View source for LR-N23-0005, License Amendment Request to Amend Technical Specifications (TS) 6.8.4.f for Permanent Extension of Type a and Type C Leak Rate Test Frequencies

{{Adams
| number = ML23174A186
| issue date = 06/23/2023
| title = License Amendment Request to Amend Technical Specifications (TS) 6.8.4.f for Permanent Extension of Type a and Type C Leak Rate Test Frequencies
| author name = Sharbaugh D
| author affiliation = PSEG Nuclear, LLC
| addressee name = 
| addressee affiliation = NRC/NRR, NRC/Document Control Desk
| docket = 05000272, 05000311
| license number = DPR-070, DPR-075
| contact person = 
| case reference number = LR-N23-0005, LAR S22-04
| document type = Letter type:LR, License-Application for Facility Operating License (Amend/Renewal) DKT 50, Technical Specification, Amendment
| page count = 1
| project = 
| stage = Request
}}

=Text=
{{#Wiki_filter:10 CFR 50.90 June 23, 2023 LR-N23-0005 LAR S22-04 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001 Salem Generating Station, Units 1 and 2 Renewed Facility Operating License Nos. DPR-70 and DPR-75 NRC Docket Nos. 50-272 and 50-311

==Subject:==
License Amendment Request to Amend Technical Specifications (TS) 6.8.4.f for Permanent Extension of Type A and Type C Leak Rate Test Frequencies In accordance with the provisions of 10 CFR 50.90, PSEG Nuclear LLC (PSEG) is submitting a request for an amendment to the Technical Specifications (TS) for Salem Generating Station (Salem) Units 1 and 2.
The proposed change will revise Salem Unit 1 and 2 Technical Specification (TS) 6.8.4.f, Primary Containment Leakage Rate Testing Program, by replacing the reference to Regulatory Guide 1.163 with a reference to Nuclear Energy Institute (NEI) Report NEI 94-01, Revision 3-A, dated July 2012 and the conditions and limitations specified in NEI 94-01, Revision 2-a, dated October 2008.
The Enclosure provides a description and assessment of the proposed changes. Attachment 1 provides the existing TS pages marked up to show the proposed changes. Attachment 2 provides a risk assessment for the Type A permanent extension request. No TS Bases changes are required.
PSEG requests approval of this LAR in accordance with standard NRC approval process and schedule. Once approved, the amendment will be implemented within 60 days from the date of issuance.
In accordance with 10 CFR 50.91, a copy of this application, with attachments, is being provided to the designated State of New Jersey Official.
There are no regulatory commitments contained in this letter.
If you have any questions or require additional information, please contact Mr. Brian Thomas at 856-339-2022.

LR-N23-0005                                                                10 CFR 50.90 Page 2 I declare under penalty of perjury that the foregoing is true and correct.
Executed on __ June 23, 2023____
(Date)
Respectfully, Digitally signed by Sharbaugh, Sharbaugh, David David     Date: 2023.06.23 17:33:47 -04'00' David Sharbaugh Site Vice President - Salem

==Enclosure:==
Evaluation of the Proposed Changes  Mark-up of Proposed Technical Specification Pages  Risk Assessment for the Type A Permanent Extension Request cc:
Mr. R. Lorson, Administrator, Region I, NRC Mr. J. Kim, Project Manager, NRC NRC Senior Resident Inspector, Salem Ms. A Pfaff, Manager NJBNE PSEG Corporate Commitment Tracking Coordinator Site Commitment Tracking Coordinator

LR-N23-0005                                    LAR S22-04 Enclosure Evaluation of the Proposed Changes

LR-N23-0005                                                                 LAR S22-04 Enclosure Enclosure Evaluation of the Proposed Change

==SUBJECT:==
License Amendment Request to Revise Salem Nuclear Generating Station Units No. 1 and 2 Technical Specification 6.8.4.f, "Primary Containment Leakage Rate Testing Program," for Permanent Extension of Type A and Type C Leak Rate Test Frequencies 1.0   

==SUMMARY==
DESCRIPTION 2.0   DETAILED DESCRIPTION

==3.0   TECHNICAL EVALUATION==

3.1    Containment System 3.2    Net Positive Suction Head (NPSH) and Spray Water Entrapment 3.3    Justification for the TS Change 3.4    Plant Specific Confirmatory Analysis 3.5    Non-Risk Based Assessment 3.6    Operating Experience (OE) 3.7    License Renewal Aging Management 3.8    NRC SER Limitations and Conditions 3.9    Conclusion

==4.0   REGULATORY EVALUATION==

4.1    Applicable Regulatory Requirements/Criteria 4.2    Precedent 4.3    No Significant Hazards Consideration 4.4    Conclusion

==5.0   ENVIRONMENTAL CONSIDERATION==

==6.0   REFERENCES==

Attachments:
: 1. Mark-up of Proposed Technical Specification Pages
: 2. Risk Assessment for the Type A Permanent Extension Request

LR-N23-0005                                                                LAR S22-04 Enclosure 1.0     

==SUMMARY==
DESCRIPTION In accordance with 10 CFR 50.90, "Application for amendment of license, construction permit, or early site permit," PSEG Nuclear LLC (PSEG) requests an amendment to Renewed Facility Operating License Nos. DPR-70 and DPR-75 for Salem Nuclear Generating Station (SNGS)
Units 1 and 2, respectively.
The proposed change revises Units 1 and 2 Technical Specifications (TS) 6.8.4.f, "Primary Containment Leakage Rate Testing Program," to reflect the following:
* Increase the existing Type A integrated leakage rate test (ILRT) program test interval from 10 years to 15 years in accordance with Nuclear Energy Institute (NEI) Topical Report (TR) NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J," Revision 3-A (Reference 2), and the conditions and limitations specified in NEI 94-01, Revision 2-A (Reference 8).
* Adopt an extension of the containment isolation valve (CIV) leakage rate testing (Type C) frequency from the 60 months currently permitted by 10 CFR 50, Appendix J, Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors, Option B, per Regulatory Guide (RG) 1.163, Performance-Based Containment Leak-Test Program (Reference 1), to 75 months for Type C leakage rate testing of selected components, in accordance with NEI 94-01, Revision 3-A.
* Adopt the use of American National Standards Institute/American Nuclear Society (ANSI/ANS) 56.8-2002, Containment System Leakage Testing Requirements (Reference 37).
* Adopt a more conservative allowable test interval extension of nine months, for Type A, Type B and Type C leakage rate tests in accordance with NEI 94-01, Revision 3-A.
Specifically, the proposed change contained herein revises each of the SNGS Units 1 and 2 TS 6.8.4.f by replacing the references to RG 1.163 with a reference to NEI 94-01, Revision 3-A, and the limitation and conditions specified in NEI 94-01, Revision 2-A, dated October 2008. These documents will be used by SNGS to implement the performance-based leakage testing program in accordance with Option B of 10 CFR 50, Appendix J, Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors.
This License Amendment Request (LAR) also proposes the following administrative change to SNGS Units 1 and 2 TS 6.8.4.f, paragraph a.:
* Delete the information regarding the performance of the next SNGS Type A tests as these dates have already occurred and the associated Type A tests have been successfully performed.
2.0    DETAILED DESCRIPTION SNGS Units 1 and 2 TS 6.8.4.f, "Primary Containment Leakage Rate Testing Program,"
currently states, in part:
2

LR-N23-0005                                                                 LAR S22-04 Enclosure SNGS Unit 1 A program shall be established, implemented, and maintained to comply with the leakage rate testing of the containment as required by 10CFR50.54(o) and 10CFR50, Appendix J, Option B, as modified by approved exemptions. This program shall be in accordance with the guidelines contained in Regulatory Guide 1.163, "Performance-Based Containment Leak-Test Program," dated September 1995, as modified by the following exception to NEI 94-01, Rev. 0, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J":
: a. Section 9.2.3: The first Type A test performed after May 7, 2001, shall be performed no later than May 7, 2016.
SNGS Unit 2 A program shall be established, implemented, and maintained to comply with the leakage rate testing of the containment as required by 10CFR50.54(o) and 10CFR50, Appendix J, Option B, as modified by approved exemptions. This program shall be in accordance with the guidelines contained in Regulatory Guide 1.163, "Performance-Based Containment Leak-Test Program," dated September 1995, as modified by the following exception:
: a. NEI 94-01-1995, Section 9.2.3: The first Type A test performed after March 24, 1992 shall be performed no later than March 24, 2007.
The proposed changes to SNGS Units 1 and 2 TS 6.8.4.f, will replace the reference to RG 1.163 with a reference to NEI 94-01, Revisions 2-A and 3-A (Reference 8 & 2, respectively).
Additionally, this LAR incorporates the following administrative change to SNGS Units 1 and 2 TS 6.8.4.f.a.:
* Delete Units 1 and 2 TS 6.8.4.f.a. These changes will have no impact on the SNGS 10 CFR 50, Appendix J Testing Program requirements, as these dates have already occurred.
The proposed change revises the SNGS Units 1 and 2 TS 6.8.4.f to read as follows in part (with recommended changes using strike-out for deleted text and bold-type for added text for clarification purposes):
SNGS Unit 1 A program shall be established, implemented, and maintained to comply with the leakage rate testing of the containment as required by 10CFR50.54(o) and 10CFR50, Appendix J, Option B, as modified by approved exemptions. This program shall be in accordance with the guidelines contained in Regulatory Guide 1.163, "Performance-Based Containment Leak-Test Program," dated September 1995, NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J," Revision 3-A, dated July 2012, and the conditions and limitations specified in NEI 94-01, Revision 2-A, dated October 2008. as modified by the following exception to NEI 94-01, Rev. 0, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J":
3

