RA-25-0237, Unit 2, Subsequent License Renewal Application Supplement 2

Unit 2, Subsequent License Renewal Application Supplement 2

ML25274A131
Person / Time
Site:	Robinson
Issue date:	10/01/2025
From:	Basta L Duke Energy Florida
To:	Office of Nuclear Reactor Regulation, Document Control Desk
References
RA-25-0237
Download: ML25274A131 (1)

Text

Laura A. Basta Site Vice President H.B. Robinson Steam Electric Plant Unit 2 Duke Energy 3581 West Entrance Road Hartsville, SC 29550 o: 864.951.1701 Laura.Basta @duke-energy.com October 1, 2025 10 CFR 50.4 Serial: RA-25-0237 10 CFR Part 54 ATTN: Document Control Desk U.S Nuclear Regulatory Commission Washington, DC 20555-0001

Subject:

Duke Energy Progress, LLC (Duke Energy)

H.B. Robinson Steam Electric Plant, Unit Number 2 Docket Number 50-261 / Renewed License Number DPR-23 Subsequent License Renewal Application Supplement 2 References:

1. Duke Energy Letter (RA-25-0067), Application for Subsequent Renewed Operating Licenses, dated April 1, 2025 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML25091A291)

2. U.S. NRC Letter, Determination of Acceptability and Sufficiency for Docketing, Proposed Review Schedule, and Opportunity for a Hearing Regarding the Duke Energy Progress, LLC Application for Subsequent License Renewal, dated April 28, 2025 (ADAMS Accession No. ML25106A069)

3. U.S. NRC Letter, Aging Management Audit Plan Regarding the Subsequent License Renewal Application Review, dated April 25, 2025 (ADAMS Accession No. ML25113A162)

4. U.S. NRC Letter, Revision of Schedule for the Safety Review of the H.B. Robinson Steam Electric Plant, Unit 2, Subsequent License Renewal Application, dated August 7, 2025 (ADAMS Accession No. ML25202A136)

5. Duke Energy Letter (RA-25-0200), H.B. Robinson Steam Electric Plant, Unit Number 2, Subsequent License Renewal Application Supplement 1, dated August 28, 2025 (ADAMS Accession Nos. ML25240B656, ML25240B657)

6. U.S. NRC, Standardization Recommendations for License Renewal Applications, May 2025 (ADAMS Accession No. ML25132A176)

By letter dated April 1, 2025 (Reference 1), Duke Energy Progress, LLC (Duke Energy) submitted an application for the subsequent license renewal of Renewed Facility Operating License Number DPR-23 for the H.B. Robinson Steam Electric Plant (RNP), Unit 2 to the U.S. Nuclear Regulatory Commission (NRC). On April 28, 2025 (Reference 2), the NRC determined that the RNP subsequent license renewal application (SLRA) was acceptable and sufficient for docketing. By letter dated April 25, 2025 (Reference 3), the NRC issued the regulatory audit plan for the aging management portion of the SLRA review. On August 7, 2025 (Reference 4), the NRC provided a change in the review schedule. During the audit, conducted from April 30, 2025 to August 7, 2025, Duke Energy agreed to supplement the SLRA with new or clarifying information. On August 28, 2025, Duke Energy submitted Supplement 1 to the SLRA (Reference 5). This letter provides the NRC staff with additional information in support of the development of the safety evaluation report, as Supplement 2.

fa DUKE

~ ENERGY

U.S. Nuclear Regulatory Commission RA-25-0237 Page 2 to this letter provides the index of topics to be supplemented. Duke Energy followed the standardization recommendations for license renewal applications (Reference 6), including the formatting guidelines outlined for Section 3 RAI responses and supplements. These changes are described for each attachment, with affected section(s), page number(s), and document mark-ups clearly identified. Changes to commitments are provided in Table A6.0-1 for Attachments 4, 8, 10, 11,

12, 16, and 21.

If you have additional questions, please contact Daniel Roberts at (704) 382 3444 or by email at daniel. roberts2@duke-energy.com.

I declare under penalty of perjury that the foregoing is true and correct. Executed on October 1, 2025.

Sincerely, Laura A. Basta Site Vice President H.B Robinson Steam Electric Plant : Index of Attachment Topics Involving SLRA Supplements : Modifications to Auxiliary Systems Scoping and Screening : Screening Fire Protection Gas Cylinders : Fire Protection Scoping and Screening and TRP 27 : Fire Protection Scoping and Screening, TRP 27, and TRP 82 : Onsite Audit Electrical Questions 6 & 10 - Revise SBO Recovery Path Figures : Onsite Audit Electrical Question 17 for XI. E6 in Appendix 82.1.44 : Updates to the SLRA based on NRG SLRA On Site Structural Walkdown Audit : SLRA revisions related to TRP 14 (Buried and Underground Piping and Tanks Program : Additional clarification to AMP description regarding Potable Water System Hot Water Heater 0: SLRA revisions related to TRP 17 (Flow Accelerated Corrosion Program) 1 : TRP 46 - Structures Monitoring Program Breakout Updates 2: TRP 51 Changes to XI.E1 AMP in Section 82.1.37 3: Change Table 3.6.2-2 AMR Note for E3C AMP 4: Add Cable Bus & Plant-Specific Note to XI.E1 AMP Description & AMR Table 5: TRP 63 - Add AMR Table and Lines for EQ Equipment 6: Supplement changes to address issues related to TRP 76 7: Supplement changes to address issues related to TRP-142.2 8: Supplement changes to address issues related to TRP-143.4 9: Supplement changes to address PWSCC concern measures, water hammer, and low and high cycle fatigue related to TRP 147.31 0: Concrete Containment Bonded Tendon Prestress TLAA 1 : Concrete Containment Bonded Tendon Prestress AMP

U.S. Nuclear Regulatory Commission Page 3 RA-25-0237 CC: W/O

Enclosures:

Julio Lara, Acting Regional Administrator U.S. Nuclear Regulatory Commission - Region II Marquis One Tower 245 Peachtree Center Ave., NE Suite 1200 Atlanta, Georgia 30303-1257 Andrew Siwy, Project manager (by electronic mail only)

U.S. Nuclear Regulatory Commission 11555 Rockville Pike Rockville, Maryland 20852 Karen Loomis, Project Manager (by electronic mail only)

U.S. Nuclear Regulatory Commission 11555 Rockville Pike Rockville, Maryland 20852 Natreon Jordan, Project Manager (by electronic mail only)

U.S. Nuclear Regulatory Commission 11555 Rockville Pike Rockville, Maryland 20852 John Zeiler (by electronic mail only)

NRC Senior Resident Inspector H.B. Robinson Steam Electric Plant, Unit 2 A. Wilson, Attorney General (SC)

R.S. Mack, Assistant Bureau Chief, Bureau of Environmental Health Services (SC)

L. Garner, Manager, Radioactive and Infectious Waste Management Section (SC)

U.S. Nuclear Regulatory Commission RA-25-0237 H.B. ROBINSON STEAM ELECTRIC PLANT, UNIT 2 SUBSEQUENT LICENSE RENEWAL APPLICATION H.B. ROBINSON SLRA SUPPLEMENT 2

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application H.B. Robinson SLRA Supplement 2 H.B. Robinson SLRA Supplement 2 Index of Attachment Topics Involving SLRA Supplements Attachment Number Topics Title 1

Auxiliary Systems Scoping and Screening Modifications to Auxiliary Systems Scoping and Screening 2

Fire Protection Scoping and Screening Screening Fire Protection Gas Cylinders 3

Fire Protection Scoping and Screening and TRP 27 Fire Protection Scoping and Screening and TRP 27 4

Fire Protection Scoping and Screening, TRP 27, and TRP 82 Fire Protection Scoping and Screening, TRP 27, and TRP 82 5

Onsite Audit Electrical Questions 6 & 10 Onsite Audit Electrical Questions 6 & 10 - Revise SBO Recovery Path Figures 6

Onsite Audit Electrical Question 17 Onsite Audit Electrical Question 17 for XI.E6 in Appendix B2.1.44 7

SLRA On Site Structural Walkdown Updates to the SLRA based on NRC SLRA On Site Structural Walkdown Audit 8

TRP 14 SLRA revisions related to TRP 14 (Buried and Underground Piping and Tanks Program) 9 TRP-15, Rev 1 Additional clarification to AMP description regarding Potable Water System Hot Water Heater.

10 TRP 17 SLRA revisions related to TRP 17 (Flow-Accelerated Corrosion Program) 11 TRP 46 TRP 46 - Structures Monitoring Program Breakout Updates 12 TRP 51 TRP 51 Changes to XI.E1 AMP in Section B2.1.37 13 TRP 53.3 Change Table 3.6.2-2 AMR Note for E3C AMP 14 TRP 58 Add Cable Bus & Plant-Specific Note to XI.E1 AMP Description & AMR Table

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application H.B. Robinson SLRA Supplement 2 15 TRP 63 TRP 63 - Add AMR Table and Lines for EQ Equipment 16 TRP 76 Supplement changes to address issues related to TRP 76.

17 TRP-142.2 Supplement changes to address issues related to TRP-142.2.

18 TRP-143.4 Supplement changes to address issues related to TRP-143.4 19 TRP 147.31 Supplement changes to address PWSCC concern measures, water hammer, and low and high cycle fatigue related to TRP 147.31 20 TRP 147.7 Concrete Containment Bonded Tendon Prestress TLAA 21 TRP 151 Concrete Containment Bonded Tendon Prestress AMP

ENCLOSURE 1 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT 2 SUBSEQUENT LICENSE RENEWAL APPLICATION H.B. ROBINSON SLRA SUPPLEMENT 2 ATTACHMENT 1 Auxiliary Systems Scoping and Screening

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 1 1, Attachment 1 Modifications to Auxiliary Systems Scoping and Screening (Auxiliary Systems Scoping and Screening)

Affected SLRA Table(s):

2.3.4-9 3.4.2-9 SLRA Page Numbers:

2 - 153 3 - 828 Description of Change:

Table 2.3.4-9 adds a new row for the Gland Steam Condenser Exhauster blower casings.

Table 3.4.2-9 adds 4 new AMR lines to reflect the inclusion of the Gland Steam Condenser Exhauster blower casings.

The following boundary drawings have been revised:

RSLRD-5379-00685-001 (Rev. 1) - Revised to correct a minor drawing error RSLRD-HBR2-08680 (Rev. 1) - Revised to highlight the Gland Steam Condenser Exhausters and associated piping/valves.

SLRA Revisions:

SLRA Section 2.3.4.9 is revised as follows:

Section 2.3.4.9 Components Subject to Aging Management Review Table 2.3.4-9 Gland Seal System Component/Commodity Group Intended Functions Blower Casing (gland steam condenser)

Structural Integrity

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 1 2

SLRA Table 3.4.2-9 is revised as follows:

Table 3.4.2-9 Steam and Power Conversion Systems - Gland Seal System - Aging Management Evaluation AMR ID Component Type Intended Function Material Environment Aging Effect Aging Management Program NUREG-2191 Item NUREG-2192 Table 1 Notes New -

9286 Blower Casing (gland steam condenser)

Structural Integrity Steel Air - Outdoor (External)

Loss of Material External Surfaces Monitoring of Mechanical Components (B2.1.23)

VIII.H.S-402a 3.4.1-063 C

New -

9287 Blower Casing (gland steam condenser)

Structural Integrity Steel Treated Water (Internal)

Long-Term Loss of Material One-Time Inspection (B2.1.20)

VIII.A.S-432 3.4.1-081 C

New -

9289 Blower Casing (gland steam condenser)

Structural Integrity Steel Treated Water (Internal)

Loss of Material One-Time Inspection (B2.1.20)

VIII.B1.SP-74 3.4.1-014 C

New -

9288 Blower Casing (gland steam condenser)

Structural Integrity Steel Treated Water (Internal)

Loss of Material Water Chemistry (B2.1.2)

VIII.B1.SP-74 3.4.1-014 C

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ENCLOSURE 1 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT 2 SUBSEQUENT LICENSE RENEWAL APPLICATION H.B. ROBINSON SLRA SUPPLEMENT 2 ATTACHMENT 2 Fire Protection Scoping and Screening

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 2 1, Attachment 2 Screening Fire Protection Gas Cylinders (Fire Protection Scoping and Screening)

Affected SLRA Section(s):

2.3.3.11 2.3.3.12 2.3.3.13 2.3.3.17 SLRA Page Numbers:

2-86 2-87 2-88 2-94 Description of Change:

Add statement that gas bottles are inspected and replaced in accordance with applicable NFPA codes, and are not subject to aging management review.

SLRA Revisions:

SLRA Section 2.3.3.11 is revised as follows:

Section 2.3.3.11 System Description The Dry Agent Suppression System is a gaseous fire suppression system used in Switchgear Building 469 Relay Rooms A and B and in the Hagan room adjacent to the control room. The system uses a clean agent fire suppressant governed by NFPA 2001, Standard on Clean Agent Fire Extinguishing Systems. The Dry Agent Fire Suppression System clean agent cylinders are installed and maintained in accordance with NFPA 2001 (Standard on Clean Agent Fire Extinguishing Systems). The clean agent cylinders are subject to frequent inspection and replacement under the Robinson maintenance program as required by NFPA 2001, and are not subject to aging management review.

SLRA Section 2.3.3.12 is revised as follows:

Section 2.3.3.12 System Description The Emergency Diesel Generator Car Dox System provides fire protection for the safety-related diesel generator rooms. The system consists of an automatic carbon dioxide system with separate detectors in each diesel room so that the room containing a fire will be the only one blanketed. The room ventilation system is interlocked so that ventilation supply and exhaust fans will be deenergized in the affected room on a carbon dioxide system actuation. Also, the diesel room dampers are closed on a fire detector initiation. Initiation of the carbon dioxide system also shuts down the fuel supply system to the affected diesel day tank without affecting the other diesel. The Emergency Diesel Generator Car Dox System Car Dox cylinders are installed and maintained in accordance with NFPA 12 (Standard on Carbon Dioxide

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 2 2

Extinguishing Systems). The Car Dox cylinders are subject to frequent inspection and replacement under the Robinson maintenance program as required by NFPA 12, and are not subject to aging management review.

SLRA Section 2.3.3.13 is revised as follows:

Section 2.3.3.13 System Description The Fire Protection CO2 System provides for automatic fire suppression in the south and north cable vaults in the Auxiliary Building. Multiple cylinders of carbon dioxide discharge in order to provide the design concentration. The design concentration is ensured by automatic damper closure upon actuation of the system. The Fire Protection CO2 System CO2 storage cylinders are installed and maintained in accordance with NFPA 12 (Standard on Carbon Dioxide Extinguishing Systems). The CO2 cylinders are subject to frequent inspection and replacement under the Robinson maintenance program as required by NFPA 12, and are not subject to aging management review.

SLRA Section 2.3.3.17 is revised as follows:

Section 2.3.3.17 System Description The Halon Supply System provides an automatic means of fire suppression for the Unit 2 Cable Spreading Room and the Emergency Switchgear E1/E2 Room. The system is designed to supply the required atmospheric concentration of Halon to the rooms for fire suppression. The design concentration is ensured by closure of the affected room ventilation dampers. The Halon Supply System Halon storage cylinders are installed and maintained in accordance with NFPA 12A (Standard on Halon 1301 Fire Extinguishing Systems). The Halon cylinders are subject to frequent inspection and replacement under the Robinson maintenance program as required by NFPA 12A, and are not subject to aging management review.

ENCLOSURE 1 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT 2 SUBSEQUENT LICENSE RENEWAL APPLICATION H.B. ROBINSON SLRA SUPPLEMENT 2 ATTACHMENT 3 Fire Protection Scoping and Screening and TRP 27

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 3 1, Attachment 3 Fire Protection Scoping and Screening and TRP 27 (Fire Protection Scoping and Screening and TRP 27)

Affected SLRA Section(s)/Table(s):

3.3.2.2.8 3.3.2-14 3.3.2.1.14 SLRA Page Numbers:

3-231 3-280 3-509 3-514 Description of Change:

Diesel Fire Pump Fuel Oil Tank Subcomponent AMR SLRA Revisions:

SLRA Section 3.3.2.2.8 is revised as follows:

Section 3.3.2.2.8 x

The flame arrestor on the Diesel Fire Pump Fuel Oil Tank in the Fuel Oil System is constructed of an unknown aluminum alloy series, and therefore evaluated as susceptible to SCC. This component is exposed to a non-aggressive outdoor air environment at the intake structure. This flame arrestor is not encapsulated in materials containing halides or exposed to secondary sources of moisture or halides.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 3 2

SLRA Table 3.3.2-14 is revised as follows:

Table 3.3.2-14 Auxiliary Systems - Fuel Oil System - Aging Management Evaluation AMR ID Component Type Intended Function Material Environment Aging Effect Aging Management Program NUREG-2191 Item NUREG-2192 Table 1 Notes New -

9308 Tank (diesel fire pump fuel oil)

Pressure Boundary Aluminum Air - Outdoor (External)

Cracking One-Time Inspection (B2.1.20) VII.H1.A-451a 3.3.1-189 A,5 New -

9309 Tank (diesel fire pump fuel oil)

Pressure Boundary Aluminum Air - Outdoor (External)

Loss of Material One-Time Inspection (B2.1.20) VII.H1.A-763a 3.3.1-234 A,5 New -

9306 Tank (diesel fire pump fuel oil)

Pressure Boundary Aluminum Condensation (Internal)

Cracking One-Time Inspection (B2.1.20) VII.H1.A-451a 3.3.1-189 A,5 New -

9307 Tank (diesel fire pump fuel oil)

Pressure Boundary Aluminum Condensation (Internal)

Loss of Material One-Time Inspection (B2.1.20) VII.H1.A-763a 3.3.1-234 A,5 New -

9305 Tank (diesel fire pump fuel oil)

Pressure Boundary Copper Alloy Air - Outdoor (External)

None None VII.J.AP-144 3.3.1-114 A,4 New -

9304 Tank (diesel fire pump fuel oil)

Pressure Boundary Copper Alloy Condensation (Internal)

None None VII.J.AP-144 3.3.1-114 A,4 Plant Specific Notes:

4. The copper alloy (brass) components are the flash arrestor and emergency vent mounted on the top of the Diesel Fire Pump Fuel Oil Tank

5. The aluminum component is the flame arrestor mounted on the top of the Diesel Fire Pump Fuel Oil Tank I I I I I I I I I I I

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H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 3 3

SLRA Section 3.3.2.1.14 is revised as follows:

Section 3.3.2.1.14 x

Aluminum x

Condensation (Internal) x None

ENCLOSURE 1 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT 2 SUBSEQUENT LICENSE RENEWAL APPLICATION H.B. ROBINSON SLRA SUPPLEMENT 2 ATTACHMENT 4 Fire Protection Scoping and Screening, TRP 27, and TRP 82

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 4 1, Attachment 4 Fire Protection Scoping and Screening, TRP 27, and TRP 82 (Fire Protection Scoping and Screening, TRP 27, and TRP 82)

Affected SLRA Section(s)/Table(s):

2.3.3.37 2.3.3-37 3.3.2.1.37 3.3.2-37 A2.1.16 A6.0-1 B2.1.16 SLRA Page Numbers:

2-130 2-131 3-655 3-660 3-663 A-16 A-60 B-104 B-106 Description of Change:

Include VEWFDS stainless steel tubing in Fire Protection System and subject to Aging Management Review. Add screening information for the Diesel Driven Fire Pump engine, and replacement requirement for the Diesel Driven Fire Pump and Motor Driven Fire Pump relief valves. Address sprinkler testing and additional TRP-27 questions SLRA Revisions:

SLRA Section 2.3.3.37 is revised as follows:

Section 2.3.3.37 System Description The Site Fire Protection System protects plant equipment in the event of a fire to ensure safe plant shutdown and to minimize the risk of a radioactive release to the environment. The Site Fire Protection System consists of the water suppression systems. systems and mechanical fire detection components. Suppression systems using carbon dioxide, dry agent, and Halon are evaluated separately. Passive fire barriers are evaluated as structural commodities, except for fire dampers which are evaluated with the HVAC systems. Stainless steel tubing in the Fire detection systems Detection System is evaluated with the Fire Protection System. Other Fire Detection System components are evaluated with Electrical and Instrumentation and Controls.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 4 2

The fire pump diesel engine is an active skid-mounted unit. Components attached to the engine and within the skid boundaries are integral parts of the engine. These components are tested as a unit as part of the active engine and are excluded from aging management review. The Diesel Driven Fire Pump Engine jacket water heat exchanger cooler and charging air cooler will be replaced on a specified time period and are not subject to aging management review under 10 CFR 54.21(a)(1)(ii). A review of operating experience shows that the existing coolers have provided satisfactory service since the diesel engine was replaced in 2014. These coolers will be replaced and inspected before the SPEO to assess their condition and set a replacement frequency during the SPEO, not to exceed 20 years. The Diesel Driven Fire Pump Engine exhaust muffler and fuel oil supply components outside of the skid are subject to aging management review. The water supply from the fire pumps, via the yard loop to applicable hydrants, hose reels, and sprinkler systems are also subject to aging management review.

The Diesel Driven Fire Pump relief valve and Motor Driven Fire Pump relief valve operating experience includes service induced erosion in the discharge nozzles, which resulted in the creation of a preventive maintenance activity in 2004 for replacement on a fifteen-year interval.

A review of operating experience shows the Motor Driven Fire Pump relief valve has failed twice since it was replaced in 2004, with a service life of six to eight years under current operating conditions. The Diesel Driven Fire Pump relief valve provided acceptable service (no failures) through the first fifteen-year replacement interval. The Diesel Driven and Motor Driven Fire Pump relief valves will be replaced and assessed prior to entering the SPEO to establish an appropriate future replacement interval. The replacement frequency for the Motor Driven Fire Pump relief valve in the SPEO will not exceed 6 years, while the Diesel Driven Fire Pump relief valve's replacement frequency will not exceed 15 years. Since the Diesel Driven Fire Pump relief valve and Motor Driven Fire Pump relief valve will be replaced on a specified time period, they are not subject to aging management review under 10 CFR 54.21.(a)(1)(ii).

SLRA Section 2.3.3.37 is revised as follows:

Section 2.3.3.37 Table 2.3.3-37 Site Fire Protection System Component/Commodity Group Intended Functions Flexible Connection (diesel exhaust)

Pressure Boundary Silencer (diesel exhaust)

Pressure Boundary SLRA Section 3.3.2.1.37 is revised as follows:

Section 3.3.2.1.37 x

Diesel Exhaust (Internal)

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 4 3

SLRA Table 3.3.2-37 is revised as follows:

Table 3.3.2-37 Auxiliary Systems - Site Fire Protection System - Aging Management Evaluation AMR ID Component Type Intended Function Material Environment Aging Effect Aging Management Program NUREG-2191 Item NUREG-2192 Table 1 Notes New -

9298 Flexible Connection (diesel exhaust)

Pressure Boundary Stainless Steel Air - Outdoor (External)

Cracking External Surfaces Monitoring of Mechanical Components (B2.1.23)

VII.H2.AP-209b 3.3.1-004 A

New -

9299 Flexible Connection (diesel exhaust)

Pressure Boundary Stainless Steel Air - Outdoor (External)

Loss of Material External Surfaces Monitoring of Mechanical Components (B2.1.23)

VII.H2.AP-221b 3.3.1-006 A

New -

9295 Flexible Connection (diesel exhaust)

Pressure Boundary Stainless Steel Diesel Exhaust (Internal)

Cracking Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25)

VII.H2.AP-128 3.3.1-083 A

New -

9297 Flexible Connection (diesel exhaust)

Pressure Boundary Stainless Steel Diesel Exhaust (Internal)

Loss of Material Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25)

VII.H2.AP-104 3.3.1-088 A

New -

9291 Piping (uninsulated)

Pressure Boundary Stainless Steel Air - Indoor Uncontrolled (External)

Cracking External Surfaces Monitoring of Mechanical Components (B2.1.23)

VII.G.AP-209b 3.3.1-004 A

New -

9293 Piping (uninsulated)

Pressure Boundary Stainless Steel Air - Indoor Uncontrolled (External)

Loss of Material External Surfaces Monitoring of Mechanical Components (B2.1.23)

VII.G.AP-221b 3.3.1-006 A

New -

9290 Piping (uninsulated)

Pressure Boundary Stainless Steel Air - Indoor Uncontrolled (Internal)

Cracking One-Time Inspection (B2.1.20) VII.G.AP-209a 3.3.1-004 A

New -

9292 Piping (uninsulated)

Pressure Boundary Stainless Steel Air - Indoor Uncontrolled (Internal)

Loss of Material One-Time Inspection (B2.1.20) VII.G.AP-221a 3.3.1-006 A

New -

9294 Piping (uninsulated)

Pressure Boundary Stainless Steel Air with Borated Water Leakage (External)

None None VII.J.AP-18 3.3.1-120 A

New -

9300 Silencer (diesel exhaust)

Pressure Boundary Steel Air - Outdoor (External)

Loss of Material External Surfaces Monitoring of Mechanical Components (B2.1.23)

VII.I.A-77 3.3.1-078 A

New -

9296 Silencer (diesel exhaust)

Pressure Boundary Steel Diesel Exhaust (Internal)

Loss of Material Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25)

VII.H2.AP-104 3.3.1-088 A

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H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 4 4

SLRA Section A2.1.16 is revised as follows:

Section A2.1.16 The Fire Water System aging management program is an existing condition monitoring program that manages aging effects associated with water-based fire protection system components.

The program manages loss of material and flow blockage due to fouling by conducting periodic visual inspections, tests, and flushes performed consistent with the 2011 Edition of NFPA 25.

Testing or replacement of sprinklers that have been in place for 50 years is will be performed consistent with the requirements of NFPA 25. 25, Section 5.3.1. A one-time inspection and plant-specific evaluation will be performed to confirm that wetted sprinklers are not subject to a harsh environment. In addition to NFPA codes and standards, portions of the water-based fire protection system that are normally dry but periodically subject to flow have been confirmed verified to drain properly and are do not subjected to require augmented testing beyond that described what is specified in NFPA 25.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 4 5

SLRA Table A6.0-1 is revised as follows:

Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule Difference

- 16 Fire Water System (B2.1.16)

The Fire Water System aging management program is an existing program that will be enhanced to:

1. Prior to 50 years in service, sprinkler Sprinkler heads will either be replaced, or a representative sample will be submitted for field-service testing by a recognized testing laboratory consistent with NFPA 25, 2011 Edition, Section 5.3.1. Prior to the SPEO, a plant-specific evaluation will be performed to demonstrate that the Fire Protection water supply is not corrosive to the wet pipe sprinklers.

This evaluation will be supported by a one-time inspection of at least 3 percent or maximum of 10 sprinklers with no more than four sprinklers per structure in the scope of subsequent license renewal being tested. If the plant specific evaluation concludes that fire water constitutes a harsh environment, Robinson will either perform a one-time test of sprinklers prior to the SPEO or ongoing testing of sprinklers, consistent with the guidance of NUREG-2191, Table XI.M27-1, Footnote 7.

2. Perform a one-time volumetric wall thickness inspection on a representative sample of deluge and preaction system supply piping that is periodically subject to flow during functional testing. The representative sample will be based on the population of deluge and preaction system piping that is periodically subject to flow but is normally dry. The one-time volumetric wall thickness inspection activity will include criteria for selection of inspection locations and Program will be enhanced no later than six months prior to the SPEO, and pre-SPEO inspections and tests will begin within the five-year period before the SPEO.

Inspections or tests that are to be completed prior to the SPEO will be completed no later than six months prior to the SPEO, or no later than the last refueling outage prior to the SPEO.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 4 6

Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule acceptance criteria. The activity will specify the need for follow-up examinations based on inspection results.

3. Perform an obstruction investigation consistent with NFPA 25, 2011 Edition, Section 14.3 if evidence of unacceptable internal flow blockage that could result in the failure of a system function is identified during internal inspections. When unacceptable internal flow blockage is detected, corrective actions will include removal of the material, an extent of condition determination, review for increased inspections, follow-up examinations, and a flush consistent with NFPA 25 Annex D.5, Flushing Procedures.

4. Revise inspection procedures to include inspection parameters for items such as lighting, distance, offset, presence of protective coatings, and cleaning processes and to provide specific guidance for the identification and documentation of indications of age-related degradation. For internal surfaces this includes indications of corrosion such as surface irregularities and signs of fouling which could lead to flow blockage. For external surfaces age-related degradation includes indications of corrosion beyond minor surface rusting and signs of current or past leakage.

5. Perform flow testing of at least one hose station in each building within the scope of SLR every five years to demonstrate the capability to provide the design pressure at required flow. Flow testing will be performed at the hydraulically most remote hose station consistent with Section 6.3.1 of NFPA 25, 2011 Edition. If acceptance criteria are not met, at least two additional tests will be

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 4 7

Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule performed within five years. the same 5-year inspection interval in which the original test was conducted. The number of increased tests will be determined in accordance with the Corrective Action Program with no fewer than two additional tests for each test that did not meet acceptance criteria. If subsequent tests do not meet acceptance criteria, the issue will be entered into the Corrective Action Program and an extent of condition and extent of cause analysis will be conducted performed to determine the further extent of further tests.

6. Perform flushing of the mainline strainers after each system operation or flow test consistent with Section 10.2.7 of NFPA 25, 2011 Edition.

7. Perform main drain testing of the system risers at least once every two years. Main drain testing will be performed consistent with the procedure described in Sections 13.2.5 and A.13.2.5 of NFPA 25, 2011 Edition. When there is a ten percent reduction in full flow pressure when compared to an established baseline value, the cause of the reduction will be identified and evaluated. If acceptance criteria are not met, at least two additional tests will be performed within the same 2-year inspection interval in which the original test was conducted. The number of increased tests will be determined in accordance with the Corrective Action Program with no fewer than two years. additional tests for each test that did not meet acceptance criteria. If subsequent tests do not meet acceptance criteria, the issue will be entered into the Corrective Action Program

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 4 8

Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule and an extent of condition and extent of cause analysis will be conducted performed to determine the further extent of further tests.

8. Perform internal visual inspections of piping and branch lines every five years by opening a flushing connection at the end of one main and by removing a sprinkler head toward the end of one branch line for the purpose of inspecting for the presence of foreign material, consistent with Section 14.2 of NFPA 25, 2011 Edition. The sprinkler head removed for inspection in pre-action systems is to be from the most remote branch line from the source of water that is not equipped with an inspectors test valve.

9. Perform internal visual inspection of each in-scope wet pipe system in each building within scope of SLR every five years consistent with Section 14.2.2 of NFPA 25, 2011 Edition. In buildings with multiple wet pipe system, an internal inspection of 50 percent of the piping systems will be performed every five years. During the subsequent five-year inspection period, the alternate systems will be inspected such that piping in 100 percent of the wet pipe systems within the scope of the program is inspected every ten years.

10. The Diesel Driven Fire Pump Engine jacket water cooler and charge air cooler will be replaced and inspected prior to the SPEO to assess their condition and set a replacement frequency during the SPEO, not to exceed 20 years.

