NOC-AE-120027, Response to Requests for Additional Information for the South Texas Project License Renewal Application Aging Management Program, Set 12: Difference between revisions

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{{Adams
#REDIRECT [[NOC-AE-120027, Clarification to Supplemental Response to Request for Additional Information for the South Texas Project License Renewal Application - SAMA]]
| number = ML12069A024
| issue date = 02/27/2012
| title = Response to Requests for Additional Information for the South Texas Project License Renewal Application Aging Management Program, Set 12
| author name = Rencurrel D
| author affiliation = South Texas Project Nuclear Operating Co
| addressee name =
| addressee affiliation = NRC/Document Control Desk, NRC/NRR
| docket = 05000498, 05000499
| license number =
| contact person =
| case reference number = TAC ME4936, TAC ME4937, NOC-AE-12002797
| document type = Letter type:NOC
| page count = 94
| project = TAC:ME4936, TAC:ME4937
| stage = Response to RAI
}}
 
=Text=
{{#Wiki_filter:Nuclear Operating Company South Texas Pmo/ect ERectnc Generating Station P.. Box 289 Wadswvrth. Texas 77483
* n.
February 27 2012 NOC-AE-12062797 10 CFR 54 STI: 33330748 File: G25 U. S. Nuclear Regulatory Commission Attention: Document Control Desk One White Flint North 11555 Rockville Pike Rockville, MD 20852-2738 South Texas Project Units 1 and 2 Docket Nos. STN 50-498, STN 50-499 Response to Requests for Additional Information for the South Texas Project License Renewal Application Agqingq Managqement Proqram, Set 12 (TAC Nos. ME4936 and ME4937)
 
==References:==
: 1. STPNOC {{letter dated|date=October 25, 2010|text=letter dated October 25, 2010}}, from G. T. Powell to NRC Document Control Desk, "License Renewal Application" (NOC-AE-1 0002607) (ML103010257)
: 2. NRC {{letter dated|date=February 8, 2012|text=letter dated February 8, 2012}}, "Requests for Additional Information for the Review of the South Texas Project, Units 1 and 2 License Renewal Application -
Aging Management, Set 12 (TAC Nos. ME4936 and ME 4937)"(ML12009A117)
By Reference 1, STP Nuclear Operating Company (STPNOC) submitted a License Renewal Application (LRA) for South Texas Project (STP) Units 1 and 2. By Reference 2, the NRC staff requests additional information for review of the STP LRA. STPNOC's response to the request for additional information is provided in Enclosure 1 to this letter. Changes to LRA pages described in are depicted as line-in/line-out pages provided in Enclosure 2.
Two new regulatory commitments and one revised regulatory commitment are provided in. There are no other regulatory commitments provided in this letter.
Should you have any questions regarding this letter, please contact either Arden Aldridge, STP License Renewal Project Lead, at (361) 972-8243 or Ken Taplett, STP License Renewal Project regulatory point-of-contact, at (361) 972-8416.
I declare under penalty of perjury that the foregoing is true and correct.
Executed on
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Date D. W. Rencurrel Senior Vice President, Technical Support & Oversight KJT
 
==Enclosure:==
: 1. STPNOC Response to Requests for Additional Information
: 2. STPNOC LRA Changes with Line-in/Line-out Annotations
: 3. Regulatory Commitments
/4(4/7
 
NOC-AE-12002797 Page 2 cc:
(paper copy)
(electronic copy)
Regional Administrator, Region IV U. S. Nuclear Regulatory Commission 1600 East Lamar Boulevard Arlington, Texas 76011-4511 Balwant K. Singal Senior Project Manager U.S. Nuclear Regulatory Commission One White Flint North (MS 8B13) 11555 Rockville Pike Rockville, MD 20852 Senior Resident Inspector U. S. Nuclear Regulatory Commission P. 0. Box 289, Mail Code: MN1 16 Wadsworth, TX 77483 C. M. Canady City of Austin Electric Utility Department 721 Barton Springs Road Austin, TX 78704 John W. Daily License Renewal Project Manager (Safety)
U.S. Nuclear Regulatory Commission One White Flint North (MS 011-Fl)
Washington, DC 20555-0001 Tam Tran License Renewal Project Manager (Environmental)
U. S. Nuclear Regulatory Commission One White Flint North (MS 011 F01)
Washington, DC 20555-0001 A. H. Gutterman, Esquire Kathryn M. Sutton, Esquire Morgan, Lewis & Bockius, LLP John Ragan Chris O'Hara Jim von Suskil NRG South Texas LP Kevin Polio Richard Pena City Public Service Peter Nemeth Crain Caton & James, P.C.
C. Mele City of Austin Richard A. Ratliff Alice Rogers Texas Department of State Health Services Balwant K. Singal John W. Daily Tam Tran U. S. Nuclear Regulatory Commission NOC-AE-12002797 STPNOC Response to Requests for Additional Information NOC-AE-12002797 Page 1 of 24 SOUTH TEXAS PROJECT, UNITS 1 AND 2 REQUEST FOR ADDITIONAL INFORMATION -
AGING MANAGEMENT, SET 12 (TAC NOS. ME4936 AND ME4937)
Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (013)
RAI 3.1.1.57-1a - follow-up Backgqround:
By {{letter dated|date=November 21, 2011|text=letter dated November 21, 2011}}, the applicant responded to RAI 3.1.1.57-1 that addresses the susceptibility of the reactor coolant fittings made of cast austenitic stainless steel (CASS). In its response, the applicant indicated that the Hull's equivalent factor was used to calculate delta ferrite content of Class I fittings using chemistry data from certified material test reports (CMTRs). The applicant also indicated that the screening calculation found that the delta ferrite content of the fittings to be < 20 percent, and accordingly the fittings are not considered susceptible to a loss of fracture toughness due to thermal aging embrittlement.
GALL Report, Revision 2, AMP XI.M12, "Thermal Aging Embrittlement of Cast Austenitic Stainless Steel Program (CASS)," indicates that in the susceptibility screening method, ferrite content is calculated by using the Hull's equivalent factors (described in NUREG/CR-4513, Revision 1) or a staff-approved method for calculating delta ferrite in CASS materials.
Issue:
The staff needs to further confirm if the applicant's susceptibility screening method for material is consistent with the GALL Report. The GALL Report addresses the guidance of NUREG/CR-4513, Revision 1 (Section 3.2) for ferrite content calculations using Hull's equivalent factors.
Request:
Provide the bounding case chemical composition of the reactor coolant fittings that estimates the highest ferrite content of these CASS components, including the contents of Cr, Mo, Si, Ni, Mn, N and C.
In addition, provide the calculated highest ferrite content in order to confirm that the applicant's screening analysis indicates no susceptibility of these fittings to thermal aging embrittlement. As part of the response, clarify if the applicant's susceptibility screening method is consistent with the GALL Report that addresses the guidance of NUREG/CR-4513, Revision 1, for ferrite content calculations using Hull's equivalent factors.
NOC-AE-12002797 Page 2 of 24 STPNOC Response:
(1) The bounding case chemical composition of Unit 1 reactor coolant fittings that estimates the highest ferrite content is listed below:
Unit 1 highest ferrite content is 14.9% of Heat Number 17743-1 using the Hull's equivalent factor method.
The chemical composition of Heat Number 17743-1 is:
Cr%=19.87 Mo%=O Si%= 1.08 Ni%= 8.35 Mn%= 0.73 N
* C%=0.03 (2) The bounding case chemical composition of Unit 2 reactor coolant fittings that estimates the highest ferrite content is listed below:
Unit 2 highest ferrite content is 15.4% of Heat Numbers 21389-1 and 21389-2 using the Hull's equivalent factor method.
The chemical composition of Heat Number 21389-1 is:
Cr%= 19.88 Mo%=0 Si%= 1.18 Ni%=8.57 Mn%=0.82 N
* C%=0.02 The chemical composition of Heat Number 21389-2 is:
Cr%= 19.88 Mo%=0 Si%= 1.18 Ni%=8.57 Mn%=0.82 N
* C%=0.02 (3) The calculation of the ferrite content from chemical composition in terms of Hull's equivalent factors, as shown below, is consistent with the guidance of NUREG/CR-4513, Rev. 1, Section 3.2 for ferrite content calculations using Hull's equivalent factors.
The ferrite content (6c%) is given by:
6c% = 100.3[Square(Creq/Nieq)] - 170.72(Creq/Nieq) + 74.22, where Creq = Cr% + 1.21 (Mo%) + 0.48(Si%) - 4.99 Nieq = Ni% + 0.1 l(Mn%) - 0.0086[Square(Mn%)] + 18.4(N%) + 24.5(C%) + 2.77
* The concentration of N, when not provided on the CMTR, is assumed to be 0.04%.
(Ref: NUREG/CR-4513, Rev. 1, Section 3.2)
NOC-AE-12002797 Page 3 of 24 Flow-Accelerated Corrosion (018)
RAI B2.1.6-1a
 
==Background:==
GALL AMP XI.M17, "Flow-Accelerated Corrosion," states that the program relies on implementation of the guidelines in NSAC-202L for an effective flow-accelerated corrosion program. NSAC-202L states, in part, that the systems may be susceptible to damage from other corrosion or degradation mechanisms, which include cavitation, erosion, liquid impingement, etc., but these mechanisms are not part of a flow-accelerated corrosion program and should be evaluated separately.
In response to RAI 3.4.2.6-1, dated November 21, 2011, STP stated that components in the auxiliary feedwater system were initially identified as not susceptible to flow-accelerated corrosion due to infrequent operation. The response stated, however, that wear has been noted in some auxiliary feedwater components and that an item was added to Table 3.4.2-6 identifying carbon steel piping exposed to secondary water as being managed for wall thinning by the Flow-Accelerated Corrosion Program. The response also stated that as a result of a review to determine whether other systems in the scope of license renewal should be included in the program, six systems were identified and LRA Section B2.1.6 was revised to indicate that the Flow-Accelerated Corrosion Program manages wall thinning due to other causes, such as erosion/corrosion, in addition to flow-accelerated corrosion. This appears to correlate with information provided in response to RAI 3.3.2.19-1, dated November 4, 2011, which stated that several systems are being monitored for wall thinning due to erosion/corrosion, but these systems had initially not been identified in the license renewal application (LRA) as being subject to wall thinning or as being managed by the Flow-Accelerated Corrosion Program.
Issue:
The guidance document for the flow-accelerated corrosion programs, NSAC-202L, states that the systems may be susceptible to damage from other corrosion or degradation mechanisms, which include cavitation, erosion, liquid impingement, etc., but these mechanisms are not part of a flow-accelerated corrosion program and should be evaluated separately. However, since STP has chosen to include mechanisms other than flow-accelerated corrosion in its program, this is an enhancement to the flow-accelerated corrosion program that needs to be further described in the LRA.
Request:
: 1) Provide detailed information describing the apparent enhancement to the Flow-Accelerated Corrosion Program, including which of the 10 program elements are affected and how they are affected.
: 2) Since the initial integrated plant assessment did not identify the aging effects acknowledged in response to RAI 3.4.2.6-1, provide information regarding corrective actions taken and extent of condition conducted that provide reasonable assurance that there are no other aging effects that have been overlooked during the preparation of the LRA.
NOC-AE-12002797 Page 4 of 24 STPNOC Response:
: 1) The Flow-Accelerated Corrosion (FAC) program includes piping and piping components susceptible to wall thinning, which cannot be modeled by the predictive code CHECWORKS. Piping and piping components susceptible to wall thinning due to mechanisms other than FAC are managed as susceptible non-modeled lines. The inspections for these system components are administratively controlled using a database developed by the South Texas Project. The LRA Basis Document XI.M17 (B2.1.6) for the FAC aging management program includes a separate discussion of susceptible non-modeled components where appropriate. In several program elements, the discussion applies equally to modeled and non-modeled system components.
For clarification, LRA Appendix A1.6, Appendix B2.1.6, and the LRA Basis Document, XI.M1 7, Flow Accelerated Corrosion program, are revised to state explicitly that system components susceptible to wall thinning due to causes such as erosion/corrosion, cavitation, flashing, and impingement damage are included in the susceptible non-modeled portion of the FAC program.
: 2) As part of the extent-of-condition review for RAI 3.4.2.6-1, six systems were identified and the LRA was revised in response to RAI 3.4.2.6-1, dated November 21, 2011 (ML11335A131) to include wall thinning as an aging effect for these systems. This review also concluded that no other managed aging effects are omitted from the LRA submittal. provides the line-in/line-out revision for the changes to Appendices A1.6 and B2.1.6.
Cast Austenitic Stainless Steel (073)
RAI 3.1.1.80-1a Back-ground:
By {{letter dated|date=November 21, 2011|text=letter dated November 21, 2011}}, the applicant responded to RAI 3.1.1.80-1 that addresses the need for AMR line items to manage cracking or loss of material of reactor vessel internal components using the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program. In its response, the applicant revised LRA Table 3.1.2-1 and Section 3.1.2.2.12. The applicant's revisions indicate that consistent with MRP-227, Revision 0, the PWR Reactor Internals Program is not an applicable aging management program for managing cracking of the components listed in the revised LRA Section 3.1.2.2.12. One of these components listed in the revised LRA Section 3.1.2.2.12 is the upper core support plate. The applicant also indicated that cracking of the upper core plate is managed by the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program.
Sections 3.2.2 and 4.1.1 of the staff s safety evaluation (June 22, 2011; ADAMS Accession No. ML111600498) of MRP-227, Revision 0, address Topical Report Condition 1 for high consequence components. This condition specifies the upper core plate and lower support forging or casting as the expansion components linked to the control rod guide tube (CRGT) assembly lower flange welds, which are the primary components. Section 3.2.2 of the staffs NOC-AE-12002797 Page 5 of 24 safety evaluation also indicates that inspections of these high consequence components shall be triggered by the degradation of the primary component (in this case, CRGT lower flanges).
The staffs safety evaluation further indicates that the examination method for these additional inspections shall be consistent with the examination method used to detect the degradation of the primary component (in this case, EVT-1).
Issue:
The staff needs clarification as to whether the PWR Reactor Internals Program identifies the upper core plate as an expansion component linked to the CRGT lower flange welds to manage loss of material due to wear and cracking due to fatigue, as specified in the staffs safety evaluation (June 22, 2011) of MRP-227, Revision 0.
The staff also needs clarification as to whether the applicant's PWR Reactor Internals Program identifies lower internals assembly lower support forging or casting as an expansion component linked to the CRGT lower flange welds to ensure adequate aging management and structural integrity, consistent with the staffs safety evaluation (June 22, 2011) of MRP-227, Revision 0.
Request:
: 1. Clarify whether the applicant's PWR Reactor Internals Program identifies the upper core plate as an expansion component linked to the CRGT lower flange welds to manage loss of material due to wear and cracking due to fatigue, consistent with the staffs safety evaluation (June 22, 2011) of MRP-227, Revision 0.
: 2. Clarify whether the applicant's PWR Reactor Internals Program identifies the lower internals assembly lower support forging or casting as an expansion component linked to the CRGT lower flange welds to ensure adequate aging management and structural integrity, consistent with the staff's safety evaluation (June 22, 2011) of MRP-227, Revision 0.
: 3. Revise the LRA consistent with the applicant's response.
STPNOC Response:
The STP PWR Reactor Internals Program (B2.1.35) was initially prepared using EPRI 1016596, Material Reliability Program: PWR Internals Inspection and Evaluation Guidelines (MRP-227).
The NRC issued Revision 1 of the NRC Safety Evaluation (ML11308A770) for MRP-227, Rev. 0 on December 16, 2011 and the industry published EPRI-1022863 (MRP-227-A) as an NRC Topical Report in December 2011. As part of this RAI response, the LRA reactor vessel internals sections listed below are revised to be consistent with NRC Safety Evaluation, Revision 1 and MRP-227-A. Enclosure 2 provides the line-in/line-out revision to the following LRA sections:
LRA Table 3.1.1 items 30 and 37 LRA Table 3.1.2-1 LRA Sections 3.1.2.2.6, 3.1.2.2.9, 3.1.2.2.12, 3.1.2.2.15, and 3.1.2.2.17 LRA Appendix A1.35 LRA Table A4-1 Item 27 LRA Appendix B2.1.35 NOC-AE-12002797 Page 6 of 24
: 1) NRC Safety Evaluation, Revision 1, Sections 3.2.2 and 4.1.1 and MRP-227-A, Table 4 6 identify the upper core plate as an expansion component linked to the control rod guide tube (CRGT) assembly lower flange welds, which are the primary components.
LRA Appendix B2.1.35 and LRA Basis Document, PWRRI (B2.1.35), PWR Reactor Internals program, are revised to include the upper core plate as an expansion component to manage loss of material due to wear and cracking due to fatigue, consistent with NRC Safety Evaluation, Revision 1, and MRP-227-A, Table 4-6.
LRA Table 3.1.2-1 is revised to manage the aging effects of cracking due to fatigue in the upper core plate with Aging Management Program (AMP) Water Chemistry (B2.1.2) and PWR Reactor Internals Program (B2.1.35). LRA Table 3.1.2-1 is revised to manage loss of material in the upper core plate due to wear using AMP PWR Reactor Internals Program (B2.1.35). LRA Section 3.1.2.2.12 is also revised to delete the upper core support upper core plate from the list of components not included in the PWR Reactor Internals Program.
: 2) NRC Safety Evaluation, Revision 1, Sections 3.2.2 and 4.1.1 and MRP-227-A, Table 4 6 identify the lower internals support lower support forging as an expansion component linked to the CRGT assembly lower flange welds. LRA Appendix B2.1.35 and LRA Basis Document PWRRI (B2.1.35), PWR Reactor Internals program, are revised to include the lower internals assembly lower support forging as an expansion component linked to the CRGT lower flange welds to manage cracking due to fatigue, consistent with NRC Safety Evaluation, Revision 1 and MRP-227-A,Table 4-6.
An Aging Management Review (AMR) line exists in LRA table 3.1.2-1 to manage cracking of the lower support forging.
: 3) Enclosure 2 provides the line-in/line-out revision for the changes identified in response to 1 and 2 above.
RAI 3.1.1.80-2a
 
