ML11347A365

Supplement to the South Texas Project License Renewal Application

ML11347A365
Person / Time
Site:	South Texas
Issue date:	12/07/2011
From:	Rencurrel D South Texas
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
NOC-AE-11002769, TAC ME4936, TAC ME4937
Download: ML11347A365 (25)

Text

Nuclear Operating Company South Texas Project Electric Generating Station PO Box 289 Wadsworth Texas 77483 December 7, 2011 NOC-AE-1 1002769 10 CFR 54 STI: 33157678 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 Supplement to the South Texas Project License Renewal Application (TAC NOS. ME4936 and ME4937)

Reference:

1. STPNOC Letter dated October 25, 2010, from G. T. Powell to NRC Document Control Desk, "License Renewal Application" (NOC-AE-10002607)

(ML103010257)

2. Summary of Telephone Conference Call Held on November 17, 2011, Between the U.S. Nuclear Regulatory Commission and STP Nuclear Operating Company, Concerning Clarifications to Some Responses to Requests for Additional Information - South Texas Project Units 1 and 2 License Renewal Application (TAC NOS. ME4936, ME4937) (ML11335A076)

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 requested that STPNOC clarify responses to previous requests for information regarding the LRA. The supplemental responses are provided in Enclosure 1 to this letter. Enclosure 2 provides changes to the LRA with the reason for the change explained in Enclosure 1. provides a revised regulatory commitment to the LRA. There are no other regulatory commitments 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 IL"2U Date LY 1 Senior Vice President, Technical Support & Oversight KJT

Enclosures:

1. Supplemental Responses to RAIs

2. STP LRA Changes with Line-in/Line-out Annotations

3. Revised LRA Regulatory Commitment bQ-T

NOC-AE-1 1002769 Page 2 cc:

(paper copy)

(electronic copy)

Regional Administrator, Region IV U. S. Nuclear Regulatory Commission 612 East Lamar Blvd, Suite 400 Arlington, Texas 76011-4125 Balwant K. Singal Senior Project Manager U.S. Nuclear Regulatory Commission One White Flint North (MS 8B1) 11555 Rockville Pike Rockville, MD 20852 Senior Resident Inspector U. S. Nuclear Regulatory Commission P. 0. Box 289, Mail Code: MN116 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 O11-F1) 11555 Rockville Pike Rockville, MD 20852 Tam Tran License Renewal Project Manager (Environmental)

U. S. Nuclear Regulatory Commission One White Flint North (MS 011 F01) 11555 Rockville Pike Rockville, MD 20852 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-11002769 Enclosure I Supplemental Responses to RAI's NOC-AE-1 1002769 Page 1 of 8 Supplemental Responses to RAI's

References:

1. STPNOC letter dated October 10, 2011, from G. T. Powell to NRC Document Control Desk, "Response to Requests for Additional Information for the South Texas Project License Renewal Application" (TAC Nos. ME4936 and ME4937)

(NOC-AE-1 1002732) (ML11291A152)

2. STPNOC Letter dated August 23, 2011, from G. T. Powell to NRC Document Control Desk, "Response to Requests for Additional Information for the South Texas Project License Renewal Application" (TAC Nos. ME4936 and ME4937)(NOC-AE-1 1002714) (ML 1238A072)

3. STPNOC Letter dated November 4, 2011, from D. W. Rencurrel to NRC Document Control Desk, "Supplement to the South Texas Project License Renewal Application" (TAC Nos. ME4936 and ME4937)(NOC-AE-1 1002750)

(ML11319A026)

4. Summary of Telephone Conference Call Held on November 17, 2011, Between the U.S. Nuclear Regulatory Commission and STP Nuclear Operating Company, Concerning Clarifications to Some Responses to Requests for Additional Information - South Texas Project Units 1 and 2 License Renewal Application (TAC NOS. ME4936, ME4937) (ML11335A076)

The following table lists the affected Request for Additional Information numbers from the referenced letters where the response is initial response is either revised or supplemented.

RAI Initial Response Letter Impact of Initial Response Number 4.7.1-1 Reference 1 (ML11291A152)

Response Revised B2.1.32-06 Reference 1 (ML11291A152)

Response Supplemented 2.1-2 Reference 2 (ML11238A072)

Response Supplemented B2.1.20-5 Reference 3 (ML11319A026)

Information Supplemented This enclosure also describes a revision to LRA Appendices A1.25 and B2.1.25 and Table A4-1 Item 20. This revision is referenced to RAI B2.1.25-1.