11. The Diesel Driven and Motor Driven Fire Pump relief valves will be replaced and assessed prior to entering the SPEO to establish an appropriate future replacement interval. The replacement frequency I

I I

I

~

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 4 9

Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule for the Motor Driven Fire Pump relief valve in the SPEO will not exceed 6 years, while the Diesel Driven Fire Pump relief valve's replacement frequency will not exceed 15 years.

Changed

- 16 Fire Water System (B2.1.16)

The Fire Water System aging management program is an existing program that will be enhanced to:

1. Sprinkler heads will either be replaced, or a representative sample will be submitted for field-service testing by a recognized testing laboratory consistent with NFPA 25, 2011 Edition, Section 5.3.1.

Prior to the SPEO, a plant-specific evaluation will be performed to demonstrate that the Fire Protection water supply is not corrosive to the wet pipe sprinklers. This evaluation will be supported by a one-time inspection of at least 3 percent or maximum of 10 sprinklers with no more than four sprinklers per structure in the scope of subsequent license renewal being tested. If the plant specific evaluation concludes that fire water constitutes a harsh environment, Robinson will either perform a one-time test of sprinklers prior to the SPEO or ongoing testing of sprinklers, consistent with the guidance of NUREG-2191, Table XI.M27-1, Footnote 7.

2. Perform a one-time volumetric wall thickness inspection on a representative sample of deluge and preaction system supply piping that is periodically subject to flow during functional testing. The representative sample will be based on the population of deluge and preaction system piping that is periodically subject to flow but is Program will be enhanced no later than six months prior to the SPEO, and pre-SPEO inspections and tests will begin within the five-year period before the SPEO.

Inspections or tests that are to be completed prior to the SPEO will be completed no later than six months prior to the SPEO, or no later than the last refueling outage prior to the SPEO.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 4 10 Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule normally dry. The one-time volumetric wall thickness inspection activity will include criteria for selection of inspection locations and acceptance criteria. The activity will specify the need for follow-up examinations based on inspection results.

3. Perform an obstruction investigation consistent with NFPA 25, 2011 Edition, Section 14.3 if evidence of unacceptable internal flow blockage that could result in the failure of a system function is identified during internal inspections. When unacceptable internal flow blockage is detected, corrective actions will include removal of the material, an extent of condition determination, review for increased inspections, follow-up examinations, and a flush consistent with NFPA 25 Annex D.5, Flushing Procedures.

4. Revise inspection procedures to include inspection parameters for items such as lighting, distance, offset, presence of protective coatings, and cleaning processes and to provide specific guidance for the identification and documentation of indications of age-related degradation. For internal surfaces this includes indications of corrosion such as surface irregularities and signs of fouling which could lead to flow blockage. For external surfaces age-related degradation includes indications of corrosion beyond minor surface rusting and signs of current or past leakage.

5. Perform flow testing of at least one hose station in each building within the scope of SLR every five years to demonstrate the capability to provide the design pressure at required flow. Flow testing will be performed at the hydraulically most remote hose

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 4 11 Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule station consistent with Section 6.3.1 of NFPA 25, 2011 Edition. If acceptance criteria are not met, additional tests will be performed within the same 5-year inspection interval in which the original test was conducted. The number of increased tests will be determined in accordance with the Corrective Action Program with no fewer than two additional tests for each test that did not meet acceptance criteria. If subsequent tests do not meet acceptance criteria, the issue will be entered into the Corrective Action Program and an extent of condition and extent of cause analysis will be performed to determine the extent of further tests.

6. Perform flushing of the mainline strainers after each system operation or flow test consistent with Section 10.2.7 of NFPA 25, 2011 Edition.

7. Perform main drain testing of the system risers at least once every two years. Main drain testing will be performed consistent with the procedure described in Sections 13.2.5 and A.13.2.5 of NFPA 25, 2011 Edition. When there is a ten percent reduction in full flow pressure when compared to an established baseline value, the cause of the reduction will be identified and evaluated. If acceptance criteria are not met, additional tests will be performed within the same 2-year inspection interval in which the original test was conducted. The number of increased tests will be determined in accordance with the Corrective Action Program with no fewer than two additional tests for each test that did not meet acceptance criteria. If subsequent tests do not meet acceptance criteria, the issue will be entered into the Corrective Action Program and an

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 4 12 Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule extent of condition and extent of cause analysis will be performed to determine the extent of further tests.

8. Perform internal visual inspections of piping and branch lines every five years by opening a flushing connection at the end of one main and by removing a sprinkler head toward the end of one branch line for the purpose of inspecting for the presence of foreign material, consistent with Section 14.2 of NFPA 25, 2011 Edition. The sprinkler head removed for inspection in pre-action systems is to be from the most remote branch line from the source of water that is not equipped with an inspectors test valve.

9. Perform internal visual inspection of each in-scope wet pipe system in each building within scope of SLR every five years consistent with Section 14.2.2 of NFPA 25, 2011 Edition. In buildings with multiple wet pipe system, an internal inspection of 50 percent of the piping systems will be performed every five years. During the subsequent five-year inspection period, the alternate systems will be inspected such that piping in 100 percent of the wet pipe systems within the scope of the program is inspected every ten years.

10. The Diesel Driven Fire Pump Engine jacket water cooler and charge air cooler will be replaced and inspected prior to the SPEO to assess their condition and set a replacement frequency during the SPEO, not to exceed 20 years.

11. The Diesel Driven and Motor Driven Fire Pump relief valves will be replaced and assessed prior to entering the SPEO to establish an appropriate future replacement interval. The replacement frequency

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 4 13 Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule for the Motor Driven Fire Pump relief valve in the SPEO will not exceed 6 years, while the Diesel Driven Fire Pump relief valve's replacement frequency will not exceed 15 years.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 4 14 SLRA Section B2.1.16 is revised as follows:

Section B2.1.16 Program Description The system flow testing, visual inspections and volumetric inspections ensure that aging effects are managed such that the system intended functions are maintained. Flow testing results are reviewed and trended to identify degrading trends prior to loss of system function. Unexpected results from flushing such as increased time to flush a line or the amount of sediment, corrosion products, or debris are entered into the corrective action program for evaluation and trending.

Inspections and tests are performed by personnel qualified in accordance with station procedures and programs to perform the specified task. The program ensures that testing and inspection activities have been performed and documented. Abnormal results Results that do not meet the acceptance criteria are entered into the corrective action program Corrective Action Program for review and resolution.

The Fire Water System aging management program will either replace sprinkler heads prior to 50 years in service or submit a representative sample of sprinkler heads for testing consistent with the 2011 Edition of NFPA 25, Standard for the Inspection, Testing and Maintenance of Water-Based Fire Protection Systems, Section 5.3.1. The timing for replacement or testing will be determined based on the date of the sprinkler system installation. Standard response sprinkler heads will be replaced or tested prior to 50 years in service. Fast response sprinkler heads will be replaced or tested prior to 20 years in service. A one-time inspection and plant-specific evaluation will be performed to confirm that wetted sprinklers are not subject to a harsh environment.

Enhancements Prior to the subsequent period of extended operation, the following enhancements shall be implemented in the respective program elements: Scope of Program (Element 1), Parameters Monitored or Inspected (Element 3), Detection of Aging Effects (Element 4), Monitoring and Trending (Element 5), Acceptance Criteria (Element 6), and Corrective Actions (Element 7):

1. Prior to 50 years in service, sprinkler Sprinkler heads will either be replaced, or a representative sample will be submitted for field-service testing by a recognized testing laboratory consistent with NFPA 25, 2011 Edition, Section 5.3.1. Prior to the SPEO, a plant-specific evaluation will be performed to demonstrate that the Fire Protection water supply is not corrosive to the wet pipe sprinklers. This evaluation will be supported by a one-time inspection of at least 3 percent or maximum of 10 sprinklers with no more than four sprinklers per structure in the scope of subsequent license renewal being tested. If the plant specific evaluation concludes that fire water constitutes a harsh environment, Robinson will either perform a one-time test of sprinklers prior to the SPEO or ongoing testing of sprinklers, consistent with the guidance of NUREG-2191, Table XI.M27-1, Footnote 7. (Elements 3, 4, and 5)

5. Perform flow testing of at least one hose station in each building within the scope of SLR every five years to demonstrate the capability to provide the design pressure at required flow. Flow testing will be performed at the hydraulically most remote hose station consistent with Section 6.3.1 of NFPA 25, 2011 Edition. If acceptance criteria are not met, at least two additional tests will be performed within five years. the same 5-year inspection interval in which the original test was conducted. The number of increased tests will be determined in accordance with the Corrective Action Program with no fewer than two additional tests for each test that did not meet acceptance criteria. If

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 4 15 subsequent tests do not meet acceptance criteria, the issue will be entered into the Corrective Action Program and an extent of condition and extent of cause analysis will be conducted performed to determine the further extent of further tests. (Elements 4 and

7)

7. Perform main drain testing of the system risers at least once every two years. Main drain testing will be performed consistent with the procedure described in Sections 13.2.5 and A.13.2.5 of NFPA 25, 2011 Edition. When there is a ten percent reduction in full flow pressure when compared to an established baseline value, the cause of the reduction will be identified and evaluated. If acceptance criteria are not met, at least two additional tests will be performed within the same 2-year inspection interval in which the original test was conducted. The number of increased tests will be determined in accordance with the Corrective Action Program with no fewer than two years. additional tests for each test that did not meet acceptance criteria. If subsequent tests do not meet acceptance criteria, the issue will be entered into the Corrective Action Program and an extent of condition and extent of cause analysis will be conducted performed to determine the further extent of further tests. (Elements 4 and 7)

8. Perform internal visual inspections of piping and branch lines every five years by opening a flushing connection at the end of one main and by removing a sprinkler head toward the end of one branch line for the purpose of inspecting for the presence of foreign material, consistent with Section 14.2 of NFPA 25, 2011 Edition. The sprinkler head removed for inspection in pre-action systems is to be from the most remote branch line from the source of water that is not equipped with an inspectors test valve. (Element

4)

10. The Diesel Driven Fire Pump Engine jacket water cooler and charge air cooler will be replaced and inspected prior to the SPEO to assess their condition and set a replacement frequency during the SPEO, not to exceed 20 years. (Element 1)

11. The Diesel Driven and Motor Driven Fire Pump relief valves will be replaced and assessed prior to entering the SPEO to establish an appropriate future replacement interval. The replacement frequency for the Motor Driven Fire Pump relief valve in the SPEO will not exceed 6 years, while the Diesel Driven Fire Pump relief valve's replacement frequency will not exceed 15 years. (Element 1)

ENCLOSURE 1 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT 2 SUBSEQUENT LICENSE RENEWAL APPLICATION H.B. ROBINSON SLRA SUPPLEMENT 2 ATTACHMENT 5 Onsite Audit Electrical Questions 6 & 10

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 5 1, Attachment 5 Onsite Audit Electrical Questions 6 & 10 - Revise SBO Recovery Path Figures (Onsite Audit Electrical Questions 6 & 10)

Affected SLRA Section(s):

2.1.3.4 SLRA Page Numbers:

2-13 2-14 2-15 Description of Change:

RNP SLRA Onsite Audit Electrical Question 6: Revises Figure 2.1.3-3 (SBO Offsite Recovery Paths 5 and 6) to include highlighting of the Iso-Phase Bus to the Generator Disconnect Link as part of the SBO recovery path.

RNP SLRA Onsite Audit Electrical Question 10: Revises Figure 2.1.3-1 (SBO Offsite Recovery Paths 1 and 2), Figure 2.1.3-2 (SBO Offsite Recovery Paths 3 and 4), and Figure 2.1.3-3 (SBO Offsite Recovery Paths 5 and 6) to include highlighting the Alternate AC Power Source (Dedicated Shutdown Diesel).

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 5 2

SLRA Revisions:

SLRA Section 2.1.3.4 is revised as follows:

Section 2.1.3.4 Figure 2.1.3-1: SBO Offsite Recovery Paths 1 and 2, Alternate AC Source, and Safety-Related Onsite Power System Removed Figure

• • • • • <a...

SBO RECOVERY PATHS 1 & 2 AND ALTERNATE AC SOURCE Mall!J.Yl<N

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H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 5 3

New Figure

'lliil"A' SBO RECOVERY PATHS 1 & 2 AND ALTERNATE AC SOURCE

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H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 5 4

Figure 2.1.3-2: SBO Offsite Recovery Paths 3 and 4, Alternate AC Source, and Safety-Related Onsite Power System Removed Figure Ol5COOIOIECT....

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H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 5 5

New Figure S80 RECOVERY PATHS 3 & 4 AND ALTERNATE AC SOURCE

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H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 5 6

Figure 2.1.3-3: SBO Offsite Recovery Paths 5 and 6, Alternate AC Source, and Safety-Related Onsite Power System Removed Figure SBO RECOVERY PATHS 5 & 6 AND ALTERNATE AC SOURCE

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H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 5 7

New Figure SBO RECOVERY PATHS 5 & 6 AND ALTERNATE AC SOURCE B"A'

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ENCLOSURE 1 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT 2 SUBSEQUENT LICENSE RENEWAL APPLICATION H.B. ROBINSON SLRA SUPPLEMENT 2 ATTACHMENT 6 Onsite Audit Electrical Question 17

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 6 1, Attachment 6 Onsite Audit Electrical Question 17 for XI.E6 in Appendix B2.1.44 (Onsite Audit Electrical Question 17)

Affected SLRA Section(s):

B2.1.44 SLRA Page Numbers:

B-252 Description of Change:

Revise SLRA Appendix B 2.1.44 (Electrical Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements) to include extent of condition acknowledgment from NUREG-2191 Rev. 0 (GALL-SLR) page XI.E6-2 Program Description, 2nd to last paragraph.

SLRA Revisions:

SLRA Section B2.1.44 is revised as follows:

Section B2.1.44 Program Description This program will perform a one-time test, on a representative sampling basis, to confirm the absence of loosening of connections due to thermal cycling, ohmic heating, electrical transients, vibration, chemical contamination, corrosion and oxidation. Sample selection will be based on voltage level (medium and low-voltage), circuit loading (high current load), connection type, and location (high temperature, high humidity, vibration, etc.). The technical basis for the sample selections should be documented.

If an unacceptable condition or situation is identified in the selected sample, a determination is made about whether the same condition or situation is applicable to other connections not tested. The corrective action program is used to evaluate the condition and determine appropriate corrective action.

ENCLOSURE 1 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT 2 SUBSEQUENT LICENSE RENEWAL APPLICATION H.B. ROBINSON SLRA SUPPLEMENT 2 ATTACHMENT 7 SLRA On Site Structural Walkdown

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 7 1, Attachment 7 Updates to the SLRA based on NRC SLRA On Site Structural Walkdown Audit (SLRA On Site Structural Walkdown)

Affected SLRA Section(s)/Table(s):

A2.1.35 B2.1.35 3.5.2.2.1.9 3.5.2.2.2.1 3.5.2.2.2.3 3.5.2-2 3.5.2-28 SLRA Page Numbers:

A-26 B-213 3-906 3-908 3-910 3-973 3-974 3-975 3-1056 Description of Change:

The program description for the Inspection of Water Control Structures Associated with Nuclear Power Plants AMP in both Section A2.1.35 and B2.1.35 is updated to provide clarification for the dam inspection. The inspection of the Lake Robinson and Dam is performed in accordance with Department of Army, Office of the Chief Engineers, Recommended Guidelines for Safety Inspection of Dams, Washington, DC, 1976. The inspection criteria specified in this document satisfies the intent of RG 1.127.

The Further Evaluations associated with Increase in porosity and permeability due to leaching of calcium hydroxide and carbonation are updated to clarify that Robinson does have operating experience related to Increase in porosity and permeability due to leaching of calcium hydroxide and carbonation; the evaluation determined there was no adverse impact to the concrete.

SLRA Table 3.5.2-2 and 3.5.2-28 are updated to remove AMR lines for the Groundwater/Soil and Water - Flowing environments for accessible concrete as they are only applicable to inaccessible concrete.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 7 2

SLRA Revisions:

SLRA Section A2.1.35 is revised as follows:

Section A2.1.35 The Inspection of Water-Control Structures Associated with Nuclear Power Plants aging management program is an existing condition monitoring program that consists of inspection and surveillance of the raw water control structures associated with emergency cooling systems or flood protection. The scope of the program also includes structural steel, and structural bolting associated with water control structures. In general, parameters monitored are in accordance with Section C.2 of RG 1.127 and quantitative measurements are recorded for findings that exceed the acceptance criteria for applicable parameters monitored or inspected.

Inspections are performed at least once every five years for structural components. Structures exposed to aggressive water require additional plant-specific investigation. The inspection of the Lake Robinson and Dam is performed in accordance with Department of Army, Office of the Chief Engineers, Recommended Guidelines for Safety Inspection of Dams, Washington, DC, 1976. 1976, which satisfies the intent of RG 1.127. Robinson will continue to comply with the governing document, Recommended Guidelines for Safety Inspection of Dams, during the subsequent period of extended operation.

SLRA Section B2.1.35 is revised as follows:

Section B2.1.35 Program Description RG 1.127 describes a basis acceptable to the NRC staff for developing an appropriate surveillance program for dams, slopes, canals, and other water-control structures associated with emergency cooling water systems or flood protection of nuclear power plants. The Intake Structure is committed to RG 1.127. Instead of committing to RG 1.127 for the Lake Robinson and Dam, at Robinson, the Lake Robinson and Dam are inspected using Department of Army, Office of the Chief Engineers, Recommended Guidelines for Safety Inspection of Dams, Washington, DC, 1976. 1976, which satisfies the intent of RG 1.127. Robinson will continue to comply with the governing document, Recommended Guidelines for Safety Inspection of Dams, during the subsequent period of extended operation.

SLRA Section 3.5.2.2.1.9 is revised as follows:

Section 3.5.2.2.1.9

[3.5.1-014] - Reinforced concrete structures at Robinson were designed, constructed, and inspected in accordance with ACI and ASTM standards, which provide for a good quality, dense, well-cured, and low permeability concrete. Procedural controls ensured quality throughout the batching, mixing, and placement processes. The ASME Section XI, Subsection IWL (B2.1.30) program and the Structures Monitoring (B2.1.34) program identify and manage cracks in the containment concrete. Review of plant operating experience has not identified aging effects related to increase in porosity and permeability due to leaching of calcium hydroxide and carbonation. carbonation; however, evaluations determined there was no impact to the concrete performing its intended function. The Structures Monitoring (B2.1.34) program and the ASME Section XI, Subsection IWL (B2.1.30) program confirm the absence of aging effects related to leaching of calcium hydroxide and carbonation. Therefore, a plant-specific aging management program or plant specific enhancements to the Structures Monitoring (B2.1.34) program and the ASME Section XI, Subsection IWL (B2.1.30) program for

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 7 3

inaccessible areas to manage the aging effects of increase in porosity and permeability due to leaching of calcium hydroxide and carbonation are not required.

SLRA Section 3.5.2.2.2.1 is revised as follows:

Section 3.5.2.2.2.1 (4) [3.5.1-047] - Reinforced concrete structures at Robinson were designed, constructed, and inspected in accordance with ACI and ASTM standards, which provide for a good quality, dense, well-cured, and low permeability concrete. Procedural controls ensured quality throughout the batching, mixing, and placement processes. Review of plant operating experience has not identified aging effects related to increase in porosity and permeability due to leaching of calcium hydroxide and carbonation in accessible areas. areas; however, evaluations determined there was no impact to the concrete performing its intended function.

The Structures Monitoring (B2.1.34) program manages the aging effects related to leaching of calcium hydroxide and carbonation. The Structures Monitoring (B2.1.34) program also includes consideration of the acceptability of inaccessible areas when conditions exist in accessible areas that could indicate the presence of, or result in, degradation to such inaccessible areas (e.g. exposed to groundwater/soil environment, structural components covered by metal siding).

Therefore, a plant-specific AMP or plant specific enhancements to the Structures Monitoring (B2.1.34) program for inaccessible areas to manage the aging effects of increase in porosity and permeability due to leaching of calcium hydroxide and carbonation are not required in below-grade inaccessible concrete areas of Robinson groups 1-5 and 7-9 structures.

SLRA Section 3.5.2.2.2.3 is revised as follows:

Section 3.5.2.2.2.3 (3) [3.5.1-051] - Reinforced concrete structures at Robinson were designed, constructed, and inspected in accordance with ACI and ASTM standards, which provide for a good quality, dense, well-cured, and low permeability concrete. Procedural controls ensured quality throughout the batching, mixing, and placement processes. The Structures Monitoring (B2.1.34) program, which includes Group 6 structures, identifies and manages cracks in the concrete structures and manages the aging effects related to leaching of calcium hydroxide and carbonation. The Structures Monitoring (B2.1.34) program also includes consideration of the acceptability of inaccessible areas when conditions exist in accessible areas that could indicate the presence of, or result in, degradation to such inaccessible areas (e.g. exposed to groundwater/soil environment, structural components covered by metal siding). Review of plant operating experience has not identified aging effects related to increase in porosity and permeability due to leaching of calcium hydroxide and carbonation in accessible areas. areas; however, evaluations determined there was no impact to the concrete performing its intended function. Therefore, a plant-specific aging management program or plant specific enhancements to Structures Monitoring (B2.1.34) program for inaccessible areas to manage the aging effects of increase in porosity and permeability due to leaching of calcium hydroxide and carbonation are not required in Group 6 structures.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 7 4

SLRA Table 3.5.2-2 is revised as follows:

Table 3.5.2-2 Containments, Structures, and Component Supports - Reactor Auxiliary Building - Aging Management Evaluation AMR ID Component Type Intended Function Material Environment Aging Effect Aging Management Program NUREG-2191 Item NUREG-2192 Table 1 Notes Difference

- 1772 Concrete Elements Fire Barrier; Flood Barrier; Missile Barrier;

Shelter, Protection; Structural Support Concrete Groundwater/Soil (External)

Cracking, Loss of Bond, Loss of Material (Spalling, Scaling)

Structures Monitoring (B2.1.34)

III.A3.TP-27 3.5.1-065 A,1,4 Deleted -

1772 Difference

- 1790 Concrete Elements Fire Barrier; Flood Barrier; Missile Barrier;

Shelter, Protection; Structural Support Concrete Groundwater/Soil (External)

Cracking Structures Monitoring (B2.1.34)

III.A3.TP-25 3.5.1-054 A,1,4 Deleted -

1790 Difference

- 1791 Concrete Elements Fire Barrier; Flood Barrier; Missile Barrier;

Shelter, Protection; Structural Support Concrete Water - Flowing (External)

Cracking Structures Monitoring (B2.1.34)

III.A3.TP-25 3.5.1-054 A,1,4 Deleted -

1791 I

I I

I I

I I

I I

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 7 5

SLRA Table 3.5.2-28 is revised as follows:

Table 3.5.2-28 Containments, Structures, and Component Supports - Turbine Building - Aging Management Evaluation AMR ID Component Type Intended Function Material Environment Aging Effect Aging Management Program NUREG-2191 Item NUREG-2192 Table 1 Notes Difference

- 9170 Concrete Elements Structural Support; Missile Barrier Concrete Groundwater/Soil (External)

Cracking, Loss of Bond, Loss of Material (Spalling, Scaling)

Structures Monitoring (B2.1.34)

III.A3.TP-27 3.5.1-065 A, 1 Deleted -

9170 I

I

ENCLOSURE 1 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT 2 SUBSEQUENT LICENSE RENEWAL APPLICATION H.B. ROBINSON SLRA SUPPLEMENT 2 ATTACHMENT 8 TRP 14

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 8 1, Attachment 8 SLRA revisions related to TRP 14 (Buried and Underground Piping and Tanks Program)

(TRP 14)

Affected SLRA Section(s)/Table(s):

A2.1.27 B2.1.27 A6.0-1 B2-1 SLRA Page Numbers:

A-23 A-73 A-74 A-76 B-161 B-162 B-163 B-165 B-166 B-170 Description of Change:

1. In Section A2.1.27, add description of actions taken if acceptance criteria are not met.

2. In Section B2.1.27,

a. Add new Exception 1 related to performance of planned inspections of buried service water piping prior to the SPEO.

b. Revise Enhancement 1 to include the purpose of the dedicated shutdown diesel piping modification. Also add piping inspection details required if the modification is not completed prior to the SPEO.

c. Revise Enhancement 2 to reflect the current plans for the buried service water piping modification. Delete requirement to inspect the buried service water piping if the modification is not completed prior to the SPEO.

d. Revise Enhancement 5 to include the backfill size for polymeric materials.

e. Revise Enhancement 13 to include the sample size for the inspection of concrete encapsulated components in the north service water header.

f. Revise Operating Experience item 2.a to point out that the subject piping supported Robinson Unit 1, a retired fossil plant.

g. Revise Operating Experience item 2.d to point out that the subject piping is not in SLR scope.

h. Revise Operating Experience item 2.f to point out that the subject stainless steel piping was uncoated and to provide details on additional similar OE.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 8 2

i. Revise Operating Experience item 2.h to point out that piping likely damaged by demolition of a nearby building is not an aging effect.

j. Add new Operating Experience item 9 to document historical soil resistivity test results.

3. In Table A6.0-1, revise Buried and Underground Piping and Tanks Commitments 1, 2, 5 and 13 to align with the enhancement changes described in 2. above.

SLRA Revisions:

SLRA Section A2.1.27 is revised as follows:

Section A2.1.27 The Buried and Underground Piping and Tanks aging management program is an existing condition monitoring program that manages the aging effects associated with the external surfaces of buried and underground piping and piping components, including loss of material and cracking of components in soil or underground environments, including concrete encapsulated components, within the scope of subsequent license renewal. The program addresses piping of any material, including carbon steel, ductile iron, gray cast iron, polyvinyl chloride, stainless steel and super austenitic. There are no buried or underground tanks within the scope of subsequent license renewal at Robinson. Condition monitoring of the buried and underground piping relies on inspections conducted by qualified individuals. Where the coatings, backfill or the condition of exposed piping do not meet acceptance criteria such that the depth or extent of degradation of the base metal could have resulted in a loss of pressure boundary function when the loss of material rate is extrapolated to the end of the subsequent period of extended operation, an increase in the sample size is conducted.

SLRA Section B2.1.27 is revised as follows:

Section B2.1.27 NUREG-2191 Consistency The Buried and Underground Piping and Tanks aging management program is an existing program that, following enhancement, will be consistent with NUREG-2191,Section XI.M41, Buried and Underground Piping and Tanks. Tanks with the following exception:

Exception to NUREG-2191 None. Exception 1 to NUREG-2191 The following program elements are affected: Preventative Actions (Element 2),

Parameters Monitored or Inspected (Element 3) and Detection of Aging Effects (Element

4)

1. Planned inspections of buried Service Water piping will not be performed prior to the subsequent period of extended operation.

Justification for Exception 1 Per Enhancement #2, most of the buried Steel Service Water piping will be replaced with new piping that is no longer exposed to a soil environment. A small portion of piping that must remain exposed to soil will be replaced with super austenitic material. The modification to replace the buried steel Service Water piping is scheduled to be completed during the Fall 2030 refueling outage (several months after the subsequent period of extended operation). Because all of the buried steel Service Water piping is scheduled to be replaced within a few months of

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 8 3

entering the subsequent period of extended operation, performing extensive excavations to allow inspection of 10% of the piping length (per NUREG 2191 Table XI.M41-2 Preventative Action Category F) provides limited value. This elimination of the requirement to inspect the piping prior to the subsequent period of extended operation is mitigated by a requirement in Enhancement #2 to inspect 10% of the piping length (or perform 6 inspections) if the modification to replace the buried steel service water piping is not completed by the end of the second refueling outage after the subsequent period of extended operation. In addition, inspections have shown no evidence of external aging of the pipe coating or the base metal.

Also, the soil environment at Robinson is not corrosive, as shown in Operating Experience Item

1. 9. Degradation of the coating integrity would not result in a loss of material or a loss of intended function prior to the second refueling outage after the subsequent period of extended operation.

Enhancements

1. Complete a modification to replace the buried steel Dedicated Shutdown Diesel Generator piping within the scope of this program with aboveground piping. The purpose of the modification is to eliminate the need for a cathodic protection upgrade and ongoing buried piping inspections. There is no current equipment reliability concern with this piping. If the Dedicated Shutdown Diesel Generator piping modification is not completed prior to entering the subsequent period of extended operation, inspection of the buried Dedicated Shutdown Diesel Generator piping will be performed in the 10-year period prior to entering the subsequent period of extended operation. Inspections will be performed on the external surfaces of the buried piping via visual examination. Visual inspections are supplemented with surface and/or volumetric nondestructive testing if evidence of wall loss beyond minor surface scale is observed. The extent of the visual inspections will be 10% of the piping length (minimum 10 feet) or 6 inspections of 10 feet each. Inspections shall be capable of detecting both general and pitting corrosion on the external surface of the piping. Loss of material that does not meet acceptance criteria shall be identified. Perform opportunistic visual inspections in the 10-year period prior to entering the subsequent period of extended operation whenever the pipe is excavated for other reasons. (Elements 2 and 3)

2. Complete a modification to remediate the existing buried concrete lined steel Service Water intake piping within the scope of this program. The purpose of the modification will modify is to address degradation of the existing concrete lining in a manner that and to eliminate the need for extensive ongoing buried steel piping inspections. Inspections have shown no longer performs a pressure boundary function, evidence of external aging of the pipe coating or the base metal. Most of the buried concrete lined steel Service Water pipes within the scope of the program will be replaced with new piping that is no longer exposed to a soil environment. A small portion of piping that must remain exposed to soil will be replaced with super austenitic material. If the Service Water modification is not completed prior to entering by the end of the second refueling outage after the subsequent period of extended operation, inspection external inspections of the buried Service Water steel piping will be performed in on 10% of the 10-year period piping length or 6 inspections of 10 feet each. The additional inspections will be completed prior to entering the end of the second refueling outage after the subsequent period of extended operation. Inspections will be performed on either the external or internal surfaces of the buried piping. If external piping or coating surfaces are inspected, the inspection will be conducted by via visual examination. Visual inspections are supplemented with surface and/or volumetric nondestructive testing if

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 8 4

evidence of wall loss beyond minor surface scale is observed. The extent of the visual inspections will Inspections shall be either 1% of the piping length (16 feet) or 2 inspections of 10 feet each. If internal piping surfaces are inspected, the internal inspection method will utilize a volumetric nondestructive examination technique capable of measuring wall thickness and detecting depth of pits. At a minimum, 25% of the total length of buried piping in the system will be inspected internally. The inspection technique used shall be capable detecting both general and pitting corrosion on the external surface of the piping and qualified to identify loss piping. Loss of material that does not meet acceptance criteria. criteria shall be identified. In general, external inspections of the buried steel piping will be performed as described above in each of the 10 year periods in the subsequent period of extended operation. Perform opportunistic visual inspections in the 10-year period prior to entering the subsequent period of extended operation whenever the pipe is excavated for reasons other reasons.

than the piping replacement modification. (Elements 2, 3, and 4)

5. Specify that backfill placed within 6 inches of buried non-Seismic Class I piping within the scope of the program will meet or exceed the objectives of ASTM D448-08 size 67.