==Background:==
By {{letter dated|date=November 21, 2011|text=letter dated November 21, 2011}}, the applicant responded to RAI 3.1.1.80-2 that addresses the aging management for loss of fracture toughness of the CRGT assembly lower flanges and related components. The applicant indicated that the CRGT assembly lower flange welds are sub-components of the reactor vessel internal (RVI) CRGT assembly listed in LRA Table 3.1.2-1. The applicant also indicated that the CRGT lower flanges are fabricated of stainless steel and cracking is the only aging effect to be managed by MRP-227 for these components.
The applicant further indicated that upon detection of cracking in a component susceptible to loss of fracture toughness, the PWR Reactor Internals Program defines an assessment of cracking with limit load and/or fracture mechanics evaluations.
In comparison, LRA Table 3.1.2-1 indicates that loss of fracture toughness due to irradiation embrittlement of the CRGT assembly made of stainless steel is managed by the PWR Reactor Internals Program. In addition, Table 3-3 of MRP-227, Revision 0, indicates that the CRGT lower flanges made of CASS are susceptible to cracking due to stress corrosion cracking NOC-AE-12002797 Page 7 of 24 (SCC) and fatigue, and loss of fracture toughness due to thermal aging embrittlement and irradiation embrittlement.
In its response, the applicant also indicated that the bottom mounted instrumentation (BMI) column bodies are listed in LRA Table 3.1.2-1 as RVI in-core instrumentation (ICI) support structures-instrument column (BMI). The applicant further indicated that cracking is the only aging effect to be managed by MRP-227 for the BMI column bodies. In comparison, Table 3-3 of MRP-227. Revision 0 indicates that the BMI column bodies made of Type 304 stainless steel are susceptible to cracking due to fatigue, and loss of fracture toughness due to irradiation embrittlement.
Issue:
The staff needs clarification as to whether the CRGT lower flanges are made of CASS. If the CRGT lower flanges are made of CASS, the staff needs to further clarify if loss of fracture toughness, in addition to cracking, is considered as an aging effect to be managed by the PWR Reactor Internals Program for these components. In addition, the staff needs clarification as to why cracking is the only aging effect to be managed by the PWR Reactor Internals Program for the BMI column bodies, without inclusion of aging management for loss of fracture toughness.
Request:
: 1. Clarify whether the CRGT lower flanges are made of CASS.
If the CRGT lower flanges are made of CASS, clarify why cracking is the only aging effect to be managed by the PWR Reactor Internals Program for these components, without inclusion of aging management for loss of fracture toughness due to thermal aging embrittlement and irradiation embrittlement.
In addition, resolve the apparent conflict between the applicants claim that cracking is the only aging effect to be managed by the PWR Reactor Internals Program for the CRGT lower flanges and the applicants aging management review results in LRA Table 3.1.2-1 indicating that loss of fracture toughness of the CRGT assembly is managed by the PWR Reactor Internals Program.
: 2. Clarify why cracking is the only aging effect to be managed by the PWR Reactor Internals Program for the BMI column bodies, without inclusion of aging management for loss of fracture toughness due to irradiation embrittlement.
: 3. Revise the LRA consistent with the applicants response. As part of the revision, if loss of fracture toughness is identified as an applicable aging effect of the BMI column bodies, add an AMR line item to manage this aging effect.
NOC-AE-12002797 Page 8 of 24 STPNOC Response:
(1) LRA Table 3.1.2-1 and RAI 3.1.1.80-2 response dated November 21, 2011 (ML11334A131),
identified that the control rod guide tube (CRGT) assembly lower flanges are fabricated of stainless steel, not cast austenitic stainless steel (CASS). Westinghouse confirmed that the CRGT assembly lower flanges are fabricated from forged stainless steel.
The STP PWR Reactor Internals Program (B2.1.35) was initially prepared using EPRI 1016596, Material Reliability Program: PWR Internals Inspection and Evaluation Guidelines (MRP-227). The NRC issued Revision 1 of the Safety Evaluation (ML11308A770) for MRP-227 on December 16, 2011 and the industry published EPRI-1022863 (MRP-227-A) as an NRC Topical Report in December 2011. As part of the response to RAI 3.1.1.80-1a, the LRA reactor vessel internals sections are revised to be consistent with NRC Safety Evaluation, Revision 1 and MRP-227-A.
An aging management line for loss of fracture toughness due to irradiation embrittlement of the stainless steel CRGT assembly lower flanges is currently included in LRA Table 3.1.2-1 and is consistent with Table 4-3 of MRP-227-A.
(2) STP concurs that the aging effect, loss of fracture toughness due to irradiation embrittlement, is applicable to the BMI column bodies. The aging effect of loss of fracture toughness due to irradiation embrittlement of BMI column bodies is identified in NUREG-1801, Rev. 2, Item IV.B2.RP-292 and MRP-227-A, Table 4-6.
(3) LRA Table 3.1.2-1 is revised to add a loss of fracture toughness aging management line for the BMI column bodies, which is consistent with MRP-227-A Table 4-6. provides the line-in/line-out revision for the changes to LRA Table 3.1.2-1.
RAI 3.1.2.1-1a BackQround:
By {{letter dated|date=November 21, 2011|text=letter dated November 21, 2011}}, the applicant responded to RAI 3.1.2.1-1 that addresses the aging management of inaccessible locations of the reactor vessel internal components. In its response, the applicant indicated that the applicant's program will inspect one hundred percent of the volume/area of each accessible component in accordance with MRP-227 as approved by the NRC safety evaluation report dated June 22, 2011. The applicant also indicated that the minimum examination coverage for primary and expansion inspection categories is 75 percent of the component's total (accessible plus inaccessible) inspection area/volume or, when addressing a set of like components (e.g. bolting), the inspection will examine a minimum sample size of 75 percent of the total population of like components. The applicant further indicted that a technical justification will be required of any minimum coverage requirements below 75 percent of total inspection area/volume or sample size. In addition, the applicant indicated that the PWR Reactor Internals Program is consistent with these conditions regarding the minimum examination coverage addressed in Section 3.3.1 of the staffs safety evaluation of MRP-227, Revision 0.
NOC-AE-1 2002797 Page 9 of 24 In RAI 3.1.2.1-1, the staff requested that, if an aging effect has been identified in accessible locations of the reactor vessel internal components, the applicant should provide further evaluation to ensure that the aging effect is adequately managed for the inaccessible locations as recommended in GALL Report, Revision 2 (items IV.B2.RP-268 and IV.B2.RP-269) and SRP-LR, Revision 2 (Sections 3.1.2.2.9 and 3.1.2.2.10).
SRP-LR Sections 3.1.2.2.9 and 3.1.2.2.10 state that if aging effects are identified in accessible locations, the GALL Report recommends further evaluation of the aging effects in inaccessible locations on a plant-specific basis to ensure that this aging effect is adequately managed.
Issue:
The staff noted that the applicant confirmed that the minimum examination coverage criteria of the applicant's program are consistent with the Topical Report Conditions in the staffs safety evaluation (June 22, 2011) of MRP-227, Revision 0. However, the staff noted that in its response, the applicant did not indicate whether the applicant performed further evaluation for the aging effect in the inaccessible locations of partially accessible components (including a set of multiple components such as bolts), consistent with the GALL Report and SRP-LR, when an aging effect was detected in the accessible locations of the components.
In addition, the staff needs clarification as to whether the applicant's aging management will perform further evaluation to ensure adequate aging management for the inaccessible locations of partially accessible components if an aging effect is identified in the accessible locations of the components.
Request:
: 1. If an aging effect was detected in the accessible locations of partially accessible reactor vessel internal components (including a set of multiple components such as bolts), describe the plant-specific evaluation of the aging effect in the inaccessible locations of the components, which was performed to ensure that this aging effect is adequately managed.
: 2. Clarify whether the applicant's aging management program will perform plant-specific evaluation to ensure adequate aging management for the inaccessible locations of partially accessible components (including a set of multiple components such as bolts) if an aging effect is identified in the accessible locations of the components.
: 3. Revise the LRA consistent with the applicant's response.
STPNOC Response:
: 1) The STP PWR Reactor Internals Program (B2.1.35) recent operating experience associated with ASME Code inspections or modifications of the reactor vessel internals did not identify any defects requiring MRP-227-A engineering evaluations. ASME Code, Section XI, Examination Category B-N-3 examinations of the reactor internals conducted during refueling outage 1RE15 (Fall 2009) for Unit 1, and during refueling outage 2RE14 (Spring 2010) for Unit 2, did not identify any conditions that required repair, replacement or evaluation. STP replaced the Alloy-750 control rod guide tube support pins (split pins) with strained hardened (cold worked) 316 stainless steel pins during refueling outage 1 RE12 NOC-AE-12002797 Page 10 of 24 (Spring 2005) for Unit 1 and during refueling outage 2RE1 1 (Fall 2005) for Unit 2. The pin replacement process did not discover any cracked Alloy X-750 split pins.
LRA Appendix B2.1.35 and LRA Basis Document PWRRI (2.1.35), PWR Reactor Internals Program, are revised to incorporate the operating experience associated with the recent ASME Code inspections and the control rod guide tube support pin (split pin) replacements.
(2) One hundred percent of the accessible volume/area of each Primary component and, when required, the Expansion component will be examined subject to the minimum examination coverage criteria in NRC safety evaluation sections 3.3.1, 3.3.2 and 4.1.4 for MRP-227-A (December 16, 2011; ADAMS Accession No. ML11308A770).
LRA Appendix B2.1.35 and LRA Basis Document PWRRI (2.1.35), PWR Reactor Internals Program, are revised to specify the component-specific minimum examination coverage criteria consistent with MRP-227-A Tables 4-3 and 4-6. If defects are discovered during the examination, STP will enter the information into the corrective action program and evaluate whether the results of the examination ensure that the component (or set of components) will continue to meet its intended function under all licensing-basis conditions of operation until the next scheduled examination. Engineering evaluations that demonstrate the acceptability of a detected condition are performed consistent with WCAP-1 7096-NP.
(3) Enclosure 2 provides the line-in/line-out revisions for changes to LRA Appendix B2.1.35.
RAI 3.0-1a (Follow-up to RAI 3.0-1)
 
==Background:==
LRA Table 3.0-1 states that the applicant's environment of "plant indoor air" encompasses the GALL Report defined environments of "air-indoor controlled," "air-indoor uncontrolled,"
"condensation," "air, moist," "air with steam or water leakage," etc., depending on whether the "plant indoor air" is an internal or external environment. The applicant used the term "plant indoor air" in its AMR tables and did not use the GALL Report defined environments. The GALL Report identifies the potential for different aging effects when components are exposed to each of these different environments.
By {{letter dated|date=September 22, 2011|text=letter dated September 22, 2011}}, the staff issued RAI 3.0-1 requesting that the applicant identify which AMR items in the LRA are exposed to a "plant indoor air" environment for which humidity, condensation, or moisture is present. In its response dated November 21,2011, the applicant stated that some AMR items were inadvertently associated with a GALL Report item for exposure to "air-indoor controlled" that should have been associated with a GALL Report item for exposure to "air-indoor uncontrolled," and the applicant made the associated changes to the LRA. The applicant did not revise its definition of "plant indoor air" or make any other changes to the LRA to indicate whether the AMR items that have an environment of "plant indoor air" are exposed to humidity, condensation, or moisture. In a teleconference held December 12, 2011, the applicant clarified that anytime the environment "plant indoor air" is used in the LRA, there is a potential for moisture in the air.
NOC-AE-12002797 Page 11 of 24 The staff identified several instances in the LRA in which NUREG-1800, "Standard Review Plan for License Renewal of Nuclear Power Plants" (SRP-LR), Table 1 items for exposure to "air-indoor uncontrolled" are being used inappropriately for components with a "plant indoor air environment." As a result, the applicant has inappropriately concluded that the components have no aging effects requiring management. Examples include:
Several aluminum components in the LRA exposed to "plant indoor air" reference SRP-LR Table 3.2-1, item 50, which is for aluminum components exposed to "air-indoor uncontrolled" and recommends that there are no aging effects requiring management.
However, since the applicant's definition of "plant indoor air" includes condensation and moisture, these components are susceptible to loss of material, as documented in SRP-LR Revision 2 Table 3.3-1, item 92.
Several stainless steel, copper alloy, and nickel alloy components in the LRA exposed to "plant indoor air" reference SRP-LR Table 3.4-1, item 41, which is for components exposed to "air-indoor uncontrolled" and recommends that there are no aging effects requiring management. However, these components are susceptible to loss of material when exposed to condensation and moisture, as documented in SRP-LR Revision 2 Table 3.3-1, items 79 and 95.
Similar situations occur for other aluminum, steel, galvanized steel, stainless steel, copper alloy, and nickel alloy components exposed to a "plant indoor air environment" for which no aging effects requiring management are identified in the LRA.
Issue:
It is not clear to the staff why there are aluminum, steel, galvanized steel, stainless steel, copper alloy, and nickel alloy AMR items in the LRA exposed to an environment of "plant indoor air" that do not have any aging effects identified. It is also not clear to the staff how SRP-LR Table 1 items for components exposed to "air-indoor uncontrolled" are adequate references for components in the LRA that are exposed to "plant indoor air." The applicant's "plant indoor air" environment includes moisture or condensation, which is not part of the SRP-LR environment of "air-indoor uncontrolled."
Request:
For all of the aluminum, steel, galvanized steel, stainless steel, copper alloy, and nickel alloy AMR items in the LRA with an environment of "plant indoor air" that do not have any aging effects identified, explain why the components have no aging effects requiring management or identify appropriate aging effects and aging management programs consistent with the guidance in the GALL Report, Revision 2, for air environments that contain moisture.
STPNOC Response:
The LRA Table 3.0-1 environments of Plant Indoor Air (Internal) and Plant Indoor Air (External) include the NUREG-1801 environment of condensation. LRA Table 3.0-1, Mechanical Environments Description, is revised as follows to clarify the use of Plant Indoor Air as an internal or external environment.
NOC-AE-12002797 Page 12 of 24 Plant Indoor Air (When used as Internal) -
 
== Description:==
Plant Indoor air (Internal) is air with temperatures at or below the dew point.
Condensation is assumed to occur and the environment is potentially aggressive. Plant Indoor Air (Internal) includes non-dried compressed air and gases. Plant Indoor Air (Internal) is used for the internal surfaces of drain lines.
Plant Indoor Air (When used as External) -
 
== Description:==
Plant Indoor air (External) is air with temperatures higher than the dew point.
Condensation can occur, but only rarely, component surfaces are normally dry.
Condensation is only assumed to occur on external surfaces of plant components in chilled water and air conditioning systems. These plant systems may produce external component surface temperatures at or below the dew point. Plant Indoor Air (External) with condensation is potentially aggressive.
A review of the aging management review (AMR) lines for components exposed to Plant Indoor Air (Internal) found AMR lines that require the addition of aging effects and aging management programs to address loss of material caused by condensation. LRA Tables 3.3.2-8, 3.3.2-16, 3.3.2-20, 3.3.2-23, and 3.4.2-1 are revised to assign aging effects and aging management programs to these Plant Indoor Air (Internal) AMR lines. In addition, LRA Section 3.3.2.1.8 and Section 3.3.2.1.16 are affected by this change and are revised.
A review of the AMR lines for Plant Indoor Air (External) found AMR lines for the chilled water and the air conditioning systems that require aging effects and aging management programs to address loss of material due to condensation. LRA Tables 3.3.2-9, 3.3.2-10, 3.3.2-11, 3.3.2-12, and 3.3.2-15 are revised to assign aging effects and aging management programs to these AMR lines where components are constructed of galvanized steel and stainless steel. In addition, LRA Section 3.3.2.2.10.5 is affected by this change and is revised. provides the line-in/line-out revision for the changes to LRA Sections 3.3.2.1.8, 3,3.2.1.16, and 3.3.2.2.10.5 and LRA Tables 3.3.2-8, 3.3.2-9, 3.3.2-10, 3.3.2-11, 3.3.2-12, 3,3.2-15, 3.3.2-16, 3.3.2-20, 3.3.2-23, and 3.4.2-1.
Future consideration of Operating Experience RAI B1.4-2 Backgqround:
In request for additional information (RAI) B13.4-1, issued on May 24, 2011, the staff asked the applicant to describe the programmatic activities that will be used to continually identify aging issues, evaluate them, and as necessary, enhance the AMPs or develop new AMPs for license renewal. In its response dated June 23, 2011, the applicant stated that it maintains procedures for feedback of operating information, including aging-related issues, pursuant to NUREG-0737, "Clarification of TMI Action Plan Requirements," Item I.C.5, "Procedures for Feedback of Operating Experience to Plant Staff." The applicant also stated that the Corrective Action NOC-AE-1 2002797 Page 13 of 24 Program (CAP) complements the Operating Experience (OE) Program to monitor aging-related issues.
Issue The applicant's response provides a general description of how it considers operating experience on an ongoing basis; however, it does not directly address several areas in RAI B1.4-1 on which the staff requested information. Further, in certain areas, the applicant's response does not provide enough information on how the operating experience review activities address issues specific to aging. The staff identified the following issues with the applicant's response:
(a) It is not clear as to whether the applicant only reviews certain sources of plant-specific and industry operating experience information. Additional information is needed to determine whether the applicant's processes would preclude the consideration of relevant operating experience information, because it is not from a prescribed source.
(b) The applicant did not describe how it ensures the timely completion of operating experience evaluations, nor did it describe how it prioritizes the evaluations. It is therefore unclear as to whether the operating experience evaluations will be completed in a timely manner or whether they will be appropriately prioritized.
(c) The applicant provided example sources of plant-specific and industry operating experience that it monitors on an ongoing basis to identify potential aging issues and stated that the results of the monitoring are documented and maintained in accordance with plant records management and administration procedures. It is unclear as to whether "results of the monitoring" includes the operating experience evaluations. Also, the applicant did not describe what's recorded on the operating experience evaluations with respect to addressing aging issues. In addition, it is not clear whether maintenance "in accordance with plant records management and administration procedures" is equivalent to keeping the evaluations in an auditable and retrievable form.
(d) The applicant indicated that it only would record the monitoring results for the example sources of operating experience it provided. It is therefore not clear how the applicant will keep the monitoring or evaluation results for reviews of other sources of plant specific and industry operating experience.
(e) The applicant listed example sources of plant-specific and industry operating experience that are monitored on an ongoing basis to identify potential aging issues and stated that they are placed in the CAP, as appropriate. Additional information is needed to determine how enhancements to the aging management activities, including the development of new AMPs, will be implemented.
(f) For its OE Program, the applicant stated that it maintains procedures for the feedback of operating information pursuant to NUREG-0737 Item I.C.5. Additional information is needed on how the applicant ensures the effectiveness of this program.
(g) The applicant did not describe its criteria for identifying and categorizing operating experience items as related to aging.
NOC-AE-12002797 Page 14 of 24 (h) The applicant stated that it does not review under its OE Program NRC regulatory guides, license renewal interim staff guidance, revisions to the GALL Report, and revisions to industry standards on which the AMPs are based. However, guidance documents, like the GALL Report, can provide a convenient source of operating experience information, useful recommendations, and best practices, the consideration of which would help to ensure the effectiveness of the AMPs, or indicate the need to enhance the AMPs or develop new AMPs.
(i) The applicant did not describe how evaluations of operating experience related to aging consider the potentially affected plant for the following:
systems, structures, and components materials environments aging effects aging mechanisms AMPs (j) The applicant did not describe criteria for considering when AMPs should be modified or new AMPs developed due to operating experience.
(k) The applicant stated that conditions adverse to quality, including adverse results of inspections performed under the AMPs, are monitored on an ongoing basis to identify potential aging issues and placed in the CAP. Additional information is needed on how the applicant will consider as operating experience the results of the inspections, tests, analyses, etc., conducted through implementation of the AMPs, particularly when the results meet the AMP's acceptance criteria.
(I) The applicant stated that engineering support personnel have been trained on the equipment reliability process, which includes age-related inputs, and on the Electric Power Research Institute's aging assessment field guide. Additional information is needed on the training that will be provided for those plant personnel responsible for screening, assigning, evaluating, and submitting operating experience items.
(m)The applicant stated that it shares lessons learned with other utilities to promote industry-wide safety and reliability; however, the applicant did not provide criteria for reporting its plant-specific operating experience on age-related degradation to the industry.
Request:
Provide a response to each item below.
(a) Indicate whether plant-specific and industry operating experience is only considered from a prescribed list of sources. If only prescribed sources are considered, provide a justification as to why it is unnecessary to consider other sources.
NOC-AE-1 2002797 Page 15 of 24 (b) Describe how plant-specific and industry operating experience evaluations will be prioritized and completed in a timely manner.
(c) Describe the operating experience evaluation records with respect to what will be considered and recorded for aging. Indicate whether the evaluation records will be maintained in auditable and retrievable form.
(d) Indicate whether there are any differences between evaluation records kept for the review of operating experience from the list of example sources and records kept for the review of other sources of plant-specific and industry operating experience. If there are differences, describe and justify them.
(e) Describe how enhancements to the aging management activities will be implemented, including the development of new AMPs, when it is determined through an operating experience evaluation that enhancements are necessary.
(f) Describe the administrative controls for the OE Program and indicate whether they include periodic audits to ensure the program's effectiveness (g) Describe how operating experience issues will be identified and categorized as related to aging. If an identification code is used, provide its definition or the criteria for its application. Also, describe how age-related operating experience will be trended.
(h) Provide a plan for considering the content of guidance documents, such as the GALL Report, as operating experience applicable to aging management.
(i) Describe how evaluations of operating experience issues related to aging will consider the following:
systems, structures, or components materials environments aging effects aging mechanisms AMPs
() Describe criteria for considering when AMPs should be modified or new AMPs developed due to operating experience.
(k) Describe how the results of the AMP inspections, tests, analyses, etc. will be considered as operating experience, both when they meet and do not meet the applicable acceptance criteria.
(I) Describe the training requirements and justify the level of training on aging issues for those plant personnel responsible for screening, assigning, evaluating, and submitting plant-specific and industry operating experience. Also, provide the periodicity of the training and describe how it will account for personnel turnover.
NOC-AE-12002797 Page 16 of 24 (m) Provide criteria for reporting plant-specific operating experience on age-related degradation to the industry.
STPNOC Response:
(a) The South Texas Project (STP) Operating Experience Program (OEP) procedure uses various source documents (e.g., INPO, NRC, or NEI websites) for applicable OE reports. In addition, STP reviews Nuclear Network Operating Experience Reports weekly and forwards these documents to the applicable subject matter expert. These documents are coded and all age-related failures are forwarded to the appropriate personnel for disposition.
The OEP procedure will be revised to add License Renewal Interim Staff Guidance and revisions to NUREG-1801, "Generic Aging Lessons Learned (GALL) Report", as source documents applicable for review. (See Commitment Item 41 in Enclosure 3)
(b) Within 10 days of receiving an OE source document, a condition report is initiated to screen the OE for applicability to STP. The OE is then evaluated within the next 40 days to determine impact on STP programs and procedures. The OEP process allows for extension of these evaluations up to 180 days. Implementing actions initiated from plant-specific and industry operating experience evaluations are managed through the correction action program with action due dates established commensurate with their safety significance.
(c) The OEP procedure will be revised to include "aging effects" to the list of characteristics for determining applicability of an OE document that may require further evaluation.
Evaluations should consider: (a) systems, structures, or components; (b) materials; (c) environments; (d) aging effects; (e) aging mechanisms; and (f) aging management programs. (See Commitment Item 41 in Enclosure 3)
The screening and evaluation results of OE reviews including implementation actions are documented in the corrective action program and are captured in a retrievable data base.
(d) The South Texas Project (STP) Operating Experience Program (OEP) procedure uses various source documents (e.g., INPO, NRC, or NEI websites) for applicable OE reports. All source documents evaluated become quality documents once completed and stored for retrieval. All specific documents are identified by event codes and the types of evaluations are categorized by action type codes. This procedure applies to all activities and organizations within STPNOC and is applicable to source documents listed in the procedure and vendor Nuclear Safety Advisory Letters. The OEP procedure will be revised to add License Renewal Interim Staff Guidance and revisions to NUREG-1801, "Generic Aging Lessons Learned (GALL) Report", as source documents applicable for review.
The STP Corrective Action Program (CAP) requires that condition owners evaluate conditions (which would include those conditions related to aging effects) and determine the need to capture OE and enter data in required fields in the CAP data base. The OEP procedure provides a process for sharing lessons learned from "plant-specific" OE NOC-AE-12002797 Page 17 of 24 identified in CAP with the industry.
(e) The Station Operating Experience Coordinator creates a screening condition report when Industry OE documents for top tier documents identified within the scope of the procedure is received. A designated line organization evaluator may be required to support the screening and evaluation. A number of characteristics are considered for determining applicability. The OEP procedure will be revised to include "aging effects" to the list of characteristics for determining applicability of an OE document that may require further evaluation. Evaluations should consider: (a) systems, structures, or components; (b) materials; (c) environments; (d) aging effects; (e) aging mechanisms; and (f) aging management programs. (See Commitment Item 41 in Enclosure 3) If the OE document is applicable to a plant aging management program (AMP), the program owner is assigned an action to review the OE for impact on the AMP. If the AMP requires enhancement, it is identified during the impact review.
Station-level OE is identified through the generation of condition reports. The CAP procedure lists "aging" as an example of a condition that can reduce the capability of a system and thus result in a degraded condition. There are several "event codes" related to equipment failures or degradation that are aging-related. Corrective Action Program Event Codes will be reviewed to determine if additional codes are needed to ensure age-related degradation effects are identified. (See Commitment Item 41 in Enclosure 3)
The CAP process requires determining the extent of condition of nonconforming or degraded conditions. Corrective action may include enhancements to existing AMP.
Another outcome of either Industry OE or station-level OE is that corrective action could result in the development of a new AMP if the condition can not be adequately addressed by an existing AMP. LRA Licensing Commitment #29 states that, as additional industry and plant-specific applicable operating experience becomes available, it will be evaluated and incorporated into each aging management program or in the development of a new aging management program(s), as necessary, to provide assurance that the effects of aging will be managed during the period of extended operation.
(f) The STP OEP procedure is a quality-related procedure. While OEP effectiveness reviews focus on historical INPO Significant Operating Event Reports and Level 1 and Level 2 INPO Event Reports, oversight organizations may perform audits and assessments on the OEP. In addition, the Station Self-Assessment Coordinator performs a biennial effectiveness review of the OEP and ensures an industry peer is available to support this review.
(g) The Station Operating Experience Coordinator creates a screening condition report when Industry OE documents are received. A designated line organization evaluator may be required to support the screening. A number of characteristics are considered for determining applicability. The CAP procedure requires that condition owners evaluate the condition and determine the need to capture OE and enter data in required fields.
The OEP procedure will be revised to include "aging effects" to the list of characteristics for determining applicability of a OE document that may require further evaluation.
NOC-AE-12002797 Page 18 of 24 Evaluations should consider: (a) systems, structures, or components; (b) materials; (c) environments; (d) aging effects; (e) aging mechanisms; and (f) aging management programs. (See Commitment Item 41 in Enclosure 3)
There are several "event codes" in CAP related to equipment failures or degradation that are aging-related. Corrective Action Program Event Codes will be reviewed to determine if additional codes are needed to ensure age-related degradation effects are identified. (See Commitment Item 41 in Enclosure 3)
Each AMP discusses the appropriate elements of monitoring and trending to provide predictability of the extent of degradation and to provide for timely corrective action or mitigating actions.
(h) See response to item (a).
(i) See response to item (c).
(j) Results of inspections, tests, analyses, etc. conducted through the implementation of aging management programs are considered as operating experience on an ongoing basis. When applicable acceptance criteria are met, results are retained for future use and evaluation to determine whether it is necessary to adjust the frequency for future inspections, establish new inspections, and ensure an adequate depth and breadth of component, material, environment, and aging effect combinations. When applicable acceptance criteria are not met, corrective actions are initiated in accordance with the quality assurance program.
(k) See response to item (j).
(I) A training "needs analysis" will be performed for those plant personnel who screen, assign, evaluate, and submit plant-specific and industry operating experience information for age-related effects. (See Commitment Item 41 in Enclosure 3)
The "needs analysis" should consider whether responsible personnel:
Can appropriately identify when operating experience has the potential to involve age-related degradation, Understand the purpose and scope of the aging management programs, how these programs manage the effects of aging applicable to the plant, and which aging degradation is likely to occur, and Can identify the difference between an evaluation for operability and an evaluation for age-related degradation.
(m)The OEP procedure provides the requirements for posting internal OE to the INPO Nuclear Network. The procedure will be revised to provide criteria for reporting plant-specific operating experience on age-related degradation. (See Commitment Item 41 in Enclosure 3)
NOC-AE-12002797 Page 19 of 24 Enclosures 2 and 3 describe the enhancements to be made to the OEP and the CAP provided in the above responses to this RAI.
RAI A1-1
 
