for Additional Information (RAI), from Gettys E H,

NRC/NRRIADRO/DLR/RLRA, to McKinney B T, PPL Susquehanna,

LLC, "Request for Additional Information for the Review of the,

Susquehanna Steam Electric Station, Units 1 and 2, License Renewal

Application RAI 4.7.1 "(ML072490110)

09/20/2007 Letter, from McKinney B T, PPL Susquehanna, LLC, NRC/Document

Control Desk

NRC/NRR, "Susquehanna Steam Electric Station Units 1 & 2, Followup to Request for Additional Information for the Review of the License

Renewal Application (LRA) Section 4.1.3" (ML072750526)

10/16/2007 Letter, from McKinney B T, PPL Susquehanna, LLC, NRC/Document

Control Desk

NRC/NRR, "Susquehanna, Units 1 and 2 - Request for Additional

Information (RAI) for the Review of the License Renewal Application

(LRA) Section 4.7.1 PLA-6289" (ML073030455)

B-7
.... ... ... <..... . . . . . . .. . .. ..... S u b je c t•.. . .. i• .

10/16/2007 Letter, from McKinney B T, PPL Susquehanna, LLC, NRC/Document

Control Desk

NRC/NRR, "Susquehanna Units 1 & 2 Request for Additional

Information (RAI) for the Review of the License Renewal Application

(LRA) Section B.2.21 "(ML073030487)

10/18/2007 Letter, from McKinney B T, PPL Susquehanna, LLC, NRC/Document

Control Desk

NRC/NRR, "Susquehanna, Units 1 and 2, Response to Request for

Additional Information Regarding Review of License Application (LRA)

Sections 4.2.3, 4.2.4, 4.2.5, 4.2.7 and 4.7.3" (ML073040282)

10/18/2007 Letter, from McKinney B T, PPL Susquehanna, LLC, NRC/Document

Control Desk

NRC/NRR, "Request for Additional Information (RAI) for the Review of

the Susquehanna Steam Electric Station Units 1 and 2, License

Renewal Application (LRA) Sections 2.2, 2.3.3, 2.3.4" (ML073120069)

10/24/2007 Meeting Summary, Note to File Telcon Record, Verbal Comm

Request for Additional Information (RAI), from Gettys E H,

NRC/NRR/ADRO/DLR/RLRA, Susquehanna Steam Electric Co,

"09/12/2007 Summary of Telephone Conference Call with PPL

Susquehanna, LLC Concerning Requests for Additional Information"

(ML072640134)

10/24/2007 Letter, from McKinney B T, PPL Susquehanna, LLC, NRC/Document

Control Desk

NRC/NRR, "Susquehanna Steam Electric Station, Requests for

Additional Information - License Renewal Application (LRA) Section

2.3.3.13 RAI Follow-Up, PLA-6296 " (ML073120062)

10/24/2007 Meeting Summary

Request for Additional Information (RAI), from Gettys E H,

NRC/NRR/ADRO/DLR/RLRA, PPL Susquehanna, LLC, "09/26/2007

Summary of Telephone Conference Call Between the NRC and PPL

Susquehanna, LLC Concerning Requests for Additional Information

Pertaining to the Susquehanna Steam Electric Station, Units 1 and 2,

License Renewal Application " (ML072760276)

10/24/2007 Letter, Request for Additional Information (RAI), from Gettys E H,

NRC/NRR/ADRO/DLR/RLRA, to McKinney B T, PPL Susquehanna,

LLC, "Requests for Additional Information for the Review of the

Susquehanna Steam Electric Station, Units 1 and 2, License Renewal

Application" (ML072850255)

11/14/2007 Letter, from McKinney B T, PPL Susquehanna, LLC, NRC/Document

Control Desk, "Susquehanna Steam Electric Station, Requests for

Additional Information - License Renewal Application (LRA) Section

12.3.1,", (ML073370551)

B-8
- APPNDIX B§:-CHRONOLOGY`

Dbate." Subjec

11/16/2007 Memoranda, Note to File, Telcon Record, Verbal Comm

Request for Additional Information (RAI), from Gettys E H, PPL

Susquehanna, LLC, "Summary of Telephone Conference Call Held on

October 3, 2007, Between the U.S. Nuclear Regulatory Commission

and PPL Susquehanna, LLC Concerning Open Items Pertaining to the

Susquehanna, Units 1 and 2, License Renewal Application"

_(ML072851 110)

12/13/2007 Memoranda Note to File, Telcon Record, Verbal Comm

Request for Additional Information (RAI), from Gettys E,

NRC/NRR/ADRO/DLR/RLRA, PPL Susquehanna, LLC, "Summary of

Telephone Conference. Call Held on 10/03/07, Between the U.S.

Nuclear Regulatory Commission and PPL Susquehanna, LLC,

Concerning Fire,", (ML072880051)

12/17/2007 Final Safety Analysis Report (FSAR)

Letter, from McKinney B T, PPL Susquehanna, LLC, NRC/Document

Control Desk

NRC/NRR, "Susquehanna, Units 1 & 2 - License Renewal Application,

Request for Additional Information, Revised FSAR Supplement

Section A. 1.3.1.7, PLA-6313 " (ML073620332)

01/03/2008 Letter, from McKinney B T, PPL Susquehanna, LLC, NRC/Document

Control Desk

NRC/NRR, "Susquehanna, Units 1 and 2, Submittal of Supplemental

Information Related to RAI 2.3.3.27-4" (ML080140264)

01/22/2008 Letter, from Gettys E, NRC/NRR/ADRO/DLR, to McKinney B T, PPL

Susquehanna, LLC, "Revision of Schedule for the Conduct of Review

of the Susquehanna Steam Electric Station, Units 1 and 2, License

Renewal Application " (ML080110291)

02/11/2008 Meeting Summary, -from Gettys E, NRC/NRR/ADRO/DLR, to

McKinney B T, Susquehanna Steam Electric Co, "Summary of

Telephone Conference Call Held on December 28, 2007, Between the

U.S. Nuclear Regulatory Commission and PPL Susquehanna, LLC,

Concerning Requests for Additional Information Pertaining to the

Susquehanna Steam Electric Station, Units 1 and 2 "(ML080140515)

05/01/2008 Letter from NRC to PPL Susquehanna, LLC Revision of Schedule for

the Conduct of Review of the Susquehanna Steam Electric Station,

Units 1 and 2 License Renewal Application, (ML080580119)

05/07/2008 Letter, from McKinney B T, PPL Susquehanna, LLC, to NRC/Document

Control "Susquehanna Steam Electric Station, Request for Additional

Information for the Review of License Renewal Application Station

Blackout Scope Addition," (ML081420028)

05/30/2008 Letter, Request for Additional Information (RAI), from Gettys E H, to

McKinney B T, PPL Susquehanna, LLC, "Susquehanna Steam Electric

Station, Units 1 and 2, Request for Additional Information, Review of

License Renewal Application.," (MI081480435)

B-9
_APPENDIX B: C-HRONOLOiGY.