67 (size number 10 for polymeric materials). (Element 2)

13. Perform visual inspections of the concrete encapsulated components in the North service water header (30-CW-11) at pit #3 at least once in the 10-year period prior to entering the subsequent period of extended operation. Inspect the concrete surrounding the pipe for cracks that could admit groundwater to the external surface of the pipe. The sample size for the inspection is the portion of the exterior of the buried piping where it interfaces with the exterior surface of the concrete of pit #3, exposed by excavation of the top surfaces and at least 50 percent of the side surface. (Element 4)

Operating Experience

a. In 2008, a Unit 1 Site Fire Protection System pipe feeding fire hydrant was visually inspected. The cast iron pipe was uncoated and buried in moist/damp sand clay soil at a depth of three feet below grade. A slight amount of rusting was found on the exterior of the pipe, consisting of several penny-sized areas. Overall, the pipe was in good condition with the metal intact. The trench was backfilled using the original excavated material which contained small amounts of gravel from the roadway above. Unit 1 was a fossil plant that began service in 1960 and was retired in 2012.

10 CFR 50 Appendix B did not apply to Unit 1. For Robinson Unit 2, buried cast iron fire protection headers were installed with a coal tar epoxy coating in accordance with NFPA 24.

d. In 2012, a 2-inch carbon steel pipe in the Potable Water System, System (not in subsequent license renewal scope), at the Weld Test Shop, was opportunistically inspected due to a through wall leak. No coating was present on the pipe. The suspected cause of the leak was due to damage from a rock located adjacent to the pipe. A layer of oxidation was present over the entire surface of the exposed pipe, but there were no indications of wall loss, aside from the location of the leak. The pipe was repaired. Gravel and rocks, possibly from the excavation effort, were noted in the as-found backfill material.

f. In 2013, a an uncoated Primary and Demineralized Water pipe, located at the South side of the roadway at the northeast corner of the Unit 2 fuel oil storage tank was opportunistically inspected. Inspection of the stainless steel pipe showed no evidence of leakage, degradation, or corrosion. The as-found backfill material

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 8 5

consisted of a sandy soil, with no debris found. A review of Robinson operating experience revealed four additional examples of excavation and visual inspection of uncoated stainless steel piping with no degradation found.

h. In 2014, a Primary and Demineralized Water pipe, located at the B Deepwell pump, was opportunistically inspected due to a known leak. The polyolefin coating and the carbon steel pipe was found to have been damaged in the area where the leak occurred. A 5/8-inch hole was found at the damage location which was caused by a rock or other hard material next to the pipe (likely due to demolition of a nearby building). building - which is not considered to be an aging effect for subsequent license renewal). Corrosion was only present at the point of contact. When the coatings were removed on both sides of the leak, the pipe was found to be in pristine condition. Ultrasonic test inspection showed wall thickness was greater than the minimum allowable. The coating was otherwise in excellent condition. The as-found backfill material was in good overall condition, consisting of sand and clay. A ductile iron pipe coupling was installed to repair the pipe.

9. Additional Robinson Soil Resistivity Measurement results: In August 1958, soil resistivity measurements were taken prior to the construction of the Robinson Unit 1 fossil unit. The survey showed very high soil resistivity. Soil resistivity measurements were taken at 33 locations at depths ranging from 2.5 to 25.0 feet. Average, maximum, and minimum values from that survey are summarized in the table below:

New Figure In December 1966, another survey was taken to confirm soil resistivity for Robinson Unit 2.

Measurements were taken at 27 locations at depths ranging from 2.5 to 25 feet with the following results:

g Average Soil Resistivity [ohm-cm), 1958 Survey Depth Average 1Maximum Minimum

[feet) 2.5 648 000 2 500 000 23,000 5.0 630,000 2,300,000 35.000 7.5 658,000 1,650,000 51,000 10.0 690 000 1800000 64,000 15.0 652,000 1,650,000 75.000 25.0 682,000 1800000 95,000

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 8 6

Average values from both the 1958 and 1966 surveys are well above the 25,000 ohm-cm value considered to be very high soil resistivity per EPRI guidelines. The lower values from the 1966 survey were attributed to incursion of water from the impoundment of Lake Robinson, which did not exist in 1958. During the 1966 survey, some test locations were saturated with water from the water pumped out of the test wells.

In September 2022, soil resistivity measurements were taken at two locations near the Unit 1 Fuel Oil tanks as part of a design survey to install a supplemental ground bed cathodic protection system for the Fuel Oil System. Results from the survey are summarized in the table below:

A review of plant-specific operating experience has not identified any instances of through-wall leakage of buried stainless steel piping at Robinson. This confirms the position established following the pre-construction soil survey that the use of uncoated stainless steel in buried piping systems is appropriate for the plant-specific environmental conditions Average Soil Resistivity [ohm-cm), 1966 Survey Depth Average Maximum Minimum

[feet) 2.5 414,000 2 390 000 35,000 5.0 450,000 2,199,000 59.000 7.5 409,000 1,72t000 83,000 10.0 377,000 2 103 000 61,000 15.0 347.000 1,577,000 26.000 25.0 277,000 1.864 000 8.000 September 2022 Soil Resistivity Results Vicinity of the Unit 1 Fuel Oil Tanks Depth Average Soil Resistivity lfeet]

[ohm-cm]

Location 1 (34.40410°, -80.157168°)

2.5 455 797 5.0 225 983 10 31 216 15 10,342 20 11 874 Location 2 (34.403850°, -80.156370°)

2.5 59 943 5

50 463 10 36 847 15 24130 20 18 768

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 8 7

to which this piping is exposed at Robinson. The only buried stainless steel piping in the scope of the aging management program are line 3/4-DW-6A and 2-DW-6 in the Primary and Demineralized Water Makeup System. Both of these lines are buried approximately 3 feet below grade.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 8 8

SLRA Table A6.0-1 is revised as follows:

Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule Difference

- 27 Buried and Underground Piping and Tanks (B2.1.27)

The Buried and Underground Piping and Tanks aging management program is an existing program that will be enhanced to:

1. Complete a modification to replace the buried steel Dedicated Shutdown Diesel Generator piping within the scope of this program with aboveground piping. The purpose of the modification is to eliminate the need for a cathodic protection upgrade and ongoing buried piping inspections. There is no current equipment reliability concern with this piping. If the Dedicated Shutdown Diesel Generator piping modification is not completed prior to entering the subsequent period of extended operation, inspection of the buried Dedicated Shutdown Diesel Generator piping will be performed in the 10-year period prior to entering the subsequent period of extended operation. Inspections will be performed on the external surfaces of the buried piping via visual examination. Visual inspections are supplemented with surface and/or volumetric nondestructive testing if evidence of wall loss beyond minor surface scale is observed. The extent of the visual inspections will be 10%

of the piping length (minimum 10 feet) or 6 inspections of 10 feet each. Inspections shall be capable of detecting both general and pitting corrosion on the external surface of the piping. Loss of material that does not meet acceptance criteria shall be identified.

Perform opportunistic visual inspections in the 10-year period prior to entering the subsequent period of extended operation whenever the pipe is excavated for other reasons.

Program enhancements for SLR will be implemented six months prior to the SPEO. SPEO unless otherwise noted.

Inspections required during the 10 year interval prior to the SPEO will be completed no later than six months prior to the SPEO.

Modification to remediate the buried steel Service Water piping will be implemented no later than 10 years after entering the SPEO, and associated inspections will be completed no later

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 8 9

Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule

2. Complete a modification to remediate the existing buried concrete lined steel Service Water intake piping within the scope of this program. The purpose of the modification will modify is to address degradation of the existing concrete lining in a manner that and to eliminate the need for extensive ongoing buried steel piping inspections. There has been no longer performs a pressure boundary function, evidence of external aging of the pipe coating or the base metal. Most of the buried concrete lined steel Service Water pipes within the scope of the program will be replaced with new piping that is no longer exposed to a soil environment. A small portion of piping that must remain exposed to soil will be replaced with super austenitic material. If the Service Water modification is not completed prior to entering by the end of the second refueling outage after the subsequent period of extended operation, inspection external inspections of the buried Service Water steel piping will be performed in on 10% of the 10-year period piping length or 6 inspections of 10 feet each. The additional inspections will be completed prior to entering the end of the second refueling outage after the subsequent period of extended operation.

Inspections will be performed on either the external or internal surfaces of the buried piping. If external piping or coating surfaces are inspected, the inspection will be conducted by via visual examination. Visual inspections are supplemented with surface and/or volumetric nondestructive testing if evidence of wall loss beyond minor surface scale is observed. The extent of the visual inspections will Inspections shall be either 1% of the piping length (16 feet) or 2 inspections of 10 feet each. If internal piping surfaces than 6 months prior to entering the SPEO.

I I I I

I I

I

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 8 10 Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule are inspected, the internal inspection method will utilize a volumetric nondestructive examination technique capable of measuring wall thickness and detecting depth of pits. At a minimum, 25% of the total length of buried piping in the system will be inspected internally. The inspection technique used shall be capable detecting both general and pitting corrosion on the external surface of the piping and qualified to identify loss piping. Loss of material that does not meet acceptance criteria. criteria shall be identified. In general, external inspections of the buried steel piping will be performed as described above in each of the 10 year periods in the subsequent period of extended operation. Perform opportunistic visual inspections in the 10-year period prior to entering the subsequent period of extended operation whenever the pipe is excavated for reasons other reasons. than the piping replacement modification.

3. Maintain a structure to soil potential less negative than -1,200 mV.

4. Annual cathodic protection system monitoring will be performed with a maximum grace period of two months. The system will be monitored at least once during each calendar year.

5. Specify that backfill placed within 6 inches of buried non-Seismic Class I piping within the scope of the program will meet or exceed the objectives of ASTM D448-08 size 67. 67 (size number 10 for polymeric materials).

6. Utilize an inspection method that has been demonstrated to be capable of detecting cracking when inspections of uncoated stainless steel piping are performed. Indications of cracking will be I

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 8 11 Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule evaluated in accordance with applicable codes and plant-specific design criteria.

7. Inspect controlled low-strength material backfill for cracking that could admit groundwater to the external surface of the embedded pipe. Inspect the lesser of ten linear feet or actual total length embedded in controlled low-strength material, including the top surfaces and at least 50 percent of the side surface.

8. Perform wall thickness measurement if visual inspections identify evidence of corrosion beyond minor surface rusting for both coated and uncoated metallic piping. The results of the wall thickness measurement will be used to calculate a corrosion rate and project wall thickness through the end of the subsequent period of extended operation. If the depth or extent of degradation of the base metal could have resulted in a loss of pressure boundary function when the loss of material is extrapolated to the end of the subsequent period of extended operation, then additional inspections will be performed as follows: When measured pipe wall thickness, projected to the end of the subsequent period of extended operation, does not meet the minimum pipe wall thickness requirements due to external corrosion, the number of inspections within the affected piping category will be doubled or increased by five, whichever is smaller. If adverse indications are found in the expanded sample, an analysis will be conducted to determine the extent of condition and extent of cause. The size of the follow up inspections will be determined based on the analysis. Timing of any additional inspections will be based on the severity of the identified

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 8 12 Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule degradation and the consequences of leakage or loss of function.

Any additional inspections will be performed within the same 10-year inspection interval in which the original degradation was identified, or within four years after the end of the 10-year interval if the degradation was identified in the latter half of the 10-year interval. Expansion of sample size may be limited by the extent of piping subject to the observed degradation mechanism or if the piping system or portion of the system is replaced or otherwise mitigated within the same 10-year inspection interval in which the original degradation was identified or within four years after the end of the 10-year interval, if the degradation was identified in the latter half of the 10-year interval.

9. Perform visual inspections of buried steel piping in the Fuel Oil System at least once every ten years. The inspection quantity of buried steel piping will be determined based on the effectiveness of preventive actions in accordance with NUREG-2191, Table XI.M41-

2. Ten linear feet of piping will be exposed for each inspection.

10. Perform visual inspections of at least one ten-linear foot section of buried stainless steel piping in the Primary and Demineralized Water Makeup System at least once every ten years. Piping inspection locations will be selected based on risk (i.e., susceptibility to degradation and consequences of failure).

11. Perform visual inspections of at least two ten-linear foot sections of underground coated steel piping in the Condensate or Service Water Systems at least once every ten years. Piping inspection

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 8 13 Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule locations will be selected based on risk (i.e., susceptibility to degradation and consequences of failure).

12. Perform visual inspections of at least one ten-linear foot section of underground uncoated stainless steel piping in the Auxiliary Feedwater, Chemical and Volume Control, Condensate, Primary and Demineralized Water Makeup, or Service Water System at least once every ten years. Piping inspection locations will be selected based on risk (i.e., susceptibility to degradation and consequences of failure).

13. Perform visual inspections of the concrete encapsulated components in the North service water header (30-CW-11) at pit #3 at least once in the 10-year period prior to entering the subsequent period of extended operation. Inspect the concrete surrounding the pipe for cracks that could admit groundwater to the external surface of the pipe. The sample size for the inspection is the portion of the exterior of the buried piping where it interfaces with the exterior surface of the concrete of pit #3, exposed by excavation of the top surfaces and at least 50 percent of the side surface.

14. Perform trending of flow testing of the Site Fire Protection System fire main headers to identify changes that could indicate leakage of buried piping.

15. Personnel performing inspections of buried coated piping will either:

1) possess an Association for Materials Protection and Performance coating inspector program level 2 or level 3 inspector qualification,

2) complete the EPRI Comprehensive Coatings Course and

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 8 14 Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule complete the EPRI Buried Pipe Condition Assessment and Repair Training Computed Based Training Course, or 3) be qualified as a coatings specialist in accordance with ASTM D7108.

16. Inspect polyvinyl chloride components in the scope of the program for absence of cracking and perform an evaluation when blisters, gouges, or wear is detected.

17. If significant coating damage is identified during visual inspections, then perform an evaluation to determine if the coating damage was caused by nonconforming backfill. If it is determined that the coating damage was caused by nonconforming backfill, then conduct an extent of condition evaluation to determine the extent of degraded backfill in the vicinity of the observed damage.

Changed

- 27 Buried and Underground Piping and Tanks (B2.1.27)

The Buried and Underground Piping and Tanks aging management program is an existing program that will be enhanced to:

1. Complete a modification to replace the buried steel Dedicated Shutdown Diesel Generator piping within the scope of this program with aboveground piping. The purpose of the modification is to eliminate the need for a cathodic protection upgrade and ongoing buried piping inspections. There is no current equipment reliability concern with this piping. If the Dedicated Shutdown Diesel Generator piping modification is not completed prior to entering the subsequent period of extended operation, inspection of the buried Dedicated Shutdown Diesel Generator piping will be performed in the 10-year period prior to entering the subsequent period of Program enhancements for SLR will be implemented six months prior to the SPEO unless otherwise noted.

Inspections required during the 10 year interval prior to the SPEO will be completed no later

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 8 15 Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule extended operation. Inspections will be performed on the external surfaces of the buried piping via visual examination. Visual inspections are supplemented with surface and/or volumetric nondestructive testing if evidence of wall loss beyond minor surface scale is observed. The extent of the visual inspections will be 10%

of the piping length (minimum 10 feet) or 6 inspections of 10 feet each. Inspections shall be capable of detecting both general and pitting corrosion on the external surface of the piping. Loss of material that does not meet acceptance criteria shall be identified.

Perform opportunistic visual inspections in the 10-year period prior to entering the subsequent period of extended operation whenever the pipe is excavated for other reasons.

2. Complete a modification to remediate the existing buried concrete lined steel Service Water intake piping within the scope of this program. The purpose of the modification is to address degradation of the existing concrete lining and to eliminate the need for extensive ongoing buried piping inspections. There has been no evidence of external aging of the pipe coating or the base metal.

Most of the buried concrete lined steel Service Water pipes within the scope of the program will be replaced with new piping that is no longer exposed to a soil environment. A small portion of piping that must remain exposed to soil will be replaced with super austenitic material. If the Service Water modification is not completed by the end of the second refueling outage after the subsequent period of extended operation, external inspections of the buried steel piping will be performed on 10% of the piping length or 6 inspections of 10 than six months prior to the SPEO.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 8 16 Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule feet each. The additional inspections will be completed prior to the end of the second refueling outage after the subsequent period of extended operation. Inspections will be performed on the external surfaces of the buried piping via visual examination. Visual inspections are supplemented with surface and/or volumetric nondestructive testing if evidence of wall loss beyond minor surface scale is observed. Inspections shall be capable of detecting both general and pitting corrosion on the external surface of the piping.

Loss of material that does not meet acceptance criteria shall be identified. In general, external inspections of the buried steel piping will be performed as described above in each of the 10 year periods in the subsequent period of extended operation. Perform opportunistic visual inspections in the 10-year period prior to entering the subsequent period of extended operation whenever the pipe is excavated for reasons other than the piping replacement modification.

3. Maintain a structure to soil potential less negative than -1,200 mV.

4. Annual cathodic protection system monitoring will be performed with a maximum grace period of two months. The system will be monitored at least once during each calendar year.

5. Specify that backfill placed within 6 inches of buried non-Seismic Class I piping within the scope of the program will meet or exceed the objectives of ASTM D448-08 size 67 (size number 10 for polymeric materials).

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 8 17 Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule

6. Utilize an inspection method that has been demonstrated to be capable of detecting cracking when inspections of uncoated stainless steel piping are performed. Indications of cracking will be evaluated in accordance with applicable codes and plant-specific design criteria.

7. Inspect controlled low-strength material backfill for cracking that could admit groundwater to the external surface of the embedded pipe. Inspect the lesser of ten linear feet or actual total length embedded in controlled low-strength material, including the top surfaces and at least 50 percent of the side surface.

8. Perform wall thickness measurement if visual inspections identify evidence of corrosion beyond minor surface rusting for both coated and uncoated metallic piping. The results of the wall thickness measurement will be used to calculate a corrosion rate and project wall thickness through the end of the subsequent period of extended operation. If the depth or extent of degradation of the base metal could have resulted in a loss of pressure boundary function when the loss of material is extrapolated to the end of the subsequent period of extended operation, then additional inspections will be performed as follows: When measured pipe wall thickness, projected to the end of the subsequent period of extended operation, does not meet the minimum pipe wall thickness requirements due to external corrosion, the number of inspections within the affected piping category will be doubled or increased by five, whichever is smaller. If adverse indications are found in the expanded sample, an analysis will be conducted to determine the

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 8 18 Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule extent of condition and extent of cause. The size of the follow up inspections will be determined based on the analysis. Timing of any additional inspections will be based on the severity of the identified degradation and the consequences of leakage or loss of function.

Any additional inspections will be performed within the same 10-year inspection interval in which the original degradation was identified, or within four years after the end of the 10-year interval if the degradation was identified in the latter half of the 10-year interval. Expansion of sample size may be limited by the extent of piping subject to the observed degradation mechanism or if the piping system or portion of the system is replaced or otherwise mitigated within the same 10-year inspection interval in which the original degradation was identified or within four years after the end of the 10-year interval, if the degradation was identified in the latter half of the 10-year interval.

9. Perform visual inspections of buried steel piping in the Fuel Oil System at least once every ten years. The inspection quantity of buried steel piping will be determined based on the effectiveness of preventive actions in accordance with NUREG-2191, Table XI.M41-

2. Ten linear feet of piping will be exposed for each inspection.

10. Perform visual inspections of at least one ten-linear foot section of buried stainless steel piping in the Primary and Demineralized Water Makeup System at least once every ten years. Piping inspection locations will be selected based on risk (i.e., susceptibility to degradation and consequences of failure).

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 8 19 Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule

11. Perform visual inspections of at least two ten-linear foot sections of underground coated steel piping in the Condensate or Service Water Systems at least once every ten years. Piping inspection locations will be selected based on risk (i.e., susceptibility to degradation and consequences of failure).

12. Perform visual inspections of at least one ten-linear foot section of underground uncoated stainless steel piping in the Auxiliary Feedwater, Chemical and Volume Control, Condensate, Primary and Demineralized Water Makeup, or Service Water System at least once every ten years. Piping inspection locations will be selected based on risk (i.e., susceptibility to degradation and consequences of failure).

13. Perform visual inspections of the concrete encapsulated components in the North service water header (30-CW-11) at pit #3 at least once in the 10-year period prior to entering the subsequent period of extended operation. Inspect the concrete surrounding the pipe for cracks that could admit groundwater to the external surface of the pipe. The sample size for the inspection is the portion of the exterior of the buried piping where it interfaces with the exterior surface of the concrete of pit #3, exposed by excavation of the top surfaces and at least 50 percent of the side surface.

14. Perform trending of flow testing of the Site Fire Protection System fire main headers to identify changes that could indicate leakage of buried piping.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 8 20 Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule

15. Personnel performing inspections of buried coated piping will either:

1) possess an Association for Materials Protection and Performance coating inspector program level 2 or level 3 inspector qualification,

2) complete the EPRI Comprehensive Coatings Course and complete the EPRI Buried Pipe Condition Assessment and Repair Training Computed Based Training Course, or 3) be qualified as a coatings specialist in accordance with ASTM D7108.

16. Inspect polyvinyl chloride components in the scope of the program for absence of cracking and perform an evaluation when blisters, gouges, or wear is detected.

17. If significant coating damage is identified during visual inspections, then perform an evaluation to determine if the coating damage was caused by nonconforming backfill. If it is determined that the coating damage was caused by nonconforming backfill, then conduct an extent of condition evaluation to determine the extent of degraded backfill in the vicinity of the observed damage.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 8 21 SLRA Table B2-1 is revised as follows:

Table B2-1 RNP Program Consistency with NUREG-2191 Program NUREG-2191 Program Appendix B

Reference Existing or New Program has NUREG-2191 Enhancements Program has Exceptions to NUREG-2191 Buried and Underground Piping and Tanks B2.1.27 Existing X

X

ENCLOSURE 1 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT 2 SUBSEQUENT LICENSE RENEWAL APPLICATION H.B. ROBINSON SLRA SUPPLEMENT 2 ATTACHMENT 9 TRP-15, Rev 1

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 9 1, Attachment 9 Additional clarification to AMP description regarding Potable Water System Hot Water Heater.

(TRP-15, Rev 1)

Affected SLRA Section(s):

B2.1.25 SLRA Page Numbers:

B-153 Description of Change:

Provide additional information regarding path for leakage from the hot water heater.

SLRA Revisions:

SLRA Section B2.1.25 is revised as follows:

Section B2.1.25 Program Description x

Potable Water System hot water heater tank - The Potable Water System is within the scope subsequent license renewal for the 10 CFR 54.4(a)(2) spatial criteria only.

Therefore, detach linings from the steel lined potable water heater cannot cause downstream effects that will prevent the accomplishment of an 10 CFR 54.4(a)(1) or 10 CFR 54.4(a)(3) intended function. The intended function of the water heater is structural integrity. The environment in the water heater does not promote accelerated corrosion or microbiologically induced corrosion of the base metal since well water is the water source for the Potable Water System. The well water supplying the Potable Water System has a pH of approximately 7 and is not corrosive. It is used by the station for domestic (sanitary) use, including water for drinking fountains, lab sinks, washing of machinery, and makeup for the primary and secondary systems after it has been demineralized and chemically treated. This hot water heater supplies a bathroom in the Turbine Building, including lavatories and showers. Failure of the lining on the hot water heater tank would not impact any of the functions identified in 10 CFR 54.4(a)(1),(2) or (3). With regard to a galvanic couple at the connection of the copper supply line to the steel hot water tank, this installation is typical of hot water heaters of this nature and has proven to be acceptable in its ongoing and prevalent use in residential, commercial, and industrial applications. Should a leak occur at this connection, it would be contained and routed to local drains, and would not present the potential for adverse spatial interactions. A corrosion allowance has not been identified for the hot water heater.

ENCLOSURE 1 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT 2 SUBSEQUENT LICENSE RENEWAL APPLICATION H.B. ROBINSON SLRA SUPPLEMENT 2 ATTACHMENT 10 TRP 17

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 10 1, Attachment 10 SLRA revisions related to TRP 17 (Flow-Accelerated Corrosion Program)

(TRP 17)

Affected SLRA Section(s)/Table(s):

B2.1.8 B2.1.11 B2.1.12 A6.0-1 SLRA Page Numbers:

A-49 A-52 A-54 B-60 B-79 B-87 Description of Change:

1. In Section B2.1.8 (Flow-Accelerated Corrosion Program),

a. Add new enhancement to perform inspections for wall thinning due to erosion downstream of the restricting orifice in each of the recirculation lines for the Auxiliary Feedwater pumps prior to the SPEO.

b. Add new enhancement to implement a pre-outage review of all scheduled FAC Program inspection locations to ensure that all locations that are erosion susceptible are properly identified.

c. Add new enhancement to revise the Robinson and Fleet License Renewal Aging Management procedures to include text related to managing erosion in non-FAC susceptible systems per EPRI guidance.

2. In Section B2.1.11 (Open Cycle Cooling Water Program),

a. Add new enhancement to require that wall thinning due to erosion in open cycle cooling water systems is managed per EPRI guidance.

3. In Section B2.1.12 (Closed Treated Water Systems),

a. Add new enhancement to require that wall thinning due to erosion in closed treated water systems is managed per EPRI guidance.

4. Update Table A6.0-1, Subsequent License Renewal Commitments, to reflect the new enhancements.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 10 2

SLRA Revisions:

SLRA Section B2.1.8 is revised as follows:

Section B2.1.8 Enhancements Prior to the subsequent period of extended operation, the following enhancement enhancements will be implemented in the following program element: elements: Detection of Aging Effects (Element 4). 4) and Acceptance Criteria (Element 6):

2. Prior to entry into the subsequent period of extended operation, perform inspections for wall thinning due to erosion downstream of the restricting orifice in each of the recirculation lines for the motor-driven and steam-driven Auxiliary Feedwater pumps. The inspection results will be evaluated to determine an appropriate reinspection schedule (if necessary) using a minimum safety factor of 2.0. Update the Erosion Susceptibility Analysis to reflect the results of the inspection if appropriate. (Element 4)

3. Implement a pre-outage review of all scheduled FAC Program inspection locations to ensure that all locations that are erosion susceptible are properly identified. The review shall further ensure that the erosion specific safety factor is applied where appropriate. (Element 4 and Element 6)

4. Revise the Robinson and Fleet License Renewal Aging Management procedures to include the following text: The Flow-Accelerated Corrosion (FAC) Program manages wall thinning due to FAC and erosion in FAC susceptible systems. Wall thinning due to erosion in non-FAC susceptible systems is managed per the guidelines of EPRI Report 3002005530, Recommendations for an Effective Program Against Erosive Attack, using a minimum safety factor of 2.0. (Element 6)

SLRA Section B2.1.11 is revised as follows:

Section B2.1.11 Enhancements

4. Wall thinning due to erosion in open cycle cooling water systems is managed per the guidelines of EPRI Report 3002005530, Recommendations for an Effective Program Against Erosive Attack, using a minimum safety factor of 2.0. (Element 6)

SLRA Section B2.1.12 is revised as follows:

Section B2.1.12 Enhancements Prior to the subsequent period of extended operation, the following enhancements will be implemented in the following program elements: Scope of Program (Element 1), Parameters Monitored or Inspected (Element 3), Detection of Aging Effects (Element 4), Monitoring and Trending (Element 5), Acceptance Criteria (Element 6) and Corrective Actions (Element 7):

8. Wall thinning due to erosion in closed treated water systems is managed per the guidelines of EPRI Report 3002005530, Recommendations for an Effective Program Against Erosive Attack, using a minimum safety factor of 2.0. (Element 6)

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 10 3

Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule Difference

- 8 Flow-Accelerated Corrosion (B2.1.8)

The Flow-Accelerated Corrosion AMP is an existing program that will be enhanced to:

1. Reassess infrequently used piping systems excluded from the scope of the program with respect to evaluations performed to determine susceptibility to both wall thinning due to flow accelerated corrosion and wall thinning due to erosion mechanisms to ensure adequate bases exist to justify this exclusion for the subsequent period of extended operation.

2. Prior to entry into the subsequent period of extended operation, perform inspections for wall thinning due to erosion downstream of the restricting orifice in each of the recirculation lines for the motor-driven and steam-driven Auxiliary Feedwater pumps. The inspection results will be evaluated to determine an appropriate reinspection schedule (if necessary) using a minimum safety factor of 2.0.

Update the Erosion Susceptibility Analysis to reflect the results of the inspection if appropriate.

3. Implement a pre-outage review of all scheduled FAC Program inspection locations to ensure that all locations that are erosion susceptible are properly identified. The review shall further ensure that the erosion specific safety factor (minimum of 2.0) is applied where appropriate.

4. Revise the Robinson and Fleet License Renewal Aging Management procedures to include the following text: The Flow-Accelerated Corrosion (FAC) Program manages wall thinning due to FAC and erosion in FAC susceptible systems. Wall thinning due to Program enhancements for SLR will be implemented six months prior to the SPEO.

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H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 10 4

Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule erosion in non-FAC susceptible systems is managed per the guidelines of EPRI Report 3002005530, Recommendations for an Effective Program Against Erosive Attack, using a minimum safety factor of 2.0.

Changed

- 8 Flow-Accelerated Corrosion (B2.1.8)

The Flow-Accelerated Corrosion AMP is an existing program that will be enhanced to:

1. Reassess infrequently used piping systems excluded from the scope of the program with respect to evaluations performed to determine susceptibility to both wall thinning due to flow accelerated corrosion and wall thinning due to erosion mechanisms to ensure adequate bases exist to justify this exclusion for the subsequent period of extended operation.

2. Prior to entry into the subsequent period of extended operation, perform inspections for wall thinning due to erosion downstream of the restricting orifice in each of the recirculation lines for the motor-driven and steam-driven Auxiliary Feedwater pumps. The inspection results will be evaluated to determine an appropriate reinspection schedule (if necessary) using a minimum safety factor of 2.0.

Update the Erosion Susceptibility Analysis to reflect the results of the inspection if appropriate.

3. Implement a pre-outage review of all scheduled FAC Program inspection locations to ensure that all locations that are erosion susceptible are properly identified. The review shall further ensure Program enhancements for SLR will be implemented six months prior to the SPEO.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 10 5

Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule that the erosion specific safety factor (minimum of 2.0) is applied where appropriate.

4. Revise the Robinson and Fleet License Renewal Aging Management procedures to include the following text: The Flow-Accelerated Corrosion (FAC) Program manages wall thinning due to FAC and erosion in FAC susceptible systems. Wall thinning due to erosion in non-FAC susceptible systems is managed per the guidelines of EPRI Report 3002005530, Recommendations for an Effective Program Against Erosive Attack, using a minimum safety factor of 2.0.

Difference

- 11 Open-Cycle Cooling Water System (B2.1.11)

The Open-Cycle Cooling Water System aging management program is an existing program that will be enhanced to:

1. Provide additional guidance in procedures for inspections of non-ASME Code components for items such as lighting, distance, offset, surface coverage, presence of protective coatings, and cleaning processes.