==Background:==
In RAI B13.4-1, the staff asked the applicant to provide, in accordance with 10 CFR 54.21(d), an updated final safety analysis report (UFSAR) supplement summary description of the programmatic activities for the ongoing review of operating experience. By {{letter dated|date=August 18, 2011|text=letter dated August 18, 2011}}, the applicant provided this description:
Operating experience is applied to all aging management programs discussed in Sections Al and A2. Plant-specific and industry operating experience is continuously reviewed to confirm the effectiveness of AMPs and is utilized, as necessary, to enhance each AMP or to develop new AMPs in order to adequately manage the effects of aging so that the intended function(s) of structures and components are met.
Issue:
As described above in RAI B13.4-2, the applicant described generally how it intends to consider operating experience on an ongoing basis; however, it did not provide specific information on how its operating experience review activities will address issues related to aging. Similarly, the above entry for UFSAR supplement also lacks details on how aging is considered in the ongoing operating experience reviews.
Request:
Consistent with the response to RAI B13.4-2, provide additional details in the FSAR supplement on how the ongoing operating experience review activities address issues related to aging.
STPNOC Response: provides the line-in/line-out revision for the changes to Appendix Al. This change provides the additional details in the FSAR supplement on how the ongoing operating experience review activities address issues related to aging consistent with the response to RAI B13.4-2. provides line-in new regulatory commitment Item 41 that captures the enhancements that will be made to the OEP and the CAP.
NOC-AE-12002797 Page 20 of 24 Heat Exchangers (085)
RAI 3.3.2.2.4-1a
 
==Background:==
In RAI 3.3.2.2.4-1, the staff asked the applicant to clarify whether the non-regenerative heat exchangers will be included in the sample of components to be inspected using the One-Time Inspection Program and to justify why eddy current testing is not used to detect cracking in the heat exchanger tubes. In its response, dated November 21, 2011, the applicant stated that non-regenerative heat exchangers are included in the material/environment component population in its One-Time Inspection Program and that the LRA Basis Document for B2.1.16, One-Time Inspection Program, "scope of program" element will be revised to add a specific requirement to perform eddy current inspections of the tubes in one of the non-regenerative heat exchangers. Also in its response, the applicant revised LRA Section 3.3.2.2.4.1 by stating that the one-time inspection will perform eddy current inspection of the tubes in one of the non-regenerative heat exchangers.
Issue:
The staff finds the technical portion of response acceptable because the applicant will perform eddy current testing of the non-regenerative heat exchanger tubes, which will manage potential cracking as recommended in SRP-LR 3.3.2.2.4.1. However, it was not clear to the staff that this specific license renewal activity had been appropriately captured in the current licensing basis.
Request:
Revise LRA Section A1.16, associated with the One-Time Inspection Program, to include a description of the eddy current testing of non-regenerative heat exchanger tubes, or provide another licensing basis document to accomplish a comparable commitment.
STPNOC Response:
LRA Appendices A1.16 and B2.1.16 and LRA Basis Document XI.M32(B2.1.16), One-Time Inspection Program, are revised to include the following statement.
The sample population includes eddy current testing of the tubes in one non-regenerative heat exchanger. provides the line-in/line-out revision for the changes to LRA Appendices Al. 16 and B2.1.16.
B2.1.39-1
 
==Background:==
The generic aging lessons learned (GALL) Report AMP XI.S8 recommends using American Society for Testing and Materials (ASTM) D 5163, in as much as it defines the Service Level 1 NOC-AE-12002797 Page 21 of 24 coating inspection frequency to be each refueling outage or during other major maintenance outages, as needed. The LRA Section B2.1.39 states that general visual inspections of Service Level 1 coatings are conducted as part of American Society of Mechanical Engineers (ASME)
Section XI, Subsection IWE program and the Structures Monitoring Program at intervals not exceeding five years.
Issue:
The LRA does not state the specific standards used to perform coating assessment (e.g., ASTM D 5163). In addition, the frequency of Service Level 1 coating inspection seems to be inconsistent with the recommendations of the GALL Report.
Request:
Please discuss the standards and/or guidance used (e.g., ASTM standards) to perform coating assessments and discuss the frequency of coating inspections and how it is consistent with the GALL Report.
STPNOC Response:
LRA Appendix B2.1.39 and LRA Basis Document PSCOAT (B2.1.39), Protective Coating Monitoring and Maintenance program, are revised to specify that condition assessments of Service Level 1 coatings inside the containment be performed consistent with the standards provided in ASTM D 5163-08 and NRC Regulatory Guide 1.54, Revision 2, as addressed in NUREG 1801, Rev 2, XI.S8 and are conducted during every refueling outage.
LRA Table A4-1, Appendix A1.39, Appendix B2.1.39 and LRA Basis Document PSCOAT (B2.1.39) are revised to include the following enhancements:
" Parameters monitored or inspected include any visible defects, such as blistering, cracking, flaking, peeling, rusting, and physical damage.
Inspection frequencies, personnel qualifications, inspection plans, inspection methods, and inspection equipment meet the requirements of ASTM D 5163-08.
" A pre-inspection review is performed of the previous two monitoring reports and repair areas are prioritized as either needing repair during the same outage, needing repair during the next available outage, or monitored and re-evaluated in next available outage.
" A standardized coating condition assessment report form includes the identification of coatings found intact with no defects identified, identification of coatings that were not inspected, and the reason why the inspection cannot be conducted.
" A standardized coating condition assessment report includes written and/or photographic documentation of coating inspection areas, failures, and defects.
Destructive/non-destructive tests are performed on an as-needed basis, determined by the Nuclear Coatings Specialist or Coatings Planner.
NOC-AE-12002797 Page 22 of 24 provides the line-in/line-out revision to the changes to LRA Table A4-1, Appendix A1.39, and Appendix B2.1.39.
B2.1.39-2
 