RAI 4.7.1-1 Backqround:

LRA Section 4.7.1 states that the estimated number of significant lifts per refueling outage for each machine is estimated from the UFSAR Section 9.1.4.2.2 description of refueling operations.

A factor of 1.5 is used to account for non-refueling lifts. LRA Section 4.7.1 further states that based on an 18-month refuel cycle, approximately 27 refuel cycles are expected over a 40-year plant design life, or about 40 refuel cycles in a 60-year plant design life.

Issue:

LRA table 4.7-1 shows that the estimated maximum number of significant crane lifts for the cask handling overhead crane is 420 for a 40-year design life and 740 for a 60-year design life. The table indicates that the calculation uses 10 refuels for the 40-year calculation and 20 refuels for the 60-year calculation; however, no explanation of why these numbers were used instead of the NOC-AE-1 1002769 Page 2 of 8 27 and 40 refuel cycles as described in LRA Section 4.7.1. It is unclear to the staff how the estimated maximum number of significant crane lifts were calculated for the cask handling overhead crane and why the calculation is based on a different number of refuels than that described in LRA Section 4.7.1.

Request:

1. Provide the basis for the estimated maximum number of significant crane lifts for the cask handling overhead crane for both a 40 and 60-year design life.

2. Explain why the number of refuels used in the calculation differs from the 27 refuel cycles expected over a 40-year design life, and the 40 refuel cycles expected over a 60-year design life, based on an 18-month refuel cycle.

Requested Clarification (Reference 4)

The applicant agreed to supplement its RAI response to more fully describe its reasoning that brought it to the values above, namely, the "10 refuels," "20 refuels," how the crane's work is related to a refueling cycle, and why the upper bound for the 60-year PEO is 740 lifts. The description should be such that an independent reviewer can reconstruct and follow the logic, and verify that the values are correct.

STPNOC Revised Response

1. Once cask loading is commenced, the number of fuel assemblies moved to dry cask storage is equal to the number of new fuel assemblies received each refueling outage. Therefore, the number of casks loaded, and hence the number of cask handling crane lifts, is dependent on the number of refueling outages. For each new fuel shipment, it is assumed that 7 casks will be required to be filled. The number of lifts for the cask handling overhead crane is based on three lifts per cask, which equals 21 lifts (3 x7) per new fuel shipment. As noted in the LRA Table 4.7-1, the calculated number for each outage was multiplied by 1.5 for conservatism, resulting in an estimated 32 significant lifts per refueling outage. In addition to the refueling outage lifts, the 40-year and 60-year cycles include an estimated 100 construction lifts.

40 year estimate = (32 lifts / refueling)

• 10 refueling + 100 construction lifts = 420 lifts 60 year estimate = (32 lifts / refueling)

• 20 refueling + 100 construction lifts = 740 lifts

2. The number of refueling outages assumed in the lift estimate for the cask handling crane differs from the 27 refuel cycles expected over a 40-year design life,.and the 40 refuel cycles expected over a 60-year design life assumed in the lift estimate for other cranes because cask loading is assumed to begin in year 30 of plant operation.

40-year estimate = (40 year life - 30 years) / (1.5 years per refueling) = 6.67 refuelings This value was rounded up to 10 refueling to simplify the calculation.

60-year estimate = (60 year life - 30 years) / (1.5 years per refueling) = 20 refuelings NOC-AE-1 1002769 Page 3 of 8 RAI B2.1.32-06 Backqround:

In GALL AMP XI.S6, program elements 3 and 4 state that for each structure/aging effect combination the specific parameters monitored or inspected are selected to ensure that the aging degradation leading to loss of intended function will be detected and quantified before there is a loss of intended function.

Issue:

As a result of the field walk-down with the applicant's technical staff on June 14, 2011, the staff noticed that in the area between the fuel handling building and the Unit 2 containment, water had accumulated to a depth of 6 ft. or 7 ft. The staff also noted that some indications of deposits were observed on the wall of the fuel handling building above the current water level. When asked, the applicant noted that there were no criteria related to when to remove the water and that the surfaces of the containment and the fuel handling building subjected to the standing water were not routinely inspected after the water had been removed. The staff is uncertain whether the standing water has resulted in concrete degradation or could lead to degradation during the period of extended operation.

Request:

1. Explain where the standing water between the fuel handling building and the Unit 2 containment is coming from and provide justification for this conclusion.