Date 'Subject

06/09/2008 Letter, License-Application for Facility Operating License

(Amend/Renewal) DKT 50, from McKinney B T, PPL Susquehanna,

LLC, NRC/Document Control Desk

NRC/NRR, "Susquehanna Units 1 & 2, License Renewal Application,

Amendment to Section 4.2.2 " (ML081710132)

06/10/2008 Letter, Request for Additional Information (RAI), from Gettys E H, to

McKinney B T, PPL Susquehanna, LLC, "Request for Additional

Information for the Review of the Susquehanna Steam Electric Station,

Unit 1 and 2, LRA., Generic RAI,",(MI081540571)

06/12/2008 Letter, Request for Additional Information (RAI), from Gettys E H, to

McKinney B T, PPL Susquehanna, LLC, "Request for Additional

Information for the Review of the Susquehanna Steam Electric Station,

Unit 1 and 2, LRA" (MI081550670)

06/13/2008 Letter, Request for Additional Information (RAI), from Gettys E H, to

McKinney B T, PPL Susquehanna, LLC, "Request for Additional

Information for the Review of the Susquehanna Steam Electric Station,

Unit 1 and 2, LRA" (ML081540668)

06/13/2008 Letter, Request for Additional Information (RAI), from Gettys E H, to

McKinney B T, PPL Susquehanna, LLC, "Susquehanna Steam Electric

Station, Units 1 and 2, Request for Additional Information, Review of

License Renewal Application " (ML081410172)

06/17/2008 Letter, Request for Additional Information (RAI), from Gettys E H,

NRC/NRR/ADRO/DLR/RLRA, to McKinney B T, PPL Susquehanna,

LLC, "Susquehanna Steam Electric Station, Units 1 and 2, Request for

Additional Information, License Renewal Application " (ML081550515)

06/23/2008 Letter, Request for Additional Information (RAI), from Gettys E H,

NRC/NRPR/ADRO/DLR, to McKinney B T, PPL Susquehanna, LLC,

"Susquehanna, Units 1 and 2, Request for Additional Information,

Review of License Renewal Application " (ML081650217)

06/23/2008 Letter, Request for Additional Information (RAI), from Gettys E H,

NRC/NRR/ADRO/DLR, to McKinney B T, PPL Susquehanna, LLC,

"Request for Additional Information for the Review of the Susquehanna

Steam Electric Station, Units 1 and 2, License Renewal Application"

(ML081540622)

06/30/2008 Letter, Request for Additional Information (RAI), from Gettys E H, to

McKinney B T, PPL Susquehanna, LLC, "Request for Additional

Information for the Review of the Susquehanna Steam Electric Station,

Units 1 and 2, License Renewal Application " (ML081780094)

06/30/2008 Letter, from McKinney B T, PPL Susquehanna, LLC, to NRC/Document

Control "Susquehanna Steam Electric Station, Request for Additional

Information for the Review of License Renewal Application, Sections

B.2.11, B.2.13, B.2.16 and B.2.17 (ML081980121)

B-1 0
........ ........... PPENDIX B C HRONOLOGY". .

Date <Subject'

07/03/2008 Letter, Request for Additional Information (RAI), from Gettys E H, to

McKinney B T, PPL Susquehanna, LLC, "Susquehanna, Units 1 and 2,

Request for Additional Information, Review of License Renewal

Application" (ML081780698)

07/03/2008 Letter, Request for Additional Information (RAI), from Gettys E H, to

McKinney B T, PPL Susquehanna, LLC, "Request for Additional

Information for the Review of the Susquehanna Steam Electric Station,

Units 1 and 2, License Renewal RAI " (ML081790066)

07/08/2008 Letter, from McKinney B T, PPL Susquehanna, LLC, to NRC/Document

Control "Susquehanna Steam Electric Station, Request for Additional

Information for the Review of License Renewal Application Appendix B,

PLA-6378 " (ML082040588)

07/08/2008 Letter, from McKinney B T, PPL Susquehanna, LLC, NRC/Document

Control Desk

NRC/NRR, "Susquehanna, Units 1 & 2, Response for Additional

Information for Review of License Renewal Application (LRA) Sections

B.2.39, 3.5, & 4.6" (ML082040626)

07109/2008 Letter

Request for Additional Information (RAI), from Gettys E H,

NRC/NRR/ADRO/DLR, to McKinney B T, PPL Susquehanna, LLC,

"Request for Additional Information for the Review of the Susquehanna

Steam Electric Station, Units 1 & 2, License Renewal Application"

(ML081890503)

07/10/2008 Letter

Request for Additional Information (RAI), from Gettys E H,

NRC/NRR/ADRO/DLR, to McKinney B T, PPL Susquehanna, LLC,

"Susquehanna, Units 1 & 2, Request for Additional Information, Review

of License Renewal Application " (ML081890576)

07/14/2008 Letter, from McKinney B T, PPL Susquehanna, LLC, NRC/Document

Control Desk

NRC/NRR, "Susquehanna Units 1 & 2, Response to Request for

Additional Information for the Review of the Units 1 & 2, License

Renewal Application (LRA) Sections B.2.1, B.2.5, B.2.7, B.2.9, and

B.2.10" (ML082110399)

07/14/2008 Letter, from McKinney B T, PPL Susquehanna, LLC, NRC/Document

Control Desk

NRC/NRR, "Susquehanna, Units 1 & 2, Response to Request for

Additional Information for the Review of License Renewal Application

Sections B.2.18 and B.2.30" (ML082110400)

07/15/2008 Letter, Request for Additional Information (RAI), from Gettys E,

NRC/NRR/ADRO/DLRIRLRA, to McKinney B T, PPL Susquehanna,

LLC, "Request for Additional Information for the Review of the

Susquehanna.Electric Station, Units 1 and 2, License Renewal

Application " (ML081920575)

B-11
APPENDIX B: CHRONOLOGY.