==Background:==
The Standard Review Plan (SRP) -LR Section A. 1.2.3.10 provides guidance on required information for the operating experience program element for aging management programs. In particular, SRP-LR states that the operating experience of AMPs that are existing programs, including past corrective actions information operating resulting in program enhancements or additional programs, should be included in this program element. This information can show where an existing program has succeeded and where it has failed (if at all) in intercepting aging degradation in a timely manner.
The LRA operating experience program element gives a general overview of the program and does not provide specific instances of degradation and its associated repair or other corrective actions performed.
Issue:
The staff does not have adequate information in the LRA operating experience program element to determine whether this program element is acceptable.
Request:
Please discuss any instances of degradation and repair of Service Level 1 coatings. In addition, provide information that demonstrates the effectiveness of corrective actions performed.
STPNOC Response:
The STP Service Level I coatings program owner and coatings planner are qualified Nuclear Coatings Specialists in accordance with ASTM D 7108-05 and actively participate in industry sponsored training and conferences. STP participates in industry benchmarking and in nuclear power plant coatings self-assessments, and attends The National Association of Corrosion Engineers (NACE) and Electric Power Research Institute (EPRI) webcasts. Through the above activities, industry issues and operating experience are shared and drawn upon to maintain and enhance the STP Service Level I coatings program.
Unit 1 reactor containment building - Service Level 1 Coating Degradations and Repair Examples Cracks were identified in the concrete coating on the knockout block wall at the -11 foot elevation in 1992. The coating degradation was characterized as a minor crack less than 30 mils in width and not associated with delamination. The degraded coatings were repaired in November, 1993 in accordance with safety-related coatings specification 3C080AS1001.
NOC-AE-12002797 Page 23 of 24 Mechanical damage to concrete floor coatings at the equipment tugger shaft between columns C5 and C6 at the -11 foot elevation were identified. The coatings degradation was characterized as mechanical damage. Repairs to the degraded floor coatings were made during the next scheduled refueling outage (1RE05) in March 1995 in accordance with safety-related coatings specification 3CO80AS1001.
Indications on the containment liner plate at the -11, 19, 37, 52, and 68 foot elevations were identified when performing IWE surveillance testing during refueling outage (1 RE1 1) in April, 2003. The coating degradations were characterized as mechanical damage with a total area less than 30 square inches. The degraded coatings were cleaned and repaired during the next scheduled refueling outage (1RE12) in March, 2005 in accordance with safety-related coatings specification 3C080AS1001.
Surface corrosion on hanger support CC-1214-RR-010 at the -11 foot elevation was identified while performing a coatings condition assessment walkdown during refueling outage 1RE15 in November, 2009. The coatings degradation was characterized as minor surface rusting due to condensation. Repairs to degraded coatings were made during the subsequent scheduled outage (1RE16) in April, 2011 in accordance with the safety-related coatings specification 3C080AS1001.
During a refueling outage (1 RE09) in May 2000, an indication of approximately 4 inches by 8 inches on the containment liner plate at the 270 degree azimuth near the 84 foot elevation was identified near the reactor vessel head lift rig. An investigation determined that the outer coating was removed with the primed surface below exposed with no signs of corrosion or further coating deterioration noted. The condition was found acceptable as-is. The indication was re-evaluated the following refueling outage during a coatings condition assessment walkdown and found to be approximately the same size and color (i.e., dark primer coat) as the condition identified in May 2000. The indication shows no signs of corrosion and no streaks of rust on the liner plate below. The indication will be monitored and re-evaluated during the refueling outage in November 2012 (1RE17).
Unit 2 reactor containment building - Service Level 1 Coatings Degradations and Repair Examples Minor surface corrosion on the liner plate at the interface of the liner plate and concrete basemat at the -11 foot elevation was identified in April, 2000. Coatings degradation was characterized as minor rusting. Repairs to degraded coatings were made in June, 2000 in accordance with safety-related coatings specification 3C080AS1001.
Minor surface corrosion at the interface of column C8 and the ceiling at 206 degree azimuth and the -11 foot elevation was identified in February 2005. Coatings degradation was characterized as minor rusting due to condensation. The area of degraded coatings was cleaned and repaired during the subsequent scheduled refueling outage (2RE1 1) in October, 2005 in accordance with safety-related coatings specification 3C080AS1001.
NOC-AE-12002797 Page 24 of 24 Mechanical damage to coatings at a 20 inch penetration east of the 270 degree azimuth at 47 foot elevation and at a ten inch penetration west of the 270 degree azimuth at the 47 foot elevation was identified while performing a coatings condition assessment walkdown during a refueling outage (2RE1 1) in October, 2005. The coatings degradation was characterized as mechanical damage of less than one square foot for each penetration. Repairs to the degraded coatings at both penetrations were made during the subsequent scheduled refueling outage (2RE12) in April, 2007 in accordance with safety-related coatings specification 3CO80AS1001.
A crack in the concrete coating on the secondary wall approximately six inches from the floor at the 159 degree azimuth at the -11 foot elevation was identified while performing a coatings condition assessment walkdown during a refueling outage (2RE12) in April, 2007). The coatings degradation was characterized as a minor isolated crack measuring less than 30 mils in width and meeting the coatings specification criteria for cosmetic repair. The coating repairs were made during the subsequent scheduled refueling outage (2RE1 3) in October, 2008. The cosmetic repair was made in accordance with design change notice 9604087 to Specification 2A010CS1009, which allows the use of concressive paste as an approved concrete surfacer for cosmetic repairs in the reactor containment building.
Minor surface rusting on bolts at base support of columns located at the 106, 127 and 139 degree azimuths at the -11 foot elevation was identified while performing a coatings condition assessment walkdown during a refueling outage (2RE14) in May, 2010.
Coatings degradation was characterized as minor rusting. Repairs to degraded coatings were made during the subsequent scheduled refueling outage (2RE15) in November, 2011 in accordance with safety-related coatings specification 3C080AS1001.
Summary Service Level 1 coatings are inspected during Coating Condition Assessment Walkdowns, IWE Inspections, Structures Monitoring Program Inspections and in response to the STP Condition Reporting Process for those degraded coating conditions previously identified.
The "Service Level 1 Coatings Degradations and Repair Examples" listed above are representative of the coating failures identified in Unit 1 and Unit 2 reactor containment buildings. Historically, Service Level 1 coating failures include mechanical damage, minor isolated cracking measuring less than 30 mils in width, and minor surface rusting.
The potential for an adverse impact on the function of the Emergency Core Cooling System and the Containment Spray System following a loss-of-coolant accident because of Service Level 1 coating degradation is extremely unlikely based on the Service Level 1 coating degradation identified to date and the timely corrective action taken. Flaking, peeling, blistering and delamination of Service Level 1 coatings that have the potential to block sumps and strainers have not been experienced at STP.
NOC-AE-12002797 STPNOC LRA Changes with Line-in/Line-out Annotations NOC-AE-12002797 Page 1 of 63 List of Revised LRA Sections RAI Affected LRA Section B2.1.6-1a A1.6 B2.1.6 3.1.1.80-1a Table 3.1.1 Table 3.1.2-1 Section 3.1.2.2.6 Section 3.1.2.2.9 Section 3.1.2.2.12 Section 3.1.2.2.15 Section 3.1.2.2.17 Appendix A1.35 Appendix B2.1.35 Table A4-1 (See Enclosure 3) 3.1.1.80-1b Table 3.1.2-1 3.1.2.1-1a Appendix B2.1.35 3.0-1a Section 3.3.2.1.8 Section 3.3.2.1.16 Section 3.3.2.2.10.5 Table 3.3.2-8 Table 3.3.2-9 Table 3.3.2-10 Table 3.3.2-11 Table 3.3.2-12 Table 3.3.2-15 Table 3.3.2-16 Table 3.3.2-20 Table 3.3.2-23 Table 3.4.2-1 A1-1 Appendix Al Table A4-1 (See Enclosure 3) 3.3.2.2.4-1a Appendix Al.16 Appendix B2.1.16 B2.1.39-1 Appendix A1.39 Appendix B2.1.39 Table A4-1 (See Enclosure 3)
NOC-AE-12002797 Page 2 of 63 A1.6 FLOW-ACCELERATED CORROSION The Flow-Accelerated Corrosion (FAC) program manages wall thinning due to flow-accelerated corrosion on the internal surfaces of carbon or low alloy steel piping and system components which contain high energy fluids (both single phase and two phase). The FAC program also manages wall thinning due to other causes, such as erosion/corrosion, cavitation, flashing, and impingement damage.
The objectives of the FAC program are achieved by (a) identifying system components susceptible to wall thinning due to FAC or causes such as erosion/corrosion, cavitation, flashing, and impingement damagesT (b) performing an analysis using a predictive code such as CHECWORKS to determine critical locations for inspection and evaluation of components that can be modeled:
(c) using operating experience and engineering evaluation to determine inspection locations for components which cannot be modeled by the predictive code, including components susceptible to wall thinning due to causes such as erosion/corrosion, cavitation, flashing, and impingement damage; (d) (_)providing guidance for follow-up inspections--.
(4) (e) repairing or replacing components, as determined by the guidance provided by the program-- and
() ff) continual evaluation and incorporation of the latest technologies, industry and plant in-house operating experience.
Procedures and methods used by the FAC program are consistent with STP commitments to NRC Bulletin 87-01, Thinning of Pipe Wall in Nuclear Power Plants, and NRC Generic Letter 89-08, Erosion/Corrosion-Induced Pipe Wall Thinning. The program relies on implementation of the EPRI guidelines of NSAC-202L, Recommendations for an Effective Flow Accelerated Corrosion Program.
NOC-AE-12002797 Page 3 of 63 B2.1.6 Flow-Accelerated Corrosion Program Description The Flow-Accelerated Corrosion (FAC) program manages wall thinning due to flow-accelerated corrosion on the internal surfaces of carbon or low alloy steel piping and system components which contain high energy fluids (both single phase and two phase). The program also manages wall thinning due to other causes, such as erosion/corrosion, cavitation, flashing, and impingement damage. The program implements the EPRI guidelines in NSAC-202L-R3 to detect, measure, monitor, predict and mitigate component wall thinning due to FAC. To aid in the planning of inspections and choosing inspection locations, STP utilizes the EPRI predictive computer program CHECWORKS for components which can be modeled. Inspection locations for components which can not be modeled by CHECWORKS are selected based on engineering evaluation and operating experience. that u*.. the implementation guid.nce o.
NSAG 2021 R3.
System components susceptible to wall thinning due to causes such as erosion/corrosion, cavitation, flashing, and impingement damage are also included in the program and are selected for inspection based on engineering evaluation and operating experience.
The objectives of the FAC program at STP are achieved by (a) identifying system components susceptible to wall thinning due to FAC or causes such as erosion/corrosion, cavitation, flashing, and impingement damage;:
(b) performing analyses using the predictive code CHECWORKS to determine critical locations for inspection and evaluation of components that can be modeled:T (c) using operating experience and engineering evaluation to determine inspection locations for components which cannot be modeled or are susceptible to wall thinning due to causes such as erosion/corrosion, cavitation, flashing, and impingement damage:
(-) (d) providing guidance for follow up inspections.-7 (4) (e) repairing, replacing, or performing evaluations for components not acceptable for continued service, based on the wear rates and minimum acceptable design thickness;--and (e)-(fl evaluating and incorporating the latest technologies, industry and plant in-house operating experience.
Procedures and methods used by the FAC program are consistent with STP commitments to NRC Bulletin 87-01, Thinning of Pipe Wall in Nuclear Power Plants, and NRC Generic Letter 89-08, Erosion/Corrosion-Induced Pipe Wall Thinning.
NUREG-1801 Consistency The Flow-Accelerated Corrosion program is an existing program that is consistent, with exception, to NUREG-1801, Section XI.M17, Flow-Accelerated Corrosion.
NOC-AE-12002797 Page 4 of 63 Exceptions to NUREG-1801 Scope of Program (Element 1) and Detection of Aging Effects (Element 4)
NUREG-1801, Section XI.M17 indicates the Flow-Accelerated Corrosion program relies on implementation of EPRI guidelines in NSAC-202L-R2. However, STP uses the recommendations provided in the EPRI Guideline NSAC-202L-R3. The new revision of EPRI guidelines incorporates lessons learned and improvements to detection, modeling, and mitigation technologies that became available since Revision 2 was published. The updated recommendations are intended to refine and enhance those of previous revisions without contradictions to ensure continuity of existing plant FAC programs.
Scope of Program (Element1), Parameters Monitored or Inspected (Element 3). Detection of Aging Effects (Element 4), Monitoring and Trending (Element 5), Acceptance Criteria (Element 6), and Corrective Action (Element 7)
NUREG-1801, Section XI.M17 states that the FAC program relies on implementation of NSAC-202L-R2 for an effective FAC program. NSAC-202L-R2 addresses wall thinning due to FAC, but not other mechanisms. STP manages wall thinning due to other mechanisms in addition to FAC. Management of wall thinning due to mechanisms in addition to FAC is acceptable because 1) the aging effect of the additional mechanisms, wall thinning, is the same as for FAC, and 2) the management of the additional mechanisms is the same as the management of FAC for lines which cannot be modeled in CHECWORKS.
Enhancements None Operating Experience Review of work orders from 1998 through present showed that there has been no reported FAC-related leak or rupture at STP for the components within the scope of license renewal.
Most of the work orders identified the effect of wall thinning during the FAC program inspections. There were cases where the allowable thickness determined in accordance with the program guidelines was reached and more rigorous stress analyses were performed to justify continued service and to postpone the replacement. Problems identified during implementation of the program activities were not significant to the safe operation of the plant, and adequate corrective actions were taken to prevent recurrence. Industry and plant operating experience have been reviewed for applicability and adjustments have been made to outage inspection lists in accordance with program guidelines.
For refueling outages 1 RE12 through 1 RE14 (April 2008) and 2RE10 through 2RE12, 102 to 112 locations of large-bore systems were selected for inspection before the outage. The scope was expanded when necessary based on UT findings to adiacent components and similar locations in other trains. An inspection location included the subject component (such as an elbow) and its adjacent area (such as upstream and downstream piping). For small-bore systems, 28 to 54 inspections were selected before the outage for RT inspections. The scope was also expanded when necessary based on RT findings. A total of 11 replacements were made in four of these outages, with no replacements in the other two. Scheduling of piping replacements for each outage takes into consideration 1) the projected remaining service life of NOC-AE-12002797 Page 5 of 63 the pipe based on FAC analysis; 2) industry experience of wall thinning for the pipe and its operating environment; and 3) cost of replacement compared to the cost of performing future inspections. The selections of FAC-resistant materials were stainless steel or chrome-moly alloy. Baseline inspections were performed for selected replacement locations of chrome-moly alloy.
Wall thinning due to causes such as erosion/corrosion, cavitation, flashing, and impingement damage has been minimal for systems within the scope of license renewal. Most of the components exhibiting wall thinning due to erosion/corrosion, cavitation, flashing, and impingement damage are in the essential cooling water system, the condensate polisher system, or the circulating water system. The components in the essential cooling water system are managed by the Open-Cycle Cooling Water System program (XI.M20). The circulating water system and most of the components in the condensate polisher system are not within the scope of license renewal.
During 1RE12 (spring., 2005), wall thinning was detected in an elbow downstream of valve AF01 19. The cause of the wall thinning was determined to be erosion, not FAC. Based on the results of the inspection, the elbow was re-inspected in 1 RE1 3 (fall, 2006). This inspection indicated that the remaining life for the elbow was 5.4 EFPY beyond 1 RE1 4, so the next inspection was scheduled for 1 RE17 (fall, 2012).
Based on the system engineers knowledge of the dynamics of the systems and the results of visual inspections during maintenance, components susceptible to wall thinning due to causes such as erosion/corrosion, cavitation, flashing, and impingement damage have been added to the FAC program.
The operating experience of the Flow-Accelerated Corrosion program demonstrates that the program effectively monitors and trends the aging effects of wall thinning. Appropriate corrective action is taken prior to loss of intended function. Wall thinning occurrences identified under the Flow-Accelerated Corrosion program are evaluated to ensure there is no significant impact to safe operation of the plant, and corrective action is taken to prevent recurrence.
Guidance for re-evaluation, repair, or replacement is provided for locations where aging is found. There is confidence that the continued implementation of the Flow-Accelerated Corrosion program will effectively manage aging prior to loss of intended function.
Conclusion The continued implementation of the Flow-Accelerated Corrosion program provides reasonable assurance that aging effects will be managed such 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.
NOC-AE-12002797 Page 6 of 63 Table 3.1.1 Summary of Aging Management Evaluations in Chapter IV of NUREG-1801 for Reactor Vessel, Internals, and Reactor Coolant System Item Component Type Aging Effect / Mechanism Aging Management Further Discussion Number Program Evaluation I Recommended 3.1.1.30 Stainless steel reactor Cracking due to stress Water Chemistry (B2.1.2) and No Consistent with NUREG vessel internals corrosion cracking, irradiation-FSAR supplement 1801 for material, components (e.g.,
assisted stress corrosion commitment to (1) participate environment, and aging Upper internals cracking in industry RVI aging effect, but different AMPs are assembly, RCCA guide programs (2) implement credited: Water Chemistry tube assemblies, applicable results (3) submit program (B2.1.2) augmented Baffle/former for NRC approval > 24 by the plant-specific aging assembly, Lower months before the extended management program PWR internal assembly, period an RVI inspection plan Reactor Internals (B2.1.35).
shroud assemblies, based on industry Consistent with EPRI Plenum cover and recommendation.
1022863 101656-(MRP-plenum cylinder, Upper 227-A), cracking is managed grid assembly, Control by ASME Section XI rod guide tube (CRGT)
Inservice Inspection for assembly, Core selected components.
support shield
**See further evaluation in assembly, Core barrel Section 3.1.2.2.12.
assembly, Lower grid assembly, Flow distributor assembly, Thermal shield, Instrumentation support structures)
NOC-AE-1 2002797 Page 7 of 63 Item Component Type Aging Effect / Mechanism Aging Management Further Discussion Number Program Evaluation Recommended 3.1.1.37 Stainless steel and nickel alloy reactor vessel internals components (e.g.,
Upper internals assembly, RCCA guide tube assemblies, Lower internal assembly, CEA shroud assemblies, Core shroud assembly, Core support shield assembly, Core barrel assembly, Lower grid assembly, Flow distributor assembly)
Cracking due to stress corrosion cracking, primary water stress corrosion cracking, irradiation-assisted stress corrosion cracking Water Chemistry (B2.1.2) and FSAR supplement commitment to (1) participate in industry RVI aging programs (2) implement applicable results (3) submit for NRC approval > 24 months before the extended period an RVI inspection plan based on industry recommendation.
No Consistent with NUREG-1801 for material, environment, and aging effect, but different AMPs are credited: Water Chemistry program (B2.1.2) augmented by the plant-specific aging management program PWR Reactor Internals (B2.1.35).
Consistent with EPRI 1022863 0!6596 (MRP-227-A), cracking is managed by ASME Section XI Inservice Inspection for selected components.
**See further evaluation in Section 3.1.2.2.17.
NOC-AE-12002797 Page 8 of 63 Table 3.1.2-1 Reactor Vessel, Internals, and Reactor Coolant System - Summary of Aging Management Evaluation - Reactor Vessel and Internals (Continued)
Component Type Intended Material Environment Aging Effect Aging Management NUREG-Table I Notes Function Requiring Program 1801 Vol.
Item Management 2 Item RVI Upper Core SS Stainless Reactor Coolant None None IV.B2-41 3.1.1.33 I, 4 Support-Upper Steel (Ext)
Core Plate RVI Upper Core SS Stainless Reactor Coolant Loss of material PWR Reactor Internals IV.B2-34 3.1.1.63 E, 3 Support-Upper Steel (Ext)
(B2.1.35)
Core Plate RVI Upper Core SS Stainless Reactor Coolant Cracking ASME S9etion Xl IV.B2-42 3.1.1.30 E, 35 Support-Upper Steel (Ext) n..r...
Insp'ction, Core Plate Subsections IWB, !WC, and IWD (12, ".A)Water Chemistry (B2.1.2) and PWR Reactor Internals (B2.1.35)_
RVI Upper Core SS Stainless Reactor Coolant Cumulative Time-Limited Aging IV.B2-31 3.1.1.05 A