2. For ongoing degradation due to specific aging mechanisms (e.g.,

microbiologically influenced corrosion), revise procedures to require trending of wall thickness measurements of raw water system piping at susceptible locations to adjust the monitoring frequency and the number of inspection locations.

3. If inspections identify wall thickness below the minimum required wall thickness and the cause of the aging effect for each applicable Program enhancements for SLR will be implemented six months prior to the SPEO.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 10 6

Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule material and environment is not corrected by repair or replacement for all components constructed of the same material and exposed to the same environment, additional inspections will be conducted. The number of increased inspections is determined in accordance with the Corrective Action Program; however, no fewer than five additional inspections will be conducted for each inspection that did not meet acceptance criteria, or 20% of each applicable material, environment, and aging effect combination is inspected, whichever is less.

4. Wall thinning due to erosion in open cycle cooling water systems is managed per the guidelines of EPRI Report 3002005530, Recommendations for an Effective Program Against Erosive Attack, using a minimum safety factor of 2.0.

Changed

- 11 Open-Cycle Cooling Water System (B2.1.11)

The Open-Cycle Cooling Water System aging management program is an existing program that will be enhanced to:

1. Provide additional guidance in procedures for inspections of non-ASME Code components for items such as lighting, distance, offset, surface coverage, presence of protective coatings, and cleaning processes.

2. For ongoing degradation due to specific aging mechanisms (e.g.,

microbiologically influenced corrosion), revise procedures to require trending of wall thickness measurements of raw water system piping Program enhancements for SLR will be implemented six months prior to the SPEO.

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H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 10 7

Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule at susceptible locations to adjust the monitoring frequency and the number of inspection locations.

3. If inspections identify wall thickness below the minimum required wall thickness and the cause of the aging effect for each applicable material and environment is not corrected by repair or replacement for all components constructed of the same material and exposed to the same environment, additional inspections will be conducted. The number of increased inspections is determined in accordance with the Corrective Action Program; however, no fewer than five additional inspections will be conducted for each inspection that did not meet acceptance criteria, or 20% of each applicable material, environment, and aging effect combination is inspected, whichever is less.

4. Wall thinning due to erosion in open cycle cooling water systems is managed per the guidelines of EPRI Report 3002005530, Recommendations for an Effective Program Against Erosive Attack, using a minimum safety factor of 2.0.

Difference

- 12 Closed Treated Water Systems (B2.1.12)

The Closed Treated Water Systems aging management program is an existing program that will be enhanced to:

1. Include component cooling water piping susceptible to wall-thinning due to erosion in the scope of the Closed Treated Water Systems program. Perform periodic volumetric (wall-thickness) inspection of component cooling water piping downstream of the spent fuel pool heat exchanger that is susceptible to wall-thinning due to erosion Program enhancements for SLR will be implemented six months prior to the SPEO.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 10 8

Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule mechanism. Perform the initial volumetric inspection prior to entering the subsequent period of extended operation. Frequency for subsequent volumetric inspections will be established based on the initial inspection results.

2. Perform condition monitoring using techniques (visual, surface, or volumetric) capable of detecting loss of material, cracking, and fouling as appropriate. Perform visual inspections for loss of material and fouling whenever the system boundaries of the closed treated water systems are opened. Perform surface or volumetric examinations when susceptible materials are inspected for cracking.

3. In each 10-year period during the subsequent period of extended operation, perform sufficient number of inspections to ensure that the minimum representative sample of 20 percent of the population up to 25 inspections per population is met. A population is defined as components having the same material, water treatment program and aging effect combination. Perform inspections on those components that are more likely to be susceptible to aging based on time in service and severity of operating conditions.

4. Provide additional guidance in procedures for inspections of non-ASME Code components for items such as lighting, distance, offset, surface coverage, presence of protective coatings, and cleaning processes.

5. Perform additional inspections when inspections do not meet acceptance criteria and are not corrected by repair or replacement.

Perform at least five additional inspections for every inspection not Initial volumetric inspection of component cooling water piping susceptible to wall-thinning due to erosion will be performed prior to entering the SPEO and will be completed no later than six months prior to the SPEO.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 10 9

Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule meeting acceptance criteria or 20 percent of each applicable material, environment, and aging effect combination, whichever is less.

6. Where practical, project the rate of any degradation until the next scheduled inspection or the end of the subsequent period of extended operation (whichever is shorter). Adjust the sampling bases (e.g., selection, size, frequency) as necessary based on the projections. For erosion mechanisms, wall thickness measurements will be trended to determine the need for further actions (e.g.,

adjustments to monitoring frequency, repair, or replacement).

Periodic wall thickness measurements will continue until effectiveness of corrective actions has been confirmed.

7. If subsequent inspections identify aging effects, the corrective action program will be used to determine the extent of condition and extent of cause to determine the further extent of inspections. Perform additional inspections with the same material, environment, and aging effect combinations and within the interval of the original inspection (e.g., refueling outage interval, 10-year inspection interval).

8. Wall thinning due to erosion in closed treated water systems is managed per the guidelines of EPRI Report 3002005530, Recommendations for an Effective Program Against Erosive Attack, using a minimum safety factor of 2.0.

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H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 10 10 Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule Changed

- 12 Closed Treated Water Systems (B2.1.12)

The Closed Treated Water Systems aging management program is an existing program that will be enhanced to:

1. Include component cooling water piping susceptible to wall-thinning due to erosion in the scope of the Closed Treated Water Systems program. Perform periodic volumetric (wall-thickness) inspection of component cooling water piping downstream of the spent fuel pool heat exchanger that is susceptible to wall-thinning due to erosion mechanism. Perform the initial volumetric inspection prior to entering the subsequent period of extended operation. Frequency for subsequent volumetric inspections will be established based on the initial inspection results.

2. Perform condition monitoring using techniques (visual, surface, or volumetric) capable of detecting loss of material, cracking, and fouling as appropriate. Perform visual inspections for loss of material and fouling whenever the system boundaries of the closed treated water systems are opened. Perform surface or volumetric examinations when susceptible materials are inspected for cracking.

3. In each 10-year period during the subsequent period of extended operation, perform sufficient number of inspections to ensure that the minimum representative sample of 20 percent of the population up to 25 inspections per population is met. A population is defined as components having the same material, water treatment program and aging effect combination. Perform inspections on those components that are more likely to be susceptible to aging based on time in service and severity of operating conditions.

Program enhancements for SLR will be implemented six months prior to the SPEO.

Initial volumetric inspection of component cooling water piping susceptible to wall-thinning due to erosion will be performed prior to entering the SPEO and will be completed no later than six months prior to the SPEO.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 10 11 Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule

4. Provide additional guidance in procedures for inspections of non-ASME Code components for items such as lighting, distance, offset, surface coverage, presence of protective coatings, and cleaning processes.

5. Perform additional inspections when inspections do not meet acceptance criteria and are not corrected by repair or replacement.

Perform at least five additional inspections for every inspection not meeting acceptance criteria or 20 percent of each applicable material, environment, and aging effect combination, whichever is less.

6. Where practical, project the rate of any degradation until the next scheduled inspection or the end of the subsequent period of extended operation (whichever is shorter). Adjust the sampling bases (e.g., selection, size, frequency) as necessary based on the projections. For erosion mechanisms, wall thickness measurements will be trended to determine the need for further actions (e.g.,

adjustments to monitoring frequency, repair, or replacement).

Periodic wall thickness measurements will continue until effectiveness of corrective actions has been confirmed.

7. If subsequent inspections identify aging effects, the corrective action program will be used to determine the extent of condition and extent of cause to determine the further extent of inspections. Perform additional inspections with the same material, environment, and aging effect combinations and within the interval of the original

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 10 12 Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule inspection (e.g., refueling outage interval, 10-year inspection interval).

8. Wall thinning due to erosion in closed treated water systems is managed per the guidelines of EPRI Report 3002005530, Recommendations for an Effective Program Against Erosive Attack, using a minimum safety factor of 2.0.

ENCLOSURE 1 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT 2 SUBSEQUENT LICENSE RENEWAL APPLICATION H.B. ROBINSON SLRA SUPPLEMENT 2 ATTACHMENT 11 TRP 46

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 11 1, Attachment 11 TRP 46 - Structures Monitoring Program Breakout Updates (TRP 46)

Affected SLRA Section(s)/Table(s):

2.4.1 2.4.13 2.4-13 2.4.16 2.4.26 3.3.1 3.5.2.1.13 3.5.1 3.5.2-6 3.5.2-8 3.5.2-13 3.5.2-16 3.5.2-18 3.5.2-26 3.5.2-28 B2.1.34 A6.0-1 SLRA Page Numbers:

2-169 2-188 2-190 2-193 2-209 3-355 3-884 3-950 3-990 3-993 3-999 3-1012 3-1020 3-1022 3-1023 3-1026 3-1052

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 11 2

3-1055 3-1056 B-207 B-208 B-209 A-85 through A-89 Description of Change:

The following changes were made in response to the TRP 46 - Structures Monitoring Breakout:

x Section 2.4.1 is updated to point to the Component Supports group for conduits, cable trays, cabinets, enclosures, racks, frames and panels.

x Section 2.4.13 is updated to specify the environment for the new fuel storage room and demonstrate that cracking due to SCC is not an applicable aging effect for the new fuel storage racks.

x Table 2.4-13 is updated to add the Spent Fuel Storage Rack and New Fuel Storage Rack component type.

x Section 2.4.16 is updated to state that the Intake Structure does not include trash racks.

x Section 2.4.26 updated to provide clarification that transmission towers are in the scope of SLR. Table 3.5.2-26 Switchyard and Transformers is updated to provide clarification for the in-scope components in an updated Plant Specific Note.

x Table 3.3.1 updated 3.3.1-111 to clarify that the item is utilized for aging management of the New Fuel Storage Rack component type.

x Section 3.5.2.1.13 is updated to include additional credited AMPs associated with Fuel Handling Building.

x Table 3.5.1 updated 3.5.1-088 updated to remove last sentence that aligned steel elements to this item.

x Table 3.5.2-6 Component Supports has an updated Plant Specific Note that clarifies pipe whip restraints, jet impingement shields and tube tracks are included in the Steel Elements component type. Additionally, an AMR line item is added for Sliding Surfaces in Table 3.5.2-6 aligning to GALL 3.5.1-074.

x Table 3.5.2-8 Condensate Polishing Building updated to add air-outdoor environment for steel.

x Table 3.5.2-13 Fuel Handling Building is updated to add AMR for the Spent Fuel Storage Rack and New Fuel Storage Rack component types.

x Table 3.5.2-16 Intake Structure updated to delete duplicate AMR ID 581 and align AMR ID 576 to 3.5.1-096.

x Table 3.5.2-16 Intake Structure and Table 3.5.2-28 Turbine Building updated to add AMRs for concrete in an air-indoor (uncontrolled), water-flowing, and groundwater/soil environment.

x Table 3.5.2-16 Intake Structure updated to delete 4420 and 4422.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 11 3

x Table 3.5.2-18 Miscellaneous Structural Commodities updated to add air outdoor environment for drains/ curbs.

x Structures Monitoring B2.1.34 updated to align enhancements to elements. Additionally, B2.1.34 and Table A6.0-1 are updated to revise Enhancement 6 and 8 to align with standard GALL language.

x Structures Monitoring updated program description and to add enhancements for Boric Acid monitoring.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 11 4

SLRA Revisions:

SLRA Section 2.4.1 is revised as follows:

Section 2.4.1 System Evaluation Boundary Components not included in the evaluation boundary of the Reactor Containment Building are component supports and electrical enclosures (conduit, cable trays, cabinets, enclosures, racks, frames and panels for electrical equipment and instrumentation). Component supports are evaluated in the Component Supports commodity group. Conduit, cable trays, cabinets, enclosures, racks, frames and panels for electrical equipment and instrumentation are evaluated in the Miscellaneous Structural Commodities Component Supports commodity group.

Mechanical and electrical systems and components housed inside the structure are separately evaluated with their respective mechanical systems, electrical systems, or commodities.

SLRA Section 2.4.13 is revised as follows:

Section 2.4.13 System Description The New Fuel Building is a separate area whose location facilitates the unloading of new fuel assemblies from fuel containers. The new fuel storage room includes new fuel racks, hoist/handling tool, and new fuel lift. The new fuel storage room temperatures do not exceed 140°F (60°C), nor does the environment contain contaminants that could induce SCC at temperatures below 140°F. As these conditions do not exist in the new fuel storage room, where the new fuel storage racks are located, cracking due to SCC is not an applicable aging effect for the new fuel storage racks.

SLRA Section 2.4.13 is revised as follows:

Section 2.4.13 Table 2.4-13 Fuel Handling Building Component/Commodity Group Intended Functions New Fuel Storage Rack Structural Support Spent Fuel Storage Rack Shelter, Protection; Structural Support SLRA Section 2.4.16 is revised as follows:

Section 2.4.16 System Description The Intake Structure is located on the shore of Lake Robinson. The Intake Structure is a three-bay reinforced concrete structure supported by a reinforced concrete mat foundation. Each bay is separated by a reinforced concrete wall. The four service water pumps are located in three separate bays in the intake structure, the middle bay containing two pumps. Additionally, the Intake Structure supports the three firewater pumps (booster pump, motor driven pump, engine

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 11 5

driven pump). The pumps take suction from the bays and supply water to the plant via their respective systems. The Robinson Intake Structure does not utilize trash racks.

SLRA Section 2.4.26 is revised as follows:

Section 2.4.26 System Evaluation Boundary The evaluation boundary of the Switchyard and Transformers includes the steel elements, concrete element, and miscellaneous structural elements. The transmission towers are included in the scope of the Switchyard and Transformers.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 11 6

SLRA Table 3.3.1 is revised as follows:

Table 3.3.1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report Item Number Component Aging Effect/Mechanism Aging Management Program Further Evaluation Recommended Discussion Difference -

3.3.1-111 Steel structural steel exposed to air - indoor uncontrolled Loss of material due to general, pitting, crevice corrosion AMP XI.S6, "Structures Monitoring" No Not applicable. Consistent with NUREG-2191. Stainless Steel structural steel New Fuel Storage Racks are Civil / Structural components and addressed by SRP items in Section 3.5. The associated NUREG-2191 aging items are not used. aligned to this item.

Changed -

3.3.1-111 Steel structural steel exposed to air - indoor uncontrolled Loss of material due to general, pitting, crevice corrosion AMP XI.S6, "Structures Monitoring" No Consistent with NUREG-2191.

Stainless Steel New Fuel Storage Racks are aligned to this item.

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H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 11 7

SLRA Section 3.5.2.1.13 is revised as follows:

Section 3.5.2.1.13 x

One-Time Inspection

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 11 8

SLRA Table 3.5.1 is revised as follows:

Table 3.5.1 Summary of Aging Management Programs for Containments, Structures, and Component Supports Evaluated in Chapter II and III of the GALL-SLR Report Item Number Component Aging Effect/Mechanism Aging Management Program Further Evaluation Recommended Discussion Difference -

3.5.1-088 Structural bolting Loss of preload due to self-loosening AMP XI.S6, "Structures Monitoring" No Consistent with NUREG-2191, except that the Inspection of Water-Control Structures Associated with Nuclear Power Plants (B2.1.35) is used to manage loss of preload due to self-loosening at the Intake Structure and the Reservoir and Dam. In addition to structural bolting, steel elements are aligned to this item number.

Changed -

3.5.1-088 Structural bolting Loss of preload due to self-loosening AMP XI.S6, "Structures Monitoring" No Consistent with NUREG-2191, except that the Inspection of Water-Control Structures Associated with Nuclear Power Plants (B2.1.35) is used to manage loss of preload due to self-loosening at the Intake Structure and the Reservoir and Dam.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 11 9

SLRA Table 3.5.2-6 is revised as follows:

Table 3.5.2-6 Containments, Structures, and Component Supports - Component Supports - Aging Management Evaluation AMR ID Component Type Intended Function Material Environment Aging Effect Aging Management Program NUREG-2191 Item NUREG-2192 Table 1 Notes New -

9313 Sliding Surfaces Structural Support Lubrite; Fluorogold; Lubrofluor Air - Indoor Uncontrolled (External)

Loss of Mechanical Function Structures Monitoring (B2.1.34)

III.B2.TP-46 3.5.1-074 A

New -

9315 Sliding Surfaces Structural Support Lubrite; Fluorogold; Lubrofluor Air - Indoor Uncontrolled (External)

Loss of Mechanical Function Structures Monitoring (B2.1.34)

III.B4.TP-46 3.5.1-074 A

New -

9314 Sliding Surfaces Structural Support Lubrite; Fluorogold; Lubrofluor Air - Outdoor (External)

Loss of Mechanical Function Structures Monitoring (B2.1.34)

III.B2.TP-47 3.5.1-074 A

New -

9316 Sliding Surfaces Structural Support Lubrite; Fluorogold; Lubrofluor Air - Outdoor (External)

Loss of Mechanical Function Structures Monitoring (B2.1.34)

III.B4.TP-47 3.5.1-074 A

2. Steel elements include support members, bearing plates, base plates, connections, instrument racks, cable trays, conduits and structural racks.

racks, pipe whip restraints, jet impingement shields and tube tracks.

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H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 11 10 SLRA Table 3.5.2-8 is revised as follows:

Table 3.5.2-8 Containments, Structures, and Component Supports - Condensate Polishing Building - Aging Management Evaluation AMR ID Component Type Intended Function Material Environment Aging Effect Aging Management Program NUREG-2191 Item NUREG-2192 Table 1 Notes New -

9324 Steel Elements

Shelter, Protection; Structural Support Steel Air - Outdoor (External)

Loss of Material Structures Monitoring (B2.1.34)

III.A3.TP-302 3.5.1-077 A,2 I

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H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 11 11 SLRA Table 3.5.2-13 is revised as follows:

Table 3.5.2-13 Containments, Structures, and Component Supports - Fuel Handling Building - Aging Management Evaluation AMR ID Component Type Intended Function Material Environment Aging Effect Aging Management Program NUREG-2191 Item NUREG-2192 Table 1 Notes New -

9327 New Fuel Storage Rack Structural Support Stainless Steel Air - Indoor Uncontrolled (External)

Loss of Material Structures Monitoring (B2.1.34)

VII.A1.A-94 3.3.1-111 F

New -

9326 Spent Fuel Storage Rack

Shelter, Protection; Structural Support Stainless Steel Treated Borated Water (External)

Loss of Material One-Time Inspection (B2.1.20)

VII.A2.A-99 3.3.1-125 A

New -

9325 Spent Fuel Storage Rack

Shelter, Protection; Structural Support Stainless Steel Treated Borated Water (External)

Loss of Material Water Chemistry (B2.1.2)

VII.A2.A-99 3.3.1-125 A

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H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 11 12 SLRA Table 3.5.2-16 is revised as follows:

Table 3.5.2-16 Containments, Structures, and Component Supports - Intake Structure - Aging Management Evaluation AMR ID Component Type Intended Function Material Environment Aging Effect Aging Management Program NUREG-2191 Item NUREG-2192 Table 1 Notes New -

9320 Concrete Elements

Shelter, Protection; Structural Support Concrete Air - Indoor Uncontrolled (External)

Cracking Inspection of Water-Control Structures Associated with Nuclear Power Plants (B2.1.35)

III.A6.T-34 3.5.1-096 A,1 Difference

- 581 Concrete Elements

Shelter, Protection; Structural Support Concrete Air - Outdoor (External)

Cracking Structures Monitoring (B2.1.34)

III.A6.TP-25 3.5.1-054 A,1 Deleted -

581 Difference

- 576 Concrete Elements

Shelter, Protection; Structural Support Concrete Air - Outdoor (External)

Cracking Inspection of Water-Control Structures Monitoring (B2.1.34)

Associated with Nuclear Power Plants (B2.1.35)

III.A6.TP-25 III.A6.T-34 3.5.1-054096 A,1 Changed

- 576 Concrete Elements

Shelter, Protection; Structural Support Concrete Air - Outdoor (External)

Cracking Inspection of Water-Control Structures Associated with Nuclear Power Plants (B2.1.35)

III.A6.T-34 3.5.1-096 A,1 New -

9322 Concrete Elements

Shelter, Protection; Structural Support Concrete Groundwater/Soil (External)

Cracking Inspection of Water-Control Structures Associated with Nuclear Power Plants (B2.1.35)

III.A6.T-34 3.5.1-096 A,1 New -

9321 Concrete Elements

Shelter, Protection; Structural Support Concrete Water - Flowing (External)

Cracking Inspection of Water-Control Structures Associated with Nuclear Power Plants (B2.1.35)

III.A6.T-34 3.5.1-096 A,1 Difference

- 4420 Steel Elements Structural Support Steel Air - Outdoor (External)

Loss of Preload Inspection of Water-Control Structures Associated with Nuclear Power Plants (B2.1.35)

III.A6.TP-261 3.5.1-088 E,2 Deleted -

4420 Difference

- 4422 Steel Elements Structural Support Steel Water - Flowing (External)

Loss of Preload Inspection of Water-Control Structures Associated with Nuclear Power Plants (B2.1.35)

III.A6.TP-261 3.5.1-088 E,2 Deleted -

4422 I

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H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 11 13 SLRA Table 3.5.2-18 is revised as follows:

Table 3.5.2-18 Containments, Structures, and Component Supports - Miscellaneous Structural Commodities - Aging Management Evaluation AMR ID Component Type Intended Function Material Environment Aging Effect Aging Management Program NUREG-2191 Item NUREG-2192 Table 1 Notes New -

9323 Drains/ Curbs Direct Flow Concrete Air - Outdoor (External)

Increase in Porosity and Permeability, Cracking, Loss of Material (Spalling, Scaling)

Structures Monitoring (B2.1.34)

III.A3.TP-28 3.5.1-067 A

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H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 11 14 SLRA Table 3.5.2-26 is revised as follows:

2. Steel elements include beams, columns, baseplates, bracing, stairs, platforms, grating, decking, ladders and embedded steel. Steel elements also include transmission towers.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 11 15 SLRA Table 3.5.2-28 is revised as follows:

Table 3.5.2-28 Containments, Structures, and Component Supports - Turbine Building - Aging Management Evaluation AMR ID Component Type Intended Function Material Environment Aging Effect Aging Management Program NUREG-2191 Item NUREG-2192 Table 1 Notes New -

9317 Concrete Elements Structural Support; Missile Barrier Concrete Air - Indoor Uncontrolled (External)

Cracking Structures Monitoring (B2.1.34)

III.A3.TP-25 3.5.1-054 A,1 New -

9319 Concrete Elements Structural Support; Missile Barrier Concrete Groundwater/Soil (External)

Cracking Structures Monitoring (B2.1.34)

III.A3.TP-25 3.5.1-054 A,1 New -

9318 Concrete Elements Structural Support; Missile Barrier Concrete Water - Flowing (External)

Cracking Structures Monitoring (B2.1.34)

III.A3.TP-25 3.5.1-054 A,1 I

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H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 11 16 SLRA Section B2.1.34 is revised as follows:

Section B2.1.34 Program Description The Refuel Cavity and portion of the Fuel Transfer Canal located in the Reactor Containment Building do not contain tell-tales. The Refuel Cavity and Fuel Transfer Canal will manage aging effects associated with boric acid through inspections of areas adjacent to and below the Refuel Cavity and portion of the Fuel Transfer Canal. These areas are included in the scope of the Reactor Containment Building Structures Monitoring inspections and boric acid findings would be entered into the corrective action program.

The Spent Fuel Pit and a portion of the Fuel Transfer Canal located in the Fuel Handling Building contain tell-tales. The Spent Fuel Pit and a portion of the Fuel Transfer Canal will manage aging effects associated with boric acid through tell-tale sampling, sample analyzing, inspection and cleaning in addition to inspections of areas adjacent to and below the Spent Fuel Pit and Fuel Transfer Canal. These inspection areas are included in the scope of the Fuel Handling Building Structures Monitoring inspections and boric acid findings would be entered into the corrective action program.

Enhancements The following enhancements will be implemented in the following program elements: Scope of Program (Element 1), Preventive Actions (Element 2), Parameters Monitored/Inspected (Element 3), Detection of Aging Effects (Element 4), Monitor and Trending (Element 5), and Acceptance Criteria (Element 6). 6), and Corrective Actions (Element 7).

2. Expand the monitoring and evaluation of raw water and ground water chemistry, for pH, chlorides, and sulfates, on a frequency not to exceed five years that accounts for seasonal variations (e.g., quarterly monitoring every fifth year), from locations that are representative of the groundwater in contact with structures within the scope of second license renewal. (Element 1) (Elements 1 and 4)

5. Expand the program to monitor structural sealants and seismic joint fillers for cracking, loss of material, and hardening. Establish acceptance criteria for structural sealants and seismic joint fillers as no loss of material, cracking, or hardening that can lead to loss of sealing and resulting leakage that could lead to a loss of intended function. (Element (Elements 1, 3, 4, and 6)

6. Provide inspection and evaluation criteria for structural concrete using quantitative second tier criteria of Chapter 5 in ACI 349.3R. Base the acceptance criteria for concrete surfaces on the second-tier evaluation criteria provided in Chapter 5 of ACI 349.3R.

The program will be enhanced to explicitly mention loss of material, the changes in material properties of increase in porosity and permeability, and loss of strength, which can be indicated by honeycombs, discoloration, misalignment inspections, water in-leakage and pattern cracking with darkened edges. (Element 3 and 6)

7. Develop a new implementing procedure or revise an existing implementing procedure to address aging management of inaccessible areas exposed to potentially aggressive groundwater/soil environment that will include the following: (Element 3 (Elements 3, 4, and 4) 6)

8. Monitor and trend through-wall leakage and groundwater leakage, infiltration, infiltration volumes, and leakage water chemistry for signs of concrete or steel reinforcement

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 11 17 degradation. Develop additional engineering evaluations, which consider more frequent inspections, as well as destructive testing of affected concrete to validate existing concrete properties, and leakage water chemistry results. If leakage volumes allow, consider water chemistry analysis of the leakage pH, along with mineral, chloride, sulfate and iron content in the water. (Element 3 and 4)

10. Expand the program to monitor elastomeric vibration isolators and bearing pads, for cracking, loss of material, and hardening. Supplement visual inspection of elastomeric elements with tactile inspection to detect hardening, if the intended function is suspect.

Establish acceptance criteria for elastomeric pads and vibration isolation elements, as no loss of material, cracking, or hardening that can lead to reduction or loss of isolation or support function. (Element 4) (Elements 1, 3, 4, and 6)

12. Inspection results that do not meet the acceptance criteria are entered into the corrective action program and are evaluated by engineering. Conditions that are not repaired are projected to the next scheduled inspection to ensure that the component will continue to perform its intended function. If inspection results cannot be projected to the next scheduled inspection, then the inspection frequency is adjusted to ensure that a loss of the components intended function does not occur prior to the next scheduled inspection.

(Elements 4 4, 5, and 5) 7)

17. Explicitly address the potential for exposure of SSCs to leakage containing boric acid and require that the periodic walkdowns include all accessible interior walls and ceilings of rooms that are adjacent to (including below) the SFPs, Refueling Cavity and Fuel Transfer Canals. (Element 3)

18. Revise existing preventive maintenance tasks to require periodic inspection and cleaning, including blockage removal, of the SFP and South End of the Fuel Transfer Canal tell-tale drains. (Element 3)

19. Sample and analyze discharge from the leak chase system for, at a minimum, flow (drip) rate and the following chemistry parameters: pH, boron concentration, and iron content.

Chloride and Sulfate monitoring included if groundwater intrusion is occurring. (Element

3)

20. Inspect for evidence of leakage from the SFP, Refueling Cavity or Fuel Transfer Canals, such as the formation of deposits or wet areas on the structures. (Element 4)

21. Assess the frequency of inspection of the tell-tale drains (to increase confidence that there are no blockages), including sample collection and analysis. An initial frequency of once per year for the SFP and South End of the Fuel Transfer Canal tell-tales will be established. The long-term frequency may be adjusted by evaluating internal and external operating experience. (Element 4)

22. Assess blockage detection techniques, including the use of video probes to check for development of blockages in the tell-tales. (Element 4)

23. Develop appropriate acceptance criteria for the parameters that are monitored for the leak detection system, including, at a minimum, leak chase system discharge flow (drip) rate, pH, boron concentration, and iron content. Chloride and Sulfate monitoring included if groundwater intrusion is occurring. Any indications of new or increased leakage from the SFP, Refueling Cavity or Fuel Transfer Canals (formation of white crystal deposits or wet areas) will be documented and evaluated via the corrective action program. The following guidance for acceptance criteria will be included in the evaluation: (Element 6)

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 11 18 x

Drip rate: > 0 if any leakage has previously occurred; 0 if leakage has not previously occurred. No discharge from a tell-tale that had previously drained leakage may indicate a blockage. New leakage may indicate a change to leakage pathways.

Significant changes to the drip rate will be reviewed as part of the overall trend analysis.

x pH: > 5 or within +/- 1.5 pH units of 12-month average for each tell-tale drain.

x Boron: The reason for measuring the boron concentration is to assist in interpretation of the other chemistry results. Therefore, a specific acceptance criterion for boron concentration is not warranted.

x Chloride: < 500 ppm for aggressive groundwater. This will only be present if groundwater intrusion is occurring.

x Sulfate: < 1,500 ppm for aggressive groundwater. This will only be present if groundwater intrusion is occurring.

x Iron: Detection of any changes in iron corrosion occurring behind the liner. Iron levels will be trended and evaluated.

24. Revise existing preventive maintenance tasks to include cleaning of the SFP and South End of the Fuel Transfer Canal tell-tale drains using a rod or brush or by high-pressure cleaning (hydrolasing) or other alternative measures if inspection results indicate that cleaning is necessary. (Element 7)

25. Require that any results of inspections of analysis of data collected (associated with leak detection for the SFP and South End of the Fuel Transfer Canal) that do not meet the acceptance criteria will be entered into the CAP and evaluated, including consideration of revisiting structural evaluations to determine whether any future observed indications of changes in the leakage conditions cause structural margin to become inadequate.

(Element 7)

26. Evaluate operating experience relative to effective methods for restoring flow to tell-tale drains. (Element 7)

27. Expand the program to monitor New Fuel Storage Racks for loss of material. (Elements 1, 3, and 4)

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 11 19 SLRA Table A6.0-1 is revised as follows:

Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule Difference

- 34 Structures Monitoring (B2.1.34)

Structures Monitoring AMP is an existing program that will be enhanced to:

1. Add the following structures to the scope of the program:

x Auxiliary Boiler C Shed x

CAS Building x

Condensate Polishing Building x

General Employee Training (G.E.T.) Building

2. Expand the monitoring and evaluation of raw water and ground water chemistry, for pH, chlorides, and sulfates, on a frequency not to exceed five years that accounts for seasonal variations (e.g.,

quarterly monitoring every fifth year), from locations that are representative of the groundwater in contact with structures within the scope of second license renewal.