LR-N23-0005                                                                   LAR S22-04 Enclosure
: a. Section 9.2.3: The first Type A test performed after May 7, 2001, shall be performed no later than May 7, 2016.
SNGS Unit 2 A program shall be established, implemented, and maintained to comply with the leakage rate testing of the containment as required by 10CFR50.54(o) and 10CFR50, Appendix J, Option B, as modified by approved exemptions. This program shall be in accordance with the guidelines contained in Regulatory Guide 1.163, "Performance-Based Containment Leak-Test Program," dated September 1995, NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J," Revision 3-A, dated July 2012, and the conditions and limitations specified in NEI 94-01, Revision 2-A, dated October 2008, as modified by the following exception:
: a. NEI 94-01-1995, Section 9.2.3: The first Type A test performed after March 24, 1992 shall be performed no later than March 24, 2007.
Therefore, the retyped ("clean") version of SNGS Units 1 and 2 TS 6.8.4.f will appear as follows:
A program shall be established, implemented, and maintained to comply with the leakage rate testing of the containment as required by 10CFR50.54(o) and 10CFR50, Appendix J, Option B, as modified by approved exemptions. This program shall be in accordance with the guidelines contained in NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J," Revision 3-A, dated July 2012, and the conditions and limitations specified in NEI 94-01, Revision 2-A, dated October 2008.
The marked-up TS pages 6-19 for SNGS Units 1 and 2, TS 6.8.4.f, showing these proposed changes, are provided in Attachment 1. contains the plant specific risk assessment conducted to support this proposed change. This risk assessment follows the guidelines of NRC RG 1.174, Revision 3 (Reference 3) and RG 1.200, Revision 2 (Reference 4). The risk assessment concludes that increasing the ILRT interval to 15 years is not considered to be significant since it represents a small change in the SNGS risk profile.

==3.0    TECHNICAL EVALUATION==

3.1   Containment System 3.1.1   Description of Containment System The SNGS Units 1 and 2 reactor containment structure is a reinforced concrete vertical right cylinder with a flat base and a hemispherical dome. A welded steel liner with a minimum thickness of 1/4 inch is attached to the inside face of the concrete shell to ensure a high degree of leak tightness. The design objective of the containment structure is to contain all radioactive material which might be released from the core following a loss-of-coolant accident (LOCA). The structure serves as both a biological shield and a pressure container.
The structure consists of side walls measuring 142 feet in height from the liner on the base to the springline of the dome and has an inside diameter of 140 feet. The side walls of the cylinder and the dome are 4 feet-6 inches and 3 feet-6 inches thick, respectively. The inside radius of the 4

LR-N23-0005                                                                    LAR S22-04 Enclosure dome is equal to the inside radius of the cylinder so that the discontinuity at the springline due to the change in thickness is on the outer surface. The flat concrete base mat is 16-feet thick with a bottom liner plate located on top of this mat. The bottom liner plate, in the annulus area between the circular crane wall and the outer cylindrical wall, is covered with a minimum of 2 feet of concrete, and the area within the crane wall is covered with 5 feet of concrete. The top of these concrete slabs is the floor of the containment. The base mat is directly supported on lean concrete fill.
The underground portion of the containment structure is waterproofed in order to avoid seepage of ground water through cracks in the concrete. The waterproofing consists of an impervious membrane which is placed under the mat and on the outside of the walls. The Ethylene Propylene Diene Monomers (by Uniroyal, Inc.) membrane will not tear in handling or placing of backfill against it.
The basic structural elements considered in the design of the containment structure are the base slab, side walls, and dome acting as one structure under all possible loading conditions. The liner is anchored to the concrete shell by means of anchors so that it forms an integral part of the entire composite structure under all loadings. The reinforcing in the structure will have an elastic response to all loads with limited maximum strains to ensure the integrity of the steel liner. The lower portions of the cylindrical liner are insulated to avoid buckling of the liner due to restricted radial growth when subjected to a rise in temperature.
A welded steel liner of thicknesses varying from 1/4 inch to 1/2 inch is anchored to the inside face of the concrete shell with 1/2 inch diameter studs to ensure containment leak tightness.
Each liner plate splice in the dome, cylinder, and mat is covered by a steel channel (Note -
throughout this document these channels are referred to as either liner plate monitor channels or leak chase channels). The steel channels are embedded in the concrete mat. To prevent any possible shearing of the channels from the differential movement between the liner plate and the inner concrete slab, they are isolated from the concrete by 1/4 inch of asphalt impregnated expansion material, and Styrofoam all around. Where there are a large number of penetrations in one area, the thickness of the liner plate is increased from 3/8 inch to 3/4 inch for reinforcement.
The original intent of the steel channels was for leak testing the liner welds. However, leak testing is performed in accordance with 10CFR50, Appendix J, "Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors," instead of pressurizing the liner weld channels.
The 3/4-inch knuckle plate connects the cylinder liner to the base liner. The thicker plate is used to resist buckling due to concentrated loadings from liner anchors in the base mat and also to take care of the warped surface created by the double curvature at the junction.
The inside surface of the liner plate in the cylinder and dome is coated with a Service Level I coating system as defined in USNRC Regulatory Guide 1.54, Rev. 0. Coating system repairs are performed in accordance with procedures that are consistent with the application of a Service Level I coating system with limited exceptions that are tracked as non-qualified coatings. A train of strainer modules has been connected to the containment sump at the 78-ft elevation of the containment structure for retaining coating debris to mitigate recirculating water flow blockage following a design basis accident.
5

LR-N23-0005                                                                  LAR S22-04 Enclosure Liner Insulation The liner insulation extends from just above the bottom floor at elevation 78' to approximately elevation 110' except locally around some liner penetrations and around other interferences. The insulation consists of 2" thick semi-rigid thermal blocks manufactured from refractory fibers bonded with intermediate temperature binder. The fibrous joints mesh closely to give a monolithic, continuous insulation.
Penetrations In general, a penetration consists of a sleeve embedded in the concrete wall and welded to the containment liner. The weld to the liner is shrouded by a continuous channel which is test pressurized to demonstrate the integrity of the penetration-to-liner weld joint. The pipe, electrical conductor, duct, or equipment access hatch passes through the embedded sleeve and the end of the resulting annulus is closed off, either by welded end plates, bolted flanges, or a combination of these. Provision has been made for differential expansion and misalignment between each pipe and sleeve. No piping loads are imposed on the liner. Pressurizing connections are provided to demonstrate the integrity of the penetration assemblies.
There are three large openings that significantly perturb the reinforcing pattern. One is the equipment hatch with an 18-foot diameter outer barrel; the others are two personnel hatches with 9 foot-9-inch diameter outer barrels. The main wall reinforcing, consisting of vertical and horizontal reinforcing bars, is bent around all the openings. Continuity of shell reinforcement is therefore maintained. For large openings, in addition to these bars, circular reinforcing bars have been provided to take care of axial thrust and principal moments around the opening. Radial stirrups have been provided to take care of the torsion and shear. This combination of reinforcing bars takes care of all primary and secondary stresses.
Equipment and Personnel Access Hatches Equipment and personnel access hatches are fabricated from A516, Grade 60 steel normalized to A300 requirements. All personnel locks and the portion of the equipment access hatch extending inside the containment structure beyond the concrete shell are designed in accordance with ASME Boiler and Pressure Vessel Code, Section III, Class B. The Code was used as a guide; therefore, the N Stamp requirement is waived.
The hatch barrel is embedded in the containment wall and welded to the liner. Provision is made to test pressurize the space between the double gaskets of the door flanges and the weld seam channels at the liner joint, hatch flanges, and dished door. The personnel hatches will be double door, mechanically latched, welded steel assemblies. A quick-acting type equalizing valve connects the personnel hatch with the interior of the containment vessel for the purpose of equalizing pressure in the two systems when entering or leaving the containment. The personnel hatch doors are interlocked to prevent both being opened simultaneously and to ensure that one door is completely closed before the opposite door can be opened. Remote indicating lights and annunciators situated in the control room indicate the door operational status. Provision is made to permit bypassing the door interlocking system to allow doors to be left open during plant cold shutdown. Each door lock hinge is designed to be capable of independent three-dimensional adjustment to assist proper seating. An Emergency Lighting and Communication System powered from an external emergency power supply are provided in the lock interior. Emergency access to either the inner door, from the containment interior; or to the outer door, from outside, is possible by the use of special door unlatching tools.
6