Support-Upper Steel (Ext) fatigue damage Analysis evaluated for Support Column the period of extended
_operation RVI ICI Support SS Stainless Reactor Coolant Cracking Water Chemistry IV.B2-12 3.1.1.30 E, 3 Structures-lnstr Steel (Ext)
(B2.1.2) and PWR Column (BMI)
Reactor Internals (B2.1.35)
RVI ICI Support SS Stainless Reactor Coolant Loss of fracture PWR Reactor Internals IV.B2-9 3.1.1.22 E. 3 Structures-lnstr Steel (Ext) toughness (B2.1.35)
Column (BMI)
RVI ICI Support SS Stainless Reactor Coolant Loss of material Water Chemistry IV.B2-32 3.1.1.83 A
Structures-lnstr Steel (Ext)
(B2.1.2)
Column (BMI)
I NOC-AE-1 2002797 Page 9 of 63 3.1.2.2.6 Loss of Fracture Toughness due to Neutron Irradiation Embrittlement and Void Swelling Loss of fracture toughness due to neutron irradiation embrittlement and void swelling for stainless steel reactor internals components exposed to reactor coolant is managed by the plant-specific PWR Reactor Internals program (B2.1.35) based on the guidelines provided in EPRI 1022863 !016596 (MRP-227-A). Consistent with EPRI 1022863 10!596 (MRP-227-A),
loss of fracture toughness is not an applicable aging effect requiring management for the RVI neutron shield panel.
3.1.2.2.9 Loss of Preload due to Stress Relaxation Loss of preload due to stress relaxation for nickel-alloy and stainless steel reactor internals components exposed to reactor coolant is managed by the plant-specific PWR Reactor Internals program (B2.1.35) based on the guidelines provided in EPRI 1022863 1016596 (MRP-227-A).
Consistent with EPRI 1022863 4016596 (MRP-227-A), loss of preload is not an applicable aging effect requiring management for the RVI Lower Core Support-Clevis Insert Bolting and RVI Upper Support Column Bolting.
NOC-AE-12002797 Page 10 of 63 3.1.2.2.12 Cracking due to Stress Corrosion Cracking and Irradiation-Assisted Stress Corrosion Cracking (IASCC)
For managing the aging effect of cracking due to stress corrosion cracking and irradiation-assisted stress corrosion cracking of stainless steel reactor internals components exposed to reactor coolant, Water Chemistry (B2.11.2) is augmented by the plant-specific PWR Reactor Internals program (B2.1.35) based on the guidelines provided in EPRI 1022863 !0!6596 (MRP-227-A). Consistent with EPRI 1022863 1016596 (MRP-227-A), PWR Reactor Internals (B2.1.35) is not an applicable aging program for managing cracking of the following components. Instead, cracking is managed by ASME Section Xl Inservice Inspection (B2. 1.1):
- RVI Hold Down Spring
- RVI Neutron Shield Panel RVI Upper Cro Support UppoIr Core Plate
- RVI Upper Core Support-Upper Support Column
- RVI Upper Core Support-Upper Support Column Base
- RVI Upper Core Support-Upper Support Plate
- RVI Control Rod Guide Tube Guide Plates
- RVI ICI Support Structures - Exit Thermocouples
- RVI ICI Support Structures - Upper/Lower Tie Plates
- RVI Irradiation Specimen Basket
- RVI Lower Core Support - Energy Absorber Assembly NOC-AE-12002797 Page 11 of 63 3.1.2.2.15 Changes in dimensions due to Void Swelling Changes in dimensions due to void swelling for stainless steel reactor internals components exposed to reactor coolant will be managed by the plant-specific PWR Reactor Internals program (B2.1.35) based on the guidelines provided in EPRI 1022863 4016596 (MRP-227-A).
Consistent with EPRI 1022863 4016596 (MRP-227-A), changes in dimension is not an applicable aging effect requiring management for the following components:
- RVI Control Rod Guide Tube Assembly
- RVI Control Rod Guide Tube Bolting
- RVI Control Rod Guide Tube Guide Plates
- RVI Core Barrel Assembly
- RVI Hold Down Spring
- RVI ICI Support Structures-Instrument Column (BMI)
- RVI ICI Support Structures-Upper/Lower Tie Plates
- RVI Lower Core Support Bolts
- RVI Lower Core Support-Clevis Insert Bolting
- RVI Lower Core Support-Core Support Plate Forging
- RVI Neutron Shield Panel
- RVI Radial Support Keys and Clevis Inserts
- RVI Upper Core Plate Guide Pins
- RVI Upper Core Support-Protective Skirt
- RVI Upper Core Support-Upper Core Plate
- RVI Upper Core Support-Upper Support Column
- RVI Upper Core Support-Upper Support Column Base
- RVI Upper Core Support-Upper Support Plate
- RVI Upper Support Column Bolting NOC-AE-1 2002797 Page 12 of 63 3.1.2.2.17 Cracking due to Stress Corrosion Cracking, Primary Water Stress Corrosion Cracking, and Irradiation-Assisted Stress Corrosion Cracking For managing the aging effect of cracking due to stress corrosion cracking, primary water stress corrosion cracking, and irradiation-assisted stress corrosion cracking of stainless steel reactor internals components exposed to reactor coolant, Water Chemistry program (B2.1.2) is augmented by the plant-specific PWR Reactor Internals program (B2.1.35) based on the guidelines provided in EPRI 1022863 !016596 (MRP-227-A). Consistent with EPRI 1022863 1016596 (MRP-227-A), PWR Reactor Internals (B2.1.35) is not an applicable aging management program for managing cracking of the following components. Instead, cracking is managed by ASME Section XI Inservice Inspection (B2. 1.1):
- RVI Lower Core Support-Clevis Insert Bolting
- RVI Radial Support Keys and Clevis Inserts
- RVI Upper Support Column Bolting
- RVI Lower Core Support Bolts NOC-AE-12002797 Page 13 of 63 A1.35 PWR REACTOR INTERNALS The PWR Reactor Internals program manages cracking, loss of material, loss of fracture toughness, dimensional changes, and loss of preload for reactor vessel components that provide a core structural support intended function. The program implements the guidance of EPRI 4016696 1022863, PWR Internals Inspection and Evaluation Guideline (MRP-227-A, Rev
.0) and EPRI 1016609, Inspection Standard for PWR Internals (MRP-228). The program manages aging consistent with the inspection guidance for Westinghouse designated primary components in Table 4-3 of MRP-227-A and Westinghouse designated expansion components in Table 4-6 of MRP-227-A. The expansion components are specified to expand the primary component sample should the indications of the sample be more severe than anticipated. The aging effects of a third set of MRP-227-A internals locations are deemed to be adequately managed by existing program components whose aging is managed consistent with ASME Section XI Table IWB-2500-1, Examination Category B-N-3.
Program examination methods include visual examination (VT-3), enhanced visual examination (EVT-1), volumetric examination, and physical measurements. The program provides both examination acceptance criteria for conditions detected as a result of monitoring the primary components, as well as criteria for expanding examinations to the expansion components when warranted by the level of degradation detected in the primary components. Based on the identified aging effect, and supplemental examinations if required, the disposition process results in an evaluation and determination of whether to accept the condition until the next examination or implement corrective actions. Any detected conditions that do not satisfy the examination acceptance criteria are required to be dispositioned through the corrective action program, which may require repair, replacement, or analytical evaluation for continued service until the next inspection.
The PWR Reactor Internals program is a new program and will be implemented within 24 months after the issuance of EPRI !0!6596 1022863, PWR Internals Inspection and Evaluation Guideline MRP-227-A.
NOC-AE-12002797 Page 14 of 63 B2.1.35 PWR Reactor Internals Program Description The PWR Reactor Internals program manages cracking, loss of material, loss of fracture toughness, dimensional changes, and loss of preload for reactor vessel components that provide a core structural support intended function. The program implements the guidance of EPRI 10465961022863, PWR Internals Inspection and Evaluation Guideline (MRP-227-A) and EPRI 1016609, Inspection Standard for PWR Internals (MRP-228, Rev. 0). The program manages aging consistent with the inspection guidance for Westinghouse designated primary components in Table 4-3 of MRP-227-A, Westinghouse designated expansion components in Table 4-6 of MRP-227-A, and the Westinghouse designated existing components in Table 4-9 of MRP-227-A. Primary components are expected to show the leading indications of the degradation effects. The expansion components are specified to expand the primary component sample should the indications of the sample be more severe than anticipated. The aging effects of a third set of MRP-227-A internals locations are deemed to be adequately managed by existing program components whose aging is managed consistent with ASME Section Xl Table IWB-2500-1, Examination Category B-N-3.
Program examination methods include visual examination (VT-3), enhanced visual examination (EVT-1), volumetric examination, and physical measurements. Bolting ultrasonic examination technical justifications in MRP-228 have demonstrated the indication detection capability to detect loss of integrity of PWR internals bolts, pins, and fasteners, such as baffle-former bolting. For some components, the MRP-227-A_ methodology specifies a focused visual (VT-3) examination, similar to the current ASME Code, Section XI, Examination Category B-N-3 examinations, in order to determine the general mechanical and structural condition of the internals by (a) verifying parameters, such as clearances, settings, and physical displacements; and (b) detecting discontinuities and imperfections, such as loss of integrity at bolted or welded connections, loose or missing parts, debris, corrosion, wear, or erosion. In some cases, VT-3 visual methods are used for the detection of surface cracking when the component material has been shown to be tolerant of easily detected large flaws. In some cases, where even more stringent examinations are required, enhanced visual (EVT-1) examinations or ultrasonic methods of volumetric inspection, are specified for certain selected components and locations.
The program provides both examination acceptance criteria for conditions detected as a result of monitoring the primary components, as well as criteria for expanding examinations to the expansion components when warranted by the level of degradation detected in the primary components. Based on the identified aging effect, and supplemental examinations if required, the disposition process results in an evaluation and determination of whether to accept the condition until the next examination or implement corrective actions. Any detected conditions that do not satisfy the examination acceptance criteria are required to be dispositioned through the corrective action program, which may require repair, replacement, or analytical evaluation for continued service until the next inspection.
The PWR Vessel Internals program is a new program that will be implemented within 24 months after the issuance of MRP-227-A, PWR Internals Inspection and Evaluation Guideline.
The program will include future industry operating experience, as it is incorporated into the future revisions of MRP-227-A, to provide reasonable assurance for long-term integrity of the reactor internals. The reactor vessel internals included in the scope of the PWR Reactor NOC-AE-12002797 Page 15 of 63 Internals program are identified in Element 1. The scope of the program does not include welded attachments to the internal surface of the reactor vessel because these components are managed by the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD program (B2.1.1) (exam category B-N-2) and /or the Nickel-Alloy Aging Management Program (B2.1.34). The scope of the program also does not include BMI flux thimble tubes which are managed by the Flux Thimble Tube Inspection program (B2.1.21).
Aging Management Program Elements The results of an evaluation of each element against the 10 elements described in Appendix A of NUREG-1 800, Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants are provided below.
Scope of Program - Element I The scope of the program applies the guidance in MRP-227-A which provides augmented inspection and flaw evaluation methodology for assuring the functional integrity of Westinghouse reactor vessel internals. The scope of the PWR Reactor Internals program includes components that provide a core structural support intended function and are managed by the Westinghouse designated primary components in Table 4-3 of MRP-227-A and Westinghouse designated expansion components in Table 4-6 of MRP-227-A and applicable MRP-227-A methodology license renewal applicant action items. MRP-227-A Table 4-9 also identifies existing program components whose aging is managed consistent with ASME Section XI Table IWB-2500-1, Examination Category B-N-3.
Primary components are expected to show the leading indications of the degradation effects.
The expansion components are specified to expand the primary component sample should the indications of the sample be more severe than anticipated. The aging effects of a third set of MRP-227-A internals locations are deemed to be adequately managed by existing program components whose aging is managed consistent with ASME Section XI Table IWB-2500-1, Examination Category B-N-3.
The STP reactor vessel internals are divided into the following major component groups: the lower core support assembly (including the entire core barrel assembly, baffle-former assembly, neutron shield panel, core support plate, and energy absorber assembly), the upper core support (UCS) assembly (including the upper support plate, support column, control rod guide tube assembly, upper core plate, and protective skirt), the incore instrumentation support structures (including the instrumentation columns (exit thermocouples), upper/lower tie plates, and instrumentation columns (BMI)), and miscellaneous alignment/interface components (including internals hold-down spring, upper core plate guide pins, and radial support keys including clevis inserts).
The following reactor vessel internals are included in the scope of the PWR Reactor Internals program:
: 1. Control rod guide tube assembly and Bolting Guide plate (cards) [Primary componentl Lower flange welds and adjacent base metal (Addressed in AMR by Component Type of "RVI Control Rod Guide Tube Assembly") [Primary componenti NOC-AE-12002797 Page 16 of 63 Guide Tube Support Pins (Split Pins) (Addressed in AMR by Component Type of "RVI Control Rod Guide Tube Bolting") rExisting programs component]
: 2. Core barrel assembly Upper core barrel flange weld and adjacent base metal (Addressed in AMR by Component Types of "RVI Core Barrel Assembly") [Primary component]
Core barrel assembly-former bolting [Expansion componenti Core barrel flange (Addressed in AMR by Component Types of "RVI Core Barrel Assembly") [Expansion component and Existing programs component]
Core barrel axial welds and adjacent base metal [Expansion component]
Core barrel girth welds and adiacent base metal [Primary component]
Core barrel outlet nozzle welds and adjacent base metal [Expansion component]
Lower core barrel flange weld and adjacent base metal (Addressed in AMR by Component Types of "RVI Core Barrel Assembly") [Primary component]
: 3. Baffle-former assembly and bolting Baffle-edge bolting [Primary component]
Baffle-former bolting [Primary component1 Baffle-former assembly [Primary component]
: 4. Alignment and interfacing components Internals hold-down spring [Primary component]
Radial support key clevis insert bolts rExisting programs component]
Upper core plate guide pins [Existing pro-grams component]
-5. Neutrot~n shield panel (thermal shield arssembly)
: 5. Instrumentation support structures Instrumentation columns - BMI [Expansion component]
: 6. Upper core support assembly Upper core support protective skirt [Existing programs component]
Upper Core Plate [Expansion component]
: 7. Lower Core Support Structure NOC-AE-12002797 Page 17 of 63 Core Support Plate Forging [Expansion component]
The scope of the program also does not include welded attachments to the internal surface of the reactor vessel because these components are managed by the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD program (B2.1.1) (exam category B-N-2) and /or the Nickel-Alloy Aging Management Program (B2.11.34). The scope of the program also does not include BMI flux thimble tubes which are managed by the Flux Thimble Tube Inspection program (B2.1.21).
The STP reactor vessel internals configuration does not include the lower internals assembly (lower support column bodies and lower core plate) noted in MRP-227-A.
The PWR Reactor Internals program is consistent with the following MRP-227-A assumptions (determination of applicability) which are based on PWR representative internals configurations and operational histories.
(1) STP has operated for less than 30 years of operation with high leakage core loading patterns. Operation with high leakage core loading was followed by implementation of a low-leakage fuel management pattern for the remaining operating life.
(2) STP operates at fixed power levels and does not usually vary power based on calendar or load demand schedule.
(3) STP has not implemented any design changes beyond those identified in industry guidance or recommended by Westinghouse.
Preventive Actions - Element 2 The PWR Reactor Intornals program is consistent with the following MRP 227 assumptions (detormination of applicability) which are basod-on; PWR representatiVe internals configuFatioRn and opeFational histories (1) STP has ope.atod for lem s than 30 years of operation with high leakage core loading patterR Operatior with high leakagm oe coreading was foallowed by iopilefmetation of a low loakago fuel management pattern for the remaining operatfing life-.
(2) STPR operates at fixed power levels-and-does not usually var,' power based on calendar or load dem~and schedule1A.
(3) STP has not ipentdany design changes be9yond these4 id-entified in industr,'
guidance or recoFmmended by Wes6tinghouse8.
The PWR Reactor Internals program does net prevent degradation due to aging effects, but provides measures for monitoring to detect the degradation prior to loss of intended function.
Preventive measures to mitigate aging effects such as loss of material and cracking include monitoring and maintaining reactor coolant water chemistry consistent with the guidelines of EPRI TR 1014986, PWR Primary Water Chemistry Guidelines, Volume 1. The primary water chemistry program is described separately in the Water Chemistry program (B2.1.2).
NOC-AE-1 2002797 Page 18 of 63 Parameters Monitored or Inspected - Element 3 The PWR Reactor Internals program monitors the following aging effects by inspection in accordance with the guidance of MRP-227-A or ASME Section XI Category B-N-3:
(1). Cracking Cracking is due to stress corrosion cracking (SCC), primary water stress corrosion cracking (PWSCC), irradiation assisted stress corrosion cracking (IASCC), or fatigue /cyclical loading.
Cracking is monitored with a visual inspection for evidence of surface breaking linear discontinuities or a volumetric examination. Surface examinations may also be used to supplement visual examinations for detection and sizing of surface-breaking discontinuities.
(2). Loss of Material Loss of Material is due to wear. Loss of material is monitored with a visual inspection for gross or abnormal surface conditions.
(3). Loss of Fracture Toughness Loss of fracture toughness is due to thermal aging7 or neutron irradiation embrittlement,-or-Yeid swellig. The impact of loss of fracture toughness is indirectly monitored by using visual or volumetric examination techniques to monitor for cracking and by applying applicable reduced fracture toughness properties in the flaw evaluations if cracking is detected and is extensive enough to warrant a supplemental flaw growth or flaw tolerance evaluation.
(4). Dimensional Changes Dimensional Changes are due to void swelling and irradiation growth, distortion or deflection.
The program supplements visual inspection with physical measurements to monitor for any dimensional changes due to void swelling, irradiation growth, distortion, or deflection.
(5). Loss of Preload Loss of preload is caused by thermal and irradiation-enhanced stress relaxation or creep. Loss of preload is monitored with a visual inspection for gross surface conditions that may be indicative of loosening in applicable bolted, fastened, keyed, or pinned connections.
The PWR Reactor Internals program manages the aging effects noted above consistent with the inspection guidance for Westinghouse designated primary components in Table 4-3 of MRP-227-A and Westinghouse designated expansion components in Table 4-6 of MRP-227-A.
MRP-227-A also identifies Existing Program components whose aging is managed consistent with ASME Section XI Table IWB-2500-1, Examination Category B-N-3. See the component list in element 1 to identify Primary, Expansion, and Existing components.
Detection of Aging Effects - Element 4 The PWR Reactor Internals program detects aging effects through the implementation of the parameters monitored or inspected criteria and bases for Westinghouse designated Primary Components in Table 4-3 of MRP-227-A and for Westinghouse designated Expansion Components in Table 4-6 of MRP-227-A. The aging effects of a third set of MRP-227-A internals locations identified in Table 4-9 of MRP-227-A are deemed to be adequately managed by existing program components whose aging is managed consistent with ASME Section Xl Table IWB-2500-1, Examination Category B-N-3.
NOC-AE-12002797 Page 19 of 63 One hundred percent of the accessible volume/area of each component will be examined for the Primary and Expansion components inspection category components. The minimum examination coverage for primary and expansion inspection categories is 75 percent of the component's total (accessible plus inaccessible) inspection area/volume be examined. When addressing a set of like components (e.g. bolting), the minimum examination coverage for primary and expansion inspection categories is 75 percent of the component's total population of like components (accessible plus inaccessible).
If defects are discovered during the examination, STP enters the information into the STP corrective action program and evaluates whether the results of the examination ensure that the component (or set of components) will continue to meet its intended function under all licensing basis conditions of operation until the next scheduled examination. Engineering evaluations that demonstrate the acceptability of a detected condition will be performed consistent with WCAP-1 7096-NP.