3. For structural bolting consisting of ASTM A325, ASTM F1852, ASTM F2280, and/or ASTM A490, provide guidance for storage, lubricant selection, and bolting and coating material selection based on Section 2 of RCSC (Research Council for Structural Connections) publication, Specification for Structural Joints Using High-Strength Bolts.

4. Provide guidance so that when new or replacement high strength structural bolting is required, the bolting material, installation torque or tension, and use of lubricants and sealants will be in accordance Program enhancements for SLR will be implemented six months prior to the SPEO.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 11 20 Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule with the guidelines of EPRI NP-5769, EPRI TR-104213, and the additional recommendations of NUREG-1339.

5. Expand the program to monitor structural sealants and seismic joint fillers for cracking, loss of material, and hardening. Establish acceptance criteria for structural sealants and seismic joint fillers as no loss of material, cracking, or hardening that can lead to loss of sealing and resulting leakage that could lead to a loss of intended function.

6. Provide inspection and evaluation criteria for structural concrete using quantitative second tier criteria of Chapter 5 in ACI 349.3R.

Base the acceptance criteria for concrete surfaces on the second-tier evaluation criteria provided in Chapter 5 of ACI 349.3R. The program will be enhanced to explicitly mention loss of material, the changes in material properties of increase in porosity and permeability, and loss of strength, which can be indicated by honeycombs, discoloration, misalignment inspections, water in-leakage and pattern cracking with darkened edges.

7. Develop a new implementing procedure or revise an existing implementing procedure to address aging management of inaccessible areas exposed to potentially aggressive groundwater/soil environment that will include the following:

x Monitor raw water and ground water chemistry, for pH, chlorides, and sulfates, on a frequency not to exceed five years that accounts for seasonal variations (e.g., quarterly monitoring every fifth year), from locations that are representative of the

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 11 21 Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule groundwater in contact with structures within the scope of second license renewal.

x Enter adverse results, which exceed water chemistry criteria, into the corrective action program. As part of the corrective actions, if aggressive groundwater is identified that might affect structures in scope for license renewal, perform additional water testing at additional locations and perform soil testing in order to confirm the extent, severity, and potential aging mechanisms resulting from the aggressive groundwater/soil.

x Develop engineering evaluations to evaluate the water chemistry results to assess the impact, if any, on below-grade concrete, including the potential for further degradation due to the aggressive groundwater, as well as consideration of current conditions. As part of the engineering evaluations, determine if additional actions are warranted, which might include enhanced inspection techniques and/or increased frequency, destructive testing, and focused inspections of representative accessible (leading indicator) or below grade, inaccessible concrete structural elements exposed to aggressive groundwater/soil.

x Develop the initial engineering evaluations prior to the second period of extended operation. Develop follow-up engineering evaluations on an interval not to exceed five years.

x If aggressive groundwater or soil is identified, at a minimum, perform focused inspections of representative, accessible (leading indicator) structural elements, or if accessible areas will

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 11 22 Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule not be leading indicators for the potential aging mechanisms, excavate and inspect buried concrete elements exposed to aggressive groundwater/soil.

x If degraded concrete is identified, as part of the focused inspections of leading indicators (representative, accessible or exposed inaccessible concrete), enter adverse results that exceed ACI 349.3R second-tier criteria into the corrective action program, and expose inaccessible concrete so that the extent of the condition can be determined, baseline conditions documented, and additional actions identified such as repairs, new preventative actions, additional evaluations, and future inspections.

8. Monitor and trend through-wall leakage and groundwater leakage, infiltration, infiltration volumes, and leakage water chemistry for signs of concrete or steel reinforcement degradation. Develop additional engineering evaluations, which consider more frequent inspections, as well as destructive testing of affected concrete to validate existing concrete properties, and leakage water chemistry results. If leakage volumes allow, consider water chemistry analysis of the leakage pH, along with mineral, chloride, sulfate and iron content in the water.

9. Perform inspections under the enhanced program in order to establish quantitative baseline inspection data to a sufficient detail to allow for trending, prior to the second period of extended operation.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 11 23 Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule

10. Expand the program to monitor elastomeric vibration isolators and bearing pads, for cracking, loss of material, and hardening.

Supplement visual inspection of elastomeric elements with tactile inspection to detect hardening, if the intended function is suspect.

Establish acceptance criteria for elastomeric pads and vibration isolation elements, as no loss of material, cracking, or hardening that can lead to reduction or loss of isolation or support function.

11. Require that personnel performing inspections and evaluations meet the qualifications specified within ACI 349.3R with respect to knowledge of inservice inspection of concrete and visual acuity requirements.

12. Inspection results that do not meet the acceptance criteria are entered into the corrective action program and are evaluated by engineering. Conditions that are not repaired are projected to the next scheduled inspection to ensure that the component will continue to perform its intended function. If inspection results cannot be projected to the next scheduled inspection, then the inspection frequency is adjusted to ensure that a loss of the components intended function does not occur prior to the next scheduled inspection.

13. Revise station procedures to state inspections occur on a frequency not to exceed 5-years.

14. Revise program procedures to specify that evaluation of inspection results includes consideration of the acceptability of inaccessible areas when conditions exist in accessible areas that could indicate

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 11 24 Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule the presence of, or result in, degradation to such inaccessible areas (e.g. exposed to groundwater/soil environment).

15. Revise inspection procedures to base inspection acceptance criteria on quantitative requirements derived from industry codes and standards, including but not limited to ACI 349.3R, ACI 318, SEI/ASCE 11, or the relevant AISC specifications and consider industry and plant OE. Use justified quantitative acceptance criteria whenever applicable.

16. Clarify that loose bolts and nuts are not acceptable unless accepted by engineering evaluation.

17. Explicitly address the potential for exposure of SSCs to leakage containing boric acid and require that the periodic walkdowns include all accessible interior walls and ceilings of rooms that are adjacent to (including below) the SFPs, Refueling Cavity and Fuel Transfer Canals.

18. Revise existing preventive maintenance tasks to require periodic inspection and cleaning, including blockage removal, of the SFP and South End of the Fuel Transfer Canal tell-tale drains.

19. Sample and analyze discharge from the leak chase system for, at a minimum, flow (drip) rate and the following chemistry parameters:

pH, boron concentration, and iron content. Chloride and Sulfate monitoring included if groundwater intrusion is occurring.

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H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 11 25 Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule

20. Inspect for evidence of leakage from the SFP, Refueling Cavity or Fuel Transfer Canals, such as the formation of deposits or wet areas on the structures.

21. Assess the frequency of inspection of the tell-tale drains (to increase confidence that there are no blockages), including sample collection and analysis. An initial frequency of once per year for the SFP and South End of the Fuel Transfer Canal tell-tales will be established.

The long-term frequency may be adjusted by evaluating internal and external operating experience.

22. Assess blockage detection techniques, including the use of video probes to check for development of blockages in the tell-tales.

23. Develop appropriate acceptance criteria for the parameters that are monitored for the leak detection system, including, at a minimum, leak chase system discharge flow (drip) rate, pH, boron concentration, and iron content. Chloride and Sulfate monitoring included if groundwater intrusion is occurring. Any indications of new or increased leakage from the SFP, Refueling Cavity or Fuel Transfer Canals (formation of white crystal deposits or wet areas) will be documented and evaluated via the corrective action program.

The following guidance for acceptance criteria will be included in the evaluation:

x Drip rate: > 0 if any leakage has previously occurred; 0 if leakage has not previously occurred. No discharge from a tell-tale that had previously drained leakage may indicate a blockage. New leakage may indicate a change to leakage I

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H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 11 26 Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule pathways. Significant changes to the drip rate will be reviewed as part of the overall trend analysis.

x pH: > 5 or within +/- 1.5 pH units of 12-month average for each tell-tale drain.

x Boron: The reason for measuring the boron concentration is to assist in interpretation of the other chemistry results. Therefore, a specific acceptance criterion for boron concentration is not warranted.

x Chloride: < 500 ppm for aggressive groundwater. This will only be present if groundwater intrusion is occurring.

x Sulfate: < 1,500 ppm for aggressive groundwater. This will only be present if groundwater intrusion is occurring.

x Iron: Detection of any changes in iron corrosion occurring behind the liner. Iron levels will be trended and evaluated.

24. Revise existing preventive maintenance tasks to include cleaning of the SFP and South End of the Fuel Transfer Canal tell-tale drains using a rod or brush or by high-pressure cleaning (hydrolasing) or other alternative measures if inspection results indicate that cleaning is necessary.

25. Require that any results of inspections of analysis of data collected (associated with leak detection for the SFP and South End of the Fuel Transfer Canal) that do not meet the acceptance criteria will be entered into the CAP and evaluated, including consideration of revisiting structural evaluations to determine whether any future I

I

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 11 27 Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule observed indications of changes in the leakage conditions cause structural margin to become inadequate.

26. Evaluate operating experience relative to effective methods for restoring flow to tell-tale drains.

27. Expand the program to monitor New Fuel Storage Racks for loss of material.

Changed

- 34 Structures Monitoring (B2.1.34)

Structures Monitoring AMP is an existing program that will be enhanced to:

1. Add the following structures to the scope of the program:

x Auxiliary Boiler C Shed x

CAS Building x

Condensate Polishing Building x

General Employee Training (G.E.T.) Building

2. Expand the monitoring and evaluation of raw water and ground water chemistry, for pH, chlorides, and sulfates, on a frequency not to exceed five years that accounts for seasonal variations (e.g.,

quarterly monitoring every fifth year), from locations that are representative of the groundwater in contact with structures within the scope of second license renewal.

3. For structural bolting consisting of ASTM A325, ASTM F1852, ASTM F2280, and/or ASTM A490, provide guidance for storage, lubricant selection, and bolting and coating material selection based Program enhancements for SLR will be implemented six months prior to the SPEO.

I I

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 11 28 Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule on Section 2 of RCSC (Research Council for Structural Connections) publication, Specification for Structural Joints Using High-Strength Bolts.

4. Provide guidance so that when new or replacement high strength structural bolting is required, the bolting material, installation torque or tension, and use of lubricants and sealants will be in accordance with the guidelines of EPRI NP-5769, EPRI TR-104213, and the additional recommendations of NUREG-1339.

5. Expand the program to monitor structural sealants and seismic joint fillers for cracking, loss of material, and hardening. Establish acceptance criteria for structural sealants and seismic joint fillers as no loss of material, cracking, or hardening that can lead to loss of sealing and resulting leakage that could lead to a loss of intended function.

6. Provide inspection and evaluation criteria for structural concrete using quantitative second tier criteria of Chapter 5 in ACI 349.3R.

Base the acceptance criteria for concrete surfaces on the second-tier evaluation criteria provided in Chapter 5 of ACI 349.3R. The program will be enhanced to explicitly mention loss of material, the changes in material properties of increase in porosity and permeability, and loss of strength, which can be indicated by misalignment inspections, water in-leakage and pattern cracking with darkened edges.

7. Develop a new implementing procedure or revise an existing implementing procedure to address aging management of

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 11 29 Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule inaccessible areas exposed to potentially aggressive groundwater/soil environment that will include the following:

x Monitor raw water and ground water chemistry, for pH, chlorides, and sulfates, on a frequency not to exceed five years that accounts for seasonal variations (e.g., quarterly monitoring every fifth year), from locations that are representative of the groundwater in contact with structures within the scope of second license renewal.

x Enter adverse results, which exceed water chemistry criteria, into the corrective action program. As part of the corrective actions, if aggressive groundwater is identified that might affect structures in scope for license renewal, perform additional water testing at additional locations and perform soil testing in order to confirm the extent, severity, and potential aging mechanisms resulting from the aggressive groundwater/soil.

x Develop engineering evaluations to evaluate the water chemistry results to assess the impact, if any, on below-grade concrete, including the potential for further degradation due to the aggressive groundwater, as well as consideration of current conditions. As part of the engineering evaluations, determine if additional actions are warranted, which might include enhanced inspection techniques and/or increased frequency, destructive testing, and focused inspections of representative accessible (leading indicator) or below grade, inaccessible concrete structural elements exposed to aggressive groundwater/soil.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 11 30 Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule x

Develop the initial engineering evaluations prior to the second period of extended operation. Develop follow-up engineering evaluations on an interval not to exceed five years.

x If aggressive groundwater or soil is identified, at a minimum, perform focused inspections of representative, accessible (leading indicator) structural elements, or if accessible areas will not be leading indicators for the potential aging mechanisms, excavate and inspect buried concrete elements exposed to aggressive groundwater/soil.

x If degraded concrete is identified, as part of the focused inspections of leading indicators (representative, accessible or exposed inaccessible concrete), enter adverse results that exceed ACI 349.3R second-tier criteria into the corrective action program, and expose inaccessible concrete so that the extent of the condition can be determined, baseline conditions documented, and additional actions identified such as repairs, new preventative actions, additional evaluations, and future inspections.

8. Monitor and trend through-wall leakage and groundwater infiltration, infiltration volumes, and leakage water chemistry for signs of concrete or steel reinforcement degradation. Develop additional engineering evaluations, which consider more frequent inspections, as well as destructive testing of affected concrete to validate existing concrete properties, and leakage water chemistry results. If leakage volumes allow, consider water chemistry analysis of the

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 11 31 Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule leakage pH, along with mineral, chloride, sulfate and iron content in the water.

9. Perform inspections under the enhanced program in order to establish quantitative baseline inspection data to a sufficient detail to allow for trending, prior to the second period of extended operation.

10. Expand the program to monitor elastomeric vibration isolators and bearing pads, for cracking, loss of material, and hardening.

Supplement visual inspection of elastomeric elements with tactile inspection to detect hardening, if the intended function is suspect.

Establish acceptance criteria for elastomeric pads and vibration isolation elements, as no loss of material, cracking, or hardening that can lead to reduction or loss of isolation or support function.

11. Require that personnel performing inspections and evaluations meet the qualifications specified within ACI 349.3R with respect to knowledge of inservice inspection of concrete and visual acuity requirements.

12. Inspection results that do not meet the acceptance criteria are entered into the corrective action program and are evaluated by engineering. Conditions that are not repaired are projected to the next scheduled inspection to ensure that the component will continue to perform its intended function. If inspection results cannot be projected to the next scheduled inspection, then the inspection frequency is adjusted to ensure that a loss of the

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 11 32 Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule components intended function does not occur prior to the next scheduled inspection.

13. Revise station procedures to state inspections occur on a frequency not to exceed 5-years.

14. Revise program procedures to specify that evaluation of inspection results includes consideration of the acceptability of inaccessible areas when conditions exist in accessible areas that could indicate the presence of, or result in, degradation to such inaccessible areas (e.g. exposed to groundwater/soil environment).

15. Revise inspection procedures to base inspection acceptance criteria on quantitative requirements derived from industry codes and standards, including but not limited to ACI 349.3R, ACI 318, SEI/ASCE 11, or the relevant AISC specifications and consider industry and plant OE. Use justified quantitative acceptance criteria whenever applicable.

16. Clarify that loose bolts and nuts are not acceptable unless accepted by engineering evaluation.

17. Explicitly address the potential for exposure of SSCs to leakage containing boric acid and require that the periodic walkdowns include all accessible interior walls and ceilings of rooms that are adjacent to (including below) the SFPs, Refueling Cavity and Fuel Transfer Canals.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 11 33 Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule

18. Revise existing preventive maintenance tasks to require periodic inspection and cleaning, including blockage removal, of the SFP and South End of the Fuel Transfer Canal tell-tale drains.

19. Sample and analyze discharge from the leak chase system for, at a minimum, flow (drip) rate and the following chemistry parameters:

pH, boron concentration, and iron content. Chloride and Sulfate monitoring included if groundwater intrusion is occurring.

20. Inspect for evidence of leakage from the SFP, Refueling Cavity or Fuel Transfer Canals, such as the formation of deposits or wet areas on the structures.

21. Assess the frequency of inspection of the tell-tale drains (to increase confidence that there are no blockages), including sample collection and analysis. An initial frequency of once per year for the SFP and South End of the Fuel Transfer Canal tell-tales will be established.

The long-term frequency may be adjusted by evaluating internal and external operating experience.

22. Assess blockage detection techniques, including the use of video probes to check for development of blockages in the tell-tales.

23. Develop appropriate acceptance criteria for the parameters that are monitored for the leak detection system, including, at a minimum, leak chase system discharge flow (drip) rate, pH, boron concentration, and iron content. Chloride and Sulfate monitoring included if groundwater intrusion is occurring. Any indications of new or increased leakage from the SFP, Refueling Cavity or Fuel Transfer Canals (formation of white crystal deposits or wet areas)

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 11 34 Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule will be documented and evaluated via the corrective action program.

The following guidance for acceptance criteria will be included in the evaluation:

x Drip rate: > 0 if any leakage has previously occurred; 0 if leakage has not previously occurred. No discharge from a tell-tale that had previously drained leakage may indicate a blockage. New leakage may indicate a change to leakage pathways. Significant changes to the drip rate will be reviewed as part of the overall trend analysis.

x pH: > 5 or within +/- 1.5 pH units of 12-month average for each tell-tale drain.

x Boron: The reason for measuring the boron concentration is to assist in interpretation of the other chemistry results. Therefore, a specific acceptance criterion for boron concentration is not warranted.

x Chloride: < 500 ppm for aggressive groundwater. This will only be present if groundwater intrusion is occurring.

x Sulfate: < 1,500 ppm for aggressive groundwater. This will only be present if groundwater intrusion is occurring.

x Iron: Detection of any changes in iron corrosion occurring behind the liner. Iron levels will be trended and evaluated.

24. Revise existing preventive maintenance tasks to include cleaning of the SFP and South End of the Fuel Transfer Canal tell-tale drains using a rod or brush or by high-pressure cleaning (hydrolasing) or

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 11 35 Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule other alternative measures if inspection results indicate that cleaning is necessary.

25. Require that any results of inspections of analysis of data collected (associated with leak detection for the SFP and South End of the Fuel Transfer Canal) that do not meet the acceptance criteria will be entered into the CAP and evaluated, including consideration of revisiting structural evaluations to determine whether any future observed indications of changes in the leakage conditions cause structural margin to become inadequate.

26. Evaluate operating experience relative to effective methods for restoring flow to tell-tale drains.

27. Expand the program to monitor New Fuel Storage Racks for loss of material.

ENCLOSURE 1 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT 2 SUBSEQUENT LICENSE RENEWAL APPLICATION H.B. ROBINSON SLRA SUPPLEMENT 2 ATTACHMENT 12 TRP 51

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 12 1, Attachment 12 TRP 51 Changes to XI.E1 AMP in Section B2.1.37 (TRP 51)

Affected SLRA Section(s)/Table(s):

B2.1.37 A6.0-1 SLRA Page Numbers:

B-222 A-95 Description of Change:

- The following new paragraph is added to Section B2.1.37 Program Description, consistent with NUREG-2191 XI.E1 AMP description:

"Accessible in-scope cable and connection inspection is considered a visual inspection performed from the floor, with the use of scaffolding as opportunistically available, without the opening of junction boxes, pull boxes, or terminal boxes. The purpose of the visual inspection is to identify adverse localized environments (employing diagnostic tools such as thermography as applicable). These potential adverse localized environments are then evaluated, which may require further inspection using scaffolding or other means (e.g., opening of junction boxes, pull boxes, accessible pull points, panels, or terminal boxes) to assess cable and connector electrical insulation aging degradation."

- The following new paragraph is added to Section B2.1.37 Program Description, consistent with NUREG-2191 XI.E1 AMP's Parameters Monitored or Inspected element, and is also added as a new Enhancement 4 per that element (3):

"An adverse localized environment is a plant-specific condition; therefore, the program will clearly define the most limiting temperature, radiation, and moisture environments and their basis. The program will also inspect for adverse localized environments for each of the most limiting cable and connection electrical insulation plant environments (e.g., caused by temperature, radiation, moisture, or contamination)."

- The following new text is added to Section B2.1.37 Program Description (appending original 2nd (now 4th) paragraph), consistent with NUREG-2191 XI.E1 AMP's Detection of Aging Effects element, and is also added as a new Enhancement 5 per that element (4):

"Cable and connection insulation are evaluated to confirm that the dispositioned corrective actions continue to support in-scope cable and connection intended functions during the subsequent period of extended operation."

- The following new paragraph is added to Section B2.1.37 Program Description, per NRC staff request:

"If cables covered by fire-retardant material are found to be in an adverse localized environment, then they are assessed by other methods such as testing, visually inspecting similar cables without fire-retardment coatings in the same or more severe environments, or potentially temporarily removing a portion of the fire-retardant coating for inspection of the cable jackets."

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 12 2

- The existing corrective actions / extent-of-condition statement in Section B2.1.37 Program Description (next to last paragraph) is edited to include other in-scope accessible and inaccessible cables, consistent with NUREG-2191 XI.E1 AMP's Corrective Actions element.

- The two new Enhancements are also added to Table A6.0-1 (item 37).

SLRA Revisions:

SLRA Section B2.1.37 is revised as follows:

Section B2.1.37 Program Description An adverse localized environment is a plant-specific condition; therefore, the program will clearly define the most limiting temperature, radiation, and moisture environments and their basis. The program will also inspect for adverse localized environments for each of the most limiting cable and connection electrical insulation plant environments (e.g., caused by temperature, radiation, moisture, or contamination).

Accessible in-scope cable and connection inspection is considered a visual inspection performed from the floor, with the use of scaffolding as opportunistically available, without the opening of junction boxes, pull boxes, or terminal boxes. The purpose of the visual inspection is to identify adverse localized environments (employing diagnostic tools such as thermography as applicable). These potential adverse localized environments are then evaluated, which may require further inspection using scaffolding or other means (e.g., opening of junction boxes, pull boxes, accessible pull points, panels, or terminal boxes) to assess cable and connector electrical insulation aging degradation.

At least once every ten years, accessible insulated cables and connections installed in adverse localized environments are visually inspected for jacket surface anomalies such as embrittlement, discoloration, cracking, melting, swelling, or surface contamination. Jacket surface anomalies are precursor indications that can be visually monitored to preclude the conductor insulation applicable aging effect. The inspections acceptance criteria is no unacceptable visual indications of jacket surface anomalies which suggest that a conductor insulation applicable aging effect may exist, as determined by engineering evaluation. An unacceptable indication is defined as a noted condition or situation that, if left unmanaged, could lead to a loss of license renewal intended function. As part of the periodic inspections, previously identified and mitigated adverse localized environments cumulative aging effects applicable to in-scope cable and connection insulation will be reviewed to confirm that the insulations intended functions continue to be supported during the subsequent period of extended operation. Cable and connection insulation are evaluated to confirm that the dispositioned corrective actions continue to support in-scope cable and connection intended functions during the subsequent period of extended operation.

If cables covered by fire-retardant material are found to be in an adverse localized environment, then they are assessed by other methods such as testing, visually inspecting similar cables without fire-retardment coatings in the same or more severe environments, or potentially temporarily removing a portion of the fire-retardant coating for inspection of the cable jackets.

Further investigation will be performed on cables and connections per the corrective action program when the acceptance criteria is not met. Corrective actions may include, but are not limited to, testing, shielding or otherwise changing the environment, relocating or replacement.

When an unacceptable condition or situation is identified, a determination will be made as to

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 12 3

whether this same condition could be or situation is applicable to other cables in-scope accessible and connections. inaccessible cables or connections (extent of condition).

Enhancements

4. Add the following guidance: An adverse localized environment is a plant-specific condition; therefore, the program will clearly define the most limiting temperature, radiation, and moisture environments and their basis. The program will also inspect for adverse localized environments for each of the most limiting cable and connection electrical insulation plant environments (e.g., caused by temperature, radiation, moisture, or contamination). (Element

3)

5. Add evaluation of cable and connection insulation to confirm that the dispositioned corrective actions continue to support in-scope cable and connection intended functions during the subsequent period of extended operation. (Element 4)

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 12 4

SLRA Table A6.0-1 is revised as follows:

Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule Difference

- 37 Electrical Insulation for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements (B2.1.37)

The Electrical Insulation for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements aging management program is an existing program that will be enhanced to:

1. As part of the periodic inspections, add review of previously identified and mitigated adverse localized environments cumulative aging effects applicable to in-scope cable and connection insulation to confirm that the insulations intended functions continue to be supported during the subsequent period of extended operation.

2. Add a description of potential testing and its sampling: If testing is evaluated to be necessary after visual inspections identify degraded or damaged conditions (such as unacceptable surface anomalies) that may adversely affect the performance of cable or connection insulation intended functions, then proven test(s) applicable to condition monitoring of the insulation are performed (for example, thermography may be included). For a large number of cables identified as degraded, a sample population will be tested. The sample size will be 20 percent of each affected cable and connection type with a maximum sample size of 25. Among the factors to consider for developing the test sample population are cable or connection type, environment, voltage level, circuit loading, and insulation material which is the most important factor per EPRI guidance. Testing as part of an existing maintenance, calibration, or surveillance program may be credited. The basis for the sample selection will be documented.

Program enhancements for SLR will be implemented six months prior to the SPEO.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 12 5

Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule

3. Add acceptance criteria for potential testing of accessible cables and connections with unacceptable visual inspection results to the Robinson aging management program description: Test results are to be within the acceptance criteria, as identified in the Robinson procedures.

4. Add the following guidance: An adverse localized environment is a plant-specific condition; therefore, the program will clearly define the most limiting temperature, radiation, and moisture environments and their basis. The program will also inspect for adverse localized environments for each of the most limiting cable and connection electrical insulation plant environments (e.g., caused by temperature, radiation, moisture, or contamination).

5. Add evaluation of cable and connection insulation to confirm that the dispositioned corrective actions continue to support in-scope cable and connection intended functions during the subsequent period of extended operation.

Changed

- 37 Electrical Insulation for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification The Electrical Insulation for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements aging management program is an existing program that will be enhanced to:

1. As part of the periodic inspections, add review of previously identified and mitigated adverse localized environments cumulative aging effects applicable to in-scope cable and connection insulation Program enhancements for SLR will be implemented six months prior to the SPEO.

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H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 12 6

Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule Requirements (B2.1.37) to confirm that the insulations intended functions continue to be supported during the subsequent period of extended operation.

2. Add a description of potential testing and its sampling: If testing is evaluated to be necessary after visual inspections identify degraded or damaged conditions (such as unacceptable surface anomalies) that may adversely affect the performance of cable or connection insulation intended functions, then proven test(s) applicable to condition monitoring of the insulation are performed (for example, thermography may be included). For a large number of cables identified as degraded, a sample population will be tested. The sample size will be 20 percent of each affected cable and connection type with a maximum sample size of 25. Among the factors to consider for developing the test sample population are cable or connection type, environment, voltage level, circuit loading, and insulation material which is the most important factor per EPRI guidance. Testing as part of an existing maintenance, calibration, or surveillance program may be credited. The basis for the sample selection will be documented.

3. Add acceptance criteria for potential testing of accessible cables and connections with unacceptable visual inspection results to the Robinson aging management program description: Test results are to be within the acceptance criteria, as identified in the Robinson procedures.

4. Add the following guidance: An adverse localized environment is a plant-specific condition; therefore, the program will clearly define the

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 12 7

Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule most limiting temperature, radiation, and moisture environments and their basis. The program will also inspect for adverse localized environments for each of the most limiting cable and connection electrical insulation plant environments (e.g., caused by temperature, radiation, moisture, or contamination).

5. Add evaluation of cable and connection insulation to confirm that the dispositioned corrective actions continue to support in-scope cable and connection intended functions during the subsequent period of extended operation.

ENCLOSURE 1 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT 2 SUBSEQUENT LICENSE RENEWAL APPLICATION H.B. ROBINSON SLRA SUPPLEMENT 2 ATTACHMENT 13 TRP 53.3

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 13 1, Attachment 13 Change Table 3.6.2-2 AMR Note for E3C AMP (TRP 53.3)

Affected SLRA Table(s):

3.6.2-2 SLRA Page Numbers:

3-1095 Description of Change:

Table 3.6.2-2 is edited to change the Note A to Note B to indicate that the XI.E3C AMP described in Section B2.1.41 is consistent with NUREG-2191 item for component, material, environment and aging effect, but that the AMP takes some exceptions to NUREG-2191 AMP.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 13 2

SLRA Revisions:

SLRA Table 3.6.2-2 is revised as follows:

Table 3.6.2-2 Electrical and Instrumentation and Controls - Cable and Connections - Aging Management Evaluation AMR ID Component Type Intended Function Material Environment Aging Effect Aging Management Program NUREG-2191 Item NUREG-2192 Table 1 Notes Difference

- 5323 Electrical Conductor Insulation for Inaccessible Low-Voltage Power Cables (typical operating voltage of < 1 kV but no greater than 2 kV)

Electrical Insulation Various Organic Polymers such as EPR, SR, EPDM, XLPE, Butyl Rubber, and Combined Thermoplastic Jacket/Insulation Shield Adverse Localized Environment Caused by Significant Moisture Reduced Electrical Insulation Resistance or Degraded Dielectric Strength Electrical Insulation for Inaccessible Low-Voltage Power Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements (B2.1.41)

VI.A.LP-35c 3.6.1-010 A B Changed

- 5323 Electrical Conductor Insulation for Inaccessible Low-Voltage Power Cables (typical operating voltage of < 1 kV but no greater than 2 kV)

Electrical Insulation Various Organic Polymers such as EPR, SR, EPDM, XLPE, Butyl Rubber, and Combined Thermoplastic Jacket/Insulation Shield Adverse Localized Environment Caused by Significant Moisture Reduced Electrical Insulation Resistance or Degraded Dielectric Strength Electrical Insulation for Inaccessible Low-Voltage Power Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements (B2.1.41)

VI.A.LP-35c 3.6.1-010 B

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ENCLOSURE 1 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT 2 SUBSEQUENT LICENSE RENEWAL APPLICATION H.B. ROBINSON SLRA SUPPLEMENT 2 ATTACHMENT 14 TRP 58

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 14 1, Attachment 14 Add Cable Bus & Plant-Specific Note to XI.E1 AMP Description & AMR Table (TRP 58)

Affected SLRA Section(s)/Table(s):

A2.1.37 B2.1.37 3.6.2-2 SLRA Page Numbers:

A-27 B-222 3-1096 Description of Change:

x In Section A2.1.37, a statement is added to identify that the cable bus insulated cables are included within the RNP XI.E1 AMP scope described in Section B2.1.37, and that the cable bus is installed in an outdoor uncontrolled environment. For clarity in the subsequent sentence, "and conditionally tested" is removed because it is completely described by the last sentence of the paragraph.

x In Section B2.1.37, a statement is added to identify that the cable bus insulated cables are included within the RNP XI.E1 AMP scope described in Section B2.1.37, and that the cable bus is installed in an outdoor uncontrolled environment.

x In Table 3.6.2-2, a Plant-Specific-Note (1) is added to corresponding AMR ID 5314 to state: "The inspection of cable bus electrical components will be managed by the Electrical Insulation for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements (B2.1.37) program."

x In Table 3.6.2-2, an AMR line (ID 9312) is added for cables and connections insulation in an "Air-Outdoor" environment, which is different from NUREG-2191 / GALL-SLR and thus has Note G. The environment difference is the RNP cable bus generalized outdoor environment versus GALL-SLR's more focused Adverse Localized Environment.