Date Subject

07/17/2008 Letter, from McKinney B T, PPL Susquehanna, LLC, NRC/Document

Control Desk

NRC/NRR, "Susquehanna, Units 1 and 2, Response to Request for

Additional Information for the Review of License Renewal Application

(LRA) Sections B.2.2, B.2.20, and B.2.22" (ML082120075)

07/23/2008 Letter, Request for Additional Information (RAI), from Gettys E H,

NRC/NRR/ADRO/DLR, to McKinney B T, PPL Susquehanna, LLC,

"Request for Additional Information for the Review of the Susquehanna

Steam Electric Station, Units 1 and 2, License Renewal Application"

(ML081960683)

07/23/2008 Letter, Request for Additional Information (RAI), from Gettys E H,

NRC/NRR/ADRO/DLR, to McKinney B T, PPL Susquehanna, LLC,

"Request for Additional Information for the Review of the Susquehanna

Steam Electric Station, Units 1 and 2, License Renewal Application"

(ML081970397)

07/23/2008 Letter, Request for Additional Information (RAI), from Gettys E H,

NRC/NRR/ADRO/DLR, to McKinney B T, PPL Susquehanna, LLC,

"Request for Additional Information for the Review of the Susquehanna

Steam Electric Station, Units 1 and 2, License Renewal Application"

(ML081990316)

07/24/2008 Letter, from McKinney B T, PPL Susquehanna, LLC, NRC/Document

Control Desk

NRC/NRR, "Susquehanna, Units 1 and 2, Response to Request for

Additional Information for the Review of License Renewal Application

Sections B.2.19 and 3.3.2.2.6" (ML082190558)

07/25/2008 Letter, from McKinney B T, PPL Susquehanna, LLC, NRC/Document

Control Desk

NRC/NRR, "Susquehanna, Units 1 and 2, Response to Request for

Additional Information for the Review of License Renewal Application

(LRA), Sections B.2.23, B.2.24, B.2.26, B.2.27, B.2.28, B.2.31"

(ML082200292)

07/28/2008 Letter, from McKinney B T, PPL Susquehanna, LLC, NRC/Document

Control Desk

NRC/NRR, "Susquehanna, Units 1 and 2, Response to Request for

Additional Information for the Review of the License Renewal

Application Sections B.2.12 and B.2.15 " (ML082190557)

07/30/2008 Letter, Request for Additional Information (RAI), from Gettys E H,

NRC/NRR/ADRO/DLR/RLRA, to McKinney B T, PPL Susquehanna,

LLC, "Request for Additional Information for the Review of the

Susquehanna Steam Electric Station, Units 1 and 2, License Renewal

Application" (ML082100599)

B-1 2
APPENDI1X B:. CHRONOLOGYý:ý

08/01/2008 Letter, from McKinney B T, PPL Susquehanna, LLC, NRC/Document

Control Desk NRC/NRR, "Susquehanna Steam Electric Station -

Request for Additional Information for the Review of Units 1 and 2,

License Renewal Application (LRA) Sections B.3.1, 4.3, and 4.7"

(ML082250450)

08/05/2008 Letter, from McKinney B T, PPL Susquehanna, LLC, NRC/Document

Control Desk NRC/NRR, "Susquehanna, Units 1 and 2, Request for

Additional Information for the Review of the License Renewal

Application (LRA) Sections B.2.41, 6.2.42, B.2.43, B.3.2, and 3.6"

(ML082270204)

08/08/2008 Letter, from McKinney B T, PPL Susquehanna, LLC, NRC/Document

Control Desk NRC/NRR, "Susquehanna, Units 1 and 2, Response to

Request for Additional Information for the Review of the License

Renewal Application (LRA) Sections B.2.48, 3.0.3, 3.3.1 and 3.3.2"

(ML082400092)

08/12/2008 Letter, from McKinney B T, PPL Susquehanna, LLC, NRC/Document

Control Desk NRC/NRR, "Susquehanna Steam Electric Station,

Request for Additional Information for the Review of the Susquehanna

Steam Electric Station Units 1 and 2, License Renewal Application

(LRA) Sections B.2.14, B.2.25, B.2.32, and B.2.33, PLA-6400"

(ML082330526)

08/13/2008 Letter, Request for Additional Information (RAI), from Gettys E H,

NRC/NRR/ADRO/DLR, to McKinney B T, PPL Susquehanna, LLC,

"Susquehanna, Units 1 & 2, Request for Additional Information, Review

of the License Renewal Application " (ML082250477)

08/15/2008 Meeting Summary, Request for Additional Information (RAI), from

Gettys E H, NRC/NRR/ADRO/DLR, "07/25/2008 Summary of

Telephone Conference Call Between NRC and PPL Susquehanna,

LLC, Concerning Draft Request for Additional Information Pertaining to

the Susquehanna, Units 1, &2 License Renewal Application"

(ML082210375)

08/15/2008 Letter, from McKinney B T, PPL Susquehanna, LLC, NRC/Document

Control Desk, NRC/NRR, "Susquehanna, Units 1 & 2, Response to

Request for Additional Information for the Review of License Renewal

Application (LRA) Sections 3.1, 3.2, 3.3, and 3.4" (ML082400534)

08/22/2008 Letter, from McKinney B T, PPL Susquehanna, LLC, NRC/Document

Control Desk, NRC/NRR, "Susquehanna, Units 1 and 2, Response to

Request for Additional Information for the Review of the License

Renewal Application, Sections B.2.13, B.2.17, 3.x, 3.2.2, 3.3.2, and

3.5.2 " (ML082480042)

08/22/2008 Letter, from McKinney B T, PPL Susquehanna, LLC, NRC/Document

Control Desk, NRC/NRR, "Susquehanna, Units 1 and 2 - Request for

Additional Information for the Review of License Renewal Application

(LRA) Sections 3.3, B.2.6 and B.2.49.," (ML082480043)

B-1 3
APPENDIX.B: CHRONOLOGY.