2. Discuss any actions taken to address the accumulation of standing water between the fuel handling building and the Unit 2 containment (e.g. increased visual inspections, crack mapping, etc.)

3. Provide any plans to develop criteria related to when the standing water is removed and how the surfaces exposed to the standing water will be managed for aging during the period of extended operation (e.g. visual inspections, crack mapping, core bores, etc.). Provide technical justification that these actions will be adequate to manage aging.

4. If similar conditions exist in Unit 1, provide the above information for both units and a discussion of any differences in the aging management approaches between the units.

Requested Clarification (Reference 4)

The applicant agreed to submit a supplemental response related to RAI 82.1.32-06 that will clarify the following questions.

Discuss the STP response to RAI B2.1.32-06 regarding the Structures Monitoring Program and standing water between the Containment Building and the Fuel Handling Building. The following is a summary of the questions:

(i) When will the applicant drain the water?

(1) Will it be performed on a set frequency, prior to inspections, when the water reaches a particular level, etc.?

NOC-AE-1 1002769 Page 4 of 8 (2) When will it be performed initially?

(ii) What will the frequency of inspection be under the Structures Monitoring Program (SMP)? Is the "5 years" because it is exposed to ground water in leakage?

(iii) It appears the response says this area will be inspected under the SMP; however, the staff believes the containment wall should be inspected under the ASME Code, Section IWL.

Please clarify.

STPNOC Supplementary Response The initial draining for the water accumulated between the Containment Building and the Fuel Handling Building in Unit 2 is scheduled for January 2012 with completion of the concrete surface inspection shortly thereafter.

Any additional water that accumulates between the Containment Building and the Fuel Handling Building in either STP Unit 1 or Unit 2 will be removed prior to the Containment Building concrete surface inspection required by Section Xl, Subsection IWL, which is every five years.

Future inspections of the Containment Building concrete surface will follow the frequency and inspection guidance of Aging Management Program (AMP) B2.1.28, ASME Section Xl Subsection IWL.

Future inspections of the Fuel Handing Building concrete surface will follow the frequency and inspection guidance of AMP B2.1.32, Structures Monitoring Program.

RAI 2.1-2

Background:

Title 10 of the Code of Federal Regulations (10 CFR) 54.4, "Scope," states, in part, (a) Plant systems, structures and components within the scope of this part are:

(1) Safety-related systems, structures, and components which are those relied upon to remain functional during and following design-basis events (as defined in 10 CFR 50.49 (b)(1)) to ensure the following functions:

(i) The integrity of the reactor coolant pressure boundary; (ii) The capability to shut down the reactor and maintain it in a safe shutdown condition; or (iii) The capability to prevent or mitigate the consequences of accidents which could result in potential offsite exposures comparable to those referred to in 10 CFR 50.34(a)(1),

10 CFR 50.67(b)(2), or 10 CFR 100.11, as applicable.

(2) All nonsafety-related systems, structures and components whose failure could prevent satisfactory accomplishment of any of the functions identified in (a)(1)(i), (ii), or (iii) of this section.

NOC-AE-1 1002769 Page 5 of 8 Issue:

During the scoping and screening methodology audit, performed on-site May 16-19, 2011, the staff reviewed the license renewal application, license renewal implementing documents and had discussions with the applicant, to determine the applicant's approach for identifying nonsafety-related SSCs, with the potential to impact safety-related SSCs, and to include the nonsafety-related SSCs within the scope of license renewal in accordance with 10 CFR 54.4 (a)(2). The staff determined that the method used to address the potential for nonsafety-related SSCs to impact safety-related SSCs located in the turbine building as provided during discussions with the applicant, was different than the method provided in the license renewal application (LRA) and the applicant's implementing documents. The staff performed a plant walkdown of the safety-related SSCs located in the turbine building (feedwater regulating control valves' associated air solenoid valves and limit switches) and determined that there were nonsafety-related SSCs located within the vicinity of the safety-related SSCs. The LRA and the applicant's implementing documents stated that nonsafety-related piping and structures that could potentially interact with the safety-related solenoid valves and limit switches were included within the scope of license renewal in accordance with 10 CFR 54.4 (a)(2). However, during audit discussions with the staff, the applicant stated that the safety-related solenoid valves and limit switches were qualified to withstand the effects of the failure of nonsafety-related SSCs within the vicinity of the safety-related SSCs and, therefore, the nonsafety-related SSCs were not included within the scope of license renewal in accordance with 10 CFR 54.4 (a){2).