LR-N23-0005                                                                    LAR S22-04 Enclosure Pressure and monitoring taps are provided to pressure test the double gaskets on each door to a "between the seals test pressure" of 10 psig.
Tie-downs are used to prevent the inner door from becoming unseated during pressure tests.
The yoked ends of the tie-downs are pin connected to the horizontal stiffeners at the door, and the threaded ends of the tie-downs are slipped through the holes of the tie-down beams and secured with nuts.
Piping Penetrations High integrity piping penetrations are provided for all piping passing through the containment.
The pipe is centered in the embedded sleeve which is welded to the containment liner. Seal plates are welded to the pipe at both ends of the sleeve. In some instances, several pipes pass through the same embedded sleeve to minimize the number of penetrations required. In such cases, each pipe is welded to the inside seal plate and to the expansion bellows which is, in turn, welded to the outside seal plate. Large single pipe containment penetrations were installed with expansion test bellows, attaching the process piping to the penetration sleeves, which allowed for Appendix J type "B" pressure testing of the compartment formed between the process piping and the embedded sleeve, via a test connection on the bellows.
Containment piping penetrations designed for Salem are not required to be type "B" tested for 10CFR50 Appendix J. The type "B" test is applicable to piping penetrations that utilize expansion bellows as the leakage limiting boundary. The piping penetrations at Salem rely on partial/full penetration seal welds inside containment as the leakage limiting boundary, which are leak rate tested as part of the Appendix J type "A" containment Integrated Leak Rate Test (ILRT).
Therefore, for containment piping penetrations, leak rate testing of separate penetrations (type B" testing) has been replaced by the containment integrated leak rate test (type "A" testing) as allowed by 10CFR50 Appendix "J".
In the case of piping carrying hot fluid, the pipe is insulated, and cooling is provided to limit the concrete temperature adjacent to the embedded sleeve to 150oF.
For the larger hot pipe penetrations, strong anchoring is necessary. The anchors engage a large segment of the wall to adequately resist thrusts.
Should a piping failure occur within the containment, the additional loading imposed upon the penetration is transmitted through the anchor to the containment structure. Therefore, no permanent deformation of the penetration will be realized. Moment eliminators are installed outside of the containment structure. Hangers and limit stops assist in supporting and reducing any moment loading of a free-hanging pipe.
Electric Penetrations Power, control, fiber optic, and shielded conductors are assembled in canisters which have been inserted in and welded to nozzles in the field. A prototype of each type of penetration has been factory tested at 271oF and 62 psig in a steam chamber. Tests prove the ability of prototypes to function properly, electrically, and mechanically, before, during, and after subjection to these conditions. Each penetration is factory tested before shipment to verify that the leakage rate does not exceed 1 x 10-6 cc/sec at one atmosphere differential when tested with dry helium.
7

LR-N23-0005                                                                 LAR S22-04 Enclosure There are 56 electrical penetrations per unit.
3.1.2   Containment Isolation System The Containment Isolation System provides the means of isolating the containment atmosphere and the reactor coolant system (RCS) as required to prevent the release of radioactivity to the outside environment in the event of a LOCA.
Design Bases The following conditions and definitions are used in the design of the Containment Isolation System to assure that subsequent to an accident, there will be two barriers between the atmosphere outside the containment and the containment atmosphere.
: 1.      The design parameters of all piping and connected equipment within the isolated boundaries are equal to or greater than the Design Bases Accident (DBA) environment of the containment, 47 psig, 271&deg;F.
: 2.      All valves and equipment which are isolation barriers are protected against missiles and water jets, both inside and outside the containment.
: 3.      Lines which, due to safety considerations, must remain in service subsequent to certain accidents have, as a minimum, one manual isolation valve outside the containment.
: 4.      All isolation valves and equipment are designed to Class I seismic criteria.
: 5.      Per acceptance methods of General Design Criteria 55 and 56 and ANS N271-1976/ANS 56.2 the two barriers may consist of: (a) two closed piping systems or vessels, one inside and one outside the containment, (b) two automatic isolation valves, one inside and one outside the containment, (c) an automatic isolation valve inside the containment and a closed system outside the containment, (d) an automatic isolation valve outside the containment and a closed system inside the containment, or (a) an automatic isolation valve outside containment and a closed system outside the containment.
: 6.      A check valve on an incoming line or a normally closed valve is considered an automatic valve.

===System Description===
The following four classes of piping arrangement are provided in the Containment Isolation System.
Class A Class A piping is connected to a normally closed system outside the containment and is separated from the RCS and the containment atmosphere by a closed system inside the containment.
For Class A piping, no additional valves are required for isolation.
Class B Class B piping is connected to open systems outside the containment and is connected to the RCS or is open to the containment atmosphere.
8

LR-N23-0005                                                                 LAR S22-04 Enclosure For Class B piping, the following is provided, as a minimum, for isolation:
: 1.      Incoming Lines: Two auto-trip valves (one inside, one outside), or a check valve inside and an auto-trip valve outside.
: 2.      Outgoing Lines: Two auto-trip valves (one inside, one outside).
Class C Class C piping is connected to open systems outside the containment, and is separated from the RCS and the containment atmosphere by a closed system.
For Class C piping, the following is provided, as a minimum, for isolation:
: 1.      Incoming Lines: One check valve or auto-trip valve outside. No valve inside.
: 2.      Outgoing Lines: one auto-trip valve outside. No valve inside.
Class D Class D piping is connected to a closed system outside the containment and is connected to the RCS or is open to the containment atmosphere.
For Class D piping, the following is provided, as a minimum, for isolation:
: 1.      Incoming Lines: One auto-trip valve or check valve inside. No valve outside.
: 2.      Outgoing Lines: One auto-trip valve inside and no valve outside. Alternately, one auto-trip valve outside and no valve inside.
In addition to Classes B and C, for lines 1-inch nominal pipe size and larger which penetrate the containment, and which are connected to the RCS, at least two valves are provided inside the containment. The valves are normally closed or have automatic closure. For incoming lines, check valves are permitted and are considered as automatic. Piping which penetrates the containment, but which represents normally closed lines, also falls under this criterion. In this case, manual isolation valves are acceptable.
In order to be considered a "closed" system inside containment, a system must meet the following requirements:
: 1.      Does not communicate with either the RCS or the containment atmosphere.
: 2.      Safety classification same as for engineered safety systems.
: 3.      Must withstand external pressure and temperature equal to containment design pressure and temperature.
: 4.      Must withstand accident transient and environment.
: 5.      Must be missile protected.
9

LR-N23-0005                                                                    LAR S22-04 Enclosure In order to be considered a "closed" system outside containment, a system must meet the following requirements:
: 1.      Does not communicate with the atmosphere outside the containment.
: 2.      Safety classification same as for engineered safety systems.
: 3.      Internal design pressure and temperature must be at least equal to containment design pressure and temperature.
For incoming lines to the containment, check valves are used whenever an additional barrier is provided. Use of check valves in this service is confined to either liquid lines or lines that are closed outside the containment. These check valves shut under a differential pressure (d/p) when the higher pressure is on the containment side of the check valve.
These isolation valving arrangements were designed in accordance with Atomic Energy Commission (AEC) proposed General Design Criteria published in 1967, which were in effect at the Construction Permit stage. The valving arrangements that deviate from AEC General Design Criteria 55, 56, and 57 dated July 7, 1971, are the following:
: 1.      Residual Heat Removal (RHR) connections between the RCS and the RHR pumps.
Redundant isolation protection is provided by a normally closed motor operated valve inside the containment and the closed system (RHR) outside the containment.
: 2.      Seal water supply line from the seal water injection filters to the reactor coolant pump seals. Redundant isolation protection is provided by a check valve inside the containment and the closed Chemical and Volume Control System (CVCS) outside the containment.
: 3.      Safety injection recirculating suction line from the containment sump to the suction of the RHR pumps. Redundant isolation protection is provided by normally closed motor operated valves inside protective chambers outside of containment and the closed system (RHR) outside the containment.
: 4.      Containment instrument lines (see below).
: 5.      The main feedwater lines are provided with one stopcheck valve (BF22) outside containment. These valves include remote-manual motor operators.
: 6.      RHR pump discharge to cold leg Safety Injection. Redundant isolation is provided by the remote manual (SJ49) valves located outside containment and the RHR closed system outside containment. This is considered an acceptable isolation barrier per the other defined basis" in ANSI N271-1976. This standard is endorsed by Regulatory Guide 1.141.
: 7.      ECCS relief line discharge to the containment sump. Redundant isolation is provided by a check valve inside containment (PR25) and the closed system outside the containment.
: 8.      Service Water system to and from the Containment Fan Coil Units. Redundant isolation is provided by remote manual valves outside containment and the closed Nuclear Class III system inside containment. Original system design complied with AEC General Design Criteria 53 and the system meets the definition for a Safety Class 2 system.
10