,Su.bject

08/22/2008 Meeting Summary, Request for Additional Information (RAI), from

Gettys E H, NRC/NRRIDLRJRPB1, PPL Susquehanna, LLC,

"08/07/08, Summary of Telephone Conference Call Held Between the

NRC and PPL Susquehanna, LLC., Concerning Draft's Pertaining to

the Susquehanna Steam Electric Station, Units 1 & 2, License Renewal

Application.,", (ML082260181)

08/27/08 Letter, from McKinney B T, PPL Susquehanna, LLC, NRC/Document

Control Desk, Susquehanna, Units 1 &2, Response to Request for

Additional Information for the Review of the License Renewal

Application (LRA) Sections B.2.8, B.2.9, 3.1.2, 3.2.2, 3.3.2, & 3.4.2

(ML082480294)

08/29/2008 Letter, from McKinney B T, PPL Susquehanna, LLC, NRC/Document

Control Desk, NRC/NRR, "Susquehanna, Units 1 & 2, Response to

Request for Additional Information for the Review of the License

Renewal Application (LRA) Section 2.5.," (ML082610435)

09/11/2008 Letter, from McKinney B T, PPL Susquehanna, LLC, NRC/Document

Control Desk, NRC/NRR, "Susquehanna Steam Electric Station, Units

1 & 2 - Request for Additional Information for the Review of License

Renewal Application Supplemental Response to RAI's B.2.31-5 and

B.2.31-6, PLA-6419.," (ML082670889)

09/23/2008 Letter, Request for Additional Information (RAI), from Gettys E H,

NRC/NRR/DLRJRPB1, to McKinney B T, PPL Susquehanna, LLC,

"RAI for the Review of the Susquehanna Steam Electric Station, Units

1 and 2, LRA RAI on Sun (1).," (ML082530102)

09/23/2008 Letter, License-Application for Facility Operating License

(Amend/Renewal) DKT 50, from McKinney B T, PPL Susquehanna,

LLC, NRC/Document Control Desk

NRC/NRR, "Susquehanna Steam Electric Station, Units 1 & 2 - License

Renewal Application (LRA) Amendments to Sections B.2.38, B.2.39,

and B.2.47 in Response to NRC Regional Inspection PLA-6427.,"

(ML083030165)

09/26/2008 Letter, from McKinney B T, PPL Susquehanna, LLC, NRC/Document

Control Desk, NRC/NRR, "Susquehanna, Units 1 and 2, License

Renewal Application (LRA) Amendments to LRA and RAI Responses.,"

(ML082950012)

09/26/2008 Letter, from McKinney B T, PPL Susquehanna, LLC, NRC/Document

Control Desk, NRC/NRR, "Susquehanna, Units 1 & 2 - Second Annual

Amendment to the Application for Renewed Operating License

Numbers NPF-14 and NPF-22 Pursuant to 10 CFR 54.21(b), PLA-

_6429.," (ML082950013)

B-1 4
:APPENDIX B: CHRONOLOGY

Date , .Subject,

09/30/2008 Letter, License-Application for Facility Operating License

(Amend/Renewal) DKT 50, from McKinney B T, PPL Susquehanna,

LLC, NRC/Document Control Desk

NRC/NRR, "Susquehanna Units 1 & 2 - Licensee Renewal Application

Amendments to Sections 2.1.1, B.2.14, B.2.22, B.2.28, B.2.28, B.2.31,

and B.2.46 in Response to NRC Regional Inspection PLA-6428.,"

(ML082950011)

10/01/2008 Meeting Summary, Memoranda, Request for Additional Information

(RAI), from Gettys E H, NRC/NRRJDLRPRPB1, PPL Susquehanna,

LLC, "06/25/2008 Meeting Summary, Telephone Conference Call

Between the NRC and PPL Susquehanna, LLC, Concerning Draft

Request for Additional Information Pertaining to the Susquehanna,

Units 1 and 2, License Renewal Application.," (ML082260353)

10/17/2008 Letter, Request for Additional Information (RAI), from Gettys E H,

NRC/NRR/DLR/RPB1, to McKinney B T, PPL Susquehanna, LLC,

"Susquehanna, Units 1 and 2, Request for Additional Information,

Review of the License Renewal Application.," (ML082800066)

10/17/2008 Meeting Summary, Request for Additional Information (RAI), from

Gettys E H, NRC/NRRJDLR/RPB1, PPL Susquehanna, LLC,

"09/15/2008-Summary of Telephone Conference Call Between US

NRC and PPL Susquehanna, LLC, Concerning Draft Request for

Additional Information Pertaining to the Susquehanna Steam Electric

Station, Units 1 & 2, License Renewal Application.," (ML082800439)

10/17/2008 Meeting Summary, Request for Additional Information (RAI), from

Gettys E, NRC/NRRJDLRIRPB1, "09/18/2008 Meeting Summary,

Meeting Between the NRC and PPL Susquehanna, LLC., Concerning

Requests for Additional Information Responses Pertaining to the

Susquehanna Steam Electric Station, Units 1 and 2, License Renewal

Application.," (ML082820577)

10/21/2008 Meeting Summary, Memoranda, from Gettys E, NRC/NRR/DLRIRPB1,

"Summary of Telephone Conference Call Held on October 8, 2008,

Between the USNRC and PPL Susquehanna, LLC. Concerning Draft

Requests for Additional Information Pertaining to the, License Renewal

Application.," (ML082890152)

10/21/2008 Letter, from McKinney B T, PPL Susquehanna, LLC, NRC/Document

Control Desk, NRC/NRR, "Susquehanna Steam Electric Station Units 1

and 2, License Renewal Application (LRA) Amendments to Sections

B.2.13, B.2.17, B.2.20, B.2.22, B.2.28, B.2.32, and B.2.48 in Response

to NRC Regional Inspection.," (ML083181108)

10/22/2008 Letter, Request for Additional Information (RAI), from Gettys E H,

NRC/NRR/DLRIRPB1, to McKinney B T, PPL Susquehanna, LLC,

"Request for Additional Information for the Review of the Susquehanna

Steam Electric Station, Units 1 & 2, License Renewal Application.,"

,(ML082831712)

B-1 5
APPENDIXB:-CHRONOLOGY,

Date Subject

10/22/2008 Letter, from McKinney B T, PPL Susquehanna, LLC, NRC/Document

Control Desk, NRC/NRR, "Susquehanna, Units 1 and 2 - Response to

Request for Additional Information for the Review of License Renewal

Application Section B.2.12.," (ML083190019)

10/27/2008 Letter, Request for Additional Information (RAI), from Gettys E H,

NRC/NRPJDLR/RPB1, to McKinney B T, PPL Susquehanna, LLC,

"Request for Additional Information for the Review of the Susquehanna

Steam Electric Station, Units 1 and 2, License Renewal Application,"