Monitoring and Trending - Element 5 The program provides both examination acceptance criteria (See Element 6) for conditions detected as a result of monitoring the primary components as described in Element 4, as well as criteria for expanding examinations to the expansion components when warranted by the level of degradation detected in the primary components. Based on the identified aging effect, and supplemental examinations if required, the disposition process results in an evaluation and determination of whether to accept the condition until the next examination or implement corrective actions. Any detected conditions that do not satisfy the examination acceptance criteria (See Element 6) are required to be dispositioned through the corrective action program (See Element 7), which may require repair, replacement, or analytical evaluation for continued service until the next inspection.
Acceptance Criteria - Element 6 Examination acceptance for the Primary and Expansion component examinations are consistent with Section 5 of MRP-227-A. ASME Section Xl section IWB-3500 acceptance criteria apply to Existing Programs components. The following examination acceptance criteria apply to the STP reactor vessel internals:
Visual examination (VT-3) and enhanced visual examination (EVT-1)
For existing program components, the ASME Code Section XI, Examination Category B-N-3 provides the following general relevant conditions for the visual (VT-3) examination of removable core support structures.
(1) Structural distortion or displacement of parts to the extent that component function may be
: impaired, (2) Loose, missing, cracked, or fractured parts, bolting, or fasteners, (3) Corrosion or erosion that reduces the nominal section thickness by more than 5 percent, (4) Wear of mating surfaces that may lead to loss of function; and NOC-AE-12002797 Page 20 of 63 (5) Structural degradation of interior attachments such that the original cross-sectional area is reduced more than 5 percent.
In addition, for the visual examinations (VT-3) of Primary and Expansion components, the PWR Reactor Internals program is consistent with the more specific descriptions of relevant conditions provided in Table 5-3 of MRP-227-A. EVT-1 examinations are used for detecting small surface breaking cracks and surface crack length sizing when used in conjunction with sizing aids. EVT-1 examination has been selected to be the appropriate NDE method for detection of cracking in plates or their welded joints. The relevant condition applied for EVT-1 examination is the same as found for cracking in ASME Section XI section 3500 which is crack-like surface breaking indications.
Volumetric examination Individual bolts are accepted (pass/fail acceptance) based on the detection of relevant indications established as part of the examination technical justification. When a relevant indication is detected in the cross-sectional area of the bolt, it is assumed to be non-functional and the indication is recorded. Bolted assemblies are evaluated for acceptance based on meeting a specified number and distribution of functional bolts. Acceptance criteria for volumetric examination of STP reactor internals bolting are consistent with Table 5-3 of MRP-227-A.
Physical Measurements Continued functionality of the internals hold down spring is confirmed by direct physical measurement. The examination acceptance criterion for this measurement is consistent with Table 5-3 of MRP-227-A and requires that the remaining compressible height of the spring shall provide hold-down forces within the plant-specific design tolerance.
Corrective Actions - Element 7 The following corrective actions are available for the disposition of detected conditions that exceed the examination acceptance criteria:
(1) Supplemental examinations to further characterize and potentially dispose of a detected condition consistent with (Section 5.0 of MRP-227)-A; (2) Engineering evaluation that demonstrates the acceptability of a detected condition (SeetieR 6.0 ef MRP 227)-consistent with WCAP-1 7096-NP; (3) Repair, in order to restore a component with a detected condition to acceptable status (ASME Section XI); or (4) Replacement of a component with an unacceptable detected condition (ASME Section Xl)
(5) Other alternative corrective action bases if previously approved or endorsed by the NRC.
Relevant indications failing to meet applicable acceptance criteria are repaired or replaced in accordance with plant procedures. Appropriate codes and standards are specified in both the "ASME Section Xl Repair, Replacement, and Post-Maintenance Pressure Testing" procedure NOC-AE-1 2002797 Page 21 of 63 and in design drawings. Quality assurance requirements for repair and replacement activities are also included in the STP Operations Quality Assurance Plan.
STP site QA procedures, review and approval process, and administrative controls are implemented in accordance with the requirements of 10 CFR 50 Appendix B and are acceptable in addressing corrective actions. The QA program includes elements of corrective action, confirmation process and administrative controls, and is applicable to the safety-related and non-safety related systems, structures, and components that are subject to aging management review.
Confirmation Process - Element 8 STP site QA procedures, review and approval process, and administrative controls are implemented in accordance with the requirements of 10 CFR 50 Appendix B and are acceptable in addressing the confirmation process. The QA program includes elements of corrective action, confirmation process and administrative controls and is applicable to the safety-related and non-safety related systems, structures and components that are subject to aging management review.
Administrative Controls - Element 9 STP site QA procedures, review and approval process, and administrative controls are implemented in accordance with the requirements of 10 CFR 50 Appendix B and are acceptable in addressing administrative controls. The QA program includes elements of corrective action, confirmation process and administrative controls and is applicable to the safety-related and non-safety related systems, structures and components that are subject to aging management review.
Operating Experience -
Element 10 Relatively few incidents of PWR internals aging degradation have been reported in operating U.S. commercial PWR plants. However, a considerable amount of PWR internals aging degradation has been observed in European PWRs, with emphasis on cracking of baffle-former bolting. The experience reviewed includes NRC Information Notice 84-18, Stress Corrosion Cracking in PWR Systems and NRC Information Notice 98-11, Cracking of Reactor Vessel Internal Baffle Former Bolts in Foreign Plants. Most of the industry operating experience reviewed has involved cracking of austenitic stainless steel baffle-former bolts, or SCC of high-strength internals bolting. SCC of control rod guide tube split pins has also been reported.
Several other items with existing or suspected material degradation concerns that have been identified for PWR components are wear in thimble tubes and potentially in control guide cards and observed cracking in some high-strength bolting and in control rod guide tube alignment (split) pins. The latter are conditions that have been corrected primarily through bolt replacement with less susceptible material and improved control of pre-load.
Based on industry operating experience, STP replaced the Alloy-750 guide tube support pins (split pins) with strained hardened (cold worked) 316 stainless steel pins during Refueling Outage 1RE12 (Spring 2005) for Unit 1 and Refueling Outage 2RE11 (Fall 2005) for Unit 2.
The replacement was conducted to reduce the susceptibility for stress corrosion cracking in the split pins. There were no cracked Alloy X-750 pins discovered during the replacement process.
NOC-AE-12002797 Page 22 of 63 The ASME Code, Section XI, Examination Category B-N-3 examinations of core support structures conducted during Refueling Outage 1RE15 (Fall 2009) for Unit 1, and Refueling Outage 2RE14 (Spring 2010) for Unit 2, did not identify any conditions that required repair, replacement or evaluation.
The ISI Program portion of the PWR Reactor Internals program at STP is updated to account for industry operating experience. ASME Section XI is also revised every three years and addenda issued in the interim, which allows the code to be updated to reflect operating experience. The requirement to update the IS[ Program to reference more recent editions of ASME Section XI at the end of each inspection interval ensures the IS[ Program reflects enhancements due to operating experience that have been incorporated into ASME Section XI.
With exception of the ASME Section ISI portions, the PWR Reactor Internals program will be a new program and has no direct programmatic history. A key element of the MRP-227-A program is the reporting of aging of reactor vessel components. STP, through its participation in PWR Owners Group and EPRI-MRP activities, will continue to benefit from the reporting of inspection information and will share its own operating experience with the industry through those groups or INPO, as appropriate.
As additional Industry and applicable plant-specific operating experience become available, the OE will be evaluated and appropriately incorporated into the program through the STP Corrective Action and Operating Experience Programs. This ongoing review of OE will continue throughout the period of extended operation, and the results will be maintained on site.
This process will confirm the effectiveness of this new license renewal aging management program by incorporating applicable OE and performing self assessments of the program.
Conclusion The implementation of the PWR Reactor Internals program provides reasonable assurance that aging effects will be adequately managed such 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.
NOC-AE-1 2002797 Page 23 of 63 3.3.2.1.8 Primary Process Sampling System Materials The materials of construction for the primary process sampling system component types are:
Carbon Steel Stainless Steel Environment The primary process sampling system component types are exposed to the following environments:
Borated Water Leakage Closed-Cycle Cooling Water Demineralized Water Plant Indoor Air Treated Borated Water Aging Effects Requiring Management The following primary process sampling system aging effects require management:
Cracking Loss of material Loss of preload Aging Management Programs The following aging management programs manage the aging effects for the primary process sampling system component types:
Bolting Integrity (B2.1.7)
Boric Acid Corrosion (B2.1.4)
Closed-Cycle Cooling Water System (B2.1.10)
External Surfaces Monitoring Program (B2.1.20)
Inspection of Internal Surfaces in Miscellaneous Piping and Ductinq Components (B2.1.22)
One-Time Inspection (B2.1.16)
Water Chemistry (B2.1.2)
NOC-AE-1 2002797 Page 24 of 63 3.3.2.1.16 Containment Hydrogen Monitoring and Combustible Gas Control System Materials The materials of construction for the containment hydrogen monitoring and combustible gas control system component types are:
Glass Stainless Steel Environment The containment hydrogen monitoring and combustible gas control system component types are exposed to the following environment:
Plant Indoor Air Aging Effects Requiring Management The following containment hydrogen monitoring and combustible gas control system aging effects require management:
Loss of material Loss of preload Aging Management Programs The following aging management programs manage the aging effects for the containment hydrogen monitoring and combustible gas control system component types:
Bolting Integrity (B2.1.7)
Inspection of Internal Surfaces in Miscellaneous Pipinq and Ductinq Components (B2.1.22)
NOC-AE-12002797 Page 25 of 63 3.3.2.2,10.5 HVAC aluminum piping and components and stainless steel ducting and components exposed to condensation The inSPec-tion of Inona uraesi iscellaaneous Piping and Duc~ting Components program (1B2.1.22) managos the lo-s*sof m-Aterial from pitting an creice cr-rosio for st;i0nl-es stol aRd aluminum into-rnAl; surfacosr exposeqd to otlto atmosphFro anAd cond-ensation.
Condensation applies to both internal and external environments for HVAC aluminum piping and components and stainless steel ducting and components.
The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program (B2.1.22) manages the loss of material from pitting and crevice corrosion for stainless steel and aluminum internal surfaces exposed to ventilation atmosphere and condensation.
The External Surfaces Monitoring Program (B2.1.20) manages the loss of material from pitting and crevice corrosion for stainless steel and aluminum external surfaces exposed to plant indoor air and condensation.
NOC-AE-12002797 Page 26 of 63 I able 3..32-8 Auxiliary Systems - Summary ot Agin g Management Evaluation - Primary Process Samp ling System (Continued)
Component Intended Material Environment Aging Effect Aging Management NUREG-Table I Item Notes Type Function Requiring Program 1801 Vol.
Management 2 Item Valve LBS, PB, Stainless Plant Indoor Air None None VII.J-15 3.3.1.94 A
SIA Steel (Ext)_
Valve LBS, PB, Stainless Plant Indoor Air Nene Loss of Nene-Insoection of NeRe Nne E, GE 2 SIA Steel (Int) material Internal Surfaces in VII.D-4 3.3.1.54 Miscellaneous Pipinq and Ducting Components (B2.1.22)
Valve LBS, PB, Stainless Treated Borated Loss of material Water Chemistry VII.E1-17 3.3.1.91 E, 1 SIA Steel Water (Int)
(B2.1.2) and One-Time Inspection (B2.1.16)
Notes for Table 3.3.2-8:
Standard Notes:
A Consistent with NUREG-1 801 item for component, material, environment, and aging effect. AMP is consistent with NUREG-1 801 AMP.
B Consistent with NUREG-1 801 item for component, material, environment, and aging effect. AMP takes some exceptions to NUREG-1 801 AMP.
C Component is different, but consistent with NUREG-1801 item for material, environment, and aging effect. AMP is consistent with NUREG-1801 AMP.
E Consistent with NUREG-1 801 for material, environment, and aging effect, but a different aging management program is credited or NUREG-1801 identifies a plant-specific aging management program.
Enironment Anot Nin NUREG;1801 for this compoenet and matorial Plant Specific Notes:
1 The Water Chemistry program (B2.1.2) and the One-Time Inspection program (B2.1.16) manage loss of material due to pitting and crevice corrosion and cracking due to stress corrosion cracking. The One-Time Inspection program (B2.1.16) includes selected components at susceptible locations.
2 B2.1.22, Inspection of Internal Surfaces in Miscellaneous Pipincq and Ducting Components, is used because this is an a-qingq mechanism which occurs on the internal surfaces of these components.
NOC-AE-12002797 Page 27 of 63 Tnhl,'I I 1)_0 A # viIon, Q,,e'*&#xfd;mo -
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/I y./I. II UII VIIIL j.I Component Type Intended Material Environment Aging Effect Aging Management NUREG-Table I Notes Function Requiring Program 1801 Vol.
Item Management 2 Item Flow Element LBS Stainless Closed Cycle Loss of material Closed-Cycle Cooling VII.C2-10 3.3.1.50 B
Steel Cooling Water Water System (Intt)
(132. 1.10)
Flow Element LBS Stainless Plant Indoor Air None Loss of
_NeneExternal Surfaces VWj-15 3.3..
AE Steel (Ext) material Monitoring Program VII.F2-1 3.3.1.27 (B2.1.20)
Heat Exchanger PB Carbon Borated Water Loss of material Boric Acid Corrosion VI.I-10 3.3.1.89 A
(AHU Condenser)
Steel Leakage (Ext) 1 (B2.1.4)
Strainer LBS Carbon Closed Cycle Loss of material Closed-Cycle Cooling VII.F2-18 3.3.1.47 B
Steel Cooling Water Water System (Galvanized) _(Int)
_(B2.1.10)
Strainer LBS Carbon Plant Indoor Air None Loss of None External Surfaces VIJ-6 34..2 A B Steel (Ext) material Monitoring Program VII.F2-2 3.3.1.56 (Galvanized) 1 (B2.1.20)
Tank LBS, PB, Carbon Borated Water Loss of material Boric Acid Corrosion VII.I-10 3.3.1.89 A
SIA Steel Leakage (Ext)
(B2.1.4)
Tank PB Stainless Lubricating Oil Loss of material Lubricating Oil Analysis VII.C2-12 3.3.1.33 B
Steel (Int)
(B2.1.23) and One-Time Inspection (B2.1.16)
Tank PB Stainless Plant Indoor Air None Loss of None External Surfaces VWIJ-15 34.94 A E Steel (Ext) material Monitoring Program VII.F2-1 3.3.1.27
_________(B2.1
.20)
Thermowell PB Stainless Dry Gas (Int)
None None VII.J-19 3.3.1.97 A
Steel Thermowell PB Stainless Plant Indoor Air None Loss of Nene External Surfaces VWIj 15 1-A4 A E Steel (Ext) material Monitoring Program VII.F2-1 3.3.1.27
_(B2.1.20)
NOC-AE-12002797 Page 28 of 63 Tohiln z Q 1_
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Component Type Intended Material Environment Aging Effect Aging Management NUREG-Table I Notes Function Requiring Program 1801 Vol.
Item I
Management 2 Item Tubing LBS, PB Stainless Closed Cycle Loss of material Closed-Cycle Cooling VII.C2-10 3.3.1.50 B
Steel Cooling Water Water System (Int)
((B2.1.10)
Tubing PB Stainless Dry Gas (Int)
None None VII.J-19 3.3.1.97 A
_ Steel Tubing PB Stainless Lubricating Oil Loss of material Lubricating Oil Analysis VII.C2-12 3.3.1.33 B
Steel (Int)
(B2.1.23) and One-Time Inspection (B2.1.16)
Tubing LBS, PB Stainless Plant Indoor Air Neoe Loss of None External Surfaces V* J-15 3.34.94 A E Steel (Ext) material Monitoring Program VII.F2-1 3.3.1.27 (B2.1.20)
Valve LBS, PB, Carbon Closed Cycle Loss of material Closed-Cycle Cooling VII.F2-18 3.3.1.47 B
SIA Steel Cooling Water Water System (Int)
(B2.1.10)
NOC-AE-1 2002797 Page 29 of 63 Notes for Table 3.3.2-9:
Standard Notes:
A Consistent with NUREG-1801 item for component, material, environment, and aging effect. AMP is consistent with NUREG-1801 AMP.
B Consistent with NUREG-1 801 item for component, material, environment, and aging effect. AMP takes some exceptions to NUREG-1 801 AMP.
E Consistent with NUREG-1 801 for material, environment, and aging effect, but a different aging management program is credited or NUREG-1 801 identifies a plant-specific aging management proqram.
F Material not in NUREG-1 801 for this component.
H Aging effect not in NUREG-1 801 for this component, material and environment combination.
Plant Specific Notes:
1 Wall thinning due to erosion-corrosion is managed by the Flow-Accelerated Corrosion program (B2.1.6)
NOC-AE-12002797 Page 30 of 63 Table 3.3.2-10 Auxiliary Systems - Summary of Aging Management Evaluation - Electrical Auxiliary Building and Control Room HVAC System (Continued)
Component Intended Material Environment Aging Effect Aging Management NUREG-Table I Item Notes Type Function Requiring Program 1801 Vol.
Management 2 Item Damper FB, PB Carbon Steel Encased in None None VII.J-21 3.3.1.96 C
(Galvanized) Concrete (Ext)
Damper FB, PB Carbon Steel Plant Indoor Air Nene Loss of NeOe External Surfaces Vl-IJ-6 3..92 G B (Galvanized) (Ext) material Monitoring Program VII.F1-2 3.3.1.56 (B2.1.20)
Damper FB, PB Carbon Steel Ventilation Loss of material Inspection of Internal VII.F1-3 3.3.1.72 B
(Galvanized) Atmosphere (Int)
Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22)
Ductwork PB Carbon Steel Ventilation Loss of material Inspection of Internal VII.F2-3 3.3.1.72 B
Atmosphere (Int)
Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22)
Ductwork LBS, PB Carbon Steel Plant Indoor Air None Loss of Nene External Surfaces VWJ-6 3.31.92 G B (Galvanized) (Ext) material Monitoring Program VII.F1-2 3.3.1.56 1_
1__
1__
_(B2.1.20)
I I
Ductwork PB Carbon Steel (Galvanized)
Ventilation Atmosphere (Int)
Loss of material Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.11.22)
VII.F1-3 3.3.1.72 B
NOC-AE-12002797 Page 31 of 63 Table 3.3.2-10 Auxiliary Systems - Summary of Aging Management Evaluation - Electrical Auxiliary Building and Control Room HVAC Sv~te~m (Continuted)
VAC R Z...
Component Intended Material Environment Aging Effect Aging Management NUREG-Table I Item Notes Type Function Requiring Program 1801 Vol.
I Management
__2 Item Ductwork PB Carbon Steel Ventilation Loss of material Inspection of Internal VII.F2-3 3.3.1.72 B
(Galvanized) Atmosphere (Int)
Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22L Ductwork PB Stainless Plant Indoor Air None Loss of Nene External Surfaces V~kJ 6 3.3.94 G E Steel (Ext) material Monitoring Procqram VII.F1-1 3.3.1.27 (B2.1.20)
Ductwork LBS Stainless Ventilation Loss of material Inspection of Internal VII.F2-1 3.3.1.27 E
Steel Atmosphere (Ext)
Surfaces in Miscellaneous Piping and Ducting Components (B2.11.22)
Ductwork PB Stainless Ventilation Loss of material Inspection of Internal VII.F1-1 3.3.1.27 E
Steel Atmosphere (Int)
Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22)
Ductwork LBS, PB Stainless Ventilation Loss of material Inspection of Internal VII.F2-1 3.3.1.27 E
Steel Atmosphere (Int)
Surfaces in Miscellaneous Piping and Ducting I_
Components (B2.1.22)
Filter PB Carbon Steel Plant Indoor Air None Loss of Nene External Surfaces V44-j 6
3.3..9 G B (Galvanized) (Ext) material Monitoring Program VII.F1-2 3.3.1.56 (B2.1.20)
Filter PB Carbon Steel Ventilation Loss of material Inspection of Internal VII.F1-3 3.3.1.72 B
(Galvanized) Atmosphere (Int)
Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22)
NOC-AE-12002797 Page 32 of 63 Table 3.3.2-10 Auxiliary Systems - Summary of Aging Management Evaluation - Electrical Auxiliary Building and Control Room HVAC System (Continued)
Component Intended Material Environment Aging Effect Aging Management NUREG-Table I Item Notes Type Function Requiring Program 1801 Vol.
Management 2 Item Filter PB Carbon Steel Ventilation Loss of material Inspection of Internal VII.F2-3 3.3.1.72 B
(Galvanized) Atmosphere (Int)
Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22L Filter PB Stainless Plant Indoor Air Nene Loss of Nene External Surfaces V11J-45 3.3..4 CG E Steel (Ext) material Monitoring Program VII.F1-1 3.3.1.27 (B2.1.20)
Filter PB Stainless Ventilation Loss of material Inspection of Internal VII.F1-1 3.3.1.27 E
Steel Atmosphere (Int)
Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22)
Flex PB Elastomer Ventilation Hardening and Inspection of Internal VII.F2-7 3.3.1.11 E
Connectors Atmosphere (Int) loss of strength Surfaces in Miscellaneous Piping and Ducting
_ Components (B2.1.22)
Flow Element PB Carbon Steel Plant Indoor Air NoeR Loss of None External Surfaces V-1-6 3.3..92 CG B (Galvanized) (Ext) material Monitoring Program VII.F1-2 3.3.1.56 (B2.1.20)
Flow Element PB Carbon Steel Ventilation Loss of material Inspection of Internal VII.F1-3 3.3.1.72 B
(Galvanized) Atmosphere (Int)
Surfaces in Miscellaneous Piping and Ducting
;Components (B2.1.22)
NOC-AE-12002797 Page 33 of 63 Table 3.3.2-10 Auxiliary Systems - Summary of Aging Management Evaluation - Electrical Auxiliary Building and Control Room HVAC System (Continued)
Component Intended Material Environment Aging Effect Aging Management NUREG-Table I Item Notes Type Function Requiring Program 1801 Vol.
Management 2 Item Heat LBS Copper Alloy Ventilation Loss of material Inspection of Internal VII.F2-14 3.3.1.25 E
Exchanger Atmosphere (Ext)
Surfaces in (Pen Space Miscellaneous Piping AHU Cooling and Ducting Coil)
Components (B2.1.22)
Heater PB Carbon Steel Plant Indoor Air NeAe Loss of NeGe External Surfaces VIl-6 3.3-1.692 G B (Galvanized) (Ext) material Monitoring Program VII.F1-2 3.3.1.56 (B2.1.20)