Request:

The staff requests that the applicant perform a review of this issue and provide a discussion and basis for the position, as stated by the applicant during the scoping and screening methodology audit, that nonsafety-related SSCs within the vicinity of the safety-related solenoid valves and limit switches located in the turbine building are not required to be included within the scope of license renewal in accordance with 10 CFR 54.4(a)(2). Indicate if the review concludes that use of the scoping methodology precluded the identification of systems, structures, and components (SSCs) which should have been included within the scope of license renewal in accordance with 10 CFR 54.4(a)(2). Describe any additional scoping evaluations performed to address the 10 CFR 54.4(a)(2) criteria. List any additional SSCs included within the scope as a result of your efforts, and list those structures and components for which aging management reviews were conducted or any additional information related to material and environment combinations. For each structure and component, describe the aging management programs, as applicable, to be credited for managing the identified aging effects.

Requested Clarification (Reference 4)

The applicant agreed to supplement B2.1-2 to cover the following:

i) Specify what specific NS systems, or portions of systems, were included in scope for (a)(2) as a result of the potential for interaction with the SR components in the turbine buildings, and; ii) Provide information indicating the LR drawings that have highlighted portions to indicate these components.

NOC-AE-1 1002769 Page 6 of 8 STPNOC Supplementary Response The following is a list of the component types and their boundary drawing locations that are in-scope of license renewal which could potentially impact the safety-related solenoid valves and limit switches associated with the feedwater regulating valves.

Component System Type Material Internal Environment Boundary Drawing Location CD Valve Stainless Steel Secondary Water LR-STP-CD-9S219F20015 F-8 Valve Stainless Steel Secondary Water LR-STP-CD-6S189F00039 D-2 Piping Stainless Steel Secondary Water LR-STP-CD-6S189F00039 D-2 Piping Stainless Steel Secondary Water LR-STP-CD-9S219F20015 F-8 Closed Cycle Cooling CH Piping Carbon Steel Water LR-STP-CH-6V109V00010 F-6 Closed Cycle Cooling Piping Carbon Steel Water LR-STP-CH-6V109V00010 G-6 FW Piping Carbon Steel Secondary Water LR-STP-FW5S139F00063 D-1 through D-8 Piping Carbon Steel Secondary Water LR-STP-FW5S139F00063 E-1 through E-8 Valve Carbon Steel Secondary Water LR-STP-FW5S139F00063 D-1 through D-8 Valve Carbon Steel Secondary Water LR-STP-FW5S139F00063 E-1 through E-8 MS Piping Carbon Steel Steam LR-STP-MS-5S109F00016 G-3 Piping Carbon Steel Steam LR-STP-MS-5S109F00016 F-3 Piping Carbon Steel Steam LR-STP-MS-5S109F00016 D-3 Piping Carbon Steel Steam LR-STP-MS-5S109F00016 C-3 OC Piping Carbon Steel Raw Water LR-STP-OC-6T249F00033 G-3 Piping Carbon Steel Raw Water LR-STP-OC-6T249F00033 H-3 Piping Carbon Steel Raw Water LR-STP-OC-6T249F00033 G-5 Piping Carbon Steel Raw Water LR-STP-OC-6T249F00033 H-5 Piping Copper Alloy (>15% Zinc)

Raw Water LR-STP-OC-6T249F00033 H-3 Piping Copper Alloy (>15% Zinc)

Raw Water LR-STP-OC-6T249F00033 G-5 Piping Copper Alloy (>15% Zinc)

Raw Water LR-STP-OC-6T249F00033 H-5 NOC-AE-1 1002769 Page 7 of 8 Component System Type Material Internal Environment Boundary Drawing Location Valve Copper Alloy (Aluminum >8%)

Raw Water LR-STP-OC-6T249F00033 G-5 Valve Copper Alloy (Aluminum >8%)

Raw Water LR-STP-OC-6T249F00033 H-5 Valve Copper Alloy (> 15% Zinc)

Raw Water LR-STP-OC-6T249F00033 G-5 Valve Copper Alloy (>15% Zinc)

Raw Water LR-STP-OC-6T249F00033 H-5 Valve Copper Alloy (>15% Zinc)

Raw Water LR-STP-OC-6T249F00033 G-3 Valve Copper Alloy (>15% Zinc)

Raw Water LR-STP-OC-6T249F00033 H-3 WL Piping Stainless Steel Raw Water LR-STP-OC-6T249F00033 G-3 Valve Stainless Steel Raw Water LR-STP-OC-6T249F00033 G-3 NOC-AE-1 1002769 Page 8 of 8 RAI B2.1.20-5 STPNOC Revised Information Reference 3 supplemented a previous letter response to RAI B2.1.20-5 to revise LRA Appendices A1.22 and B2.1.22 volumetrically inspect the AFST and FWST tank bottoms from the inside of the tank within 5 years prior to entering the period of extended operation and whenever the tanks are drained. The revision in Reference 3 inadvertently did not include the following wording.