,(ML082890340)

11/03/2008 Meeting Summary, from Gettys E, NRC/NRRIDLRJRPB1, PPL

Susquehanna, LLC, "Summary of Telephone Conference Call Held on

Sept. 24, 2008, Between the U.S. NRC and PPL Susquehanna, LLC.,

Concerning Draft Requests for Additional Information Pertaining to the

SSES, Units 1 and 2, License Renewal Application.," (ML083030591)

11/04/2008 Letter, from Spence W H, PPL Susquehanna, LLC, NRC/Document

Control Desk

NRC/NRR, "Susquehanna, Units 1 and 2 - Response to Request for

Additional Information for the Review of the License Renewal

Application (LRA) Section 3.5.2.3.10 Follow-up to PLA-6407.,"

(ML083190052)

11/04/2008 Letter, from Spence W H, PPL Susquehanna, LLC, NRC/Document

Control Desk

NRC/NRR, "Susquehanna, Units 1 and 2, Response to Request for

Additional Information for the Review of License Renewal Application,

Section B.2.12 Followup to PLA-6436.," (ML083190053)

11/11/2008 Letter, from Spence W H, PPL Susquehanna, LLC, NRC/Document

Control Desk

NRC/NRR, "Susquehanna, Units 1 & 2, Request for Additional

Information Related to License Renewal Application Sections B.2.8 and

B.2.32.," (ML083300358)

11/11/2008 Letter, from Spence W H, PPL Corp

PPL Susquehanna, LLC, NRC/Document Control Desk

NRC/NRR, "Susquehanna Steam Electric Station, Request for

Additional Information for the Review of the Susquehanna Steam

Electric Station Units 1 and 2, License Renewal Application (LRA)

Follow-Up to PLA-6398 Responses PLA-6442.," (ML083300392)

11/17/2008 Letter, License-Application for Facility Operating License

(Amend/Renewal) DKT 50, from Spence W H, PPL Susquehanna,

LLC, NRC/Document Control Desk

NRC/NRR, "Susquehanna, Units 1 & 2, License Renewal Application

I Change to Aging Management Program B.2.30.," (ML083370200)

B-1 6
A,.,PPENDIX B:,CHIRONOLOGY

Da'te Sbjc

11/17/2008 Letter, from Spence W H, PPL Corp, PPL Susquehanna, LLC,

NRC/Document Control Desk

NRC/NRR, "Susquehanna, Units 1 and 2, Request for Additional

Information for the Review of License Renewal Application, Section

B.2.1 - Questions and Responses.," (ML083370201)

11/19/2008 Meeting Summary, Note to File, Telcon Record, Verbal Comm, from

Gettys E, NRC/NRR/DLR/RPB1, "Summary of Telephone Conference

Call Held on October 10, 2008, Between the U.S. Nuclear Regulatory

Commission and PPL Susquehanna, LLC., Concerning the Responses

to Requests for Additional Information Pertaining to the Susquehanna

Steam...," (ML083220947)

11/19/2008 Meeting Summary, Memoranda, Note to File Telcon Record, Verbal

Comm, from Gettys E H, NRC/NRR/DLR/RPB1, PPL Susquehanna,

LLC, "1 1/13/2008-Summary of Telephone Conference Call Between

NRC and PPL, Concerning the Responses to RAIs Pertaining to the

Susquehanna Steam Electric Station, Units 1 and, 2, License Renewal

Application," (ML083230786)

11/24/2008 Memoranda, Request for Additional Information (RAI), from Rahimi M,

NRC/NRR/DSS/SBPB, to Pelton D L, NRC/NRR/DLR/RPB1,

"Request for Additional Information License Renewal Application for

Susquehanna Steam Electronic Station Units 1 and 2, Section 2.3.3.18

(TAC MD3019 and MD3020)," (ML083250030)

11/25/2008 Letter, License-Application for Facility Operating License

(Amend/Renewal) DKT 50, from Spence W H, PPL Corp,

NRC/Document Control Desk, NRC/NRR, "Susquehanna, Units 1 and

2 - License Renewal Application (LRA) Amendments to LRS and RAI

Responses.," (ML083440316)

11/26/2008 Letter, from Spence W H, PPL Corp, PPL Susquehanna, LLC,

NRC/Document Control Desk, NRC/NRR, "Susquehanna, Units 1 and

2 - Request for Additional Information for the Review of License

Renewal Application (LRA) Section 4.3.," (ML083500379)

11/26/2008 No Document Type Applies, PPL Corp

PPL Susquehanna, LLC, NRC/NRR, "Enclosure 1 to PLA-6441

Proprietary Response to NRC's Request for Additional Information

(RAI).," (ML083500380)

12/03/2008 Meeting Summary Memoranda, Request for Additional Information

(RAI), from Gettys E H, NRC/NRRIDLR/RPB1, PPL Susquehanna,

LLC, "11/19/2008 Meeting Summary, Telephone Conference Call

Between U.S. NRC and PPL Susquehanna, LLC, Concerning The

Draft Request For Additional Information Pertaining To The

Susquehanna Steam Electric Station Units 1 & 2, LRA.,"

(ML083310113)

B-1 7
APPENDIX B: CHRONOLOGY:

Date 'Subje~ct

12/03/2008 Letter, Request for Additional Information (RAI), from Gettys E H,

NRC/NRR/DLR/RPB1 to Spence W H, PPL Susquehanna, LLC,

"Request For Additional Information For The Review Of The

Susquehanna Steam Electric Station, Units 1 and 2, License Renewal

Application.," (ML083310144)

12/11/2008 Letter from Spence W H, PPL Corp, PPL Susquehanna, LLC,

NRC/Document Control Desk

NRC/NRR, "Susquehanna, Units 1 and 2 - License Renewal

Application Supplemental Response to RAI B.2.14-2" (ML083590280

12/12/2008 Letter from Spence W H, PPL Corp, PPL Susquehanna, LLC,

NRC/Document Control Desk

NRC/NRR, "Susquehanna, Units 1 and 2, Response to Request for

Additional Information, for Licence Renewal Application (LRA) Section

2.3.3.18.," (ML083640308)