LR-N23-0005                                                                  LAR S22-04 Enclosure
: 9. Component Cooling to and from the Excess Letdown Heat Exchanger. Redundant isolation is provided by automatic isolation valves outside containment and the closed Nuclear Class III system inside containment. Original system design complied with AEC General Design Criteria 53 and the system meets the definition for a Safety Class 2 system.
: 10. Main Steam supply lines to the Auxiliary Feed Pump Turbine, Radiation Monitors and the Steam Safety valves support struts. These essential system branch lines off the Main Steam penetrations only utilize a single isolation barrier being the closed system inside containment. The calculated release through these paths is already bounded by the accident analysis for a primary to secondary leak and a complete blowdown of the Steam Generator.
Instrument Lines Instrument lines which penetrate the containment are the following:
: 1. The containment pressure instrument used to initiate safeguards consists of four instrument lines penetrating the containment. Each line consists of a sealed, filled measuring system whose isolation consists of a diaphragm-type sensor which separates the containment atmosphere from the seal fluid and another diaphragm in the transmitter which separates the seal from the atmosphere outside the containment.
: 2. The containment air sample radiation monitor normal inlet and outlet sample lines are each equipped with two automatic trip valves, one inside and one outside the containment, which close upon receipt of a containment isolation phase A signal. The backup inlet and outlet sample lines are normally closed and under administrative control with two remote operated isolation valves, one inside and one outside the containment for each line.
: 3. The containment pressure instrument used for wide range monitoring consists of two instrument lines penetrating the containment. Each line consists of a sealed, filled measuring system whose isolation consists of a diaphragm-type sensor, which separates the containment atmosphere from the seal fluid and another diaphragm in the transmitter, which separates the seal from the atmosphere outside containment.
: 4. The pressurizer dead-weight pressure calibrator has a single line penetrating the containment. Isolation is accomplished with two manual valves located just outside the containment. These manual valves are normally closed and are opened only under administratively controlled conditions.
: 5. Three lines penetrate the containment for instrumentation required for leak rate testing.
Each line is isolated with two manual valves, one inside and one outside containment.
These valves are normally closed and under administrative control.
These provisions meet the requirements of Regulatory Guide 1.11.
11

LR-N23-0005                                                                   LAR S22-04 Enclosure Containment Isolation Valve Summary Table TR 3.6-1 of the Salem Technical Requirements Manual (TRM) provides a listing of the major piping penetrations through the reactor containment for each fluid system and summarizes the specific isolation provision of each penetration.
The 20-inch inside diameter fuel transfer tube between the refueling canal inside the containment and the fuel transfer pool is sealed with a blind flange inside the containment, redundant isolation is provided by a double o-ring seal on the flange. The terminus of the tube outside the containment is closed by a gate valve which is not a containment isolation valve.
The equipment hatch (door) is under administrative control to assure that it is properly closed and sealed whenever containment integrity is required. No instrumentation is provided for the equipment hatch.
The main steam isolation valves (MSIVs) fulfill their containment isolation function as remote-manual containment isolation valves. The automatic closure of the MSIVs is not required for containment isolation due to having a closed system inside containment. The remote-manual containment isolation function of the MSIVs can be accomplished through either the use of the hydraulic operator or when the MSIV has been tested in accordance with Technical Specification 4.7.1.5, the steam assist closure function can be credited.
Valve closing time using the hydraulic actuator is approximately six minutes. The closure time for establishing containment isolation is that necessary to significantly limit the release of radioactivity to the environment. MSIV fast closure is not required for containment isolation in any operating Mode because the steam generator shell and main steam piping serve as the primary barrier for a LOCA. For the LOCA, the design basis does not assume a concurrent feedwater or steam line break. The main steam system does not directly connect to the reactor coolant system or the containment atmosphere. However, a steam generator tube break or rupture makes a connection between the RCS and the secondary side systems via the main steam system. The Updated Final Safety Analysis Report (UFSAR) Chapter 15 Steam Generator Tube Rupture (SGTR) accident analysis assumes a coincidental loss of offsite power that causes the steam dump valves to close, protecting the condensers. For the Mode 1 or 2 SGTR Chapter 15 accident analysis, isolation of the faulted steam generator is assumed to occur within 30 minutes as necessary to limit the release of radioactivity to the environment via the steam generator Power Operated Relief Valves (PORV) or safety relief valves. Isolation of the faulted steam generator also limits the spread of radioactivity to the interconnected steam generators, at least one of which will be used to cooldown the RCS until RHR can be initiated at 32 hours post-accident.
During low temperature (<375&deg;F) Mode 3 and Mode 4 operations, there is insufficient energy transferred to the secondary side in a SGTR or steam generator tube leak to result in lifting the steam generator PORVs or safety relief valves and there will be no release of radioactivity to the environment.
Use of the remote-manual, hydraulic actuator for containment isolation in low temperature
(<375&deg;F) Mode 3 and Mode 4 is satisfactory because even if isolation of the faulted steam generator fails, the failure will not increase the dose consequences beyond the existing Chapter 15 SGTR accident analysis that remains bounding.
12

LR-N23-0005                                                                     LAR S22-04 Enclosure 3.1.3    Steam Generator Replacements The SNGS Unit 1 Steam Generator Replacement (SGR) was performed during the extended shutdown of 1R12, April 1995 -through April 1998. The SNGS Unit 2 SGR was performed during 2R16, March 11, 2008, through May 8, 2008. Both SNGS Units 1 and 2 Steam generator replacements were performed using the installed Equipment Hatches. No modifications to containment were required.
3.1.4    Airlock Containment Vent Fitting - FLEX Analysis of the containment response during a Beyond Design Basis External Event (BDBEE),
indicated that containment pressure could challenge the design pressure due to the loss of AC power needed to utilize current design features. As a result, the strategy was developed to vent the containment using the personnel airlock vent valves. Normal venting is not available due to the loss of all AC power. In order to vent, a connection point was required to allow attachment of the vent hose.
A nominal 2.5 vent fitting was installed to the inner bulkhead of Unit 1 and 2 100ft and 130 ft containment airlocks. The fittings were attached by inserting a steel pipe approximately 1/2 inch into the exit port of the inboard vent valve. The pipe was welded at the bulkhead wall.
The vent modifications were subjected to non-destructive surface examinations. The installed fittings were pressurized to 47 psig and held for 10 minutes. Following the required hold time localized snooping inside the airlock on the fillet weld and adjacent steel immediately surrounding the welded attachment was performed. In addition, to satisfy the containment side bulkhead boundary integrity, the containment side bulkhead steel reinforcing pad and weld immediately surrounding the piping penetration leading to the equalizing valve was snooped.
3.1.5    Appendix J Liner Issues The SNGS liner plate was constructed with liner plate monitor channels. The original SNGS design/licensing basis did not take credit for the liner plate monitor channels and assumed the liner welds as the containment leakage boundary. The May 23, 1983 (Unit 2) and November 8, 1984 (Unit 1) ILRTs were performed without venting the plugged liner plate monitor channels.
PSEG submitted the justification for testing with the liner plate monitor channels plugged in letter NLR-N90016 dated January 26, 1990 (Reference 48). In the NRC Safety Evaluation Report dated December 17, 1990 (Reference 23), the NRC specifically stated:
It is the staffs position that the channels need not be vented and may remain plugged if the licensee can demonstrate that:
(a)      the channel welds are qualitatively equivalent to or better than those for primary containment liner welds (b)      the channel would maintain their integrity when subjected to the loading conditions of a postulated design basis accident as well as during normal operation, and (c)      the inspection and reporting of tests are in accordance with the requirements of a visual inspection of the accessible interior and exterior surfaces of the containment structures and components performed prior to any Type A test.
13

LR-N23-0005                                                                    LAR S22-04 Enclosure PSEG committed to perform a visual inspection of the accessible interior and exterior surfaces of the containment structure and components prior to a Type A test as required by 10 CFR Part 50, Appendix J; and to emphasize that since the plugged liner plate monitor channels serve as a pressure retaining boundary, they should be considered as part of the interior surfaces of containment for the purposes of the pre-test inspection.
In 1990 as part of the resolution of the above testing issues, a walkdown was performed by an Integrated Performance Assessment Team (IPAT) (NRC Inspection Report 50-272/311-90-81, Reference 34). The team identified corrosion was visible on portions of both containment building liners. The lower 34 feet of each liner is generally covered by insulation. Rust was visible on certain portions visible through gaps, on retention studs, and on the floor at the liner base. The licensee stated that an engineering evaluation would be performed during the next refueling outage which prompted a PSEG evaluation for the liner corrosion identified. This evaluation performed a visual inspection walkdown and assessment to address NRC Integrated Performance Assessment Team (IPAT) Question 272/311-90-81-Q0057. The evaluation discussed the containment liner plate attached to the inside surface of the containment shell, liner insulation/lagging, liner plate monitor) channels at the bottom of the insulation, top of insulation lagging, the Containment outside wall surface, and the inspection results. The evaluation concluded that the inspection results were acceptable. In summary, inspection of the different components of the liner plate showed nominal amount of degradation in several areas which pose no significant danger to the structural function of the liner plate. General housekeeping and cleanliness of the lagging, channels, floors and walls is required to preserve the life of these elements. At this time, it was concluded that although corrosion is present, it was not severe enough or prevalent enough to inhibit the liner plate from performing its design function as stated in the design basis.
ASME Section XI IWE/IWL SNGS IWE/IWL 1st 10-Year Interval Containment Inspection Program implementation started in 2000 as noted in Tables 3.1.5-1 and 3.1.5-2 below.
Table 3.1.5-1, 1st 10-Year Interval Containment Inspection Program Implementation SNGS UNIT 1 Refueling              Completed Period 1st CISI Interval                             Outage                 Outage Dates Number                   Dates 04/22/00               1R14            04/06/01 - 05/19/01 To 1R15            10/10/02 - 11/06/02 04/21/03 April 22, 2000          04/21/03               1R16            03/26/04 - 06/03/04 To                   To 1R17            10/11/05 - 11/06/05 April 21, 2010           3/26/07 3/26/07               1R18            03/27/07 - 04/20/07 To                  1R19            10/14/08 - 11/13/08 04/21/10               1R20            04/03/10 - 04/29/10 Bolded Outages were when the IWL examinations were completed 14