"within 5 years prior to entering the period of extended operation and whenever the tanks are drained" provides the line-in/line-out revision to LRA Appendix A1.22 and B2.1.22 Note: Enclosure 2 shows the revised wording provided in Reference 3 and the additional revised wording that was inadvertently not included.

RAI B2.1.25-1 STPNOC Revised Information LRA Appendices A1.25 and B2.1.25, Table A4-1 Item 20 and LRA Bases Document XI.E3 (B2.1.25), "Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 EQ Requirements",

have been revised to include performing event-driven inspections as an on-demand activity based on actual plant experience. provides the line-in/line-out revision to LRA Appendices A1.25 and B2.1.25. provides a line-in/line-out revision to Table A4-1 Item 20.

NOC-AE-1 1002769 STP LRA Changes with Line-in/Line-out Annotations NOC-AE-1 1002769 Page 1 of 10 List of Revised LRA Sections RAI Affected LRA Section RAI B2.1.20-5 Appendix A1.22 Appendix B2.1.22 RAI B2.1.25-1 Appendix A1.25 Appendix B2.1.25 Table A4-1 Item 20 (see Enclosure 3)

NOC-AE-1 1002769 Page 2 of 10 AI.22 INSPECTION OF INTERNAL SURFACES IN MISCELLANEOUS PIPING AND DUCTING COMPONENTS The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program manages cracking, loss of material, and hardening and loss of strength of the internal surfaces of piping, piping components, ducting, tanks and other components that are not inspected by other aging management programs.

The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program is a new program that uses the work control process for preventive maintenance and surveillance to conduct and document inspections. The program performs visual inspections to detect aging effects that could result in a loss of component intended function.

Visual inspections of internal surfaces of plant components are performed by qualified personnel during the conduct of periodic maintenance, predictive maintenance, surveillance testing, and corrective maintenance. Supplemental inspections not performed concurrently with planned work activities will be performed. The locations and intervals for these supplemental inspections are based on assessments of the likelihood of significant degradation and on current industry and plant-specific operating experience.

Additionally, visual inspections may will be augmented by physical manipulation of at least 10 percent of available surface area of elastomers within the scope of the program, when appropriate for the component configuration and material, to detect hardening and loss of strength of both-internal and etemat surfaces of elastomersj. In cases where internal surfaces are not available for visual inspection, an internal visual inspection may be substituted with a volumetric examination. The program includes volumetric examination of the tank bottoms of the auxiliary feedwater storage tanks and the firewater storage tanks from inside the tanks within 5 years prior to entering the period of extended operation and whenever the tanks are drained to confirm the absence of loss of material due to corrosion.

The program also includes anad-lb-volumetric evaluation to detect stress corrosion cracking of the internal surfaces of stainless steel components exposed to diesel exhaust.

The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program will be implemented 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 1002769 Page 3 of 10 B2.1.22 Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program Description The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program manages cracking, loss of material, and hardening and loss of strength of the internal surfaces of piping, piping components, ducting tanks and other components that are not inspected by other aging management programs.

The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program is a new program that uses the work control process for preventive maintenance and surveillance to conduct and document inspections. The program performs visual inspections to detect aging effects that could result in a loss of component intended function.

Visual inspections of internal surfaces of plant components are performed by qualified personnel during periodic maintenance, predictive maintenance, surveillance testing and corrective maintenance. Supplemental inspections, not performed concurrently with planned work activities will be performed. The locations and intervals for these supplemental inspections are based on assessments of the likelihood of significant degradation and on current industry and plant-specific operating experience.