SLRA Revisions:

SLRA Section A2.1.37 is revised as follows:

Section A2.1.37 This existing condition monitoring aging management program applies to accessible electrical cable and connection electrical insulation material within the scope of license renewal subjected to an adverse localized environment. The program scope includes the cable insulation within the Robinson cable bus that is installed in an outdoor uncontrolled environment. Accessible in-scope electrical cable and connection electrical insulation material is visually inspected and conditionally tested for cable and connection insulation surface anomalies indicating signs of reduced electrical insulation resistance. If visual inspections identify degraded or damaged conditions, then testing is performed for evaluation.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 14 2

SLRA Section B2.1.37 is revised as follows:

Section B2.1.37 Program Description The Electrical Insulation for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification (EQ) Requirements aging management program is an existing condition monitoring program that will continue to manage the aging effect of reduced insulation resistance of accessible non-EQ electrical cable and connection insulation in adverse localized environments. The program scope includes the cable insulation within the Robinson cable bus that is installed in an outdoor uncontrolled environment. This aging management program is the existing Robinson UFSAR 18.1.33 Non-EQ Insulated Cables and Connections Program for initial license renewal that includes accessible insulated cables and connections (such as power, instrumentation, control, and communication) installed in structures or areas within the license renewal scope. The program involves periodic inspections of accessible cables and connections installed in adverse localized environments caused by heat, radiation, or moisture to detect aging conditions that could lead to reduced insulation resistance or electrical failure.

An adverse localized environment is defined as a condition in a limited plant area that is significantly more severe than the specified service condition for the electrical cable or connection.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 14 3

SLRA Table 3.6.2-2 is revised as follows:

Table 3.6.2-2 Electrical and Instrumentation and Controls - Cable and Connections - Aging Management Evaluation AMR ID Component Type Intended Function Material Environment Aging Effect Aging Management Program NUREG-2191 Item NUREG-2192 Table 1 Notes Difference

- 5314 Electrical Insulation for Electrical Cables and Connections Electrical Insulation Various Organic Polymers (e.g.,

EPR, SR, EPDM, XLPE)

Adverse Localized Environment (e.g., Temperature, Radiation, or Moisture)

Reduced Electrical Insulation Resistance Electrical Insulation for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements (B2.1.37)

VI.A.LP-33 3.6.1-008 A A, 1 Changed

- 5314 Electrical Insulation for Electrical Cables and Connections Electrical Insulation Various Organic Polymers (e.g.,

EPR, SR, EPDM, XLPE)

Adverse Localized Environment (e.g., Temperature, Radiation, or Moisture)

Reduced Electrical Insulation Resistance Electrical Insulation for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements (B2.1.37)

VI.A.LP-33 3.6.1-008 A, 1 New -

9312 Electrical Insulation for Electrical Cables and Connections Electrical Insulation Various Organic Polymers (e.g.,

EPR, SR, EPDM, XLPE)

Air - Outdoor Reduced Electrical Insulation Resistance Electrical Insulation for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements (B2.1.37)

VI.A.LP-33 3.6.1-008 G

1. None. The inspection of cable bus electrical components will be managed by the Electrical Insulation for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements (B2.1.37) program.

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ENCLOSURE 1 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT 2 SUBSEQUENT LICENSE RENEWAL APPLICATION H.B. ROBINSON SLRA SUPPLEMENT 2 ATTACHMENT 15 TRP 63

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 15 1, Attachment 15 TRP 63 - Add AMR Table and Lines for EQ Equipment (TRP 63)

Affected SLRA Section(s)/Table(s):

3.6.2.1.8 3.6.2-8 SLRA Page Numbers:

3-1065 3-1101 Description of Change:

This Supplement Topic for TRP 63 adds a new Section 3.6.2.1.8 and AMR Table (3.6.2-8) to correlate to AMP Summary Table item 3.6.1-001 for EQ equipment.

SLRA Revisions:

SLRA Section 3.6.2.1.8 is added as follows:

Section 3.6.2.1.8 ELECTRICAL EQUIPMENT SUBJECT TO 10 CFR 50.49 EQ REQUIREMENTS Materials Components in the Electrical Equipment Subject to 10 CFR 50.49 EQ Requirements are constructed of the following materials:

x Various Metallic Materials x

Various Polymeric Materials Environments Components in the Electrical Equipment Subject to 10 CFR 50.49 EQ Requirements are exposed to the following environments:

x 10 CFR 50.49 EQ Environments, or Adverse Localized Environment Aging Effects Requiring Management Components in the Electrical Equipment Subject to 10 CFR 50.49 EQ Requirements require aging management to address the following aging effects:

x Various Aging Effects Aging Management Programs The aging effects for components in the Electrical Equipment Subject to 10 CFR 50.49 EQ Requirements are managed by the following AMPs:

x Environmental Qualification (EQ) of Electrical Components

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 15 2

SLRA Table 3.6.2-8 is added as follows:

Table 3.6.2-8 Electrical and Instrumentation and Controls - Electrical Equipment Subject to 10 CFR 50.49 EQ Requirements -

Aging Management Evaluation AMR ID Component Type Intended Function Material Environment Aging Effect Aging Management Program NUREG-2191 Item NUREG-2192 Table 1 Notes New -

6252 Electrical Equipment Subject to 10 CFR 50.49 EQ Requirements Electrical Continuity Various Metallic Materials 10 CFR 50.49 EQ Environments, or Adverse Localized Environment Various Aging Effects Environmental Qualification (EQ) of Electrical Components (B3.3)

VI.B.L-05 3.6.1-001 A

New -

8296 Electrical Equipment Subject to 10 CFR 50.49 EQ Requirements Electrical Insulation Various Polymeric Materials 10 CFR 50.49 EQ Environments, or Adverse Localized Environment Various Aging Effects Environmental Qualification (EQ) of Electrical Components (B3.3)

VI.B.L-05 3.6.1-001 A

Plant Specific Notes:

None.

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ENCLOSURE 1 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT 2 SUBSEQUENT LICENSE RENEWAL APPLICATION H.B. ROBINSON SLRA SUPPLEMENT 2 ATTACHMENT 16 TRP 76

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 16 1, Attachment 16 Supplement changes to address issues related to TRP 76.

(TRP 76)

Affected SLRA Section(s)/Table(s):

2.4.21 3.5.2.2.2.6 3.5.1 3.5.2-1 3.5.2-21 A6.0-1 B2.1.31 SLRA Page Numbers:

2-201 3-914 3-915 3-916 3-917 3-918 3-919 3-921 3-941 3-970 3-1035 3-1036 A-84 B-194 Description of Change:

This supplement item makes the changes identified below to the SLRA in response to TRP 76:

x A discussion to clarify the stainless steel and carbon steel liners, specifically their locations and where they are relative to the supports is added to Section 3.5.2.2.2.6 in response to TRP 76.

x A statement that neither the carbon steel nor the stainless steel liners are included in the integrated fluence transport model is added to Section 3.5.2.2.2.6 in response to TRP

76.

x A discussion of the permanent cavity seal plate replacement in refueling outage 28, boric acid leakage history post replacement, and how it relates to the Reactor Vessel Supports is added to Section 3.5.2.2.2.6 in response to TRP 76.

x For clarification, the wording reactor vessel nozzle "pads" is updated to "weld build-up" in Section 3.5.2.2.2.6 in response to TRP 76.

x A description that there is an anchor plate embedded into the concrete and that the load is below 6 ksi is added to Section 3.5.2.2.2.6 in response to TRP 76.

x A discussion to clarify the scope for the anchor bolts being inspected per ASME Section XI, Subsection IWF, as well as alignment of the primary shield wall (PSW) and

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 16 2

embedded steel (bolts and anchor plate) to the Structures Monitoring Program is added to Section 3.5.2.2.2.6 in response to TRP 76.

x A description of the Reactor Pressure Vessel (RPV) supports components and welds being defect free after initial fabrication is added to Section 3.5.2.2.2.6 in response to TRP 76.

x A statement that there are no significant crack growth mechanisms in the RPV support system is added to Section 3.5.2.2.2.6 in response to TRP 76.

x A discussion regarding the PSW temperature (including grout below RPV supports) being below 150°F below bottom plate and the flow velocity at air gap (Reactor Vessel/PSW cavity area) of 20 ft/sec is added to Section 3.5.2.2.2.6 in response to TRP

76.

x A discussion regarding measures to ensure PSW concrete integrity to the end of the SPEO is added to Section 3.5.2.2.2.6 in response to TRP 76.

x A description stating that the RPV supports evaluation (WCAP-18939) credits LBB and eLBB while the PSW analysis does not consider LBB and eLBB, and why the PSW analysis is conservative is added to Section 3.5.2.2.2.6 in response to TRP 76.

x A discussion addressing that the grout compressive strength could be reduced by 20%

to have 80% of design concrete strength at the maximum fluence of 1.30E19 n/cm2, the sizing of the bottom plate area based on the reduced 80% of design compressive strength and margin, and the 20% statement is added to Section 3.5.2.2.2.6 in response to TRP 76.

x A statement that grout strength is conservatively assumed at 3,000 psi based off industry standards (typically grout strength exceeds that of concrete) and a reference to a relevant statement in EBASCO concrete specifications is added to Section 3.5.2.2.2.6 in response to TRP 76. Additional detail is also provided demonstrating the calculation of the values used for the grout evaluation.

x A discussion of how the uncertainty of 20% was obtained and the conservatism associated with the development of the values used in the plant specific radiation exposure evaluations, including uncertainties in fuel elevation and the factor of 2 for the concrete composition is added to Section 3.5.2.2.2.6 in response to TRP 76.

x Provided additional detail in Section 3.5.2.2.2.6 regarding the gamma radiation effects on the Primary Shield Wall concrete.

x Provided additional detail in Section 3.5.2.2.2.6 for the conservative effects of swelling due to RIVE, assuming only quartz aggregate, and acceptability due to existing airflow margins.

x A revised description of the reactor vessel support to delete "circular box section ring girder" and ensure consistency with Section 3.5.2.2.2.6 is added to Section 2.4.21.

x Added commitment #8 in SLRA Table A6.0-1 for the ASME XI, Subsection IWF program, and added enhancement #8 to the ASME XI, Subsection IWF program in SLRA Section B2.1.31 to revise the inspection frequency for the reactor pressure vessel supports.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 16 3

x SLRA Table 3.5.2-1 changes include revision of PSN #1 to remove the word "pad" and add "(in the reactor vessel cavity area)" for NRC clarification.

x SLRA Table 3.5.2-21 changes include revision to PSN #1 to add "and steel reactor vessel support assemblies", revision to create PSN #3 and attach to AMR Line ID 869 to state "Loss of preload includes loosening", revision to create PSN #4 and attach to AMR Line ID 779 to state "This line item includes the reactor pressure vessel steel shims and includes dry-film surfaces, revision to create PSN #5 and attach to AMR Line ID 868 to state "The IWF inspection of the high strength reactor pressure vessel support anchor bolts indirectly manages the embedded anchor plate", revision to create PSN #6 for further explanation of the aging effect and to change AMR Line ID 778 to align to the IWF program, and created AMR Line ID 9311 to address reduction in fracture toughness for the embedded RPV support anchor plate with plant specific note #7.

x Revised row 3.5.1-055 in SLRA Table 3.5.1 to include mention that the IWF program will be utilized to inspect all NSSS grout pads (including the RPV support grout pads).

SLRA Revisions:

SLRA Section 2.4.21 is revised as follows:

Section 2.4.21 System Description The reactor vessel has three supports located beneath each of the three cold leg nozzles (80-,

200-, and 320- degrees). Each reactor vessel inlet nozzle includes a weld buildup that was machined to fit into a support structure consists shoe that is part of a circular box section ring girder, fabricated grillage assembly connected to the primary shield wall. The reactor vessel supports consist of carbon steel the support shoes and the grillage assembly. Each grillage assembly consists of a support shoe, shims, leveling bolts, top plate, wide flange CB sections (I-beams), bottom plate, diaphragm plates, anchor bolts and associated fasteners, and anchor plates. The bottom flange reactor vessel inlet nozzle and associated weld buildup are evaluated separately as part of the girder is in continuous contact (except for openings for neutron detectors) with a non-yielding concrete foundation. reactor vessel and are not evaluated as part of the RV component support.

The Each reactor vessel has three supports located at alternate nozzles. Each support nozzle weld buildup bears on a support shoe, which is fastened to the support structure. The support shoe is a structural member that transmits the support loads to the supporting structure. Each support is designed to restrain vertical, lateral, and rotational movement of the reactor vessel, but allows for thermal growth by permitting radial sliding on bearing plates.

SLRA Section 3.5.2.2.2.6 is revised as follows:

Section 3.5.2.2.2.6 Reactor Cavity Configuration The reactor vessel (RV) is located within the reactor cavity (also known as the primary shield wall). The reactor vessel head and control rod drives extend into the fuel transfer canal.

Openings are provided in the lower part of the shield wall to provide vent area. Piping carrying high pressure reactor coolant are routed from the reactor vessel outside the reactor cavity, to three steam generator cavities, and returned through the RCPs to the reactor vessel. The steam generator cavities (or secondary shield walls) house the steam generators, reactor coolant pumps, associated piping and the pressurizer.

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The reactor cavity serves as a biological shield wall and is also designed to contain core flooding water to the level of the reactor nozzles. The reactor cavity consists of reinforced concrete surrounding the reactor vessel and extends upward from the Reactor Building floor to form the walls of the fuel transfer canal. Concrete used for the primary shield wall is a Type II cement, also known as moderate sulfate-resistant cement, which is a type of Portland cement designed to provide moderate protection against sulfate attack. Coarse aggregates used to make the cement consist of hard durable crushed rock or natural gravel. The thickness is 10 ft.

up to the height of the reactor vessel flange, flange (248.66 ft elevation), where the thickness is reduced to 6.0 ft.

The primary shield wall includes a stainless steel liner plate that extends downward from the 275 ft elevation to the 248.66 ft elevation (see Figure 3.5.2.2.2.6-1 below). From the 248.66 ft elevation down to the 237.50 ft elevation (approximate elevation of RPV support base plate),

there is bent carbon steel plate. From the elevation of the support base plate, 237.50 ft, down to the bottom of the primary shield wall there is no stainless steel or carbon steel liner plate. The inside radius of the primary shield wall at locations below the RPV supports is 7 ft 10 inches and is concrete. Neither the carbon steel nor the stainless steel liners are included in the integrated fluence transport model.

A permanent cavity seal plate made from stainless steel was installed in refueling outage 28 in the Fall of 2013 at the 248.66 ft elevation. The seal plate is welded to the stainless steel primary shield wall liner plate.

Reactor Vessel Support Configuration The vertical loadings are transmitted from the reactor vessel nozzle pads weld build-up into the concrete, through the steel shim plates, forged support shoe, top plate, I-beams, base bottom plate, anchor bolts, and the grout pad. The horizontal loadings are transmitted from the reactor vessel nozzle pads weld build-up into the concrete, through the steel shim plates, forged support shoe, leveling bolts, top plate, fillet welds on the top of the I-beams, through the I-beams, fillet welds on the bottom of the I-beams, base bottom plate, and the anchor bolts.

Each grillage assembly consists of a support shoe, shims, leveling bolts, top plate, wide flange CB sections (I-beams), bottom plate, diaphragm plates, anchor bolts and associated fasteners, and anchor plates. A 1 3/8-inch grout pad below the grillage assembly bottom plates is used to interface with the top of the concrete primary shield wall. wall; this grout pad provides no anchorage function for the grillage assembly. Anchor bolts extend from each grillage assembly to the approximate core midplane, where they are connected using anchor plates cast in concrete within the primary shield wall. Materials of construction include high strength low alloy steel for the following items: support shoes are A 508, Class 2, leveling The anchor bolts are ASTM A434 Class BD, I-beams are ASTM A441, fastened to the top plate using a washer and bottom plates two nuts (top being a jamb nut), and diaphragm plates are A242, fastened to the anchor bolts are A490, plate using washers and two nuts. Following placement and curing of the concrete and grout below the base plate, the anchor bolt nuts are A490, were tightened to a snug fit and anchor bolt washers are A325. The shims that sit within the support shoes are A441 Timken Graph-Air Tool Steel. Anchor plates are made from A-36 carbon steel. were not preloaded.

Anchor bolt embedment length in concrete is approximately 6 ft where the bolt group for each assembly is connected to an anchor plate per assembly. Tensile stresses in the embedded anchor plates are determined to be less than 6 ksi considering normal and accident conditions and as such may be excluded from fracture toughness considerations consistent with ASME Section III, NF-2311(b)(7). However, reduction of fracture toughness (potentially leading to

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cracking) of the anchor plates is indirectly managed by the ASME Section XI, IWF inspections of the grillage assembly and is conservatively identified as an applicable aging effect as reported in Table 3.5.2-21.

Materials of construction include high strength low alloy steel for the following items: support shoes are A 508, Class 2, leveling bolts are ASTM A434 Class BD, I-beams are ASTM A441, top and bottom plates and diaphragm plates are A242, anchor bolts are A490, anchor bolt nuts are A490, and anchor bolt washers are A325. The shims that sit within the support shoes are A441 Timken Graph-Air Tool Steel. Anchor plates are made from A-36 carbon steel.

Fabrication of each grillage assembly was in accordance with EBASCO specification WELC-5379-S-15, which invoked the AISC Code (latest revision as of March 7, 1968) unless otherwise specified in WELC-5379-S-15 or on design drawings. AISC, Section 1.26, Inspection, addresses the inspection requirements for the grillage assemblies. Inspection findings from the manufacturer, Pittsburg Bridge & Irion Works, dated July 12, 1968 are summarized below.

x Ultrasonic testing of the reactor vessel support weldments and adjacent base metal was performed by Pittsburg Testing Laboratories.

x No defects were detected in the steel plates x

Butt welds (80- and 320- degree assemblies only; 200-degree location does not contain butt welds) were rejected due to lack of penetration. These were repaired by adding a 1 1/2 inch by 1/4 inch flat bar cover piece to the top plate with full fillet weld all around to compensate for lack of penetration. Penetrant testing of cover pass was performed.

x Fillet welds-Proof of weld. Soundness must be demonstrated by means other than ultrasonic testing. 10% of fillet weld lengths were removed by grinding or chipping to determine the degree of penetration. If root penetration is sound, reweld the removed fillet. If inadequate, then the fillet weld was completely removed and rewelded.

The quality control measures taken by the manufacturer included inspection and repair as summarized above. These quality control measures ensure that the RPV support assemblies installed at Robinson were free of defects.

Each support assembly receives approximately 3,000 CFM (velocities of approximately 13 ft/sec to 18 ft/sec in the grillage assembly chambers between the I-Beams) of air flow from the reactor cavity to ensure that the concrete and grout below the bottom plate of the support remains at or below 150°F. Air flow is from Diaphragm plates are placed after the reactor cavity annulus between the reactor vessel insulation first row of anchor bolts and the primary shield wall, through each support assembly just below before the RV nozzles, last row of anchor bolts to facilitate heat transfer from the HVAC ductwork that extends anchorage system to the air flow through the primary shield wall, to grillage assembly; this effectively ensures that the suction side temperature of HVAC fans HVE-6A/6B (6B is a standby fan) and discharged to the secondary cavity. HVE-6A anchor bolts, top plate and -6B fans associated fasteners, and bottom plate and grout are designated as Quality Class B or augmented quality at RNP; augmented quality exceeds those requirements for Non-Safety Related Items, but do not meet the criteria requirements for Safety-Related Items. In the schematic below, reasonably close to ambient air flow direction is from temperature downstream of the front first row of anchor bolts.

The estimated temperature increase across the grillage assembly to is 2.6 °F. The temperature of the back anchorage system, exclusion of the assembly. ASME Section XI, Subsection IWF,

VT-3 examinations are conducted by extending a remote camera through use of dissimilar materials that make up the ductwork to joint above the back top plate, and slight tensile loads

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during normal operation in the anchor bolts reduce the likelihood of self -loosening of the assembly. joint over time.

The radial temperature distribution within the 10 ft thick primary shield wall adjacent to the core at full power is reported in the Robinson UFSAR Figure 3.8.3-1 and UFSAR Figure 3.8.3-2, which demonstrate that peak concrete temperature within the primary shield wall remains below 150°F (Case I at 140.3°F). The UFSAR analysis includes gamma heating of the primary shield wall and assumes 3-inch-thick insulation, a 2.5 inch air gap between the insulation and the inner diameter of the primary shield wall, and a volumetric flowrate in the air gap of 12,000 CFM (velocity of approximately 20 ft/sec in the 2.5 inch air gap) from concrete shield cooling fans.

The fans are designated as Quality Class B or augmented quality at RNP. Assessment of gamma heating continues to align with existing conclusions in the UFSAR throughout SLR.

Jurisdictional Boundaries Aging Management Programs for Inspections RPV Supports and Primary Shield Wall With regard to the RVP RPV support assembly and primary shield wall described above, the following jurisdictional boundaries aging management programs and associated inspections apply relative to inspections: for SLR:

x Grillage assembly including grout below the bottom plate grout and all support items above the grout: grout including the applicable RPV support items, the A-490 anchor bolts, and A-36 anchor plate cast in the PSW concrete reported in Table 3.5.1 as reflected in Table 3.5.2-21: ASME Section XI, Subsection IWF, Examination Category F-A F-A. Table 3.5.2-1 conservatively includes self-loosening of the A-490 jamb nut and reduction in fracture toughness of the embedded A-36 anchor plates as applicable aging effects that are managed by IWF Examination Category F-A.

x Primary shield wall including the A-490 anchor bolts Grillage assembly ferritic items and A-36 anchor boric acid wastage. The primary source of leakage of borated water to the RPV support assemblies during refueling outages was eliminated through the installation of the permanent cavity seal plate cast in concrete: RNP Structures Monitoring Program refueling outage 28. The only potential leakage path during refueling is through the Reactor Cavity Seal Access Ports (Sand Plugs) should improper reinstallation of the sand plugs occur. This is addressed through the Boric Acid Corrosion Program, B2.1.4.

Primary Shield Wall x

Primary shield wall below the grout pads including concrete and reinforcement: RNP Structures Monitoring Program.

x Leakage of borated water on the inner diameter surfaces of the primary shield wall is possible during outages with leakage through the sand plugs if installed improperly.

Leakage on the outer diameter of the primary shield wall from leakage through various fittings that contain reactor coolant system fluid (e.g., incore seal table, and RCP seal injection) is possible during various modes of operation. Technical Specifications for reactor coolant system leakage limits, ASME Section XI (B2.1.1), Examination Category B-P visual inspections, Boric Acid Corrosion Program (B2.1.4) which evaluates identified boric acid deposits, and the Structures Monitoring Program (B2.1.34) collectively manage the effects of boric acid deposits on concrete surfaces of the primary shield wall. Additional activities/ features that ensure concrete health to the end of the SPEO include ASME ISI VT-2 inspection of the reactor vessel cavity area during start-up of the plant and cleaning as required, cavity design such that leakage from seal table is collected in the sump (below PSW), dry crystals, which have low impact outage to

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outage, are cleaned during refueling outages and additional monitoring (for example, use of active cameras if needed to mitigate/manage risk).

Analytical Methodology-Fluence and Gamma Dose-Primary Shield Wall and RV Supports To determine the potential impact of neutron and gamma radiation to the reactor vessel supports and the primary shield wall, Duke Energy utilized an a single analytical model developed by Westinghouse to estimate fluence and gamma dose analysis at the inside surface of the reactor cavity wall, RV support grillage assembly, and reactor vessel support embedment to support operation to 80 years. Discrete ordinates transport calculations were performed on a fuel-cycle-specific basis to determine the neutron and gamma ray environment within the reactor and primary shield wall geometry. The specific methods applied are consistent with those described in WCAP-18124-NP-A, Rev. 0, and WCAP-18124-NP-A, Rev. 0 Supplement 1-NP-A, Rev.0. Transport calculations were carried out using the three-dimensional RAPTOR-M3G discrete ordinates code and the BUGLE-96 cross-section library. The BUGLE-96 library provides a coupled 47-neutron-, 20-gammaray-group cross-section data set produced specifically for light water reactor applications. Anisotropic scattering was treated with a P3 Legendre expansion and the angular discretization was modeled with an S16 order of angular quadrature. Energy-and space-dependent core power distributions as well as system operating temperatures were treated on a fuel-cycle-specific basis.

The model geometry used in the transport calculations is based on that described in WCAP-18751-NP, Analysis of Ex-Vessel Neutron Dosimetry from H.B H.B. Robinson Unit 2 - Cycle 32 with expansion of the that model geometry to facilitate explicit modeling of the limiting (highest fluence) inlet nozzle and outlet nozzle and the limiting RV support and surrounding concrete. This updated transport model was used for all projections for subsequent license renewal for Robinson. Iron atom displacements (dpa) and neutron fluence results at 70 EFPY for the RV support elements listed above are made using projections with 10% positive bias on relative power of peripheral and re-entrant corner fuel assemblies and are reported below.

The projected maximum fast neutron fluence (E > 0.1 MeV) at 70 EFPY at the inside surface of the primary shield wall is 3.52 4.22 E 19 n/cm 2 and the maximum gamma dose is 1.05E 18 1.26E 08 gGy, both calculated using a 10% positive bias on relative power of peripheral and re-entrant corner fuel assemblies using the model described above. above and an upward of 20% for uncertainty. Both fluence and gamma 70 EFPY dose to the primary shield wall exceed the damage thresholds reported in NUREG-2192 (Revision 1) at 1.0E 19 n/cm 2 (E> 0.1 MeV) and 1.0E 8 gGy, respectively. The region of exceedance extends from the ID of the primary shield wall approximately 3.74 inches into the 120-inch-thick primary shield wall at selected azimuthal locations.

Uncertainty Analytical The estimated uncertainty analyses associated with the neutron fluence and gamma dose results radiation exposures at the inner surface of the primary shield wall and the dpa projections for the RV support items were not performed for Robinson. Therefore, a conservative estimate of the uncertainty associated with these results PSW was established using an existing reactor pressure vessel (RPV) the RPV extended beltline uncertainty analysis consistent with what was reported for the Point Beach Nuclear Plant Units 1 and 2, SLRA, RAIS RAI 3.5.2.2.2.6-1 and RAI 3.5.2.2.2.7-1 (ADAMS ML21189A173). NRC acceptance described in WCAP-18124-NP-A, Revision 0, Supplement 1-NP-A. The level of this methodology is reported detail in the Final Safety Evaluation model used for the plant-specific integrated model of the Point Beach Nuclear SLRA, Sections 3.5.2.2.2.6 and 3.5.2.2.2.7 (ADAMS ML22140A127). The fluence and gamma results reported above were adjusted upwards to account reactor (and

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cavity) geometry for uncertainty (20% increase) for evaluation Robinson is commensurate with that of the primary shield wall and model used for the fracture extended beltline uncertainty analysis described in Table 3-3 and Section 6 of WCAP-18124-NP-A, Revision 0, Supplement 1-NP-A. For example, the RV supports reported below. mesh sizes, treatment of anisotropic scattering, angular quadrature, modeling of internals structures, etc., are similar.

The RPV extended beltline uncertainty analysis in WCAP-18124-NP-A, Revision 0, Supplement 1-NP-A quantified the analytical uncertainty associated with calculated fast neutron (E > 1.0 MeV) fluence rates at the RPV inner and outer surfaces at various elevations above and below the active fuel. As part of this analysis, numerous parameters that were identified as having a potentially significant contribution to the core neutron source, reactor geometry, coolant temperature, discretization, and modeling approximation uncertainties at the RPV inner and outer surfaces were evaluated. Each parameter identified was evaluated on an individual basis by determining the maximum relative change in the base-case fluence rate that occurred as the magnitude of that parameter was varied over a bounding range of values. The net analytical uncertainty associated with a given RPV location was then determined by taking the root sum of squares of the individual parameter uncertainty values determined at that location. Given the parameters considered, the magnitudes of the parameter variations evaluated, and the relative proximity of the RPV outer surface to the PSW, the extended beltline uncertainty analysis results for the RPV outer surface were judged to provide a reasonable basis for estimating the analytical uncertainty associated with the radiation exposures at the PSW inner surface.

The maximum neutron fluence and gamma dose projections at the inner surface of the PSW occur at elevations that are near the core midplane. However, since the extended beltline uncertainty analysis was, by design, focused on the RPV extended beltline region only, it did not consider axial elevations near the core midplane; the elevations nearest the midplane considered were 30 cm above the top and 30 cm below the bottom of the active fuel. Therefore, the extended beltline uncertainty analysis results determined at the RPV outer surface, 30 cm above the top of the active fuel were used as the starting point for estimating the uncertainty associated with the PSW neutron and gamma exposures. This is conservative because analytical uncertainties increase with axial distance above the top of the active fuel.

In addition to using this bounding RPV location as a starting point, the concrete composition parameter uncertainty value determined at this location was increased by a factor of 2. Note that in the RPV extended beltline uncertainty analysis, the concrete composition parameter uncertainty value at this elevation was established by evaluating the change in the base-case fast neutron (E > 1.0 MeV) fluence rates along the RPV outer surface, 30 cm above the top of the active fuel as the PSW concrete composition, including the hydrogen/water content thereof, was varied. To account for the range of allowable water to cement ratio in the Robinson concrete specification, the concrete composition that resulted in the maximum change in the base-case fast neutron (E > 1.0 MeV) fluence rates, on a relative basis and from any of the wetter (i.e., higher water content) or dryer (i.e., lower water content) concrete compositions evaluated, was used to establish the magnitude of this uncertainty value. For estimating the analytical uncertainty associated with the PSW radiation exposures, the concrete composition uncertainty value was increased by a factor of 2 because it was associated with the one parameter evaluated in the RPV extended beltline analysis whose uncertainty was judged to be potentially impacted in a non-negligible manner if a detailed uncertainty analysis for the PSW were performed. Note that the standard concrete composition from the BUGLE-96 documentation was used for the PSW in both the extended beltline analytical uncertainty analysis base-case calculations and the plant-specific radiation transport calculations.

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Following this process, the analytical uncertainty associated with the fast neutron (E > 1.0 MeV) fluence and gamma dose results at the inner surface of the PSW was conservatively estimated to be 20%. It is worth noting that:

x the estimated 20% value is based on the extended beltline uncertainty analysis results determined at the RPV outer surface, 30 cm above the top of the active fuel, and x

analytical uncertainties at the RPV outer surface increase with distance from the core midplane elevation.

Therefore, the estimated 20% uncertainty is:

x representative for fast neutron (E > 1.0 MeV) fluence and gamma dose results determined at the PSW inner surface and axial elevations within a foot of the top and bottom of the active fuel and x

bounding for fast neutron (E > 1.0 MeV) fluence and gamma dose results determined at the PSW inner surface and axial elevations near the core midplane.