LR-N23-0005                                                               LAR S22-04 Enclosure Table 3.1.5-2, 1st 10-Year Interval Containment Inspection Program Implementation SNGS UNIT 2 Refueling           Completed Period 1st CISI Interval                             Outage             Outage Dates Number               Dates 04/22/00               2R11        10/06/00 - 11/15/00 To 2R12        04/05/02 - 05/17/02 04/21/03 April 22, 2000          04/22/03               2R13        10/04/03 - 11/03/03 To                   To                  2R14         04/05/05 - 5/11/05 April 21, 2010          04/21/07               2R15        10/10/06 - 11/01/06 04/22/07               2R16        03/11/08 - 05/08/08 To 2R17        10/13/09 - 11/11/09 04/21/10 Bolded Outages were when the IWL examinations were completed SNGS IWE/IWL 2nd 10-Year Interval Containment Inspection Program implementation started in 2010 as noted in Tables 3.1.5-3 and 3.1.5-4 below.
Table 3.1.5-3, 2nd 10-Year Interval Containment Inspection Program Implementation SNGS UNIT 1 Refueling           Completed Period 2nd CISI Interval                             Outage              Outage Dates Number                Dates 04/22/10               1R21         10/23/11 - 11/22/11 To 1R22         04/14/13 - 05/27/13 04/21/13 April 22, 2010          04/22/13               1R23         10/19/14 - 11/23/14 To                   To                  1R24         04/14/16 - 07/30/16 December 31, 2020          12/31/17              1R252         10/12/17 - 11/12/17 01/01/18               1R26         04/12/19 - 06/18/19 To 12/31/20              1R273         10/03/20 - 12/19/20 NOTES
: 1) Bolded Outages were when the IWL examinations were performed
: 2) 2nd Period was extended per IWA-2430(d)(3) to coincide with 1R25
: 3) 3rd Period was extended per IWA-2430(d)(3) to coincide with new Interval end date 15

LR-N23-0005                                                                   LAR S22-04 Enclosure Table 3.1.5-4, 2nd 10-Year Interval Containment Inspection Program Implementation SNGS UNIT 2 Refueling              Completed Period 2nd CISI Interval                              Outage                 Outage Dates Number                   Dates 04/22/10                                  04/09/2011 -
2R18 To                                       05/08/11 04/21/13               2R19            10/14/12 - 11/18/12 04/22/13               2R20            04/12/14 - 07/14/14 April 22, 2010              To                  2R21            10/22/15 - 12/01/15 To                  5/30/17              2R222            04/14/17 - 05/30/17 December 31, 2020 05/31/17 2R23            10/11/18 - 11/13/18 To 12/31/20 2R243            04/11/20 - 05/12/20 NOTES
: 1) Bolded Outages were when the IWL examinations were performed
: 2) 2nd Period was extended per IWA-2430(d)(3) to coincide with 2R22
: 3) 2nd Interval was extended per IWA-2430(d)(1) to include 2R24 SNGS Unit 1 & 2 Containment inspections between 2000 and 2022 had identified surface corrosion at several locations due to Service Water entering the liner insulation system through the top of flashing and at 78 floor elevation.
In the following discussion and throughout the remainder of the LAR any references to Unit 1 and 2 liner panel numbering are referenced to an elevation level followed by a liner panel number. For liner panels designated as 98-## or 100-##, these are the same liner panels (elevation 98 and 100 are synonymous, i.e., 98-2 and 100-2 are the same liner panel). The 100 panel lagging starts just below the grating and is designated in the IWE program as 98-##.
SNGS Unit 1 License Renewal Inspections (A.2.1.28)
For License Renewal, SNGS Unit 1 committed to inspect 82 random liner panel locations during outages 1R22, 1R23 and 1R24. There are a total of 348 Liner Panel locations, 116 on 3 elevations (78, 88 and 100). Of the original 82 locations no liner weld repairs were required.
During an extent of condition (EOC) liner panel inspection in the 1R24 Spring 2016 outage, corrosion was noted at bottom corner of panel 100-2 (elevation-panel number) leading to removing panel 100-3 where severe corrosion was identified which required Containment Liner weld build-up.
Additional EOC panels were removed adjacent to and below panel 100-3 during the 1R24 outage with no additional areas of concern identified. The primary cause of the severe corrosion of liner panel 100-3 was the top angle and top flashing of the liner was not sealed to prevent water in-leakage.
An EOC walkdown was performed during 1R24 outage to determine other potential locations with similar concerns. These locations were inspected during the 1R25 outage (Fall 2017) and 16

LR-N23-0005                                                                     LAR S22-04 Enclosure identified several additional areas requiring weld repairs. Additional openings in the top angle iron (where test piping was originally installed and subsequently removed) allowed water to enter the insulation system.
Six Unit 1 panels were identified with material loss requiring weld repair and subsequent testing in accordance with the SNGS Appendix J Program. Specifically, liner panels 100-032, 100-98, 100-099, 100-100, 100-104, and 100-105 had material loss in excess of 10% of the design thickness.
To test these areas, test boxes were welded to the liner and Type B LLRTs performed. An action limit of zero sccm was established which required an evaluation if the limit was exceeded. Only four test boxes achieved a leakage rate of zero sccm. The remainder had difficulty with achieving a leak free weld of the test box to the containment liner due to configuration and other issues.
These leak rates were evaluated as acceptable and added to the running summary of total leakage and will remain as a penalty until completion of the next Type A test.
The following list details the test result by liner panel grid location number:
Leakage Liner Panel Test location (sccm)
Containment Liner Panel 100-32-B10                              6.0 Containment Liner Panel 100-98-A10                            3213.0 Containment Liner Panel 100-98-B10, C10, D10                   280.0 Containment Liner Panel 100-99-C1                               0.0 Containment Liner Panel 100-99-D4                               2.0 Containment Liner Panel 100-100-A2                              0.0 Containment Liner Panel 100-100-A4                              0.0 Containment Liner Panel 100-100-A10                             38 Containment Liner Panel 100-100-A4-B13                          0.0 Containment Liner Panel 100-104-A9, B9                        1305.0 Containment Liner Panel 100-105-B6                              2.0 Total Leakage                                           4846.0 sccm More walk downs were performed during outage 1R25 with 13 additional locations identified where moisture intrusion was possible. These 13 additional inspection locations were performed during outage 1R26 (Spring 2019) where the entire top liner insulation flashing was removed to inspect the top angle and insulation system. The top flashing was reinstalled with additional fasteners and sealant to prevent water intrusion.
These 1R26 liner inspections resulted in four (4) additional liner locations requiring weld repairs, one of which was a through wall repair.
During the 1R26 examinations of containment liner panels, a thin groove in the containment liner was discovered behind a piping flange below service water restricting orifice S1SW -1RO385.
This groove appeared to be a grinding cut which penetrated the containment liner. The groove was located behind insulation panel 100-80 at UT grid location B-8. This panel is located on 100 foot elevation to the left of the 100'airlock as you face the airlock. The groove originated as result of a design modification installed in 2008. Salem completed a successful Type A test following the installation of modification including the groove in the liner. The groove was repaired by welding and a Type B mechanical LLRT performed following the repair during 1R26. The LLRT result of 5.0 sccm was added to the running leakrate summary and will be carried in the summary until the next Type A test.
17

LR-N23-0005                                                                   LAR S22-04 Enclosure During outage 1R27 (Fall 2020) the final portion of EOC and License Renewal first random expansion samples were complete with no weld repairs required.
The 1R28 (Spring 2022) outage did not require any License Renewal liner panel Inspections.
The 1R29 (Fall 2023) outage has 4 random panel inspections scheduled and is a 100% IWE and IWL outage.
A total 177 of 348 liner panel locations have been inspected at SNGS Unit 1, approximately 51%
of the insulated locations.
SNGS Unit 2 License Renewal Inspections (A.2.1.28)
For License Renewal, SNGS Unit 2 committed to inspect 72 random liner panel locations during outages S2R19, S2R20 and S2R21. There are a total of 318 Liner Panel locations, 106 on three elevations (78, 88, and& 100). The Liner Panels are slightly different widths between Unit 1 & 2.
Of the initial original 72 locations, no Liner Weld Repairs were required with no expanded sample required for Unit 2 at that time (see discussion below for repair required on one of these 72 locations during outage 2R23).
Historically inspection of the SNGS Unit 2 containment liner revealed areas of heavy corrosion at the interface between the concrete floor at 78 elevation and the liner. The heaviest corrosion is on the horizontal liner plate monitor channels several inches above the 78 floor elevation.
SNGS Unit 2 Containment IWE inspections between 2000 and 2017 had identified surface corrosion at several locations due to Service Water entering the liner insulation system through the top of flashing and at the 78 floor elevation.
During the 2R17 (Fall 2009) outage, license renewal inspections required removal of the insulation lagging in order to completely expose the moisture barrier. The inspection identified corrosion in general areas at the 78' elevation. The observed corrosion included the containment liner and portions of the vertical liner plate monitor channels in the knuckle plate region of the liner.
The corrosion had reduced the exposed containment liner below the design nominal 3/4-inch wall thickness. The thinnest wall thickness from UT measurements was 0.677 inches. The corrosion also resulted in removal of the protective coating on the liner, which could lead to further corrosion. The accessible portions of the entire knuckle plate was cleaned and recoated.
The vertical liner plate monitor channels exhibited corrosion loss of as much as 0.17 inches (i.e.,
through wall). Subsequent testing using a hammer breached six (6) vertical channels. The concern is that this provides a potential path for water to migrate down the vertical liner plate monitor channels, possibly corroding the bottom liner plate in both the exposed and unexposed section of the containment liner. These liner plate monitor channels were cut and capped.
The 2R19 (Fall 2012) outage was the first of three outages that initial IWE liner panel random sample was performed which included 25 locations. These inspections resulted in three additional locations being inspected. No weld repairs were required; however, stud replacement and coating repairs were required.
18