12/12/2008 Letter, from Spence W H, PPL Corp

PPLSusquehanna, LLC, NRC/Document Control Desk

NRC/NRR, "Susquehanna Steam Electric Station - Request for

Additional Information, and License Renewal Application (LRA) Section

4.3 Supplement.," (ML083640309)

12/29/2009 Letter from Spence W H, PPL Corp

PPL Susquehanna, LLC, NRC/Document Control Desk

NRC/NRR, "Susquehanna, Units 1 and 2 - License Renewal

Application Admendment to LRA PLA-6469," (ML090220202)

01/07/2009 Press Release, NRC/OPA/RGN-I/FO, "Press Release-l-09-002: NRC

to Discuss Results of License Renewal Inspection for Susquehanna

Nuclear Power Plant on Jan. 13, 2009," (ML090070628)

01/12/2009 Letter from Spence W H, PPL Corp PPL Susquehanna, LLC,

NRC/Document Control Desk NRC/NRR, "Susquehanna Steam

Electric Station Units 1 and 2 License Renewal Application.Amendment

for Address Aging of Emergency Diesel Genreator Exhaust"

(ML090290060)

1/16/2009 Audit Report from Gettys E, NRC/NRR/DLR/RPB1, to, to Spence W

H, PPL Susquehanna, LLC, "Audit Report Regarding the

Susquehanna Steam Electric Station, Units 1 and 2 License Renewal

Application," (ML082950351)

01/26/2009 Meeting Summary, Note to File Telcon Record, Verbal Comm, from

Gettys E, NRC/NRR/DLRIRPB1, "Summary of Telephone Conference

Call Held on 01/05/2009, Between the U.S. Nuclear Regulatory

Commission and PPL Susquehanna, LLC., (MI090090340)

1/30/2009 Meeting Summary, Note to File Telcon Record, Verbal Comm, from

Gettys E, NRC/NRR/DLR/RPB1, "Summary of Telephone Conference

Call Held on 12/18/2008, Between the U.S. Nuclear Regulatory

Commission and PPL Susquehanna, LLC., (MI090080379)

B-1 8
APPENDIX .B CHONOLOGY

DateSujc

2/10/2009 Letter from Spence W H, PPL Corp PPL NRC/Document Control Desk

NRC/NRR, "Susquehanna Steam Electric Station Units 1 and 2

License Renewal Application Amendment to LRA commitment #55",

(ML090700131)

2/27/2009 Region I Inspection Report Letter from Conte R to W.H. Spence W H,

PPL Corp PPL, IR 05000387/2008007 and 05000388/2008007,

Susquehanna Steam Electric Station Units 1 and 2; License Renewal

Inspection Program, Aging Management Programs, (ML09058021 1)

4/13/2009 Letter, Request for Additional Information (RAI), from Gettys E H,

NRC/NRR/DLRIRPB1 to Spence W H, PPL Susquehanna, LLC,

"Request For Additional Information For The Review Of The

Susquehanna Steam Electric Station, Units 1 and 2, License Renewal

Application.," (MI091030296)

4/27/2009 Letter, Request for Additional Information (RAI), from Gettys E H,

NRC/NRRJDLRIRPB1 to Spence W H, PPL Susquehanna, LLC,

"Request For Additional Information For The Review Of The

Susquehanna Steam Electric Station, Units 1 and 2, License Renewal

Application.," (ML091120056)

5/07/2009 Meeting Summary Memoranda

Request for Additional Information (RAI), from Gettys E H,

NRC/NRPJDLRJRPB1, to PPL Susquehanna, LLC, "4/14/2009 Meeting

Summary, Telephone Conference Call Between U.S. NRC and PPL

Susquehanna, LLC, Concerning The Draft Request For Additional

Information Pertaining To The Susquehanna Steam Electric Station

Units I & 2, LRA.," (ML091250254)

5/13/2009 Letter, from Spence W H, PPL Corp

PPL Susquehanna, LLC, to NRC/Document Control Desk

NRC/NRR, "Susquehanna, Units 1 and 2 - Request for Additional

Information for the Review of License Renewal Application (LRA)

Section 3.3.2.2.6," fML091520031)

5/26/2009 Letter, from Spence W H, PPL Corp

PPL Susquehanna, LLC, to NRC/Document Control Desk

NRC/NRR, "Susquehanna, Units 1 and 2 - Request for Additional

Information for the Review of License Renewal Application Section

4.3," (ML091590039)

5/28/2009 Letter, from Spence W H, PPL Corp, PPL Susquehanna, LLC, to

NRC/Document Control Desk, NRC/NRR, Susquehanna, Units 1 and 2

License Renewal Application Annual Amendment to the Application for

Renewed Operation License (ML091590041)

5/28/2009 Letter, from Spence W H, PPL Corp

PPL Susquehanna, LLC, to NRC/Document Control Desk

NRC/NRR, "Susquehanna, Units 1 and 2, License Renewal Application

(LRA) Amentdment to LRA Commitment No. 61," (ML091590040)

B-1 9
..APPENDIX B: CHRONOLOGY

Date Subject6/01/2009 Meeting Summary Memoranda, from Gettys E H,

NRC/NRR/DLR/RPB1, to PPL Susquehanna, LLC, "5/21/2009 Meeting

Summary, Telephone Conference Call Between U.S. NRC and PPL

Susquehanna, LLC, Concerning The Draft Request For Additional

Information Pertaining To The Susquehanna Steam Electric Station

Units 1 & 2, LRA," (MI091480082)

7/16/09 Meeting Summary Memoranda, from Gettys E H,

NRC/NRR/DLR/RPB1, to PPL Susquehanna, LLC, "6/25/2009 Meeting

Summary, Telephone Conference Call Between U.S. NRC and PPL

Susquehanna, LLC, Comments On The Safety Evealuation Report

With Open Items Related To The Susquehanna Steam Electric Station

Units 1 & 2, LRA," (ML091910196)

7/28/2009 Letter, from Spence W H, PPL Corp

PPL Susquehanna, LLC, to NRC/Document Control Desk NRC/NRR,

"Susquehanna, Units 1 and 2, License Renewal Application,

Amendments to the LRA and RAI 3.2.2.3-1 Response" (ML092180731)

9/9/2009 Letter, from Spence W H, PPL Corp

PPL Susquehanna, LLC, to NRC/Document Control Desk NRC/NRR,

"Susquehanna, Units 1 and 2, License Renewal Application,

Amendments to the LRA #60 (ML092650288)

B-20
Appendix C

APPENDIX C

PRINCIPAL CONTRIBUTORS

This appendix lists the principal contributors for the development of this safety evaluation report

(SER) and their areas of responsibility.