Additionally, visual inspections may-will be augmented by physical manipulation of at least 10 percent of available surface area of elastomers within the scope of the program, when appropriate for the component configuration and material, to detect hardening and loss of strength of both-internal and-e41e~nal surfaces of elastomers. In cases where internal surfaces are not available for visual inspection, an internal visual inspection may be substituted with a volumetric examination. The program includes volumetric examination of the tank bottoms of the auxiliary feedwater storage tanks and the firewater storage tanks from inside the tanks within 5 years prior to entering the period of extended operation and whenever the tanks are drained to confirm the absence of loss of material due to corrosion.

The program also includes volumetric evaluation (ultrasonic examination) to detect stress corrosion cracking of the internal surfaces of stainless steel components exposed to diesel exhaust.

This program will be initiated prior to entering the period of extended operation and provides for periodic inspection of a selected set of sample components within the scope of this program. The internal surfaces inspections are normally performed through scheduled preventive maintenance and surveillance inspections such that work opportunities are sufficient to detect aging and provide reasonable assurance that intended functions are maintained. Supplemental inspections not performed concurrently with planned work activities will be performed. The locations and intervals for these supplemental inspections will be based on assessments of the likelihood of significant degradation and on current industry and plant-specific operating experience.

NUREG-1801 Consistency The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program is a new program that, when implemented, will be consistent with exception to NUREG-1801,Section XI.M38, Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components.

NOC-AE-1 1002769 Page 4 of 10 Exceptions to NUREG-1801 Program Elements Affected:

Scope of Program (Element 1), Parameters Monitored or Inspected (Element 3), Detection of Aging Effects (Element 4), and Monitoring and Trending (Element 5)

NUREG-1801 Section XI.M38 provides for a program of visual inspections of the internal surfaces of miscellaneous steel piping and ducting components to ensure that existing environmental conditions are not causing material degradation that could result in a loss of component intended functions. The exceptions to NUREG-1 801 Section XI.M38 are an increase to the scope of the materials inspected to include stainless steel, aluminum, copper alloy, stainless steel-cast austenitic, nickel alloys, glass and elastomers, in addition to steel, and an increase to the scope of aging effects to include hardening and loss of strength for elastomers. Additionally, visual inspections iay will be augmented (1) by physical manipulation of at least 10 percent of available surface area of elastomers within the scope of the program to detect hardening and loss of strength of elastomers when appropriate for the component configuration and material, (2) volumetric examinations of the tank bottoms of the auxiliary feedwater storage tanks and the firewater storage tanks from inside the tanks, to confirm the absence of loss of material due to corrosion, and (32) by volumetric evaluation to detect stress corrosion cracking of the internal surfaces of stainless steel components exposed to diesel exhaust.

Enhancements None Operating Experience The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program is a new program; therefore, plant-specific operating experience to verify the effectiveness of the program is not available. However, visual inspections were conducted during periodic maintenance, predictive maintenance, surveillance testing and corrective maintenance. These records provided evidence of STP using maintenance opportunities to conduct internal inspections during normal plant activities. Industry operating experience that forms the basis for this program is included in the operating experience element of the corresponding NUREG-1801 aging management program. A review of plant condition reporting documents, as well as other STP current licensing basis documents, since 1998, was performed to ensure that there is no unique, plant-specific experience in addition to that in NUREG-1801. The review identified no unique operating experience.

Many of the plant condition reporting documents discussed above concerned corrosion found in HVAC systems. The corrective actions for these conditions generally included removal of the corrosion and painting to prevent recurrence.

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.

NOC-AE-1 1002769 Page 5 of 10 Conclusion The implementation of the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 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-1 1002769 Page 6 of 10 A1.25.

INACCESSIBLE MEDIUM VOLTAGE CABLES NOT SUBJECT TO 10 CFR 50.49 ENVIRONMENTAL QUALIFICATION REQUIREMENTS The Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements program manages localized damage and breakdown of insulation leading to electrical failure of inaccessible or underground medium and low voltage (>400 volts) power cables exposed to adverse localized environments caused by significant moisture (periodic exposures to moisture that lasts more than a few days) not subject to the environmental qualification (EQ) requirements of 10 CFR 50.49, and within the scope of license renewal.

All manholes and trenches that contain in-scope Non-EQ inaccessible medium or low voltage power cables are inspected for water collection. Collected water is being removed as required. This inspection and water removal is being performed based on actual plant experience with inspection frequency being at least annually. Event-driven inspections are performed as an on-demand activity based on actual plant experience.