LR-N23-0005                                                                   LAR S22-04 Enclosure The 2R20 (Spring 2014) outage was the second of three outages that initial IWE liner panel random sample was performed which included 44 locations. These inspections resulted in 11 additional locations being inspected including a portion of the subsequent 2R21 outage scope.
No weld repairs were required; however, stud replacement and coating repairs were required.
While performing 2R20 Section XI Containment (IWE) moisture barrier examinations, rust staining was identified on the surface of moisture barrier and 78 containment floor.
Rust staining was found to be originating from underneath the containment liner insulation panels.
This staining was most severe adjacent to and behind the Pressurizer Relief Tank (PRT). Other locations identified were at insulation panel locations 1, 14, 79 on the 78 elevation of containment. Upon removal of the insulation system the source of rust staining was found to be degrading horizontal liner plate monitor channels just above the 78 elevation floor. Historical service water management practices and condensation from piping allowed water on the floor to migrate under the lagging which caused the liner plate monitor channels to degrade.
The entire containment liner area where lagging was removed was examined visually. After removing the insulation system at each identified location, UT thickness measurements were performed. No wall loss exceeding the design minimum wall criteria was identified, and no rust staining was observed on the coated containment liner plates above the horizontal liner plate monitor channels. The horizontal liner plate monitor channels, where the rust staining was originating from, were found degraded. The degraded liner plate monitor channels were removed to perform UT thickness examination of containment liner inside liner plate monitor channels.
Examination revealed no wall loss exceeding the design minimum wall criteria and very little surface corrosion. In conclusion, the inaccessible containment liner plates beneath the insulation system where rust staining was observed had no significant wall loss. Liner plate monitor channels that were found degraded were permanently removed and sealed.
Additional 2R20 actions Inspected the insulation system above the areas where rust staining was identified for leak tightness. One area on the 100 elevation was discovered where insulation was open and was subsequently repaired and sealed.
Removed Insulation panels 78-1, 78-14, and 78-79 on the 78 elevation of Containment behind the pressurizer relief tank (PRT). The source of rust staining was discovered to be degraded liner plate monitor channels underneath the insulation panels.
The degraded liner plate monitor channels were removed. Visual and UT thickness examinations of the containment liner plate inside the leak test channels were performed. No significant corrosion of the containment liner was identified.
The areas inside the liner plate monitor channels were cleaned and coated to prevent further corrosion and the ends of remaining liner plate monitor channels were sealed to prevent moisture intrusion.
The 2R21 (Fall 2015) outage was the third of three outages that initial IWE liner panel random sample was performed which included 5 locations. No weld repairs were required; however, stud replacement and coating repairs were required.
No IWE or liner inspections were performed during the 2R22 (Spring 2017) outage.
19

LR-N23-0005                                                                     LAR S22-04 Enclosure During 2R23 (Fall 2018) outage, inspections of the containment liner required for License Renewal, ASME Section XI, IWE exams, and extent of condition exams of the containment liner insulation system were performed. One panel and three knuckle plates were identified with material loss requiring weld repair. Specifically, liner panels 100-1 and 106 on the 100 elevation and panels 78-90, 78-91 and 78-92 on the 78 elevation had material loss in excess of 10% of the design minimum wall thickness.
Discrepancies with the installation of the containment liner insulation lagging were identified during the License Renewal inspections. Expanded scope inspections were performed to determine if there was any impact to the containment liner based on these discrepancies.
The expanded scope inspections identified heavy surface corrosion on the containment liner on liner panel 100-1 where a 6-inch by 6-inch construction bracket was severely corroded. The bracket was removed and the liner thickness in that area had several readings below 0.338-inches with the lowest reading at 0.169-inches. The nominal thickness of liner panel 100-1 is 0.375-inches with a design thickness requirement (Tmin) of 0.333-inches. This location 100-1 was previously inspected but the area of corrosion around bracket was not identified. As a result of this random liner panel location requiring repair, an expanded random sample was established (first expansion).
Panel 100-1 was repaired by weld build-up to an appropriate thickness.
ASME Section XI, IWE, exams on the containment liner identified excessive corrosion on the knuckle plate on the 78 elevation. Heavy corrosion of the knuckle plate between the concrete floor and the horizontal liner plate monitor channel about four inches above the concrete floor was identified. In two locations, a hole was identified in the vertical liner plate monitor channels (C3 &
C50) running from the horizontal liner plate monitor channel down below the concrete; and degradation of vertical liner plate monitor channel C47. The liner plate monitor channels were repaired and sealed.
During planned containment liner moisture barrier inspections in accordance with ASME Section XI subsection IWE, degradation was identified. There was 130 linear feet of 440 total linear feet of moisture barrier identified as degraded. Actions for EOC included cutting the moisture barrier flush with the 78 elevation floor. The underlying containment liner knuckle plate was cleaned and inspected with UT thickness measurements. The initial UT thickness inspections of the 130' area after cleaning indicated several areas potentially requiring corrective measures (repair or evaluation). Engineering requested validation of these low areas and requested mapping of area for repairs. Additional UT thickness measurements were obtained in these areas resulting in an approximately 10 foot long by 3 inch wide area of knuckle plate below acceptable wall thickness.
The thinnest areas were 0.100 inch with a nominal wall thickness of 0.750 inch and a design minimum wall thickness of 0.370 inch. The containment liner knuckle plate required weld repairs, including concrete excavation to accommodate the weld repair, and required local leak rate testing.
Subsequent testing was performed in accordance with the SNGS Appendix J Program.
Specifically, liner panel 100-1 and the knuckle plates on liner panels 78-90, 78-91, and 78-92 had material loss in excess of 10% of the design minimum wall thickness. To test these areas, 8 test boxes were affixed to the liner and Type B LLRTs performed. The test boxes did not achieve a leak tight seal due to difficulties with obtaining even gasket compression and other test 20

LR-N23-0005                                                                   LAR S22-04 Enclosure configuration issues. These leak rates were evaluated as acceptable and added to the running summary and will remain as a penalty until completion of the next Type A test.
The following list details the test results by liner panel grid location number:
Leakage Liner Panel Test location (sccm)
Containment Liner Panel 100-1/106 (LLRT 1)                      422 Containment Liner Panel 78-90 (LLRT 89-1)                       420 Containment Liner Panel 78-90 (LLRT 90-1)                       155 Containment Liner Panel 78-91 (LLRT 90-2)                        23 Containment Liner Panel 78-91 (LLRT 90-3)                       399 Containment Liner Panel 78-91 (LLRT 91-1)                        11 Containment Liner Panel 78-92 (LLRT 91-2)                        29 Containment Liner Panel 78-92 (LLRT 91-3)                       231 Total Leakage                                            1690.0 sccm During the 2R24 (Spring 2020) outage, a portion of the first random sample expansion and EOC inspections were performed for a total of 25 liner panel locations. Repairs during 2R24 were coating repairs, insulation stud replacement and liner plate monitor channel removal.
During the 2R25 (Fall 2021) outage, the remainder of the first random sample expansion and a few EOC inspections were performed for a total of 47 Liner Panel locations. Repairs conducted during 2R25 consisted of coating repairs, insulation stud replacement and liner plate monitor channel removal. One random location required weld repair and resulted in an additional second expanded License Renewal Aging Management IWE Liner sampling plan. The scope of the second additional sample included inspection of 30 random liner panels that are scheduled for the S2R27 outage.
100% IWE and 100% IWL inspections are scheduled in 2023 (IWE during 2R26 outage, IWL on-line after 2R26 outage).
30 random (2nd expansion) liner panels are scheduled for inspection in the 2R27 (Fall 2024) outage.
A total of 153 of 318 liner panel locations have been inspected at SNGS Unit 2, approximately 48% of the insulated locations.
3.2      Net Positive Suction Head (NPSH) and Spray Water Entrapment Spray recirculation has been evaluated considering loss of water through entrapment outside the containment sump. There are three areas within the containment where reactor coolant blowdown liquid and spray water may become trapped: the reactor cavity, the refueling canal, and the reactor instrumentation tunnel. The reactor cavity has ventilation openings around the reactor that would allow spray water to drain to the lower elevations of the containment. The refueling canal is normally isolated from the Fuel Handling Building and would trap no more than 9,500 gallons of liquid from Containment Spray System. The instrumentation tunnel has a water capacity of approximately 70,000 gallons, none of which would drain to the sump.
21