The estimated 20% uncertainty does not explicitly account for neutrons with energies between 1.0 MeV and 0.1 MeV. However, the PSW exposures determined for the SLRA are maximum values that occur at elevations near the core midplane, where the analytical uncertainty for fast neutron (E > 1.0 MeV) fluence at the PSW inner surface is significantly less than 20%. For example, Section 4.5 of WCAP-18124-NP-A, Revision 0, documents that the analytical uncertainty for fast neutron (E > 1.0 MeV) fluence in the reactor cavity (i.e., at the RPV outer surface) at the core midplane elevation is approximately 12%. While the uncertainty associated with fast neutron (E > 0.1 MeV) fluence at the PSW inner surface and elevations near the core midplane is greater than 12%, it would not be expected to be significantly different, or greater, than the estimated uncertainty of 20% assigned to the PSW maximum exposures for Robinson.

The estimated uncertainty associated with the RPV support structure exposures was established using the same RPV extended beltline uncertainty analysis that was used for the PSW. Again, the level of detail in the model used for the plant-specific model of the reactor (and cavity) geometry for Robinson is commensurate with that of the model used for the extended beltline uncertainty analysis.

The maximum neutron fluence and iron atom displacement projections used for the RPV support structure components evaluated for the SLRA occur at elevations that are less than 55 cm above the top of the active fuel. Therefore, the extended beltline uncertainty analysis results determined at the RPV outer surface and elevations of 60 cm and 30 cm above the top of the active fuel were used as the starting point for estimating the uncertainty associated with the RPV support structure exposures. This is conservative because analytical uncertainties increase with axial distance above the top of the active fuel. In addition to using these RPV locations as a starting point, the concrete composition uncertainty value for each location was increased by a factor of 2. These uncertainty values were increased because they were associated with the one parameter evaluated in the RPV extended beltline analysis whose uncertainty was judged to be potentially impacted in a non-negligible manner if a detailed uncertainty analysis for the primary shield wall concrete were performed. Note that the standard concrete composition from the BUGLE-96 cross-section library was used for both the extended beltline analytical uncertainty analysis base-case calculations and the plant-specific radiation transport calculations.

Following this process, and linearly interpolating between the resulting uncertainties at 60 cm and 30 cm above the top of the active fuel, the analytical uncertainty associated with the fast

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 16 10 neutron (E > 1.0 MeV) fluence and iron atom displacement results for the RPV support structure 55 cm above the top of the active fuel was estimated to be 20%. This uncertainty was conservatively applied to the calculated exposure of all the exposed subcomponents of the RPV support structure.

Westinghouse has not performed an analytical uncertainty analysis associated with neutron exposures at various depths into the PSW concrete. Since the maximum neutron exposures of the RPV support anchor bolts occur at elevations near the core midplane and since analytical uncertainties increase with distance away from the top of the active fuel, the estimated 20%

uncertainty determined at 55 cm above the top of the active fuel was applied to the anchor bolt exposures as well.

The region of fast neutron (E > 0.1 MeV) fluence exceedance for the grout under the RPV support base plate was not explicitly determined. Instead, the region of maximum fast neutron (E > 0.1 MeV) fluence exceedance for the PSW, 3.74 inches, was used for the grout. This is conservative since the 3.74 inch depth was determined near the core midplane elevation, where fast neutron (E > 0.1 MeV) fluence exposures are significantly (i.e., more than 2x) greater than the maximum fast neutron (E > 0.1 MeV) fluence exposure for the grout under the RPV support baseplate of approximately:

x 1.03E19 n/cm2 for the case with no bias on the peripheral and re-entrant corner assembly relative powers and no adjustment for analytical uncertainty x

1.08E19 n/cm2 for the case with a positive 10% bias on the peripheral and re-entrant corner assembly relative powers and no adjustment for analytical uncertainty x

1.3E19 n/cm2 for the case with a positive 10% bias on the peripheral and re-entrant corner assembly relative powers and adjusted for an estimated 20% uncertainty Note that the maximum fast neutron (E > 0.1 MeV) fluence exposure for the grout, 1.3E19 n/cm2 for the case with a positive 10% bias on the peripheral and re-entrant corner assembly relative powers and adjusted for an estimated 20% uncertainty, was determined at the PSW inner surface, the 80°azimuth (i.e., the azimuthal angle corresponding to the centerline of the RPV support and closest point of the grout to the outer surface of the RPV), and the axial elevation corresponding to the bottom of the grout (or top of the PSW concrete on which the grout is located). This location was used to ensure that the limiting exposure for the grout directly under the RPV support was determined. That is, while the maximum fast neutron (E > 0.1 MeV) fluence exposure for the grout under the RPV support base plate was determined at the inner surface of the PSW, the base plate itself is set back from the inner surface of the PSW by at least 5/8 of an inch. Therefore, the fast neutron (E > 0.1 MeV) fluence exposure for the grout under the RPV support base plate is less than 1.3E19 n/cm2 since the base plate is set back from the inner surface of the PSW by at least 5/8 of an inch.

Calculations show that all NUREG-2192 gamma dose threshold exceedances of the PSW concrete at 70 EFPY occur at axial elevations between the top and bottom of the active fuel.

Since the limiting (i.e., minimum) axial elevation for the grout under the RPV support baseplate is above the top of the active fuel, the gamma dose exposures for the grout do not exceed 1.0E08 Gy at 70 EFPY.

The fluence and gamma results reported in Table 3.5.2.2.2.6-1 were adjusted upwards to account for uncertainty (20% increase) for the fracture analysis of the RV supports reported below. The fluence and gamma results for the grout below the base plate and concrete primary shield wall structural capacity evaluation are reported below.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 16 11 Evaluation of Primary Shield Wall Concrete and Grout for Irradiation As reported above, approximately 3.74 inches (rounded up to 3.75 inches) of the 120-inch primary shield wall exceeds the neutron and gamma dose threshold at 70 EFPY. The maximum gamma dose with 10% positive bias and adjusted with analytical uncertainty is found to exceed the guidance threshold (1.00E 08 Gy) at the inner surface of the PSW from Azimuthal Angle 0 degrees to 15 degrees and 77.5 degrees to 90 degrees and from Elevation -68.58 cm to Elevation 114.30 cm on each Quadrant of the PSW. The maximum gamma dose exceedance extends only to a depth into the concrete of less than 7.74 inches for a smaller Azimuthal Angle range and elevation band (Azimuthal Angle 0 degrees to 10 degrees and 82.5 degrees to 90 degrees; Elevation -38.10 cm to Elevation 91.44 cm). The approach for calculating assessing the impact of irradiated concrete relative to the original design analysis is to reduce the effective structural capacity of concrete impacted by irradiation based on 70 EFPY fluence and gamma dose maps, calculate new stresses, and compare those new stresses to allowable stresses reported in the original design analysis by EBASCO. The capacity of the primary shield wall is re-calculated considering the first 3.75 inches of concrete at the inside radius to have zero strength (accounting for neutron fluence and Radiation Induced Void Expansion-RIVE-effects).

Regarding the original EBASCO primary shield wall design report, the RPV supports analysis utilizes various loading considerations, as documented in the design report. Vertical and horizontal load contributions due to design basis earthquake include the weight of the deck, water, cavity wall, primary shield wall, and RPV supports. Inside and outside accident pressures of the PSW were considered, which do not include consideration of either leak-before break or extended leak-before break loads. The structural load capacity evaluation reported below is very conservative as it does not consider reduced accident loads due to either LBB or eLBB.

The capacity of the primary shield wall is re-calculated considering the first 3.75 inches of concrete at the inside radius to have zero strength (accounting for neutron fluence and Radiation Induced Void Expansion-RIVE-effects). In regions of the PSW where gamma dose exceeds the damage threshold, the potential exists for reduction of compressive strength. The reduction in concrete compressive strength for a given gamma dose is conservatively determined from Figure 3-4 of EPRI Technical Report 3002018400, Revision 1. The lower bound curve is used to find compressive strength ratio for the maximum gamma dose of 1.26x108 Gy = 1.26x1010 Rad, which is approximately equal to 0.96. To account for the effects of gamma dose, the region of gamma dose exceedance (interior 3.75 inches to 7.75 inches of the PSW concrete) is assumed to have 96 percent of its nominal compressive strength.

The impact of neutron and gamma exceedance on rebar relative to the original primary shield wall design report is also evaluated. A small portion of the horizontal hoop reinforcing steel rebar (approximately 0.24) is in the maximum regions of the neutron fluence exceedance. The reinforcing steel rebar in the hoop direction located within this damaged region is very limited and the loads for the reinforcing steel can be developed on both sides of the region that is affected by the exceedance. In addition, per Section 4.3.4, ACI 349.3R18, the neutron irradiation of the rebar will result in an increase in the yield strength of the carbon steel material.

This increase in yield strength (i.e. load carrying capacity) has conservatively not been credited in the evaluations herein. It should be noted, the maximum end of SPEO neutron exposures for concrete (3.52E19 n/cm2, E> 0.1 MeV, without uncertainty and 4.22E19 n/cm2, E> 0.1 MeV, with an estimated 20% uncertainty) will be less than the threshold value included in ACI 349.3R18 (1.00E20 n/cm2, E> 0.1MeV), and the rebar will not experience reduced ductility. Therefore, the ability of the rebar in the hoop direction to carry load will not be affected by the degraded concrete.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 16 12 The primary vertical and shear reinforcement, which is considered in the analysis of record, is located outside the zones of neutron threshold exceedances Therefore, there is no reduction in the ability of the primary reinforcement to carry load, and no reduction in PSW capacity as a result of the rebar capacity reduction.

This change Essentially, the capacity of the PSW is re-calculated considering the first 3.75 inches of concrete at the inside radius to have zero strength (accounting for neutron fluence, Gamma dose and RIVE effects), and considering the remaining 4 just beyond the zero strength zone to have only 96 percent of its nominal compressive strength (accounting for gamma effects). Then the capacity is recalculated based on remaining unimpacted concrete.

These two changes effectively reduces reduce the wall thickness (depth) by 3.75 inches, and wall compressive strength, resulting in a modest decreased capacity. A capacity analysis The effect of these material property changes on the aged wall section PSW structural capacity is performed quantified and compared to the original design current analysis of record capacity, to obtain the Updated SLR Stress / Code Stress Ratio in the following Table. Note that the original design loads were conservatively considered and reduced loads due to extended leak-before-break were not considered. All stress ratios remain acceptable for SLR considering the reduced capacity of the primary shield wall.

Grout strength is conservatively assumed as at 3,000 psi based off industry standards (typically grout strength exceeds that of concrete) and expectation of cementitious materials, which is the same as the minimum concrete design strength. compressive/design strength of the primary shield wall concrete in accordance with EBASCO Specification 14-65 for Class B concrete (per G-190370). Compressive strength of grout generally increases with age due to the process of hydration, where cement in the grout reacts with water, forming a hardened matrix that binds the aggregate. According to EPRI 3002018400, Figure 3-1, 3-1 conservatively entering the value on the lower bound curve, at the maximum fluence of 1.30E+19 1.30E 19 n/cm 2, the concrete grout compressive strength could be reduced by 2% 20% to have 98% 80% of design concrete strength. The 2% 20% compressive strength decrease is very localized.

According to the analysis of record, required baseplate sizes exist for normal and accident loads, considering a 2% 20% reduction in compressive strength, the required baseplate sizes increase, but are still significantly less than the actual baseplate area. area per AISC Section 1.5.5 Masonry Bearing. Therefore, there is no impact to the required baseplate area due to the 2% 20% reduction in compressive strength.

The maximum compression stresses on grout are located at the corners of Reactor Vessel Support baseplates. Utilizing liner interpolation, the compression stresses at core-facing mid edge of Reactor Vessel Support baseplates, located at 5/8 from the inside face of the Primary Shield Wall, is approximately 75% of the maximum compression stresses at the corners of the base plates. Therefore, stresses at the core-facing mid edge location are less than the reduced 98% 80% of design compressive strength and is acceptable. Because there is no neutron fluence affect at corners of RV support base plates, the reduced 98% 80% designed concrete grout compressive strength at core-facing mid edge of Reactor Vessel Support base plates has no detrimental effects on the design.

Table 3.5.2.2.2.6-2 Primary Shield Wall Updated SLR Stress/ Code Stress Ratio Vert.

Conc.

OF 1 Vert.

Conc.

IF 1 Horiz.

Conc.

OF 1 Horiz. Conc.

IF 1 Horiz.

Reinforcing Concrete Shear I

I I I I I I

I

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 16 13 Subsequent License Renewal (SLR)

Updated SLR Stress/ Code Stress Ratio

(<1.00 OK) 0.179 0.128 0.133 0.58 1.67 1.71 2 reinforcing take tension 0.94 0.33 0.34 Notes:

1. OF = Outer Face, IF = Inner Face.

2. The AOR [1] indicates that this is less than allowable tensile stress. Reinforcing rebar will take tension.

Note: The stress interaction ratios were determined assuming loads from a main coolant break.

H.B. Robinson Unit 2 was licensed for Leak Before Break and submitted the extended Leak Before Break reports to the NRC for review and approval of the Pressurizer surge line, Accumulator, and Residual Heat Romal Removal piping so the loads will be further reduced.

The margin will be increased by considering Leak Before Break or extended Leak Before Break loads.

When considering RIVE of the primary shield wall concrete, an approximate 4% localized volumetric swelling within 3.75 inches is estimated based on EPRI TR 30020117 at a fluence of 3.52E 19 n/cm 2. 3002018400. The 2.5 inch air gap between the outside Robinson aggregate content of the insulation primary shield wall may contain some quartzite, and in accordance with EPRI TR 3002018400, Table 3-1, a maximum 17.8% volumetric expansion is possible, depending on the inner diameter quartz content of the shield wall is estimate to aggregate.

Assuming 17.8% volumetric swelling within the 3.75 inch exceedance zone, the 2.5 inch air gap may be reduced by approximately 0.15 as much as 0.5 inches. This However, the actual air flow in the reactor cavity supplied by the fan is considerably higher (> 70%) than the 12,000 CFM (approximately 20 ft/sec) assumed in the original UFSAR analysis. As such, it is estimated that a maximum postulated 0.5 inch reduction in the air gap will have a negligible effect no impact on the 12,000 CFM air flow supplied by temperature profile and peak PSW temperature reported in the fan. Robinson UFSAR, Figure 3.8.3-1, with a maximum temperature of 140.3 °F.

Fracture Analysis of RV Supports The goal of the fracture mechanics evaluation is to demonstrate that brittle fracture is not a concern for the RV supports made from structural steel at H.B. Robinson Unit 2 based on 80 years (70 EFPY) of neutron embrittlement. There are no significant crack growth mechanisms in the RPV support system. Linear elastic fracture mechanics (LEFM) was used as a conservative methodology to evaluate the structural integrity of the supports. The LEFM methodology is illustrated in a flow chart format based on the guidance provided (Figure 4-1) in NUREG-1509 for a fracture mechanics approach to account for radiation effects on RPV support steels. In accordance with NUREG-1509, Section 4, the items analyzed represent locations with high stresses over 6 ksi and/or are near areas subjected to high neutron irradiation. As reported above, tensile stresses in the embedded anchor plates are determined to be less than 6 ksi considering normal and accident conditions and as such may be excluded from fracture toughness considerations consistent with ASME Section III, NF-2311(b)(7). However, reduction of fracture toughness of the anchor plates is indirectly managed by the ASME Section XI, IWF inspections of the grillage assembly. Therefore, a LEFM fracture mechanics evaluation is completed for the support shoes, top plates, bottom plates, diaphragm plates, I-beams, leveling bolts, and anchor bolts. The LEFM methodology is briefly described in the following paragraphs.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 16 14 The LEFM evaluation is completed by calculating a stress intensity factor and comparing it to a fracture toughness value for each item reported above. The limiting item for the fracture mechanics analysis is based on a combination of geometry, operating condition, stress, material property, and neutron embrittlement. H.B. Robinson Unit 2 support configurations are provided in Figures 3.5.2.2.2.6-1 and 3.5.2.2.2.6-2. The H.B. Robinson Unit 2 specific loading conditions (i.e., normal, upset, normal and accident based on extended leak before break) are considered.

Consideration of all applicable loading conditions, such as deadweight, seismic, loss-of-coolant accident for the pressurizer spray line and CVCS line breaks, welding residual stresses, and thermal stresses are accounted for in the analysis.

The loading condition definitions considered for the LEFM evaluation are consistent with the EBASCO original design report of the RPV supports, which include the following load definitions and cases.

x Normal Loads: II.A.1-normal operation weight, II.A.2-individual support loads due to weight plus thermal, II.A.3-individual support loads due to seismic acceleration and reactions, and II.A.4-combined normal loadsweight + thermal +seismic acceleration and reactions x

Accident Loads: II.B,1-loss of coolant pipe break case I, II.B.2-loss of coolant pipe break case V, II.B.3-weight + thermal + loss of coolant case I, II.B-4-weight+thermal+loss of coolant case V The LEFM evaluation included similar load definitions (i.e., only the maximum normal and maximum accident are reported below) as the original EBASCO original design report with updated loss of coolant accident loads considering LBB and eLBB. The loading combinations utilized in the original design report by EBASCO and the LEFM analysis are generally consistent with UFSAR Table 3.9.3-1.

The fracture toughness for the RPV support items are based on the 95% lower bound KJc Master Curve or a material-specific fracture toughness when additional margin was needed.

needed and is fully described in WCAP-18939P/NP, Revision 1 (ADAMS Accession Number ML25091A301). The minimum fracture toughness from the KJc Master Curve of 22.9 ksi¥in is used for the bottom plate and leveling bolts. The use of the minimum lower bound fracture toughness value represents an infinite amount of neutron embrittlement on the RPV structural steel supports. Material-specific fracture toughness for the support shoe, top plate, diaphragm plates, I-beams, and anchor bolts are calculated using the KJc Master Curve to provide additional margin in the fracture mechanics assessment for these items.

For the top plate, diaphragm plates, and I-beams, margins were also determined for fracture toughness values based on use of the KIR curve from WRC-175. Fracture toughness for the top plate is reduced from 38.0 ksi ¥in to 32.8 ksi¥in and fracture toughness for the diaphragm plates and I-beams reduced from 30.8 ksi ¥in to 29.3 ksi ¥in. Margins for the top plate, diaphragm plates and I-beams are reduced slightly but all well above 1.0.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 16 15 SLRA Table 3.5.1 is revised as follows:

Table 3.5.1 Summary of Aging Management Programs for Containments, Structures, and Component Supports Evaluated in Chapter II and III of the GALL-SLR Report Item Number Component Aging Effect/Mechanism Aging Management Program Further Evaluation Recommended Discussion Difference -

3.5.1-055 Building concrete at locations of expansion and grouted anchors; grout pads for support base plates Reduction in concrete anchor capacity due to local concrete degradation/service-induced cracking or other concrete aging mechanisms AMP XI.S6, "Structures Monitoring" No Consistent with NUREG-2191.

Note that the ASME Section XI, Subsection IWF (B2.1.31) program is utilized for inspection of NSSS grout pads (including the reactor pressure vessel support grout pad)

Changed -

3.5.1-055 Building concrete at locations of expansion and grouted anchors; grout pads for support base plates Reduction in concrete anchor capacity due to local concrete degradation/service-induced cracking or other concrete aging mechanisms AMP XI.S6, "Structures Monitoring" No Consistent with NUREG-2191.

Note that the ASME Section XI, Subsection IWF (B2.1.31) program is utilized for inspection of NSSS grout pads (including the reactor pressure vessel support grout pad)

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 16 16 SLRA Table 3.5.2-1 is revised as follows:

Plant Specific Notes:

1. Concrete Elements include beams, columns, walls, walls (in the reactor vessel air cavity area), slabs, curbs, foundations and pads foundations within the interior or above-grade exterior of the Reactor Building.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 16 17 SLRA Table 3.5.2-21 is revised as follows:

Table 3.5.2-21 Containments, Structures, and Component Supports - NSSS Supports - Aging Management Evaluation AMR ID Component Type Intended Function Material Environment Aging Effect Aging Management Program NUREG-2191 Item NUREG-2192 Table 1 Notes Difference

- 778 Grout Structural Support Grout Air - Indoor Uncontrolled (External)

Reduction in Concrete Anchor Capacity Structures Monitoring (B2.1.34)

ASME Section XI, Subsection IWF (B2.1.31)

III.B1.1.TP-42 3.5.1-055 A E,6 Changed

- 778 Grout Structural Support Grout Air - Indoor Uncontrolled (External)

Reduction in Concrete Anchor Capacity ASME Section XI, Subsection IWF (B2.1.31)

III.B1.1.TP-42 3.5.1-055 E,6 Difference

- 868 High-Strength Bolting Structural Support Steel Air (External)

Cracking ASME Section XI, Subsection IWF (B2.1.31)

III.B1.1.TP-41 3.5.1-068 A A,5 Changed

- 868 High-Strength Bolting Structural Support Steel Air (External)

Cracking ASME Section XI, Subsection IWF (B2.1.31)

III.B1.1.TP-41 3.5.1-068 A,5 Difference

- 869 High-Strength Bolting Structural Support Steel Air (External)

Loss of Preload ASME Section XI, Subsection IWF (B2.1.31)

III.B1.1.TP-229 3.5.1-087 A A,3 Changed

- 869 High-Strength Bolting Structural Support Steel Air (External)

Loss of Preload ASME Section XI, Subsection IWF (B2.1.31)

III.B1.1.TP-229 3.5.1-087 A,3 Difference

- 779 Sliding Surfaces Structural Support Lubrite; Fluorogold; Lubrofluor Air - Indoor Uncontrolled (External)

Loss of Mechanical Function ASME Section XI, Subsection IWF (B2.1.31)

III.B1.1.TP-45 3.5.1-075 A A,4 Changed

- 779 Sliding Surfaces Structural Support Lubrite; Fluorogold; Lubrofluor Air - Indoor Uncontrolled (External)

Loss of Mechanical Function ASME Section XI, Subsection IWF (B2.1.31)

III.B1.1.TP-45 3.5.1-075 A,4 New -

9311 Steel Elements Structural Support Steel Concrete (External)

Reduction in Fracture Toughness; Loss of Intended Function ASME Section XI, Subsection IWF (B2.1.31)

None None H,7 Plant Specific Notes:

1. Steel elements include support members, bearing plates, base plates and connections. connections, and steel reactor vessel support assemblies (including the steel anchor plate embedded in concrete).

3. Loss of preload includes loosening for the reactor vessel support anchor bolt jam nuts.

4. This line item includes the reactor pressure vessel steel shims and includes dry-film surfaces.

5. The IWF inspection of the high strength reactor pressure vessel support anchor bolts indirectly manages the embedded anchor plate.

6. The reactor pressure vessel support grout pads do not have an anchoring capacity function. The aging effect for this line item includes reduction in structural support. Specifically, reactor pressure vessel support grout pads are used as an interface between the top of the concrete primary shield wall and the bottom plate.

II II II II I

I I

I I

11 I

I I

I

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 16 18

7. This line item represents the reactor vessel support steel anchor plate embedded in concrete. The IWF inspection of the exposed anchor bolts indirectly manages reduction of fracture toughness of the anchor plate.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 16 19 SLRA Table A6.0-1 is revised as follows:

Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule Difference

- 31 ASME XI, Subsection IWF (B2.1.31)

The ASME Section XI, Subsection IWF AMP is an existing program that will be enhanced to:

1. Perform periodic evaluations of the acceptability of inaccessible areas of supports (e.g., portions of supports encased in concrete or grout, buried underground, portions of supports covered by insulation, or encapsulated by guard pipe), when conditions exist in accessible areas that could indicate the presence of, or result in, degradation to inaccessible areas of supports. Perform these evaluations once every ISI inspection interval the subsequent period of extended operation.

2. Maintenance procedures will be revised to specify that for structural bolting consisting of ASTM A325, ASTM F1852, ASTM F2280, and/or ASTM A490, the preventive actions for storage, lubricant selection, bolting and coating material selection discussed in Section 2 of Research Council for Structural Connections publication, Specification for Structural Joints Using High-Strength Bolts, will be used.

3. Procedures will be revised to specify that whenever replacement of bolting is required, bolting material, installation torque or tension, and use of lubricants and sealants will be in accordance with the guidelines of EPRI NP-5769, EPRI TR-104213, and the additional recommendations of NUREG-1339.

Program enhancements for SLR will be implemented six months prior to the SPEO.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 16 20 Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule

4. Revise the fleet work planning procedure to specifically prohibit the use of products containing molybdenum disulfide (MoS2) and other lubricants containing sulfur that could contribute to SCC as bolting thread lubricants.

5. Perform a one-time inspection within five years prior to entering the subsequent period of extended operation of an additional 5% of the sample populations for Class 1, 2, and 3 piping supports. The additional supports will be selected from the remaining population of IWF piping supports and will include components that are most susceptible to age related degradation. Support inspections not meeting acceptance criteria will be addressed within the corrective action program.

6. Procedures will be revised to specify that, for NSSS component supports, high-strength bolting greater than one-inch nominal diameter, volumetric examination comparable to that of ASME Code,Section XI, Table IWB-2500-1, Examination Category B-G-1 will be performed to detect cracking in addition to the VT-3 examination. In each ISI inspection interval during the subsequent period of extended operation, a representative sample of bolts will be inspected. The sample of high-strength bolting greater than one-inch nominal diameter subject to volumetric examination will consist of 20 percent of the population or a maximum of 25 bolts. The sample shall include the bolting that is most susceptible to age-related degradation (i.e., based on time in service, aggressive

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 16 21 Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule environment, etc.). Bolting inspections not meeting acceptance criteria will be addressed within the corrective action program.

7. Results that do not meet acceptance criteria are addressed as conditions adverse to quality or significant conditions adverse to quality in the Duke Energy Corrective Action Program. If a component does not exceed the acceptance standards of IWF-3400 but is repaired to design condition, the sample is increased or modified to include another support that is representative of the remaining population of supports that were not repaired.

8. Procedures will be revised to require that at least one reactor pressure vessel support will be inspected every 5 years during the subsequent period of extended operation.

Changed

- 31 ASME XI, Subsection IWF (B2.1.31)

The ASME Section XI, Subsection IWF AMP is an existing program that will be enhanced to:

1. Perform periodic evaluations of the acceptability of inaccessible areas of supports (e.g., portions of supports encased in concrete or grout, buried underground, portions of supports covered by insulation, or encapsulated by guard pipe), when conditions exist in accessible areas that could indicate the presence of, or result in, degradation to inaccessible areas of supports. Perform these evaluations once every ISI inspection interval the subsequent period of extended operation.

Program enhancements for SLR will be implemented six months prior to the SPEO.

I

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 16 22 Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule

2. Maintenance procedures will be revised to specify that for structural bolting consisting of ASTM A325, ASTM F1852, ASTM F2280, and/or ASTM A490, the preventive actions for storage, lubricant selection, bolting and coating material selection discussed in Section 2 of Research Council for Structural Connections publication, Specification for Structural Joints Using High-Strength Bolts, will be used.

3. Procedures will be revised to specify that whenever replacement of bolting is required, bolting material, installation torque or tension, and use of lubricants and sealants will be in accordance with the guidelines of EPRI NP-5769, EPRI TR-104213, and the additional recommendations of NUREG-1339.

4. Revise the fleet work planning procedure to specifically prohibit the use of products containing molybdenum disulfide (MoS2) and other lubricants containing sulfur that could contribute to SCC as bolting thread lubricants.

5. Perform a one-time inspection within five years prior to entering the subsequent period of extended operation of an additional 5% of the sample populations for Class 1, 2, and 3 piping supports. The additional supports will be selected from the remaining population of IWF piping supports and will include components that are most susceptible to age related degradation. Support inspections not meeting acceptance criteria will be addressed within the corrective action program.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 16 23 Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule

6. Procedures will be revised to specify that, for NSSS component supports, high-strength bolting greater than one-inch nominal diameter, volumetric examination comparable to that of ASME Code,Section XI, Table IWB-2500-1, Examination Category B-G-1 will be performed to detect cracking in addition to the VT-3 examination. In each ISI inspection interval during the subsequent period of extended operation, a representative sample of bolts will be inspected. The sample of high-strength bolting greater than one-inch nominal diameter subject to volumetric examination will consist of 20 percent of the population or a maximum of 25 bolts. The sample shall include the bolting that is most susceptible to age-related degradation (i.e., based on time in service, aggressive environment, etc.). Bolting inspections not meeting acceptance criteria will be addressed within the corrective action program.

7. Results that do not meet acceptance criteria are addressed as conditions adverse to quality or significant conditions adverse to quality in the Duke Energy Corrective Action Program. If a component does not exceed the acceptance standards of IWF-3400 but is repaired to design condition, the sample is increased or modified to include another support that is representative of the remaining population of supports that were not repaired.

8. Procedures will be revised to require that at least one reactor pressure vessel support will be inspected every 5 years during the subsequent period of extended operation.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 16 24 SLRA Section B2.1.31 is revised as follows:

Section B2.1.31 Enhancements Prior to the subsequent period of extended operation, the following enhancements will be implemented in the following program elements: Scope of Program (Element 1), Preventive Actions (Element 2), Detection of Aging Effects (Element 4), and Monitoring and Trending (Element 5):

8. Procedures will be revised to require that at least one reactor pressure vessel support will be inspected every 5 years during the subsequent period of extended operation. (Element 4)

ENCLOSURE 1 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT 2 SUBSEQUENT LICENSE RENEWAL APPLICATION H.B. ROBINSON SLRA SUPPLEMENT 2 ATTACHMENT 17 TRP-142.2

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 17 1, Attachment 17 Supplement changes to address issues related to TRP-142.2.

(TRP-142.2)

Affected SLRA Section(s):

4.2.6 SLRA Page Numbers:

4-35 Description of Change:

Revise reference 4.2-25 to Revision 2 to support updates to WCAP-18944-P/NP from TRP-142.2.

SLRA Revisions:

SLRA Section 4.2.6 is revised as follows:

Section 4.2.6 4.2-25 WCAP-18944-NP, H.B. Robinson Unit 2 Subsequent License Renewal: Reactor Vessel Upper Shelf Energy Equivalent Margin Analysis, Revision August 2024, 2025, Revision 0 2

ENCLOSURE 1 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT 2 SUBSEQUENT LICENSE RENEWAL APPLICATION H.B. ROBINSON SLRA SUPPLEMENT 2 ATTACHMENT 18 TRP-143.4

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 18 1, Attachment 18 Supplement changes to address issues related to TRP-143.4 (TRP-143.4)

Affected SLRA Section(s)/Table(s):

4.3.4 SLRA Page Numbers:

4-52 4-54 4-56 4-57 Description of Change:

Changes related to SLRA Section 4.3.4 (EAF), are related to discussions with NRC Staff for TRP-143.4. From this discussion, the Staff requested additional information to be placed in the SLRA related to EAF scope of evaluation and screening methodologies for both the Class 1 vessels and Pressurizer Surge line, and the B31.1 Class 1 reactor coolant piping. In addition Duke is supplementing the application regarding the appropriate use strain rates for the Appendix L crack growth analyses.