Heater PB Carbon Steel Ventilation Loss of material Inspection of Internal VII.F1-3 3.3.1.72 B
(Galvanized) Atmosphere (Int)
Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22)
Heater PB Carbon Steel Ventilation Loss of material Inspection of Internal VII.F2-3 3.3.1.72 B
(Galvanized) Atmosphere (Int)
Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22)
Heater PB Stainless Plant Indoor Air Nee Loss of NeOe External Surfaces V4lA 1-2 31-4 G E Steel (Ext) material Monitoring Program VII.F1-1 3.3.1.27 (B2.1.20)
Heater PB Stainless Ventilation Loss of material Inspection of Internal VII.F2-1 3.3.1.27 E
Steel Atmosphere (Int)
Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22)
NOC-AE-12002797 Page 34 of 63 Table 3.3.2-10 Auxiliary Systems - Summary of Aging Management Evaluation - Electrical Auxiliary Building and Control Room HVAC System (Cont inued)
Component Intended Material Environment Aging Effect Aging Management NUREG-Table I Item Notes Type Function Requiring Program 1801 Vol.
Management 2 Item Piping PB Carbon Steel Ventilation Loss of material Inspection of Internal VII.F2-3 3.3.1.72 D
Atmosphere (Int)
Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22)
Piping PB Carbon Steel Plant Indoor Air Nene Loss of Nene External Surfaces V4bJ-6 3.1.92 G B (Galvanized) (Ext) material Monitoring Pro~gram VII.F1-2 3.3.1.56 (B2.1.20)
Piping PB Carbon Steel Ventilation Loss of material Inspection of Internal VII.F1-3 3.3.1.72 B
(Galvanized) Atmosphere (Int)
Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22)
Piping PB Carbon Steel Ventilation Loss of material Inspection of Internal VII.F2-3 3.3.1.72 B
(Galvanized) Atmosphere (Int)
Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22)
Piping PB Stainless Plant Indoor Air NOee Loss of NOee External Surfaces VJ 34..1.4 A E Steel (Ext) material Monitoring Program VII.F1-1 3.3.1.27 (B2.1.20)
Piping PB Stainless Ventilation Loss of material Inspection of Internal VII.F1-1 3.3.1.27 E
Steel Atmosphere (Int)
Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22)
Piping PB Stainless Ventilation Loss of material Inspection of Internal VII.F2-1 3.3.1.27 E
Steel Atmosphere (Int)
Surfaces in Miscellaneous Piping and Ducting I
I I
I Components (B2.1.22) 1 NOC-AE-1 2002797 Page 35 of 63 Table 3.3.2-10 Auxiliary Systems - Summary of Aging Management Evaluation - Electrical Auxiliary Building and Control Room HVAC System (Continued)
Component Intended Material Environment Aging Effect Aging Management NUREG-Table N
Item otes Type Function Requiring Program 1801 Vol.
.IIManagement 2 Item Silencer PB Carbon Steel Plant Indoor Air Nene Loss of NOee External Surfaces V
6 3.3.-.1.92 G B (Galvanized) (Ext) material Monitoring Program VII.F1-2 3.3.1.56 (B2.1.20)
Silencer PB Carbon Steel Ventilation Loss of material Inspection of Internal VII.F1-3 3.3.1.72 B
(Galvanized) Atmosphere (Int)
Surfaces in Miscellaneous Piping and Ducting
_Components (B2.1.22)
Tubing PB Copper Alloy Ventilation Loss of material Inspection of Internal VII.G-9 3.3.1.28 E
Atmosphere (Int)
Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22)
Tubing PB Stainless Plant Indoor Air NeRe Loss of Nene External Surfaces 3.3..94 A E Steel (Ext) material Monitoring Program VII.F1-1 3.3.1.27 (B2.1.20)
Tubing PB Stainless Ventilation Loss of material Inspection of Internal VII.F1-1 3.3.1.27 E
Steel Atmosphere (Int)
Surfaces in Miscellaneous Piping and Ducting I_
I_
I Components (B2.1.22)
NOC-AE-12002797 Page 36 of 63 Notes for Table 3.3.2-10:
Standard Notes:
A Con.i.tent with IiIr-UREG 1A8-01 for compopnent, material, enVi*r* Me*t, a*d aging efect.-
AMAP i c.ni.tnt with N-",-R.G 1802 AhM."
B Consistent with NUREG-1801 item for component, material, environment, and aging effect. AMP takes some exceptions to NUREG-1801 AMP.
C Component is different, but consistent with NUREG-1801 item for material, environment, and aging effect. AMP is consistent with NUREG-1801 AMP.
D Component is different, but consistent with NUREG-1801 item for material, environment, and aging effect. AMP takes some exceptions to NUREG-1801 AMP.
E Consistent with NUREG-1 801 for material, environment, and aging effect, but a different aging management program is credited or NUREG-1 801 identifies a plant-specific aging management program.
H Aging effect not in NUREG-1 801 for this component, material, and environment combination.
Plant Specific Notes:
1 Loss of preload is conservatively considered to be applicable for all closure bolting.
NOC-AE-12002797 Page 37 of 63 Table 3.3.2-11 Auxiliary Systems - Summary of Aging Management Evaluation - Fuel Handling Building HVAC System (Continued)
Component Intended Material Environment Aging Effect Aging Management NUREG-Table I Item Notes Type Function Requiring Program 1801 Vol.
Management 2 Item Damper FB Carbon Steel Encased in None None VII.J-21 3.3.1.96 A
(Galvanized) Concrete (Ext)
Damper PB Carbon Steel Plant Indoor Air Nene Loss of NOee External Surfaces VW4-6 3.3.1.92 A 13 (Galvanized) (Ext) material Monitorinq Program VII.F2-2 3.3.1.56 (B2.1.20)
Damper FB, PB Carbon Steel Ventilation Loss of material Inspection of Internal VII.F2-3 3.3.1.72 B
(Galvanized) Atmosphere (Int)
Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22)
Ductwork LBS, PB Carbon Steel Plant Indoor Air Neoe Loss of None External Surfaces VWj 6 3...
A B (Galvanized) (Ext) material Monitoring Program VII.F2-2 3.3.1.56 (B2.1.20)
Ductwork LBS Carbon Steel Plant Indoor Air Loss of material Inspection of Internal VII.F2-3 3.3.1.72 B
(Galvanized) (Int)
Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22)
Ductwork PB Carbon Steel Ventilation Loss of material Inspection of Internal VII.F2-3 3.3.1.72 B
(Galvanized) Atmosphere (Int)
Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22)
Ductwork PB Stainless Plant Indoor Air NOne Loss of None External Surfaces V-4, 15 3-3-.-.4 A E Steel (Ext) material Monitoring Program VII.F2-1 3.3.1.27 (B2.1.20)
Ductwork PB Stainless Ventilation Loss of material Inspection of Internal VII.F2-1 3.3.1.27 E
Steel Atmosphere (Int)
Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22)
NOC-AE-1 2002797 Page 38 of 63 Table 3.3.2-11 Auxiliary Systems - Summary of Aging Management Evaluation - Fuel Handling Building HVAC System (Continued)
Component Intended Material Environment Aging Effect Aging Management NUREG-Table I Item Notes Type Function Requiring Program 1801 Vol.
Management 2 Item I
Filter PB Carbon Steel Ventilation Loss of material Inspection of Internal VIL.F2-3 3.3.1.72 B
Atmosphere (Ext)
Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22)
Filter PB Carbon Steel Ventilation Loss of material Inspection of Internal VII.F2-3 3.3.1.72 B
Atmosphere (Int)
Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22)
Filter PB Carbon Steel Plant Indoor Air Neoe Loss of None External Surfaces VI-IA6 3.31.92 A B (Galvanized) (Ext) material Monitoring Program VII.F2-2 3.3.1.56 (B2.11.20)
Filter PB Carbon Steel Ventilation Loss of material Inspection of Internal VII.F2-3 3.3.1.72 B
(Galvanized) Atmosphere (Int)
Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22)
NOC-AE-12002797 Page 39 of 63 Table 3.3.2-11 Auxiliary Systems - Summary of Aging Management Evaluation - Fuel Handling Building HVAC System (Continued)
Component Intended Material Environment Aging Effect Aging Management NUREG-Table I Item Notes Type Function Requiring Program 1801 Vol.
__Management 2 Item Heat HT, LBS, Copper Alloy Ventilation Loss of material Inspection of Internal VII.F2-14 3.3.1.25 E
Exchanger PB Atmosphere (Ext)
Surfaces in (ESF Miscellaneous Piping Equipment and Ducting Room AHU)
Components (B2.1.22)
Heat PB Stainless Plant Indoor Air NeWAe Loss of Nene External Surfaces V4kj-
,=%3-.1.-94 G E Exchanger Steel (Ext) material Monitoring Program VII.F2-1 3.3.1.27 (ESF (B2.1.20)
Equipment Room AHU)
Heat PB Stainless Ventilation Loss of material Inspection of Internal VII.F2-1 3.3.1.27 E
Exchanger Steel Atmosphere (Int)
Surfaces in (ESF Miscellaneous Piping Equipment and Ducting Room AHU)
I I
_Components (B2.1.22) 1 1
Notes for Table 3.3.2-11:
Standard Notes:
A Consistent with NUREG-1801 item for component, material, environment, and aging effect. AMP is consistent with NUREG-1801 AMP.
B Consistent with NUREG-1801 item for component, material, environment, and aging effect. AMP takes some exceptions to NUREG-1801 AMP.
h L v.
I m
+,*...,,
,N.,i.
RV.,.,
A and g
1, I
4904-AMP D
Component is different, but consistent with NUREG-1801 item for material, environment, and aging effect. AMP takes some exceptions to NUREG-1801 AMP.
E Consistent with NUREG-1 801 for material, environment, and aging effect, but a different aging management program is credited or NUREG-1801 identifies a plant-specific aging management program.
Plant Specific Notes:
None NOC-AE-12002797 Page 40 of 63 Table 3.3.2-12 Auxiliary Systems - Summary of Aging Management Evaluation - Mechanical Auxiliary Building HVAC System (Continued)
Component Intended Material Environment Aging Effect Aging Management NUREG-Table I Item Notes Type Function Requiring Program 1801 Vol.
Management 2 Item Damper FB, PB Carbon Steel Encased in None None VII.J-21 3.3.1.96 C
(Galvanized) Concrete (Ext)
Damper PB Carbon Steel Plant Indoor Air NOee Loss of NORe-External Surfaces VI4J--6 3.3.-92 G B (Galvanized) (Ext) material Monitoring Program VII.F2-2 3.3.1.56 (B2.1.20)
Damper FB Carbon Steel Plant Indoor Air Loss of material Inspection of Internal VII.F2-3 3.3.1.72 B
(Galvanized) (Int)
Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22)
Damper FB, PB Carbon Steel Ventilation Loss of material Inspection of Internal VII.F2-3 3.3.1.72 B
(Galvanized) Atmosphere (Int)
Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22)
I Ductwork PB Carbon Steel Plant Indoor Air None Loss of NeOe External Surfaces VIkj-6 33.1.92 G B (Galvanized) (Ext) material Monitoring Program VII.F2-2 3.3.1.56 (B2.1.20)
Ductwork PB Carbon Steel Ventilation Loss of material Inspection of Internal VII.F2-3 3.3.1.72 B
(Galvanized) Atmosphere (Int)
Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22)
Ductwork PB Stainless Plant Indoor Air NeOe Loss of NORe External Surfaces VIkj-15 3..1.94 G E Steel (Ext) material Monitoring Program VII.F2-1 3.3.1.27 (B2.1.20)
Ductwork PB Stainless Plant Indoor Air Loss of material Inspection of Internal VII.F2-1 3.3.1.27 E
Steel (Int)
Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22)
NOC-AE-12002797 Page 41 of 63 Table 3.3.2-15 Auxiliary Systems - Summary of Aging Management Evaluation - Standby Diesel Generator Building HVAC System Component Intended Material Environment Aging Effect Aging Management NUREG-Table I Item Notes Type Function Requiring Program 1801 Vol.
Management 2 Item Damper FB, PB Carbon Steel Ventilation Loss of material Inspection of Internal VII.F4-2 3.3.1.72 B
(Galvanized) Atmosphere (Int)
Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22L Damper PB Stainless Plant Indoor Air None Loss of Neoe External Surfaces V114-14 224 Q4 G E Steel (Ext) material Monitoring Program VII.F2-1 3.3.1.27 S1(B2.11.20)
Damper PB Stainless Ventilation Loss of material Inspection of Internal VII.F2-1 3.3.1.27 E
Steel Atmosphere (Int)
Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22)
Flex PB Elastomer Ventilation Hardening and Inspection of Internal VII.F4-6 3.3.1.11 E
Connectors Atmosphere (Int) loss of strength Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22)
Tubing PB Stainless Plant Indoor Air None Loss of NeRe External Surfaces VI J 45 3.3.1.4 A E Steel (Ext) material Monitoring Program VII.F2-1 3.3.1.27 3(B2.1.20)
Tubing PB Stainless Ventilation Loss of material Inspection of Internal VII.F2-1 3.3.1.27 E
Steel Atmosphere (Int)
Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22)
NOC-AE-1 2002797 Page 42 of 63 Notes for Table 3.3.2-15:
Standard Notes:
A Consistent with NUREG 1801 item for componont, material, environment, and aging effect. AMP iks cnsiStent with NUREG 1801 AMP.
B Consistent with NUREG-1 801 item for component, material, environment, and aging effect. AMP takes some exceptions to NUREG-1 801 AMP.
C Component is different, but consistent with NUREG-1801 item for material, environment, and aging effect. AMP is consistent with NUREG-1801 AMP.
E Consistent with NUREG-1 801 for material, environment, and aging effect, but a different aging management program is credited or NUREG-1 801 identifies a plant-specific aging management program.
Plant Specific Notes:
1 Loss of preload is conservatively considered to be applicable for all closure bolting.
NOC-AE-1 2002797 Page 43 of 63 Table 3.3.2-16 Auxiliary Systems - Summary of Aging Management Evaluation - Containment Hydrogen Monitoring and Combustible Gas Control System Component Intended Material Environment Aging Effect Aging Management NUREG-Table I Item Notes Type Function Requiring Program 1801 Vol.
Management 2 Item Heat HT, PB Stainless Plant Indoor Air None None VII.J-15 3.3.1.94 C
Exchanger Steel (Ext)
(Hydrogen AnallYzer)___r )...
Heat HT, PB Stainless Plant Indoor Air None Loss of None Inspection of None Nee G E Exchanger Steel (Int) material Internal Surfaces in VII.F3-1 3.3.1.27 (Hydrogen Miscellaneous Piping Analyzer) and Ductincq Components (B2.1.22)
Orifice PB, TH Stainless Plant Indoor Air None None VII.J-15 3.3.1.94 A
Steel (Ext)
Orifice PB, TH Stainless Plant Indoor Air Neoe Loss of Neoe Inspection of None None G E Steel (Int) material Internal Surfaces in VII.F3-1 3.3.1.27 Miscellaneous Piping and Ductinq Components (B2.1.22)
Piping PB, SIA Stainless Plant Indoor Air None None VII.J-15 3.3.1.94 A
Steel (Ext)
Piping PB, SIA Stainless Plant Indoor Air None Loss of Noea Inspection of None Nene G E Steel (Int) material Internal Surfaces in VII.F3-1 3.3.1.27 Miscellaneous Piping and Ducting Components (B2.1.22)
Pump PB Stainless Plant Indoor Air None None VII.J-15 3.3.1.94 A
Steel (Ext)
Pump PB Stainless Plant Indoor Air Neoe Loss of None Inspection of None None G E Steel (Int) material Internal Surfaces in VII.F3-1 3.3.1.27 Miscellaneous Piping and Ductinq I______
_Components (B2.1.22) 1 1
NOC-AE-12002797 Page 44 of 63 Table 3.3.2-16 Auxiliary Systems - Summary of Aging Management Evaluation - Containment Hydrogen Monitoring and Combustible Gas Control System (Continued)
Component Intended Material Environment Aging Effect Aging Management NUREG-Table I Item Notes Type Function Requiring Program 1801 Vol.
I Management 2 Item Tubing PB Stainless Plant Indoor Air None None VII.J-15 3.3.1.94
*A Steel (Ext)
Tubing PB Stainless Plant Indoor Air NOee Loss of NOee Inspection of NeRe NeRe G E Steel (Int) material Internal Surfaces in VII.F3-1 3.3.1.27 Miscellaneous Piping and Ductinq Components (B2.1.22)
Valve PB Stainless Plant Indoor Air None None VII.J-15 3.3.1.94 A
Steel (Ext)
Valve PB Stainless Plant Indoor Air Nene Loss of Nene Inspection of Nene Nee G E Steel (Int) material Internal Surfaces in VII.F3-1 3.3.1.27 Miscellaneous Pipinq and Ducting I__
I_
_Components (B2.1.22)
I I
Notes for Table 3.3.2-16:
Standard Notes:
A Consistent with NUREG-1801 item for component, material, environment, and aging effect. AMP is consistent with NUREG-1801 AMP.
C Component is different, but consistent with NUREG-1 801 item for material, environment, and aging effect. AMP is consistent with NUREG-1801 AMP.
E Consistent with NUREG-1 801 for material, environment, and aging effect, but a different aging mana-gement pro-gram is credited or NUJREG-1801 identifies a nlant-sn)ecific anina manaaement nrooram.
NUREG-11 801 identifies a plant-specific aging management proorarn A
I L i....
A A
* J F
*l..
t-nIyplpl Mn AV,
%i lU"Ml-
'I OA-l 4^ r 4f,c.
: nan,
&#xfd;nanna
&#xfd;nflt mla H
Aging effect not in NUREG-1801 for this component, material, and environment combination.
Plant Specific Notes:
1 Loss of preload is conservatively considered to be applicable for all closure bolting.
NOC-AE-1 2002797 Page 45 of 63 Table 3.3.2-20 Auxiliary Systems - Summary of Aging Management Evaluation - Standby Diesel Generator and Auxiliaries (flnntinue!d)
Component Intended Material Environment Aging Effect Aging Management NUREG-Table I Item Notes Type Function Requiring Program 1801 Vol Management 2 Item Expansion PB Stainless Plant Indoor Air None None VII.J-15 3.3.1.94 C
Joint Steel (Ext)
Expansion PB Stainless Plant Indoor Air NeRe Loss of NeFe Inspection of Internal NORe Nene 4,-4 E, 3 Joint Steel (Int) material Surfaces in Miscellaneous VII.D-4 3.3.1.54 Piping and Ducting Components (B2.1.22)
Expansion PB Stainless Raw Water (Int)
Loss of material Open-Cycle Cooling Water VII.H2-18 3.3.1.80 D
Joint Steel System (B2.1.9)
Thermowell PB, SIA Stainless Plant Indoor Air None None VII.J-15 13.3.1.94 A
Steel (Ext)
Thermowell SIA Stainless Plant Indoor Air NOne Loss of NOne Inspection of Internal Noe NRe G-E, 3 Steel (Int) material Surfaces in Miscellaneous VII.D-4 3.3.1.54 Piping and Ductinq Components (B2.1.22)
Thermowell PB Stainless Raw Water (Int)
Loss of material Open-Cycle Cooling Water VII.H2-18 3.3.1.80 B
Steel System (B2.1.9) 1 1
1 Tubing LBS, PB, Stainless Plant Indoor Air None None VII.J-15 3.3.1.94 A
SIA Steel (Ext)
Tubing LBS, PB, Stainless Plant Indoor Air None Loss of None Inspection of Internal Neoe NOne G E 3 SIA Steel (Int) material Surfaces in Miscellaneous VII.D-4 3.3.1.54 Piping and Ducting Components (B2.1.22)
Tubing LBS, PB, Stainless Raw Water (Int)
Loss of material Open-Cycle Cooling Water VII.H2-18 3.3.1.80 B
SIA Steel System (B2.1.9)
NOC-AE-12002797 Page 46 of 63 Table 3.3.2-20 Auxiliary Systems - Summary of Aging Management Evaluation - Standby Diesel Generator and Auxiliaries (Continued)
Component Intended Material Environment Aging Effect Aging Management NUREG-Table I Item Notes Type Function Requiring Program 1801 Vol.
Management 2 Item Valve LBS, PB, Stainless Plant Indoor Air None None VII.J-15 3.3.1.94 A
SIA Steel (Ext)
Valve LBS, PB, Stainless Plant Indoor Air None Loss of None Inspection of Internal None None G E 3 SIA Steel (Int) material Surfaces in Miscellaneous VII.D-4 3.3.1.54 Piping and Ducting Com ponents (B2.1.22)
Notes for Table 3.3.2-20:
Standard Notes:
A Consistent with NUREG-1 801 item for component, material, environment, and aging effect. AMP is consistent with NUREG-1 801 AMP.
B Consistent with NUREG-1 801 item for component, material, environment, and aging effect. AMP takes some exceptions to NUREG-1 801 AMP.
C Component is different, but consistent with NUREG-1801 item for material, environment, and aging effect. AMP is consistent with NUREG-1801 AMP.
D Component is different, but consistent with NUREG-1 801 item for material, environment, and aging effect. AMP takes some exceptions to NUREG-1801 AMP.
E Consistent with NUREG-1 801 for material, environment, and aging effect, but a different aging management program is credited or NUREG-1801 identifies a plant-specific aging management program.
F Material not in NUREG-1801 for this component G
Environment not in NUREG-1 801 for this component and material.
H Aging effect not in NUREG-1801 for this component, material, and environment combination.
Plant Specific Notes:
1 Loss of preload is conservatively considered to be applicable for all closure bolting.
2 Reduction in heat transfer due to fouling is a potential aging effect/mechanism for cast iron (gray cast iron) turbocharger components in closed cycle cooling water.
3 B2.1.22, Inspection of Internal Surfaces in Miscellaneous Pipincq and Ductinq Components, is used because this is an aging mechanism which occurs on the internal surfaces of these components.
NOC-AE-12002797 Page 47 of 63 Table 3.3.2-23 Auxiliary Systems - Summary of Aging Management Evaluation - Radioactive Vents and Drains System (Continued)
Component Intended Material Environment Aging Effect Aging Management NUREG-Table I Item Notes Type Function Requiring Program 1801 Vol.
Management 2 Item Valve LBS, PB, Stainless Plant Indoor Air None None VII.J-15 3.3.1.94 A
SIA Steel (Ext)
Valve LBS, PB Stainless Plant Indoor Air NeRe Loss of NeOe Inspection of Nene Nene G E Steel (Int) material Internal Surfaces in V.A-26 3.2.1.08 Miscellaneous Piping and Ductinq Comronents (B2.1.22)
Valve LBS, PB, Stainless Raw Water (Int)
Loss of material Inspection of Internal VI1.C1-15 3.3.1.79 E, 2 SIA Steel Surfaces in Miscellaneous Piping and Ducting
_Components (B2.1.22L Notes for Table 3.3.2-23:
Standard Notes:
A Consistent with NUREG-1801 item for component, material, environment, and aging effect. AMP is consistent with NUREG-1801 Al B
Consistent with NUREG-1801 item for component, material, environment, and aging effect. AMP takes some exceptions to NUREG AMP.
E Consistent with NUREG-1 801 for material, environment, and aging effect, but a different aging management program is credited or NUREG-1801 identifies a plant-specific aging management program.
EnVironment not in NilURE=G 1801 for this comAPOnent and mfaterial.
MIP.
-1801 H
Aging effect not in NUREG-1 801 for this component, material and environment combination.
Plant Specific Notes:
1 Loss of preload is conservatively considered to be applicable for all closure bolting.
2 The component environment is miscellaneous radioactive waste drains that have been evaluated as a raw water environment. Loss of material on internal component surfaces exposed to a mixed waste water environment classified as raw water is managed by Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22) instead of Open-Cycle Cooling Water System (B2.1.9).
NOC-AE-1 2002797 Page 48 of 63 3
The component environment is radioactive waste drains that have been evaluated as a raw water environment. Loss of material on external component surface exposed to floor and equipment drains environment is managed by External Surfaces Monitoring (B2.1.20) instead of Open-Cycle Cooling Water System (B2.1.9).
4 The Water Chemistry program (B2.1.2) and the One-Time Inspection program (B2.1.16) manage loss of material due to pitting and crevice corrosion and cracking due to stress corrosion cracking. The One-Time Inspection program (B2.1.16) includes selected components at susceptible locations.
5 The component type is internal to the ducting system, so internal inspection was selected instead of using external surfaces inspection.
The environment is external ventilation air.
NOC-AE-1 2002797 Page 49 of 63 Table 3.4.2-1 Steam and Power Conversion System - Summary of Aging Management Evaluation - Main Steam System (Continued)
Component Intended Material Environment Aging Effect Aging Management NUREG-Table I Item Notes Type Function Requiring Program 1801 Vol.
Management 2 Item Solenoid Valve PB Aluminum Plant Indoor Air None None V.F-2 3.2.1.50 A
(Ext)
Solenoid Valve PB Aluminum Plant Indoor Air Nene Loss of None Inspection of V.F2 322 so A E (Int) material Internal Surfaces in VII.F2-12 3.3.1.27 Miscellaneous Pipingq and Ductinq
_Components (B2.1.22)
Tank PB Stainless Lubricating Oil (Int) Loss of material Lubricating Oil Analysis VIII.A-9 3.4.1.19 D
Steel (B2.1.23) and One-Time
_Inspection (B2.1.16)
NOC-AE-12002797 Page 50 of 63 Al
 