LR-N23-0005                                                                   LAR S22-04 Enclosure The total quantity of water released to the containment at the beginning of the recirculation phase of the Containment Spray System operation, assuming a DBA with reactor coolant loop piping half full of water, is approximately 275,000 gallons. Discounting the water volume trapped in the refueling canal and the reactor instrumentation tunnel, the volume available at the suction of the RHR pump used for containment spray is approximately 190,000 gallons. The required NPSH for the RHR pump is a water level relative to the bottom (Elevation 70 feet) of the 8-foot-deep containment sump. The indicated available water volume is a water level several feet above the containment sump top. There is therefore no significant effect on the required static head for the RHR pump.
Available and required NPSH for the containment spray pumps and the RHR pumps are provided in Table 3.2-1.
Table 3.2-1, Net Positive Suction Heads for Containment Spray Suction      Minimum                   Maximum Flow and                                Required Pump          Elevation                   Source and     Available                   Water Condition                                 NPSH Elevation       NPSH                   Temperature Containment                     2600 gpm        RWST 86'-3"                                     29.9'        10'         100oF Spray                       Rated Flow      101'-8" Residual Heat 4850 gpm     Containment Removal (Unit 46'-10"    Recirculation     Sump           28.1'        22'       Saturation 1 one Pump Spray Flow       81'-8" Operation)
Residual Heat 4850 gpm     Containment Removal (Unit 46'-10"    Recirculation     Sump           25.7'        22'       Saturation 2 one Pump Spray Flow       81'-8" Operation)
The available NPSH was calculated for the pumps indicated above using the following conservative assumptions:
: 1. All calculations assume an empty refueling water storage tank.
: 2. No credit is taken for RWST fluid below 100&deg;F.
: 3. No credit is taken for increased containment pressures following the LOCA.
3.3   Justification for the TS Change 3.3.1    Chronology of Testing Requirements of 10 CFR 50, Appendix J The testing requirements of 10 CFR 50, Appendix J, Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors, provide assurance that leakage from the containment, including systems and components that penetrate the containment, does not exceed the allowable leakage values specified in the TS. 10 CFR 50, Appendix J also ensures that periodic surveillances of reactor containment penetrations and isolation valves are performed so that proper maintenance and repairs are made during the service life of the containment and of the systems and components penetrating primary containment. The limitation on containment leakage provides assurance that the containment would perform its design function following an accident up to and including the plant DBA. Appendix J identifies three types of required tests:
: 1)      Type A tests, intended to measure the primary containment overall integrated leakage rate; 22

LR-N23-0005                                                                    LAR S22-04 Enclosure
: 2)      Type B tests, intended to detect local leaks and to measure leakage across pressure-containing or leakage-limiting boundaries (other than valves) for primary containment penetrations, and;
: 3)      Type C tests intended to measure containment isolation valve (CIV) leakage rates.
Types B and C tests identify the vast majority of potential containment leakage paths. Type A tests identify the overall (integrated) containment leakage rate and serve to ensure continued leakage integrity of the containment structure by evaluating those structural parts of the containment not covered by Types B and C testing.
In 1995, 10 CFR 50, Appendix J, was amended to provide a performance-based Option B for the containment leakage testing requirements. Option B requires that test intervals for Type A, Type B, and Type C testing be determined by using a performance-based approach. Performance-based test intervals are based on consideration of the operating history of the component and resulting risk from its failure. The use of the term "performance-based" in 10 CFR 50, Appendix J refers to both the performance history necessary to extend test intervals as well as to the criteria necessary to meet the requirements of Option B.
Also in 1995, RG 1.163 (Reference 1) was issued. The RG endorsed NEI 94-01, Revision 0, (Reference 5) with certain modifications and additions. Option B, in concert with RG 1.163 and NEI 94-01, Revision 0, allows licensees with a satisfactory ILRT performance history (i.e., two consecutive, successful Type A tests) to reduce the test frequency for the containment Type A (ILRT) test from three tests in 10 years to one test in 10 years. This relaxation was based on an NRC risk assessment contained in NUREG-1493, (Reference 6) and Electric Power Research Institute (EPRI) TR-104285 (Reference 7), both of which showed that the risk increase associated with extending the ILRT surveillance interval was very small. In addition to the 10-year ILRT interval, provisions for extending the test interval an additional 15 months were considered in the establishment of the intervals allowed by RG 1.163 and NEI 94-01, but that this extension of interval "should be used only in cases where refueling schedules have been changed to accommodate other factors."
In 2008, NEI 94-01, Revision 2-A (Reference 8), was issued. This document describes an acceptable approach for implementing the optional performance-based requirements of Option B to 10 CFR 50, Appendix J, subject to the limitations and conditions noted in Section 4.0 of the NRC safety evaluation (SE) report (SER) on NEI 94-01. NEI 94-01, Revision 2-A, includes provisions for extending Type A ILRT intervals to up to 15 years and incorporates the regulatory positions stated in RG 1.163 (Reference 1). The document also delineates a performance-based approach for determining Type A, Type B, and Type C containment leakage rate surveillance testing frequencies. Justification for extending test intervals is based on the performance history and risk insights.
In 2012, NEI 94-01, Revision 3-A (Reference 2), was issued. This document describes an acceptable approach for implementing the optional performance-based requirements of Option B to 10 CFR 50, Appendix J and includes provisions for extending Type A ILRT intervals to up to 15 years. NEI 94-01 has been endorsed by RG 1.163 and NRC SERs of June 25, 2008 (Reference 9), and June 8, 2012 (Reference 10), as an acceptable methodology for complying with the provisions of Option B in 10 CFR 50, Appendix J. The regulatory positions stated in RG 1.163, as modified by References 9 and 10, are incorporated in NEI 94-01, Revision 3-A. It delineates a performance-based approach for determining Type A, Type B, and Type C 23

LR-N23-0005                                                                  LAR S22-04 Enclosure containment leakage rate surveillance testing frequencies. Justification for extending test intervals is based on the performance history and risk insights.
Extensions of Type B and Type C test intervals are allowed based upon completion of two consecutive periodic as-found tests where the results of each test are within a licensees allowable administrative limits. Intervals may be increased from 30 months up to a maximum of 120 months for Type B tests (except for containment airlocks) and up to a maximum of 75 months for Type C tests. If a licensee considers extended test intervals of greater than 60 months for Type B or Type C tested components, the review should include the additional considerations of as-found tests, schedule and review as described in NEI 94-01, Revision 3-A, Section 11.3.2.
The NRC has provided guidance concerning the use of test interval extensions in the deferral of ILRTs beyond the 15-year interval in NEI 94-01, Revision 2-A, NRC SER Section 3.1.1.2, which states, in part:
As noted above, Section 9.2.3, NEI TR 94-01, Revision 2, states, "Type A testing shall be performed during a period of reactor shutdown at a frequency of at least once per 15 years based on acceptable performance history." However, Section 9.1 states that the "required surveillance intervals for recommended Type A testing given in this section may be extended by up to 9 months to accommodate unforeseen emergent conditions but should not be used for routine scheduling and planning purposes." The NRC staff believes that extensions of the performance-based Type A test interval beyond the required 15 years should be infrequent and used only for compelling reasons. Therefore, if a licensee wants to use the provisions of Section 9.1 in TR NEI 94-01, Revision 2, the licensee will have to demonstrate to the NRC staff that an unforeseen emergent condition exists.
NEI 94-01, Revision 3-A, Section 10.1, Introduction, concerning the use of test interval extensions in the deferral of Type B and Type C LLRTs, based on performance, states, in part:
    "Consistent with standard scheduling practices for Technical Specifications Required Surveillances, intervals of up to 120 months for the recommended surveillance frequency for Type B testing and up to 75 months for Type C testing given in this section may be extended by up to 25 percent of the test interval, not to exceed nine months.
Notes: For routine scheduling of tests at intervals over 60 months, refer to the additional requirements of Section 11.3.2.
Extensions of up to nine months (total maximum interval of 84 months for Type C tests) are permissible only for non-routine emergent conditions. This provision (nine-month extension) does not apply to valves that are restricted and/or limited to 30-month intervals in Section 10.2 (such as BWR MSIVs) or to valves held to the base interval (30 months) due to unsatisfactory LLRT performance."
The NRC has also provided the following concerning the extension of ILRT intervals to 15 years in NEI 94-01, Revision 3-A, NRC SER Section 4.0, Condition 2:
    "The basis for acceptability of extending the ILRT interval out to once per 15 years was the enhanced and robust primary containment inspection program and the local leakage rate testing of penetrations. Most of the primary containment leakage experienced has been 24