Appendix C: Prncipal Contributors

~Namie~ Responsibility

R. Auluck Management Oversight

H. Ashar Structural Engineering

G. Cranston Management Oversight

J. Davis GALL Report Audit

R. Dennig Management Oversight

Y.Diaz-Sanabria Project Management

J. Dozier Management Oversight

J. Fair Mechanical Engineering

G. Galletti Scoping and Screening Methodology Audit

Q. Gan SER Support

E. Gettys Project Management

K. Green Scoping and Screening Methodology Audit

B. Holian Management Oversight

A. Hiser Management Oversight

D. Hoang GALL Report Audit

D. Harrison Management Oversight

N. Igbal Fire Protection

D. Jackson Mechanical Engineering

W. Jackson ATL

A. Johnson Mechanical Engineering

A. Klein Management Oversight

L. Lund Management Oversight

K. Manoly Management Oversight

J. Medoff GALL Report Audit

G. Meyer Regional 1 Inspection

M. Mitchell Management Oversight

D. Nguyen GALL Report Audit

E. Patel ATL

D. Pelton Management Oversight

J. Raval Ventilation System

S. Ray Electrical Engineering

D. Reddy Scoping and Screening Methodology Audit

B. Rogers Scoping and Screening Methodology Audit

A. Sallman Ventilation System

S. Sheng Vessels & Internals Integrity

E. Smith Plant Systems

G. Thomas Structural Engineering

R. Sun GALL Report Audit

G. Wilson Management Oversight

E.Wong Chemical Engineer

Z. Xi GALL Report Audit

C.Yang Mechanical Engineering

0. Yee GALL Report Audit

C-1
AppendP• C: Principal Contrlbutors, .

SName IRoespnsibility

ContractorsK

Advanced Technologies and Laboratories GALL Audit and Report

International, Inc.

Pacific Northwest National Laboratory Plant Systems

C-2
Appendix D

APPENDIX D

REFERENCES

This appendix lists the references used throughout this safety evaluation report (SER) for

review of the license renewal application (LRA) for Susquehanna Steam Electric Station,

Units 1 and 2.

1U L;I-K I10 CFR F

Plants."

art 54, "Requirements for Renewal of Operating Licenses For Nuclear Power

3. 10 CFR Part 100, "Reactor Site Criteria."

4. American Concrete Institute (ACI) 201.1 R-68, "Guide for Making a Condition Survey of

Concrete in Service."

5. ACI 201.2R "Guide to Durable Concrete"

6. ACI 301-72, "Specifications for Structural Concrete for Buildings."

7. ACI 318-71, "Building Code Requirements for Reinforced Concrete."

8. ACI 349.3R-96, "Evaluation of Existing Nuclear Safety-Related Concrete Structures."

9. American National Standards Institute (ANSI) B30.2, "Overhead and Gantry Cranes (Top

Running Bridge, Single or Multiple Girder, Top Running Trolley Hoist)."

10. ANSI B30.11, "Monorails and Underhung Cranes."

11. ANSI B30.16, "Overhead Hoists (Underhung)."

12. American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code

Section III

13. ASME Code Section XI

14. American Society for Metals International, "Metals Handbook," Ninth Edition.

15. American Society for Testing and Materials (ASTM) D2276-00, "Standard Test Method for

Particulate Contaminant in Aviation Fuel by Line Sampling,"

16. ASTM C-227, "Standard Test Method for Potential Alkali Reactivity of Cement-Aggregate

Combinations."

17. ASTM C-289, "Standard Test Method for Potential Alkali-Silica Reactivity of Aggregates

(Chemical Method)."

18. ASTM C-295, "Standard Guide for Petrographic Examination of Aggregates for Concrete."

19. BTP APCSB 9.5-1, "Guidelines for Fire Protection for Nuclear Power Plants," Appendix A,

August 23, 1976.

20. BWRVIP-14, "Evaluation of Crack Growth in BWR Stainless Steel RPV Internals," EPRI

Topical Report (TR)-105873

21. BWRVIP-27, "BWR Vessel and Internals Project, BWR Standby Liquid Control

System/Core Plat AP Inspection and Flaw Evaluation Guidelines," EPRI TR-1 07286

22. BWRVIP-29, "BWR Water Chemistry Guidelines - 1996 Revision," EPRI TR-1 03515.

23. BWRVIP-47, "BWR Lower Plenum Inspection and Flaw Evaluation Guidelines."

24. BWRVIP-48, "Vessel ID Attachment Weld and Inspection and Flaw Guidelines,"

EPRI TR-1 08724.

25. BWRVIP-49, "BWR Vessel and Internals Project, Instrument Penetration Inspection and

Flaw Evaluation Guidelines," EPRI TR-108695.

26. BWRVIP-74, "BWR Reactor Vessel Inspection and Flaw Evaluation Guidelines."

27. BWRVIP-75, "Technical Basis for Revisions to Generic Letter 88-01 Inspection Schedules."

28. BWRVIP-76, "BWR Core Shroud Inspection and Flaw Evaluation Guidelines."

D-1
DVVr-VIr"--W, DVVr- vesiu Inu irit[rrlait rruj•t,, v.radu uaruwri '•1b III irIdUlUmu

Stainless Steels in BWR Internal Components," EPRI Technical Report 1003018.

30. BWRVIP-1 00-A, "BWR Vessel and Internals Project, Updated Assessment of the Fracture

Toughness of Irradiated Stainless Steel for BWR Core Shrouds."

31. EPRI Report NSAC-202L-R2, "Recommendations for an Effective

Flow-Accelerated Corrosion Program," April 8, 1999.

32. EPRI TR-109619, "Guideline for the Management of Adverse Localized Equipment

Environments," June 1999.

33. General Electric Topical Report GE-NE-523-A71-0594, Revision 1, "Alternate

BWR Feedwater Nozzle Inspection Requirements."

34. Generic Letter (GL) 88-01, "NRC Position on IGSCC in BWR Austenitic Stainless Steel

Piping," January 25, 1988.

35. GL 89-13, "Service Water System Problems Affecting Safety-Related Equipment," July 18,

1989.

36. GL 2007-01, "Inaccessible or Underground Power Cable Failures that Disable Accident

Mitigation Systems or Cause Plant Transients," February 7, 2007.

37. IEEE Std. P1205-2000. "IEEE Guide for Assessing, Monitoring an Mitigating Aging Effects

on Class 1 E Equipment Used in Nuclear Power Generating Stations."