The program provides for testing of in-scope Non-EQ inaccessible medium and low voltage

(>400 volts) power cables to provide an indication of the conductor insulation condition. At least once every six years, a dielectric loss (dissipation factor/power factor), AC voltage withstand, partial discharge, step voltage, time domain reflectometry, insulation resistance, polarization index, line resonance analysis, or other testing that is state-of-the-art at the time of the testing is performed. The first test will be completed prior to the period of extended operation.

NOC-AE-1 1002769 Page 7 of 10 B2.1.25 Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program Description The Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements program manages localized damage and breakdown of insulation leading to electrical failure of inaccessible or underground medium and low voltage (>400 volts) power cables exposed to adverse localized environments caused by significant moisture (periodic exposures to moisture that last more than a few days) to ensure that inaccessible medium and low voltage power cables not subject to the environmental qualification (EQ) requirements of 10 CFR 50.49, and within the scope of license renewal are capable of performing their intended function. This program considers the technical information and guidance provided in NUREG/CR-5643, Insights Gained From Aging Research, IEEE Std. 1205, IEEE Guide for Assessing, Monitoring and Mitigating Aging Effects on Class 1E Equipment Used in Nuclear Power Generating Stations, SAND 96-0344, Aging Management Guideline for Commercial Nuclear Power Plants - Electrical Cable and Terminations, and EPRI TR-1 09619, Guideline for the Management of Adverse Localized Equipment Environments.

All manholes and trenches that contain in-scope non-EQ inaccessible medium or low voltage (>400 volts) power cables are inspected for water collection. Collected water is removed as required. This inspection and water removal is performed based on actual plant experience with the inspection frequency being at least once annually. Solar powered sump pumps provide for removal of water from some manholes prior to accumulation.

Event-driven inspections are performed as an on-demand activity based on actual plant experience.

All in-scope non-EQ inaccessible medium and low voltage (>400 volts) power cables routed through manholes or trenches are tested to provide an indication of the conductor insulation condition. A dielectric loss (dissipation factor/power factor), AC voltage withstand, partial discharge, step voltage, time domain reflectometry, insulation resistance, polarization index, line resonance analysis, or other testing that is state-of-the-art at the time of the testing is performed at least once every six years. The first test will be completed prior to the period of extended operation.

NUREG-1801 Consistency The Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements is an existing program that, following enhancement, will be consistent with NUREG-1801,Section XI.E3, Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements.

Exceptions to NUREG-1801 None NOC-AE-1 1002769 Page 8 of 10 Enhancements Prior to the period of extended operation, the following enhancement will be implemented in the following program elements:

Scope of Program (Element 1)

Procedures will be enhanced to identify the cables, manholes and trenches that are within the scope of the program.

Preventive Actions (Element 2)

Procedures will be enhanced to require the following:

Inspection of in-scope manholes and trenches based on plant-specific operating experience with inspection being conducted at least annually.

" Manhole inspection results arc evaluated based on actual plant experience withth i nspection frequencY inrGeased based On experiencae with water accu~mulation.

Event-driven inspections of in-scope manholes will be performed as an on-demand activity based on actual plant experience.

Direct observation that cables are not wetted or submerged.

Removal of collected water and verification of sump pump operability.

The initiation of a corrective action if wetted cables or inoperable sump pumps are found.

Inspection of the cables/splices and cable support structures whenever wetted cables are found.

Corrective actions to be taken to keep cables dry.

Parameters Monitored or Inspected (Element 3)

Procedures will be enhanced to require the following:

Inspection of the in-scope manholes and trenches for water accumulation based on plant experience with water accumulation.

The inspection frequency is to be at least annually.

Conduct testing of in-scope inaccessible medium and low voltage (>400 volts) power cables exposed to significant moisture using a test capable of detecting reduced insulation resistance.

Detection of Aging Effects (Element 4)

Procedures will be enhanced to require the following:

Test in-scope inaccessible medium and low voltage (>400 volts) power cables exposed to significant moisture at least once every six years with the first test being completed prior to the period of extended operation.

NOC-AE-1 1002769 Page 9 of 10 Conduct testing of in-scope inaccessible medium and low voltage (>400 volts) power cables exposed to significant moisture using a test capable of detecting reduced insulation resistance.

Monitoring and Trending (Element 5)

Procedures will be enhanced to require inspection and test results that can be trended be trended to provide additional information on the rate of cable insulation degradation.

Acceptance Criteria (Element 6)

Procedures will be enhanced to define the following:

The acceptance criterion for manhole and trench cables/splices and support structures is that they are not submerged or immersed in water.