SLRA Revisions:

SLRA Section 4.3.4 is revised as follows:

Section 4.3.4 TLAA Evaluation To ensure that any additional plant-specific component locations in the reactor coolant pressure boundary that may be more limiting than those considered in NUREG/CR-6260 are addressed, EAF screening was performed for all ASME Code,Section III vessels with existing fatigue usage values, including the pressurizer and pressurizer surge line piping, and for the RCS piping constructed to USAS B31.1, which do not have defined CUFs. These were categorized into the following six groups of major components listed below.

x Reactor Vessel (RV) and CRDMs x

Reactor Coolant Pumps (RCPs) x Steam Generators x

Pressurizer (PZR) x Excluding pressurizer subcomponents that meet fatigue exemption criteria (pressurizer shells, relief nozzles, safety nozzles, manway covers, manway cover bolts, and relief and safety nozzle safe ends) x Pressurizer Surge Line Piping-originally constructed to USAS B31.1 but analyzed to ASME III, Division I for IEB 88-11 x

RCS Loop and Branch Piping--constructed to USAS B31.1

3. Screening Fen Calculation:

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 18 2

c. For the remaining potential sentinel locations, determine the maximum Fen and Fadj for each component based on the actual material. These material specific Fen and Fadj values are used to determine a screening CUFen for each component (designated material Fen, Fadj, and screening CUFen ). Perform this calculation following the guidance in NUREG/CR-6909 Revision 1. If the screening CUFen is less than 1.0 it can be removed from the list of potential sentinel locations. For carbon steel (CS) and low-alloy steel (LAS), the applicable ASME BPV Code design fatigue curve bounds the updated NUREG/CR-6909 curve and conservatively will continue to be used.

In accordance with Section A.2 of NUREG/CR-6909 Revision 1, a maximum temperature of 325°C (617°F) is specified for the Fen equations as a reasonable bound to cover most anticipated light water reactor operating conditions. In cases where transient temperatures exceed 325°C (617°F), the guidelines in NUREG/CR-6909 Revision 1 state that the analyst shall document the exceedance and justify its use in the Fen equations. The EAF screening evaluation assumes a maximum temperature of 325°C (617°F) for the Fen equations. Since the purpose of EAF screening is to compare locations in a relative sense, the same maximum Fen was applied to all components within a transient section (because those components experience the same temperatures by definition of a transient section) so the EAF screening results would not be affected by altering the maximum Fen based on temperatures above 325°C (617°F). With regard to transformed strain rate, the lowest strain rate < 0.0004 (%/sec), was assumed.

The pressurizer spray nozzle has an operating temperature of 653°F and the 80-year CUFen is 0.129. The CUFen margin from 0.129 to 1.0 is so large that there is ample assurance to conclude that re-evaluating the pressurizer spray nozzle using an operating temperature of 653°F compared to 617°F would not cause the 80-year CUFen to increase above 1.0 and become a sentinel location. However, for completeness, the Fen penalty value was re-calculated using an operating temperature of 653°F. This increased the Fen penalty value from 12.81 to 16.06, which yields an 80-year CUFen of 0.16, thus still demonstrating a large margin to 1.0.

d. As needed, calculate refined screening Fen factors for each component in the transient section based on the maximum temperature experienced in the section in an effort to reduce CUFen from Step 3.c to a value below 1.0 (Temperature Fen and Temperature CUFen). in an effort to reduce the CUFen from Step 3.c to a value below 1.0. Methods used for refinement are as follows:

x For carbon and low-alloy steel locations, application of the NUREG/CR-6909 Revision 1 air design fatigue curves to calculate the allowable cycles for each fatigue pair in the CUF, as opposed to a bounding adjustment factor used in the EAF screening process which is applied to the CUF for changes in air design fatigue curves.

x Refinement of temperature input to the Fen calculations to reflect component-specific temperatures lower than the maximum temperature specified in the NUREG/CR-6909 Revision 1 Fen equations.

x Application of the modified rate approach (MRA), described in Section 4.4 of NUREG/CR-6909 Revision 1, to select fatigue pairs to calculate a refined Fen value associated with a partial usage factor.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 18 3

x The average temperature approach described in Section 4.1.4 of NUREG/CR-6909 Revision 1 is not used for the Fen calculation.

Reactor Coolant System Piping Designed to USAS B31.1 x

Gathering of required inputs (i.e., data collection) x Determination of thermal zones x

Identification of materials and candidate locations x

Establishing Fen

• and Uen

• values within each thermal zone x

Ranking Uen

• values by material within each thermal zone x

Identification of sentinel locations The Class 1 B31.1 piping and applicable transient sections that received a CBSE evaluation are reported below.

x Upper Pressurizer Spray Piping: Includes 4" upper horizontal pressurizer spray piping to the spray nozzle x

Charging Piping: Per operating data review which covers 21 years of operation, alternate charging was not used. Charging nozzles are a NUREG/CR-6260 location.

x Letdown Piping: Includes letdown piping (near and away from RCL) and RCL drains.

This location is bounded by charging nozzle location.

x Pressurizer Safety Valve and Relief Piping: Includes piping between the pressurizer nozzles and PORV/SRVs x

2"/8" Piping to the 10" SI Cold Leg Nozzle: Includes 10" accumulator piping from valves SI-875D, E & F to 10" SI Cold Leg Nozzles; 8" SI piping downstream of RHR return between SI and 2" SI piping between valves SI-873D, E, & F. The 10" SI cold leg nozzle is an NUREG/CR-6260 location.

x RHR Piping: Includes RHR piping near and away from RCL. RHR piping includes a NUREG/CR-6260 location.

All of the piping is fabricated from stainless steel; there are no carbon and low alloy steels or nickel-based alloy items included in the Fen calculations for the screening of piping using CBSE.

The consolidated transient sections listed in the table above are evaluated using CBSE. The inputs for Fen for stainless steel include temperature, oxygen, and strain rate using the Fen methodology from NUREG/CR-6909 Revision 1 for stainless steel.

A maximum T of 325°C (617°F) is used in the equation if service temperature exceeds 325 °C (617°F); this maximum temperature applies to the calculation of Fen only and not to other calculations. This is consistent with the treatment of temperature for the Class 1 vessels see 3 c) above. Using a maximum temperature of 325°C (617°F) for Fen screening, even for locations where the actual temperature could be higher, is acceptable because the purpose of this effort is determine if a location would be considered sentinel (estimated CUFen > 1.0). If it is determined that that the estimated CUFen is higher than 1.0, then a detailed EAF analysis is performed using actual operating temperatures. Thus, using 325°C (617°F) as a maximum screening temperature does not invalidate any EAF screening results.

For transformed strain rates, average temperature may be used for simple transients with a linear temperature response. To avoid nonconservative calculations, the Fen formula threshold temperature (100°C) or the minimum temperature of the transient (whichever is higher) is

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 18 4

applied before averaging. The EAF usage factor, Uen, is determined as Uen = (U) (Fen), where U is the fatigue usage. Fen may be calculated separately for each load set pair in a fatigue usage analysis, or a bounding Fen value may be used.

For reactor coolant pressure boundary piping constructed in accordance with USAS B31.1, with the exception of the pressurizer surge line, the following temperatures are applicable for the various thermal zones.

x RCL: 555/611°F, Includes cold leg, hot leg, and some branch piping x

Auxiliary spray: 70°F x

Charging near RCL: 510°F x

Charging away from RCL: 510°F x

Letdown away from RCL: 555°F x

Upper pressurizer spray: 550°F x

Pressurizer safety and relief near PZR: 653°F, At PZR temperature due to convection or flow. Operating temperature for this piping is 555°F.

x Pressurizer safety and relief away from PZR: 70°F x

2" Safety injection near hot log: 611°F x

2" Safety injection near cold leg: 70°F x

10" Safety injection near cold leg: 555°F x

2/8/10" safety injection away from cold leg: 70°F x

14" RHR away from RCL: 70°F The average temperature approach was used to estimate Fen values to perform EAF screening using EPRIs Common Basis Stress Evaluation (CBSE) approach. A detailed EAF evaluation was not performed following the EAF screening.

All transients considered in the CBSE EAF screening are categorized as simple transients with constant strain and linear temperature rates, which is appropriate for piping constructed to USAS B31.1 standards. Transient definitions for B31.1 piping segments within the scope for the CBSE evaluation do not include multiple increasing and decreasing temperature excursions and are not complex transients. The simple transients are further categorized with one of the following strain rate categories to define the appropriate estimated strain rates (%/sec):

x Very high ~ 1.3 x

High ~ 0.33 x

Medium-High ~ 0.087 x

Medium ~ 0.023 x

Low-Medium ~ 0.0059 x

Slow ~ 0.0015 x

Very Slow: 0.0004 Average temperature was used for the Fen estimation, and the threshold temperature (100°C) or the minimum temperature of the transient (whichever is higher) was applied before averaging.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 18 5

There were no reductions in CUFen values made by removing excessive conservatisms following the completion of the calculation of CUFen values using the CBSE process. Estimated Fen (Fen*) is calculated as the average of the value based on a qualitative estimate of strain rate, and the value based on the worst possible strain rate (Fen* = (expected Fen + worst Fen)/2), using the same values of dissolved oxygen and bounding temperature (T) for transients, up to a maximum of 325°C (617°F).

There were no reductions in CUFen values made by removing excessive conservatisms following the completion of the calculation of CUFen values using the CBSE process Average temperature was used for the Fen estimation, and the threshold temperature (100°C) or the minimum temperature of the transient (whichever is higher) was applied before averaging.

Appendix A Flaw Tolerance Evaluation for Reactor Vessel Outlet Nozzle to Shell Weld As permitted by ASME Section XI, Appendix L, L-3311, nonmandatory App. A analytical procedures may be used for ferritic steel components 4 inches or greater in thickness. As such, Robinson has demonstrated that the generic flaw tolerance evaluations performed in PWROG-17031-NP-A for underclad cracking is an adequate flaw tolerance basis for continued operation considering the Robinson reactor vessel outlet nozzle-to-shell welds, as supplemented with the flaw handbook for Robinson, WCAP-15621-NP [Reference 4.3-10]. Thus, use of flaw tolerance evaluation is acceptable for management of EAF for the Robinson reactor vessel outlet The allowable flaw sizes (depth/wall thickness) for a continuous flaw (a/l=0, which is bounding) for the Robinson outlet nozzle-to-shell weld is 3.2% (i.e. 0.32") for both the circumferential and axial flaw cases. The allowable flaw sizes for the inlet nozzle-to-shell weld is 6.6% (i.e. 0.65") and 7%

(i.e. 0.69") for the circumferential and axial flaws, respectively. The fatigue crack growth is small and similar for both the inlet and outlet nozzle-to-shell weld cases. For the bounding continuous flaw case, the fatigue crack growth for the inlet nozzle-to-shell weld is 1% (i.e. 0.098") and the outlet nozzle-to-shell weld 0.8% (i.e. 0.079") over a 20-year period. The allowable flaw size for the outlet nozzle-to-shell weld is similar but slightly lower for axial and circumferential flaws compared to the inlet nozzle-to-shell welds. Based on the fatigue crack growth (FCG) and allowable flaw depths in PWROG-17031-NP-A, weld chart, i.e., the inlet nozzle-to-shell weld is slightly more flaw tolerant than the outlet nozzle-to-shell weld. Thus, the acceptable time between inspections is 80 years. A review of the underclad crack evaluation in PWROG-17031-NP-A, showed that the total FCG for a continuous flaw shape is 0.3576 over 80 years. the results reported in PWROG-17031-NP for axial continuous flaws in the inlet nozzle are considered representative of the expected flaw growth and flaw tolerance over 80 years for the outlet nozzle as well.

The use of flaw tolerance evaluation is acceptable for management of EAF for the Robinson reactor vessel outlet nozzle-to-shell welds. Based on the fatigue crack growth (FCG) and allowable flaw depths in PWROG-17031-NP-A, the acceptable time between inspections is 80 years. A review of the underclad crack evaluation in PWROG-17031-NP-A, showed that the total FCG for a continuous flaw shape is 0.3576 over 80 years.

This is negligible considering the limiting allowable flaw size is 0.67 per PWROG-17031-NP-A.

The RV shell including the inlet and outlet nozzles are inspected on a ten or twenty year (with relief request) frequency, and there have been no indications detected during the last refueling outage in December 2022 at the reactor vessel outlet nozzle to shell weld. Taken together, the combination of the inspections performed every 10 or 20-years, which validates the absence of a flaw and the analytical crack growth results, demonstrates the structural integrity of the fatigue sensitive reactor vessel outlet nozzle to shell weld location.

Appendix L Flaw Tolerance Evaluations for Piping

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 18 6

For the pressurizer surge line reducer-to-pipe weld and charging nozzle-to-pipe weld locations, the transients used to simulate growth of the postulated flaws in the ASME Code,Section XI, Appendix L evaluations used ten years of projected cycles. In addition, these analyses utilized actual plant operating temperatures instead of generic EAF screening temperatures. For the pressurizer surge line reducer-to-pipe weld, the Appendix L used an operating temperature of 653°F to calculate fatigue crack growth. The Appendix L evaluation of the pressurizer-surge line reducer-to-pipe weld bounds all locations in the pressurizer lower shell and the surge line. For the charging nozzle-to-pipe weld, the Appendix L used the maximum operating temperature for each unique transient (550°F is the maximum temperature across all applicable transients) to calculate fatigue crack growth. Following re-inspection, the cycle counts used in the ASME Code,Section XI, Appendix L evaluation are set to zero when no flaw is disclosed for each new inspection interval. The ASME Code,Section XI, Appendix L evaluation piping locations will be inspected on a ten-year inspection frequency. The selection of transients is conservative, thereby ensuring the inspection frequencies remain adequate. The Fatigue Monitoring (B3.1) aging management program tracks significant transient cycles for the Class 1 components.

Based on the fatigue crack growth evaluation, the allowable operating period was determined as the length of time it takes for the postulated initial flaw size to grow to the maximum allowable end-of-evaluation period flaw size. The fatigue crack growth analysis was completed using the crack growth rates from ASME Code,Section XI, Code Case N-809 [Reference 4.3-11]. The results of the ASME Code,Section XI, Appendix L evaluations, time between inspections, are provided in Table 4.3.4-1.

It is understood that per Code Case N-809, for temperatures between 300°F and 650°F, the ST parameter increases with increasing temperatures, whereas for temperatures between 70°F and 300°F, the S T parameter increases with decreasing temperatures. Therefore, the Robinson Appendix L evaluation for the pressurizer surge line conservatively uses the most limiting and bounding ST value for each transient in the fatigue crack growth evaluation. Assessment of S T parameter relative to fatigue crack growth for the charging nozzle is as follows.

Using the formulation for fatigue crack growth in a PWR water environment from ASME Code Case N-809, ST is given by the following two temperature-dependent equations (i.e., one equation for high temperatures, and another equation for low temperatures), and the table below tabulates the calculated ST for select temperatures of interest:

New Figure For the Plant Heatup and Cooldown transient and the Letdown Trip Prompt Restart transient, the calculated ST of 8.9 x 10-3 at 500°F (the maximum temperature for the transient) is 4.3%

lower than the calculated ST of 9.3 x 10-3 at 70°F (the minimum temperature for the transient) and is slightly non-conservative.

For the Flow Change and Return transient, the temperature range is between 400°F and 500°F.

Thus, only the high temperature equation is used to calculate ST, and the use of ST at the maximum temperature of 500°F is conservative.

g ST

= e -

5

/ TK for 300 F < T < 650 F

= 3.39 x 105 e[ -

5 6/ 7K -o.o3o TK]

for 70 F < T < 300 F

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 18 7

For all other transients, the calculated ST of 1.1 x 10-2 at 548°F or 550°F (the maximum temperatures of all other transients) is conservatively higher than all values of ST using the equation for low temperatures. Thus, the use of the maximum temperature to calculate ST for all other transients is conservative.

Discussion of Fatigue Crack Growth Results For the most limiting result in the evaluation (Case 2, Circumferential Flaw with 79 years of allowable operation in Table 7 of 1501603.325, Revision 0), the table below lists the final crack growth at Year 79 for all transients.

x Group 1 are all transients for which the use of 548°F or 550°F to calculation ST is conservative and the flow change and return transient, which conservatively used 500°F for calculating ST with a temperature range of 400°F to 500°F.

x Group 2 are the two transients for which the use of 500°F instead of 70°F to calculate ST is non-conservative by 4.3%.

Summing the total crack growth for each group, the crack growth for conservative Group 1 is 68% (6.2 x 10-4 / 3.7 x 10-5) greater than the slightly non-conservative Group 2 with a 4.3%

addition. The 4.3% non-conservatism of the two transients in Group 2 would contribute an additional 1.5 x 10-5 inches per year of crack growth, which is negligible (less than 3%) as compared to the 6.2 x 10-4 inches per year for conservative Group 1 transients.

Thus, the non-conservatism from the use of 500°F instead of 70°F to calculate ST for the two transients in Group 2 is insignificant relative to the estimated total crack growth. The conclusions of the evaluation remain valid with a limiting allowable operating period of 79 years.

New Figure The results of the ASME Code,Section XI, Appendix L evaluations, time between inspections, are provided in Table 4.3.4-1.

The ASME Code,Section XI, Appendix L flaw tolerance inspections for the two limiting sentinel locations will be conducted by the ASME Section XI Inservice Inspection, Subsections IWB, Thermal Transient Temperature (°F)

Fatigue Crack Growth @ Year 79, inches/year (Case 2, Circumferential - Most Limiting Result)

Grouo 1 - Conservative Crack Growth Letdown Trip Delayed Restart 1 550 2.4x 10-<

Letdown Trip Delayed Restart 2 550 1.1 X 10*4 Charging Trip Prompt Restart 550 2.6 X 10**

Charging Trip Delayed Restart 550 4.9 X 10**

Charging and Letdown Trip 550 4.9 X 10**

Flow Change and Return 500 1.5 X 10*4 Reactor Trip 548 2.2 X 10**

Operating Basis Earthquake 550 5.9 X 10*7 Total Crack Grow1h - Group 1 6.2 X 10**

Grouo 2 - Non-Conservative Crack Growth Letdown Trip Prompt Restart 500 2.6 X 10**

Heatup and Cooldown 500 9.7x 10**

Total Crack Grow1h - Group 2 3.5 X 10-<

4.3% of Total Crack Grow1h - Group 2 1.5 X 10**

Total Crack Growth - Group 2 + 4.3%

3.7x 10**

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 18 8

IWC, and IWD (B2.1.1) aging management program. Each weld in the inspection population will be volumetrically inspected using the code required techniques once prior to establishing the Inspection Interval schedule for the ASME Code,Section XI, Appendix L locations. The need for subsequent inspections shall be based on the inspection results prior to entering the subsequent period of extended operation and the Appendix L flaw tolerance evaluations.

TLAA Disposition: 10 CFR 54.21(c)(1)(iii)

Table 4.3.4-1 Summary of Equipment and Piping Sentinel Locations Requiring EAF Evaluations System/ Thermal Zone Location Material CUFen (1)

Analysis Method EAF Management Method Reactor Vessel Vent Pipe - ASN 4, Inside (partial penetration weld at inside of RV closure head)

NiA 2.585 Bounded by SG Tubes None Required (6)

CVCS Charging Nozzle to Pipe Weld (6260 Location)

SS 16.907 ASME

Code,Section XI, Appendix L (5)

ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD (B2.1.1)

Program Time Between Inspections:

8179 Years I

I

ENCLOSURE 1 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT 2 SUBSEQUENT LICENSE RENEWAL APPLICATION H.B. ROBINSON SLRA SUPPLEMENT 2 ATTACHMENT 19 TRP 147.31

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 19 1, Attachment 19 Supplement changes to address PWSCC concern measures, water hammer, and low and high cycle fatigue related to TRP 147.31 (TRP 147.31)

Affected SLRA Section(s):

4.7.3.1 SLRA Page Numbers:

4-77 Description of Change:

This supplement item makes the changes identified below to the SLRA in response to TRP 147.31:

x A discussion of measures addressing PWSCC concerns including inspections per ASME Code Case N-770-5 for the Alloy 600 management plan, the zinc injection program, and EPRI eXtremely Low Probability of Rupture (xLPR) program is added to Section 4.7.3.1, TLAA Evaluation.

x A discussion to address why there is low potential for water hammer in the Reactor Coolant System is added to Section 4.7.3.1, TLAA Evaluation.

x A discussion to address why the effects of low and high cycle fatigue are negligible in the primary piping systems is added to Section 4.7.3.1, TLAA Evaluation.

SLRA Revisions:

SLRA Section 4.7.3.1 is revised as follows:

Section 4.7.3.1 TLAA Evaluation

a. Stress corrosion cracking is precluded by use of fracture resistant materials in the piping system and controls on reactor coolant chemistry, temperature, pressure, and flow during normal operation.

Alloy 82/182 welds are present at the reactor pressure vessel outlet nozzle (RPVON) and reactor pressure vessel inlet nozzle (RPVIN). The Alloy 82/182 welds are susceptible to PWSCC (Primary Water Stress Corrosion Cracking).

Regarding PWSCC concerns, Robinson has implemented the necessary Alloy 600 management plan including inspections on the hot and cold legs per ASME Code Case N-770-5. For the hot leg, this includes visual inspection each refueling outage and ultrasonic inspection every 5 years. For the cold leg, this includes visual inspection once per interval and ultrasonic inspection once per interval not to exceed 13 years.

Additionally, a zinc injection program was implemented during fuel cycle 28 via the Chemical and Volume Control System. Zinc addition provides some mitigation with respect to slowing the initiation and propagation of PWSCC. Finally, ongoing work associated with the Electric Power Research Institute (EPRI) eXtremely Low Probability of Rupture (xLPR) program along with the U.S. NRC review of the program with respect to PWSCC concerns is still in process.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 19 2

d. Water hammer should not occur in the RCS piping because of system design, testing, and operational considerations.

Overall, there is a low potential for water hammer in the RCS since it is designed and operated to preclude the voiding condition in normally filled lines. The reactor coolant system, including piping and primary components, is designed for normal, upset, emergency, and faulted condition transients. The design requirements are conservative relative to both the number of transients and their severity. Relief valve actuation and the associated hydraulic transients following valve opening are considered in the system design. Other valve and pump actuations are relatively slow transients with no significant effect on the system dynamic loads. To ensure dynamic system stability, reactor coolant parameters are stringently controlled. Temperature during normal operation is maintained within a narrow range by control rod position; pressure is controlled by pressurizer heaters and pressurizer spray also within a narrow range for steady-state conditions. The flow characteristics of the system remain constant during a fuel cycle because the only governing parameters, namely system resistance and the reactor coolant pump characteristics, are controlled in the design process. Additionally, Westinghouse has instrumented typical reactor coolant systems to verify the flow and vibration characteristics of the system. Preoperational testing and operating experience have verified the Westinghouse approach. The operating transients of the RCS primary piping are such that no significant water hammer can occur.

e. The effects of low and high cycle fatigue on the integrity of the primary piping are negligible.

An assessment of the low cycle fatigue loadings was carried out in the form of fatigue crack growth analysis as documented WCAP-15628, Revision 1, which determined that fatigue crack growth is not a concern for Robinson primary loop piping.

High cycle fatigue loads in the RCS would result primarily from pump vibrations, which are minimized by restrictions placed on shaft vibrations during hot functional testing and operation. During operation, an alarm signals the exceedance of the vibration limits.

Field measurements during hot functional testing have been conducted at a number of plants, including those similar to Robinson. Stresses in the elbow below the reactor coolant pump resulting from system vibration have been found to be very small; these stresses are well below the fatigue endurance limit for the material and would result in an applied stress intensity factor below the threshold for fatigue crack growth.

ENCLOSURE 1 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT 2 SUBSEQUENT LICENSE RENEWAL APPLICATION H.B. ROBINSON SLRA SUPPLEMENT 2 ATTACHMENT 20 TRP 147.7

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 20 1, Attachment 20 Concrete Containment Bonded Tendon Prestress TLAA (TRP 147.7)

Affected SLRA Section(s):

A4.7.7 4.7.7 SLRA Page Numbers:

4-84 4-86 A-45 Description of Change:

The following changes are made to the Robinson SLRA in response to TRP 147.7:

x Revised statement to include testing (at integrated leak rate test pressure), similar to the Structural Integrity Test performed in 1992 and 2020, will be scheduled to coincide with Appendix J containment integrated leak rate testing conducted during the subsequent period of extended operation.

x Provided additional detail regarding the anchorages are required to develop the minimum ultimate strength of the tendons without slip or excessive deformation. As a result, losses due to anchor set do not exist for these tendons and are not applicable to the prestress loss calculations.

x Revised description of the surveillance tendons that were removed for testing at year 5 and 25.

SLRA Revisions:

SLRA Section A4.7.7 is revised as follows:

Section A4.7.7 To provide additional assurance of the tendons design capacity, testing (at integrated leak rate test pressure), similar to the Structural Integrity Test performed in 1992, 1992 and 2020, will be scheduled to coincide with Appendix J containment integrated leak rate testing conducted during the subsequent period of extended operation (required frequency in accordance with 10 CFR 50, Appendix J). The monitoring criteria for these tests will be limited to deformations and cracking associated with the vertical prestressed tendons, and will not include radial monitoring.

Guidelines for performing the examinations for these tests will include additional emphasis on looking for a pattern of horizontal cracks, and additional cracking in the discontinuity areas.

SLRA Section 4.7.7 is revised as follows:

Section 4.7.7 TLAA Evaluation No prestress losses were considered for elastic shortening, due to the re-tensioning of the tendons approximately a month after the initial tensioning. Per the tendon design specification, the anchorages are required to develop the minimum ultimate strength of the tendons without

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 20 2

slip or excessive deformation. As a result, losses due to anchor set do not exist for these tendons and are not applicable to the prestress loss calculations.

Robinson had two surveillance tendons, each consisting of two short tendons, similar to the service tendons, and were in a similar environment. Each The 5-year surveillance tendon consists consisted of six-1.375-inch diameter bars bars, and the 25-year surveillance tendon consisted of six-0.5-inch diameter bars, each in a 6 inch diameter pipe sheath with anchor plates, prestressing hardware, and grout pipe, identical except for length to the working tendons. They are embedded in a section of concrete approximating the same environment as that of the service tendons.

ENCLOSURE 1 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT 2 SUBSEQUENT LICENSE RENEWAL APPLICATION H.B. ROBINSON SLRA SUPPLEMENT 2 ATTACHMENT 21 TRP 151

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 21 1, Attachment 21 Concrete Containment Bonded Tendon Prestress AMP (TRP 151)

Affected SLRA Section(s)/Table(s):

A6.0-1 B2-1 B4.1 SLRA Page Numbers:

A-102 B-18 B-271 B-275 Description of Change:

The following changes are made to the Robinson SLRA in response to TRP 147.7:

1. Revised Element 5 to clarify that the displacement values are compared against acceptance criteria values and displacements measured during the previous Structural Integrity Tests that were performed in 1970, 1992, and 2020.

2. Added Enhancement to perform the structural integrity test (SIT) in conjunction with the Appendix J integrated leak rate test. The schedule for completion of the SIT and Appendix J integrated leak rate test shall be in accordance with 10 CFR 50, Appendix J requirements, currently scheduled to occur no later than 2035 and 2050 for the next two successive tests. (Elements 3, 4, and 5)

3. Added Enhancement 2 to revise station procedures to include if acceptance criteria are not met, they are entered into the corrective action program. (Elements 6 and 7)

4. Revised Subsequent License Renewal Commitments Table A6.0-1 to include 2 new enhancements.

5. Revised Table B2-1, RNP Program Consistency with NUREG-2191 Program, to show the Concrete Containment Bonded Tendon Prestress AMP as having enhancements.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 21 2

SLRA Revisions:

SLRA Table A6.0-1 is revised as follows:

Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule Difference

- 48 Concrete Containment Bonded Tendon Prestress (B4.1)

The existing Concrete Containment Bonded Tendon Prestress AMP is credited. an existing program will be enhanced to:

1. Perform the structural integrity test (SIT) in conjunction with the Appendix J integrated leak rate test. The schedule for completion of the SIT and Appendix J integrated leak rate test shall be in accordance with 10 CFR 50, Appendix J requirements, currently scheduled to occur no later than 2035 and 2050 for the next two successive tests.

2. Revise station procedures to include if acceptance criteria are not met, they are entered into the corrective action program.

Ongoing. Program enhancements for SLR will be implemented six months prior to the SPEO.

Changed

- 48 Concrete Containment Bonded Tendon Prestress (B4.1)

The Concrete Containment Bonded Tendon Prestress AMP is an existing program will be enhanced to:

1. Perform the structural integrity test (SIT) in conjunction with the Appendix J integrated leak rate test. The schedule for completion of the SIT and Appendix J integrated leak rate test shall be in accordance with 10 CFR 50, Appendix J requirements, currently scheduled to occur no later than 2035 and 2050 for the next two successive tests.

Program enhancements for SLR will be implemented six months prior to the SPEO.

I I

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 21 3

Table A6.0-1 Subsequent License Renewal Commitments Aging Management Program (Section)

Commitment Implementation Schedule

2. Revise station procedures to include if acceptance criteria are not met, they are entered into the corrective action program.

H. B. Robinson Steam Electric Plant Unit 2 Subsequent License Renewal Application, Attachment 21 4

SLRA Table B2-1 is revised as follows:

Table B2-1 RNP Program Consistency with NUREG-2191 Program NUREG-2191 Program Appendix B

Reference Existing or New Program has NUREG-2191 Enhancements Program has Exceptions to NUREG-2191 Concrete Containment Bonded Tendon Prestress B4.1 Existing X

SLRA Section B4.1 is revised as follows:

Section B4.1 Program Description For the SIT, as containment is pressurized, displacements are measured at discrete locations around the Robinson containment. Base mat vertical displacement, containment wall vertical elongation, concrete crack width, average crack width, residual displacement, residual crack width, liner plate distortion are measured and compared with acceptance criteria identified in station procedures. Engineering reviews the displacement data at various building pressure levels (14 psig, 21 psig, 35 psig, max pressure of approximately 42 psig, and 0 psig). The acceptance criteria displacement values are compared to the against acceptance criteria values and displacements measured during the previous Structural Integrity Tests that were performed in 1970, 1992, and 2020. If acceptance criteria is not met, engineering shall develop a contingency plan in order to make repairs or perform the test at another time.

Enhancements None. Prior to the subsequent period of extended operation, the following enhancements will be implemented in the following program elements: Parameters Monitored or Inspected (Element 3), Detection of Aging Effects (Element 4), Monitoring and Trending (Element 5), Acceptance Criteria (Element 6), and Corrective Actions (Element 7).

1. Perform the structural integrity test (SIT) in conjunction with the Appendix J integrated leak rate test. The schedule for completion of the SIT and Appendix J integrated leak rate test shall be in accordance with 10 CFR 50, Appendix J requirements, currently scheduled to occur no later than 2035 and 2050 for the next two successive tests. (Elements 3, 4, and 5)

2. Revise station procedures to include if acceptance criteria are not met, they are entered into the corrective action program. (Elements 6 and 7)