38. IN 87-69, "Lessons Learned from Regional Inspections of Licensee Actions in Response to

IE Bulletin 80-11," December 31, 1987.

39. Information Notice (IN) 94-63, "Boric Acid Corrosion of Charging Pump Casing Caused by

Cladding Cracks," August 30, 1994.

40. IN 97-46, "Unisolable Crack in High-Pressure Injection Piping," July 9, 1997.

41. IN 2002-12, "Submerged Safety-Related Electrical Cables," March 21, 2002.

42. NUREG-0313, Revision 2, "Technical Report on Material Selection and Processing

Guidelines for BWR Coolant Pressure Boundary Piping," January 1988.

43. NUREG-0612, "Control of Heavy Loads at Nuclear Power Plants," July 1980.

44. NUREG-0619, Revision 1, "BWR Feedwater Nozzle and Control Rod Driven Return Line

Nozzle Cracking," November 1980

45. NUREG-0776, "Safety Evaluation Report Related to the Operation of Susquehanna Steam

Electric Station, Units 1 and 2," April 1981.

46. NUREG-1 339, "Resolution of Generic Safety Issue 29: Bolting Degradation or Failure in

Nuclear Power Plants," June 1990.

47. NUREG-1 760, "Aging Assessment of Safety-Related Fuses Used in Low- and MediumVoltage Applications in Nuclear Power Plants," May 2002.

48. NUREG-1800, Revision 1, "Standard Review Plan for Review of License Renewal

Applications for Nuclear Power Plants," September 2005.

49. NUREG-1801, Revision 1, "Generic Aging Lessons Learned (GALL) Report," September

2005.

50. NUREG-1833, 'Technical Bases for Revision to the License Renewal," October 2005.

51. NUREG/CR-6583, "Effects of LWR Coolant Environments on Fatigue Design Curves of

Carbon and Low-Alloy Steels," February 1998.

52. NUREG/CR-5643, "Effects of Smoke on Functional Circuits," October 1997.

53. NUREG/CR-5704, "Effects of LRW Coolant Environments on Fatigue Design Curves of

Austenitic Stainless Steels," April 1999..

-54. NUREG/CR-6260, "Application of NUREG/CR-5999 Interim Fatigue Curves to Selected

Nuclear Power Plant Components."

55. SAND96-0344, "Aging Management Guideline for Commercial Nuclear Power Plants -

Electrical Cable and Terminations," prepared by Sandia National Laboratories for the U.S.

Department of Energy, September 1996.

D-2
Safety Evaluation For Electric Power Research Institute

BWRVIP Topical Report "BWRVIP-1 39: BWR Vessel And

Internals Project, Steam Dryer Inspection And Flaw

Evaluation Guidelines" July 30, 2008 (ML 082040414)

D-3

NRC FORM 335 U.S. NUCLEAR REGULATORY COMMISSION 1. REPORT NUMBER

(9-2004) (Assigned by NRC, Add Vol., Supp., Rev.,

NRCMD 3.7 and Addendum Numbers, if any.)

BIBLIOGRAPHIC DATA SHEET

(See instructions on the reverse) NUREG-1931

2. TITLE AND SUBTITLE 3. DATE REPORT PUBLISHED

Safety Evaluation Report Related to the License Renewal of Susquehanna Steam Electric MONTH YEAR

Station, Units 1 and 2 November 2009

4. FIN OR GRANT NUMBER

5. AUTHOR(S) 6. TYPE OF REPORT

Evelyn Gettys

7. PERIOD COVERED (Inclusive Dates)

Sept. 13, 2006 - Nov. 25, 2009

8. PERFORMING ORGANIZATION - NAME AND ADDRESS (If NRC, provide Division, Office or Region, U.S. Nuclear Regulatory Commission, and mailing address; if contractor,

provide name and mailing address.)

Division of Regulatory Improvement Programs

Office of Nuclear Reactor Regulation

U.S. Nuclear Regulatory Commission

Washington, DC 20555-0001

9. SPONSORING ORGANIZATION - NAME AND ADDRESS (If NRC, type "Same as above"; if contractor, provide NRC Division, Office or Region, U.S. Nuclear Regulatory Commission,

and mailing address.)

Same as above

10. SUPPLEMENTARY NOTES

11. ABSTRACT (200 words or less)

This safety evaluation report (SER documents the technical review of the Susquehanna Steam Electric Station (SSES), Units 1

and 2 license renewal application (LRA) by the United States (US) Nuclear Regulatory Commission (NRC) staff. By letter dated

September 13, 2006, PPL Susquehanna, LLC (PPL) submitted the LRA in accordance with Title 10, Part 54, of the Code of

Federal Regulations, "Requirements for Renewal of Operating Licenses of Nuclear Power Plants." PPL requests renewal of the

Units 1 and 2, (Facility Operating License Numbers DPR-14 and NPR-22 respectively) for a period of 20 years beyond the

current license which expires at midnight July 17, 2022, for Unit 1 and at midnight March 23, 2024, for Unit 2.

SSES is located approximately 5 miles northeast of Berwick, Pennsylvania. The NRC issued the construction permits for Unit

1 and 2 on November 2, 1973. The NRC issued the operating licenses for Unit 1 on July 17, 1982, and on March 23, 1984, for

Unit 2. General Electric supplied the nuclear steam supply system and Bechtel originally designed and constructed the balance

of the plant. The licensed power output of each unit is 3952 megawatt thermal with a gross electrical output of approximately

1300 megawatt electric.

The SER summarizes the results of the staff's safety review of the LRA and describes the technical details considered in

evaluating the safety aspects of the units' proposed operation for an additional 20 years beyond the term of the current

operating licenses.

12. KEY WORDS/DESCRIPTORS (List words or phrases that will assist researchers in locating the report.) 13. AVAILABILITY STATEMENT

10 CFR Part 54, license renewal, SSES, Susquehanna Steam Electric Station, scoping and unlimited

screening, aging management, time-limited aging analysis, safety evaluation report 14. SECURITY CLASSIFICATION

(This Page)

unclassified

(This Report)

unclassified

15. NUMBER OF PAGES

16. PRICE

NRC FORM 335 (9-2004) PRINTED ON RECYCLED PAPER
x's.' 'D'

Federal Recycling Program

UNITED STATES

NUCLEAR REGULATORY COMMISSION

WASHINGTON, DC 20555-0001

OFFICIAL BUSINESS