The acceptance criteria for cable testing will be defined prior to each test for the specific type of test performed and the specific cable tested.

Corrective Actions (Element 7)

Procedures will be enhanced to require the following:

" An engineering evaluation is performed when the test or inspection acceptance criteria are not met. The engineering evaluation shall consider the significance of the test or inspection results, the operability of the component, the reportability of the event, the extent of the concern, the potential root causes for not meeting the test or inspection acceptance criteria, the corrective actions required, and the likelihood of recurrence.

An extent of condition when an unacceptable condition or situation is identified.

Operating Experience Industry operating experience has shown that insulation materials are most susceptible to water tree formation. Formation and growth of water trees varies directly with operating voltage. Aging effects of reduced insulation resistance due to other mechanisms may also result in a decrease in the dielectric strength of the conductor insulation.

Site-specific operating experience has shown that STP has not experienced a failure of any in-scope inaccessible power cables (>400 volts). A review of the plant operating experience indicates that STP has experienced a situation in which water was leaking into the Unit 2 cable vault and electrical auxiliary building battery rooms. The source of the water was determined to be a series of manholes leading into the rooms. The cause of the water in the manholes was discovered to be a result of damaged manhole covers as well as temporary power cable installation where the sump cover was propped open for an extended period of time. In addition, STP has experienced a recurring groundwater incursion to some manholes. Solar powered sump pumps have been installed in the affected manholes and have been found effective in preventing cable exposure to significant moisture.

STP is developing a cable management program. The development of the program is ongoing utilizing guidance from EPRI 1020805, Aging Management Guidance for Medium NOC-AE-1 1002769 Page 10 of 10 Voltage Cable Systems for Nuclear Power Plants and EPRI 1020804, Aging Management Development Guidance for AC and DC Low-Voltage Power Cable Systems for Nuclear Power Plants. STP is also assessing guidance provided by NUREG/CR-7000, Essential Elements of an Electric Cable Condition Monitoring Program, and draft Regulatory Guide DG-1240, Condition Monitoring for Electric Cables Used in Nuclear Power Plants.

As additional industry and applicable plant-specific operating experience becomes available, the operating experience will be evaluated and appropriately incorporated into the program through the STIP corrective action and operating experience programs. Industry and plant-specific operating experience will be evaluated in the development and implementation of this program.

Conclusion The continued implementation of the Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements 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-1 1002769 Revised LRA Regulatory Commitment NOC-AE-1 1002769 Page 1 of 2 A4 License 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 20 Enhance the Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 B2.1.25 Prior to the period Environmental Qualification Requirements program procedures to:

of extended identify the cables, manholes, and trenches that are within the scope of the operation

program, require all in-scope non-EQ inaccessible medium and low voltage power cables CR 10-23275-1

(>400 volts) power cables exposed to significant moisture be tested at least once every six years with the first test being completed prior to period of extended operation, require that the acceptance criteria be defined prior to each test for the specific type of test performed and the specific cable tested, require an engineering evaluation that considers the age and operating environment of the cable be performed when the test acceptance criteria are not met. The engineering evaluation shall consider the significance of the test or inspection results, the operability of the component, the reportability of the event, the extent of the concern, the potential root causes for not meeting the test or inspection acceptance criteria, the corrective actions required, and the likelihood of recurrence.

inspect in-scope manholes and trenches based on plant-specific operating experience with water accumulation, require inspections be conducted at least annually, event-driven inspections of in-scope manholes will be performed as an on-NOC-AE-1 1002769 Page 2 of 2 Table A4-1 License Renewal Commitments Item #

Commitment LRA emento Section Schedule demand activity based on actual plant experience.

perform direct observation that cables are not wetted or submerged, remove collected water and verification of sump pump operability, initiate a corrective action if wetted cables or inoperable sump pumps are found, inspect cables/splices and cable support structures if wetted cables are found,

" take corrective actions to keep cables dry,

" mnanhole inspection results are evaluated based On actual plant experience with the inspection frequnc inraed based on experience-with water accumulation.

testing of in-scope inaccessible medium and low voltage (>400 volts) power cables exposed to significant moisture using a test capable of detecting reduced insulation resistance, trend inspection and test results to provide additional information on the rate of cable insulation degradation, require that the acceptance criterion for manhole and trench be cables/splices and support structures is that they are not submerged or immersed in water, and require an extent of condition when an unacceptable condition or situation is identified.

I