==SUMMARY==
DESCRIPTIONS OF AGING MANAGEMENT PROGRAMS The integrated plant assessment and evaluation of time-limited aging analyses (TLAA) identified existing and new aging management programs necessary to provide reasonable assurance that components within the scope of license renewal will continue to perform their intended functions consistent with the current licensing basis (CLB) for the period of extended operation. Sections Al and A2 describe the programs and their implementation activities.
Three elements common to all aging management programs discussed in Sections Al and A2 are corrective actions, confirmation process, and administrative controls. The STP Quality Assurance Program includes the elements of corrective action, confirmation process, and administrative controls, and is applicable to the safety-related and nonsafety-related systems, structures, and components that are subject to aging management activities.
Results of inspections, tests, analyses, etc. conducted throuqh the implementation of aging management programs are considered as operating experience on an onqoing basis. When applicable acceptance criteria are met, results are retained for future use and evaluation to determine whether it is necessary to adjust the frequency for future inspections, establish new inspections, and ensure an adequate depth and breadth of component, material, environment, and aging effect combinations. When applicable acceptance criteria are not met, corrective actions are initiated in accordance with the quality assurance program.
Operating experience is applied to all aging management programs discussed in Sections Al and A2. Plant-specific and industry operating experience is continuously reviewed to confirm the effectiveness of aging management programs and is utilized, as necessary, to enhance each aging management program or to develop new aging management programs in order to adequately manage the effects of aging so that the intended function(s) of structures and components are met.
A systematic review of operating experience related to aqing management ensures that license renewal aging management programs are effective in manaqing the aging effects for which they are credited. Processes gather information on license renewal structures and components identified in the integrated plant assessment, and their materials, environments, aging effects, and aging mechanisms. Programs and procedures specify reviews of sources of information related to aging effects. Formal evaluations related to aginq effects are completed and prioritized commensurate with the potential significance on the issue. The evaluations are documented and retained in an auditable and retrievable form. Enhancements to programs and procedures to adequately manage the effects of aging are entered into and implemented consistent with the plant corrective action program. Aging management programs are administratively controlled to include a formal review and approval process and periodic audits.
NOC-AE-12002797 Page 51 of 63 The following enhancements will be made to the STP Operating Experience Program and Corrective Action Program for managing the effects of aging.
The OEP procedure will be revised to add License Renewal Interim Staff Guidance and revisions to NUREG-1 801, "Generic Aging Lessons Learned (GALL) Report", as source documents applicable for review.
The OEP procedure will be revised to include "aging effects" to the list of characteristics for determining applicability of an OE document that may require further evaluation. A screened-in evaluation should consider (a) systems, structures, or components, (b) materials, (c) environments, (d) aging effects, (e) aging mechanisms, and (f) aging management programs.
Corrective Action Program Event Codes will be reviewed to determine if additional codes are needed to ensure age-related degradation effects are identified.
A training "needs analysis" will be performed for those plant personnel who screen, assign, evaluate, and submit plant-specific and industry operating experience information for age-related effects.
The OEP procedure will be revised to provide criteria for reporting plant-specific operatinq experience on aqe-related degradation.
NOC-AE-12002797 Page 52 of 63 A1.16 One-Time Inspection The One-Time Inspection program conducts one-time inspections of plant system piping and components to verify the effectiveness of the Water Chemistry program (Al.2), Fuel Oil Chemistry program (A1.14), and Lubricating Oil Analysis program (A1.23). The aging effects to be evaluated by the One-Time Inspection program are loss of material, cracking, and reduction of heat transfer. The One-Time Inspection program determines non-destructive examination (NDE) sample sizes based on the population of components in a group sharing the same material, environment and aging effects. For each population, a representative sample size of 20 percent of the population is selected up to a maximum of 25 components. The components making up the sample are those determined to be most susceptible to degradation based on a review of environment, condition and operating experience. The sample population includes eddy current testing of the tubes in one non-regenerative heat exchanger. The program will focus on bounding or lead components most susceptible to aging due to time in service, and severity of operating conditions. Inspections will be performed using a variety of NDE methods, including visual, volumetric, and surface techniques by qualified inspectors. The program will not be used for component inspections with known age-related degradation mechanisms, or when the environment in the period of extended operation is not equivalent to that in the prior 40 years. The One-Time Inspection program specifies corrective actions if aging effects are found. The corrective action program may specify follow-up inspections for confirmation of aging effects at the same or different locations. If aging effects are detected, a plant-specific program will be developed for the material, environment, and aging effect combination that has produced the aging effects.
This new program will be implemented and completed within the 10 year period prior to the period of extended operation. Industry and plant-specific operating experience will be evaluated in the development and implementation of this program.
NOC-AE-1 2002797 Page 53 of 63 B2.1.16 One-Time Inspection Program Description The One-Time Inspection program manages loss of material, cracking, and reduction of heat transfer. The One-Time Inspection program conducts one-time inspections of plant system piping and components to verify the effectiveness of the Water Chemistry program (B2.1.2), Fuel Oil Chemistry program (B2.1.14), and Lubricating Oil Analysis program (B2.1.23).
The One-Time Inspection program will be implemented by STP prior to the period of extended operation. Plant system piping and components identified in the one-time inspection procedure will be subject to one-time inspections on a sampling basis, using qualified inspection personnel, following established ASME Code Section V Non-Destructive Examination techniques appropriate to each inspection. The One-Time Inspection program determines non-destructive examination (NDE) sample sizes based on the population of components in a group sharing the same material, environment and aging effects. For each population, a representative sample size of 20 percent of the population is selected up to a maximum of 25 components. The components making up the sample are those determined to be most susceptible to degradation based on a review of environment conditions and operating experience. The sample population includes eddy current testing of the tubes in one non-regenerative heat exchanger. The program will focus on bounding or lead components most susceptible to aging due to time in service, and severity of operating conditions. Inspections will be performed using a variety of NDE methods, including visual, volumetric, and surface techniques by qualified inspectors. The program will not be used for component inspections with known age-related degradation mechanisms, or when the environment in the period of extended operation is not equivalent to that in the prior 40 years. The One-Time Inspection program specifies corrective actions if aging effects are found. The corrective action program may specify follow-up inspections for confirmation of aging effects at the same or different locations. If aging effects are detected, a plant-specific program will be developed for the material, environment, and aging effect combination that has produced the aging effects.
The one-time inspections will be performed no earlier than 10 years prior to the period of extended operation. All one-time inspections will be completed prior to the period of extended operation. Completion of the One-Time Inspection program in this time period will assure that potential aging effects will be manifested based on at least 30 years of STP operation. Major elements of the STP One-Time Inspection program will include:
a) Identifying piping and component populations subject to one-time inspections based on common materials and environments, b) Determining the sample size of components to inspect for each material-environment
: group, c) Selecting piping and components within the material-environment groups for inspection based on criteria provided in the one-time inspection procedure, NOC-AE-12002797 Page 54 of 63 d) Conducting one-time inspections of the selected components within the sample using ASME Code Section V Non-Destructive Examination techniques and acceptance criteria consistent with the design codes/standards or ASME Section XI as applicable to the component, e) Evaluating inspection results and initiating corrective action for any aging effects found.
NUREG-1801 Consistency The One-Time Inspection program is a new program that, when implemented, will be consistent with NUREG-1 801, Section XI.M32, One-Time Inspection.
Exceptions to NUREG-1801 None Enhancements None Operating Experience During the 10 year period prior to the period of extended operation, one-time inspections will be accomplished at STP using ASME Code Section V Non-Destructive Examination techniques to identify possible aging effects. ASME code techniques in the ASME Section X1 ISI Program have proven to be effective in detecting aging effects prior to loss of intended function. Review of STP plant-specific operating experience associated with the ISI Program has not revealed any ISI Program adequacy issues with the STP ASME Section XI ISI Program. The same Non-Destructive Examination techniques used in the ASME Section XI ISI Program will be used in the One-Time Inspection program. Using ASME Code Section V Non-Destructive Examination techniques will be effective in identifying aging effects, if present.
As additional industry and plant-specific applicable operating experience becomes available, it will be evaluated and incorporated into the program through the STP condition reporting and operating experience programs.
Conclusion The implementation of the One-Time Inspection program will provide reasonable assurance that aging effects will be managed such 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.
NOC-AE-12002797 Page 55 of 63 A1.39 PROTECTIVE COATING MONITORING AND MAINTENANCE PROGRAM The Protective Coating Monitoring and Maintenance Program manages loss of coating integrity for Service Level 1 coatings inside containment so that the intended functions of post-accident safety systems that rely on water recycled through the containment sump/drain system are maintained consistent with the current licensing basis. The program includes a visual examination of all reasonably accessible Service Level 1 coatings inside containment during every refueling outage, including those applied to the steel containment liner, structural steel, supports, penetrations, uninsulated equipment, and concrete walls and floors receiving epoxy surface systems. This program does not include coating of surfaces that are insulated or otherwise enclosed in normal service and concrete receiving a non-film forming clear sealer coat only. This program is consistent with the standards provided in ASTM D 5163-08 and Regulatory Guide 1.54, Rev. 2, as addressed in NUREG 1801, Rev. 2, XI.S8.
NOC-AE-12002797 Page 56 of 63 B2.1.39 Protective Coating Monitoring and Maintenance Program Program Description The Protective Coating Monitoring and Maintenance Program manages loss of coating integrity for Service Level 1 coatings inside containment so that the intended functions of post-accident safety systems that rely on water recycled through the containment sump/drain system are maintained consistent with the current licensing basis. The program includes a visual examination of all reasonably accessible Service Level 1 coatings inside containment, including those applied to the steel containment liner, structural steel, supports, penetrations, uninsulated equipment, and concrete walls and floors receiving epoxy surface systems. This program does not include coating of surfaces that are insulated or otherwise enclosed in normal service and concrete receiving a non-film forming clear sealer coat only. This program is consistent with the standards provided in ASTM D 5163-08 and Regulatory Guide (RG) 1.54, Rev. 2, as addressed in NUREG 1801, Rev. 2, XI.S8.
General visual inspections of the containment building Service Level 1 coatings are conducted a. part of the ASRE SActOn Xl, Subsection IWE program and the Structure Monitoring Program at inte or.als not excooding five yoars. during every refueling outage.
Additional inspections may be necessary depending on inspection results. Thorough visual inspections are performed on previously designated areas and on areas noted as deficient during the inspection. Characterization of doficiont-ar4a-blistering, cracking, flaking, peeling, de-lamination, rusting, and physical damage is performed to allow evaluation of the deficiency for fu-tu-re su',oeillaRce or repair, and prioritization of repairs, or for future surveillance.
.haracteFrizatin of b I.literi crc I
iGng, flaking, Pooling, de lin*matnd,
*and ru.tig is consi.tent with applicable AST^
standards.&. Physical testing may be performed when directed by the evaluate Nuclear Coating Specialist. Physical tests are performed by individuals trained in applicable referenced standards of Guide D5498. Examinations are conducted by qualified personnel.
Service Level I coatings are not credited for managing loss of material of the steel containment liner.
Aging Management Program Elements The results of an evaluation of each element against the 10 elements described in Appendix A of NUREG-1 800, Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants are provided below.
Scope of Program (Element 1)
The Protective Coating Monitoring and Maintenance Program includes a visual examination of all reasonably accessible Service Level 1 coatings inside containment,
.ik g theee-as defined in RG 1.54, Rev. 2. This scope includes coatings applied to the steel containment liner, structural steel, supports, penetrations, uninsulated equipment, and concrete walls and floors receiving epoxy surface systems. This NOC-AE-1 2002797 Page 57 of 63 program pertains to the containment interior and equipment, structures or components which are permanently located inside containment. This program does not include coating of surfaces that are insulated or otherwise enclosed in normal service and concrete receiving a non-film forming clear sealer coat only.
Service Level I coatings are not credited for preventing loss of material due to corrosion for the steel containment liner. (See AMP XI.S1, ASME Section XI, SubSection IVWE)
Preventive Actions (Element 2)
The Protective Coating Monitoring and Maintenance Program does not prevent degradation due to aging effects but provides measures for monitoring to detect the degradamO -aging prior to loss of intended function. Coatings are not credited for preventing loss of material.
Parameters Monitored or Inspected (Element 3)
The Protective Coating Monitoring and Maintenance Program inspects coated surfaces for flaking, blistering, cracking, do lamination, pooling, or rustingany visible defects, such as blistering, cracking, flaking, peeling, rusting, and physical damage, as specified in ASTM D 5163-08. Any areas of coating discoloration or areas where corrosion has formed under the coating system are documented and evaluated.
Detection of Aging Effects (Element 4)
The South Texas Project (STP) petiedieally conducts condition assessments of Service Level 1 coatings inside containment during every refueling outage, as specified in ASTM D 5163-08. as part of the ASME= S*ction Xl, Subseton1. IVVE, program and the S.tructu.res Mo-nitor Program A at int.rval nOt exceeding five years. Additional inspections may be necessary depending on condition assessment results. Vis-ual i nspection of coatings in containment is intended to characterize the cond-ition of th coating systems. 'n some8 cases, a comnplete inspection is not possible due to inaccessibility. ForF these cases, the coating systems are characterized based On an inpeton of coatinlg systems that are reaSonably accessible o tr-b-aed-9n a rpeentative sample If" loaized areas. of degraded coatings are identified, those areas a~reR eigaluate~d aind scnheduled for repair/replacement, as necessary. The perioi condition assessmen8ts, and the resulting repair/eplacement actiVities, assure that th amount Of SerVOce Level 1 coatings Which mnay be suGsceptible to detachment fromth substrate during a leGs of coolant accident design basis eVent i6 m*inimized.
The Coatings Engineer in charge of the safety-related coatings pro-gram meets the qualification criteria for a Nuclear Coatings Specialist in accordance with ASTM D 7108-05. The Coating Planner is responsible for planning all coating activities, providing technical support to the applicator, and conducting assessment inspections and physical tests when directed by the Nuclear Coating Specialist. The Coating Planner meets the qualification criteria for a Nuclear Coatings Specialist in accordance with ASTM D 7108-05, is a NACE Certified Inspector, and is trained in the applicable referenced standards of Guide D 5498. These qualifications are as specified in ASTM D NOC-AE-12002797 Page 58 of 63 5163-08.The Coating Inspector is certified as a NACE Level II Coating Inspector in accordance with ASTM D 5498. These qualifications are as specified in ASTM D 5163-08.
The coatings condition assessment includes a visual examination of all accessible Service Level 1 coatings inside containment, including areas near sumps associated with the emergency core cooling system. Thorough visual inspections are conducted to identify and evaluate all accessible areas of degraded coatings, as specified in ASTM D 5163-08, Section 10.1. Location maps and checklists are used to identify the areas to be inspected and to document the inspection results. The coatings condition assessment inspectors have available to them the necessary tools to conduct a thorough inspection of accessible Service Level 1 coatings in containment, consistent with the recommendations in ASTM D 5163-08, Section 10.5.
Monitoring and Trending (Element 5)
Prior to performing the inspection, the inspector reviews the two previous coating condition assessment reports. The inspection reports prioritize repair areas as either needing repair during the same outage or as pstpon, d to future outage,, needing repair during the next available outage, or monitored and re-evaluated in the next available outage. These monitoring and trending activities are as specified in ASTM D 5163-08.
The containment I*enF plate
*1,'
se1-s part of the ASI-E SecGtiRn XI, Subsetin IWE inspection program. The resu-lts Of this inspection are reviewed to assist iR identifYing areas of degraded Or damaged coating.
Acceptance Criteria (Element 6)
As specified in ASTM D 5163-08, paragraph 11, Ppotentially defective coating surfaces identified during the course of an inspection are documented, their severity is evaluated, and corrective actions are taken to ensure there is no loss of intended functions between the inspections. Defective or deficient coating surfaces are prioritized as either needing repair during the same outage or as post*pedR, to futur outages, needing repair during the next available outage, or monitored and re-evaluated in the next available outage. The evaluation covers blistering, cracking, flaking, peeling, de-lamination, and rusting as specified below. These acceptance criteria are consistent with, or more conservative than, the acceptance criteria specified in ASTM D 5163-08, subparagraphs 10.2, 10.3, and 10.4.
Blistering-Blistering of any size is a reiectable condition. Compare any blistering fou nd te the 19I0MWORqn
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'ra 4Vaw.-m NOC-AE-12002797 Page 59 of 63 Cracking-Cracking of any size is a relectable condition. All cracks under 30 mils in width are documented and repaired in accordance with plant procedures. Cracks exceeding 30 mils in width and all cracks associated with delamination are evaluated under the site corrective action program. Crncking, may be limited to thoe layer otf cotngo oxtondl through to tho substrate. Measuo th lngth o th crac orif extensiVe cracking haso occurred, mneasure the rsiOze of the Area affecnted. Determine ifthecackn sioae or is part of a pattern. Record measuremenRts-and describe crack depth and pattern On the inspection report. Photograph the are~a affected.
Flaking/Peeling/De-lamination-Flaking/peeling/de-lamination of any size is a reiectable condition. All flaking/peeling/de-lamination is documented and repaired in accordance with plant procedures. If the sum total of the repair area exceeds 25 percent of that item's total painted area or if each individual repair area exceeds 30
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d Rusting-Comparison with pictorial standards are Performed by individuals trained in applicable referenced standards of Guide D5498 on an as-needed basis as determined by the Nuclear Coatings Specialist. The source and extent of rusting is evaluated during the visual examination by the Nuclear Coatings Specialist.
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m If no defects are found, mark "Coating Intact, No Defects" on the inspGction report coating condition assessment report form.
If portions of the coating cannot be inspected, note the specific areas on the hfspeG.iGR
-epGe coating condition assessment report form, along with the reason why the inspection cannot be conducted.
Written or photographic documentation, or both, of coating inspection areas, failures, and defects shall be made and the pro-ess of douetto s-tand-ard-ized by the facility gwRef peatF are included in the final coating condition assessment report.
NOC-AE-12002797 Page 60 of 63 For coating surfaces determined to be suspect, defective, or deficient, destructive/non-destructive tests are performed by individuals trained in applicable referenced standards of Guide D5498 on an as-needed basis as determined by the Nuclear Coatings Specialist. "k,"0r"., t9*64.6, h
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pa ittemrp mi, ay baen haAF~ed Corrective Actions (Element 7)
STP site Quality Assurance (QA) procedures, review and approval process, and administrative controls are implemented in accordance with the requirements of 10 CFR 50 Appendix B and are acceptable in addressing corrective actions. The QA program includes elements of corrective action, and is applicable to the safety-related and nonsafety-related systems, structures and components that are subject to aging management review.
Confirmation Process (Element 8)
STP site QA procedures, review and approval process, and administrative controls are implemented in accordance with the requirements of 10 CFR 50 Appendix B and are acceptable in addressing confirmation processes and administrative controls. TheQA program includes elements of corrective action, and is applicable to the safety-related and nonsafety-related systems, structures and components that are subject to aging management review.
Administrative Controls (Element 9)
STP site QA procedures, review and approval process, and administrative controls are implemented in accordance with the requirements of 10 CFR 50 Appendix B and are acceptable in addressing confirmation processes and administrative controls. The QA program includes elements of corrective action, and is applicable to the safety-related and nonsafety-related systems, structures and components that are subject to aging management review.
Operating Experience (Element 10)
The South Texas Project conducts condition assessments of Service Level 1 coatings inside containment during every refueling outage. Service Level 1 coatings are inspected during Coating Condition Assessment walkdowns, IWE inspections, Structures Monitoring Program inspections, and through STP's Condition Reporting Process for identification and timely correction of an existing degraded coating condition. A review of Service Level 1 Coatings inspection and repair documentation shows that coating failures identified in Unit 1 and Unit 2 Reactor Containment Building have not been significant. Historically, Service Level 1 coating failures include:
mechanical damage, minor isolated cracking measuring less than 30 mils in width, and minor surface rusting. Peeling, blistering, and delamination of Service Level 1 coatings that have the potential to block sumps and strainers have not been reported.
NOC-AE-12002797 Page 61 of 63 In 1992, cracks were identified in the concrete coating on the Unit 1 RCB knockout block wall. The coating degradation was characterized as a minor crack less than 30 mils in width, not associated with delamination. The degraded coatings were repaired in accordance with the safety-related coatings specification.
In April, 2000, minor surface corrosion on the Unit 2 liner plate at the interface of the liner plate and concrete basemat was identified through the Condition Reporting Process. Coating degradation is characterized as minor rusting. Repairs to degraded coatings were made in accordance with the safety-related coating specification.
In May 2000, an indication approximately 4" x 8" on the Unit 1 containment liner plate was identified near the reactor vessel head lift rig. Engineering investiqated and determined that the outer coating was removed with the primed surface below exposed with no signs of corrosion or further coating deterioration noted. The condition was found acceptable as-is. The indication was re-evaluated in 1RE16 during the next Coatings Condition Assessment Walkdown. The indication was identified to be approximately the same size and color as was identified in May 2000. The indication shows no signs of corrosion and no streaks of rust on the liner plate below. The size of the indication or its condition has not changed since May 2000: however, the indication will be monitored and re-evaluated during the next outage.
In November, 2009, surface corrosion on a hanger support was identified in Unit 1 during the Coatings Condition Assessment Walkdown. The coatings degradation was characterized as minor surface rusting due to condensation. Repairs to degraded coatings were made in accordance with the safety-related coatings specification.
STP has implemented controls for the procurement, application, and maintenance of Service Level 1 protective coatings used inside containment in a manner consistent with the licensing basis and regulatory requirements applicable to the South Texas Proeect.
The requirements of 10 CFR 50 Appendix B are implemented through specification of appropriate technical and quality requirements for the Service Level 1 coatings program which includes onqoinq maintenance activities.
Service Level 1 coatings have been tested, selected, and applied to assure that they will withstand nuclear, chemical, and physical conditions of a Design Basis Accident. The historical Service Level 1 coating performance provides reasonable assurance that coating aging effects are managed such that the operability of the Emergency Core Cooling System and the Containment Spray System will not be impaired due to Service Level 1 coating failure.
S-TP has imleenedntrols for the procureme~nt, application, and maintenance ot SeRvice L9Vel 1 protectiVe coatings used inside contain~ment in a; manner that is6 consistent with the licensing basic and regulator,' requir8emets applicable to ST-P. The requiF8rements of 10Q CFR 50 Appendix BR are-implemen~ted through specification of approapriate tocnhnicral and qualit, rqrents for theq Sepr-Ic Level 1 coatings program which includes ongoing maintenance-&#xfd; actdivfitwios.
For -T-P, Servic LevI I coatings have been tested, selected, and applied to assure9
'W"I[I WAIIRS12lR~~l d RUGleaF, GhGFneGal, and phyri NOC-AE-12002797 Page 62 of 63 A,,ident as required by Nucleal r Ge"nso-,n
-Reulatr.
Guide (
'G-1.54-Rev. 0, and ANSI N101.2 1972. Coatings used in0ide the containmet hAVe been e-stablis.h-d-as_ safety related, thus imposing the quality assurance requirem~ents of Aneend-ix B to 10 GCFIR Part 50.
The South Texas Project periodically conducts condition arsessments of Service Level 4 coatings inside containment. Coating condition assessmentS are conducted as part o9 the structures monitoriRg program. The st*rGucture moni-tring-
.. over.s the bas-.eline inspection and subsequent inspections that are condu-cted at intrvals not exceeding Wie years.
Enhancements Prior to the period of extended operation, the following enhancements will be implemented in the following program elements:
Parameters Monitored or Inspected - Element 3 Procedures will be enhanced to specify parameters monitored or inspected to include:
any visible defects, such as blistering, cracking, flaking, peeling, rusting, and physical damage, as specified in ASTM D 5163-08.
Detection of Aging Effects - Element 4 Procedures will be enhanced to specify inspection frequencies, personnel qualifications, inspection plans, inspection methods, and inspection equipment that meet the requirements of ASTM D 5163-08.
Monitoring and Trending - Element 5 Procedures will be enhanced to specify a pre-inspection review of the previous two monitoring reports and, based on inspection report results, prioritize repair areas as either needing repair during the same outage, needing repair during the next available outage, or monitored and re-evaluated in next available outaqe.
Acceptance Criteria - Element 6 Procedures will be enhanced to include a standardized coating condition assessment report form that will include the identification of coatings found intact with no defects identified, and the identification of coatings that were not inspected and the reason why the inspection cannot be conducted.
Procedures will be enhanced to include a standardized coating condition assessment report that will include written and/or photographic documentation of coating inspection areas, failures, and defects.
Procedures will be enhanced to specify that destructive/non-destructive tests are performed by individuals trained in applicable referenced standards of Guide D5498.on an as-needed basis as determined by the Nuclear Coatingis Specialist.
NOC-AE-12002797 Page 63 of 63 Conclusion The continued implementation of the Protective Coating Monitoring and Maintenance Program, following enhancements, provides reasonable assurance that aging effects will be managed such 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.
NOC-AE-12002797 Regulatory Commitments NOC-AE-12002797 Page 1 of 2 A4 LICENCE RENEWAL COMMITMENTS Table A4-1 identifies proposed actions committed to by STPNOC for STP Units 1 and 2 in its License Renewal Application. These and other actions are proposed regulatory commitments. This list will be revised, as necessary, in subsequent amendments to reflect changes resulting from NRC questions and STPNOC responses. STPNOC will utilize the STP commitment tracking system to track regulatory commitments. The Condition Report (CR) number in the Implementation Schedule column of the table is for STPNOC tracking purposes and is not part of the amended LRA.
Table A4-1 License Renewal Commitments Item #
Commitment LRA Implementation Section Schedule 27 Implement the PWR Reactor Internals program as described in LRA Section B2.1.35.
B2.1.35 Within 24 months after the issuance of EPRI 1016563 1022863, PWR Internals Inspection and Evaluation Guideline MRP-227-A CR 10-23602 40 Enhance the Protective Coating Monitoring and Maintenance Program procedures to specify:
B2.1.39 Prior to the period of Parameters monitored or inspected include any visible defects, such as blistering, extended operation cracking, flaking., peelinq, rusting, and physical damage, as specified in ASTM D 5163-
: 08.
CR 12-8955 Inspection freguencies, personnel gualifications, inspection plans, inspection methods, and inspection equipment that meet the requirements of ASTM D 5163-08.
A pre-inspection review is performed of the previous two monitoring reports and, based on inspection report results, prioritize repair areas as either needing repair during the same outage, needing repair during the next available outage, or re-evaluated in next available outage.
A standardized coating condition assessment report form that will include the identification of coatings found intact with no defects identified, and the identification of NOC-AE-12002797 Page 2 of 2 coatings that were not inspected and the reason why the inspection cannot be conducted.
A standardized coating condition assessment report that will include written and/or photographic documentation of coating inspection areas, failures, and defects.
Destructive/non-destructive tests are performed by individuals trained in the applicable referenced standards of Guide D5498 on an as-needed basis as determined by the Nuclear Coatings Specialist.
41 Enhance the STP Operating Experience Program and Corrective Action Program for managing A1.1 December 31, 2014 the effects of aging to:
Add License Renewal Interim Staff Guidance and revisions to NUREG-1801, "Generic CR 12-8990 Aging Lessons Learned (GALL) Report", to the Operating Experience Program (OEP) procedure as sources of information within the scope of this program, Revise the OEP procedure to include "aging effects" to the list of characteristics for determining applicability of an OE document that may require further evaluation. A screened-in evaluation should consider (a) systems, structures, or components, (b) materials, (c) environments, (d) aging effects, (e) aging mechanisms, and (f) aging management programs, Review the Corrective Action Program Event Codes to determine if additional codes are needed to ensure age-related degradation effects are identified, Perform a training "needs analysis" for those plant personnel who screen, assign, evaluate, and submit plant-specific and industry operating experience information for age-related effects.
Revise the OEP procedure to provide criteria for reporting plant-specific operating experience of age-related degradation.}}

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