LR-N23-0005                                                                    LAR S22-04 Enclosure attributed to penetration leakage and penetrations are thought to be the most likely location of most containment leakage at any time."
3.3.2     Current SNGS Primary Containment Leakage Rate Testing Program Requirements 10 CFR Part 50, Appendix J was revised, effective October 26, 1995, to allow licensees to choose containment leakage testing under either Option A, Prescriptive Requirements, or Option B, Performance-Based Requirements. On February 27, 1998, the NRC approved Amendment Nos. 207 and 188 to the facility operating licenses for SNGS, Units 1 and 2, respectively (Reference 14). The amendments allowed the implementation of the recently approved Option B to 10 CFR Part 50, Appendix J. This new rule allowed for a performance-based option for determining the test frequency for containment leakage rate testing.
Option B states that specific existing exemptions to Option A are still applicable unless specifically revoked by the NRC.
Currently, TS 6.8.4.f. requires that a program be established to comply with the containment leakage rate testing requirements of 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. The program is required to be in accordance with the guidelines contained in RG 1.163. RG 1.163 endorses, with certain exceptions, NEI 94-01, Revision 0, as an acceptable method for complying with the provisions of Appendix J, Option B.
RG 1.163, Section C.1 states that licensees intending to comply with 10 CFR 50, Appendix J, Option B, should establish test intervals based upon the criteria in Section 11.0 of NEI 94-01 (Reference 5) rather than using test intervals specified in ANSI/ANS 56.8-1994. NEI 94-01, Section 11.0 refers to Section 9, which states that Type A testing shall be performed during a period of reactor shutdown at a frequency of at least once-per-ten years based on acceptable performance history. Acceptable performance history is defined as completion of two consecutive periodic Type A tests where the calculated performance leakage was less than 1.0La (where La is the maximum allowable leakage rate at design pressure). Elapsed time between the first and last tests in a series of consecutive satisfactory tests used to determine performance shall be at least 24 months.
Adoption of the Option B performance-based containment leakage rate testing program altered the frequency of measuring primary containment leakage in Types A, B, and C tests but did not alter the basic method by which Appendix J leakage testing is performed. The test frequency is based on an evaluation of the "as found" leakage history to determine a frequency for leakage testing, which provides assurance that leakage limits will not be exceeded. The allowed frequency for Type A testing as documented in NEI 94-01 is based, in part, upon a generic evaluation documented in NUREG-1493. The evaluation documented in NUREG-1493 included a study of the dependence or reactor accident risks on containment leak tightness for differing containment types. NUREG-1493 concluded in Section 10.1.2 that reducing the frequency of Type A tests (ILRT) from the original three (3) tests per 10 years to one (1) test per 20 years was found to lead to an imperceptible increase in risk. The estimated increase in risk is very small because ILRTs identify only a few potential containment leakage paths that cannot be identified by Types B and C testing, and the leaks that have been found by Type A tests have been only marginally above existing requirements. Given the insensitivity of risk to containment leakage rate and the small fraction of leakage paths detected solely by Type A testing, NUREG-1493 concluded that increasing the interval between ILRTs is possible with minimal impact on public risk.
25

LR-N23-0005                                                                LAR S22-04 Enclosure 3.3.3   SNGS 10 CFR 50, Appendix J, Option B Licensing History February 27, 1998 - License Amendment Nos. 207 and 188 The NRC approved Amendment Nos. 207 (SNGS-1) and 188 (SNGS-2) (Reference 14), which allowed the implementation of Option B to 10 CFR Part 50, Appendix J. This allowed for the implementation of a performance-based option for determining the test frequency for containment leakage rate testing in accordance with RG 1.163 and ANSI/ANS 56.8-1994.
April 11, 2002 - License Amendment No. 232 The NRC approved Amendment No. 232 (SNGS-2) (Reference 13), which provided for an alternate method for complying with the requirements of Title 10 of the Code of Federal Regulations (10 CFR) Section 50.54(o), and 10 CFR Part 50, Appendix J, Option B for Salem, Unit No. 2. The amendment allowed a one-time interval increase for the Salem, Unit No. 2, Type A, Integrated Leakage Rate Test from a maximum of a 10-year interval to a maximum 15-year interval. Specifically, the amendment required that the next Type A ILRT be performed no later than March 24, 2007.
August 16, 2010 - License Amendment No. 296 The NRC approved Amendment No. 296 (SNGS-1) (Reference 12), which revised TS 6.8.4.f, "Primary Containment Leakage Rate Testing Program," to allow a one-time interval extension of the Type A, integrated leakage rate test (ILRT) from 10 to 15 years. Specifically, the amendment required that the next Type A ILRT be performed no later than May 7, 2016.
June 2011 - NUREG-2101 The NRC approved Safety Evaluation Report Related to the License Renewal of Salem Nuclear Generating Station, Docket Numbers 50-272 and 50-311, published June 2011. (Reference 17) 3.3.4   Integrated Leakage Rate Testing History (ILRT)
As noted previously, SNGS TS 6.8.4.f currently requires Types A, B, and C testing in accordance with RG 1.163, which endorses the methodology for complying with 10 CFR 50, Appendix J, Option B. Since the adoption of Option B, the performance leakage rates are calculated in accordance with NEI 94-01, Section 9.1.1 for Type A testing.
Table 3.3.4-1 lists the past periodic Type A ILRT results for SNGS Units 1, and 2.
26

LR-N23-0005                                                                  LAR S22-04 Enclosure Table 3.3.4-1, Periodic Type A ILRT Results 95% Upper                      Test Date                      Test Pressure Confidence Limit (UCL)
(wt%/day)
Unit 1
          <0.75 La                    August 1979                        47.9 psig 0.411 La                    August 1984                        48.8 psig 0.043                   December 1987                       48.66 psig 0.0417                      April 1991                       48.05 psig 0.0038                      May 2001                         47.63 psig 0.0693                       July 2016                       45.97 psig Unit 2 0.05434                     May 1983                          48.5 psig 0.043                   November 1986                        48.5 psig 0.03196                    March 1992                         48.16psig 0.0276                    October 2006                        46.1 psig 0.0141                   November 2015                       46.05 psig 3.3.5    Performance Leakage Rate Determination The current ILRT test interval for SNGS Units 1 and 2 is ten years. Verification of this interval is presented in Table 3.3.5-1. The acceptance criteria used for this verification is contained in NEI 94-01, Revisions 2-A and 3-A, Section 5.0, Definitions, and is as follows:
    "The performance leakage rate is calculated as the sum of the Type A upper confidence limit (UCL) and as-left minimum pathway leakage rate (MNPLR) leakage rate for all Type B and Type C pathways that were in service, isolated, or not lined up in their test position (i.e.,
drained and vented to containment atmosphere) prior to performing the Type A test. In addition, leakage pathways that were isolated during performance of the test because of excessive leakage must be factored into the performance determination. The performance criterion for Type A tests is a performance leak rate of less than 1.0La."
27

LR-N23-0005                                                                     LAR S22-04 Enclosure Table 3.3.5-1, SNGS ILRT Test Results Verification of Current Extended ILRT Interval Test      Upper 95%        Level        As Left Min   Adjusted As       ILRT        Test Method /
Date      Confidence    Corrections      Pathway        Left Leak   Acceptance      Data Analysis Limit      (Leakage       Penalty for       Rate         Criteria      Techniques (wt.%/day)    Savings)         Isolated     (wt.%/day)    (wt.%/day)
(Test     (wt.%/day)       Pathways Pressure)                   (wt.%/day)
Unit 1 Absolute /
0.0693 ANSI/ANS July 2016       (45.97       -0.0024          0.0013        0.0682          0.1 56.8-1994 psig)
Mass Point Absolute /
0.0038 ANSI/ANS May 2001        (47.63         0.00           0.0027        0.0065          0.1 56.8-1994 psig)
Mass Point Unit 2 Absolute /
0.0141 November                                                                                 ANSI/ANS (46.05       -0.0009          0.0027        0.0159          0.1 2015                                                                                 56.8-1994 psig)
Mass Point Absolute /
October        0.0276                                                                  ANSI/ANS 0.00           0.0025        0.0301          0.1 2006      (46.1 psig)                                                                56.8-1994 Mass Point 3.4    Plant Specific Confirmatory Analysis 3.4.1    Methodology An analysis was performed to provide a risk assessment of permanently extending the SNGS, Units 1 & 2 containment Type A integrated leak rate test (ILRT) interval from ten years to fifteen years. The risk assessment follows the guidelines from the following:
* NEI 94-01 Revision 3-A (Reference 2),
* NEI Interim Guidance for Performing Risk Impact Assessments in Support of One-Time Extensions for Containment Integrated Leakage Rate Test Surveillance Intervals (Reference 20),
* NRC regulatory guidance on the use of Probabilistic Risk Assessment (PRA) as stated in Regulatory Guide (RG) 1.200 (Reference 15) as applied to ILRT interval extensions,
* Risk insights in support of a request for a plants licensing basis as outlined in RG 1.174 (Reference 3),
28

LR-N23-0005                                                                     LAR S22-04 Enclosure
* The methodology used for Calvert Cliffs to estimate the likelihood and risk implications of corrosion-induced leakage of steel liners going undetected during the extended test interval (Reference 32),
* The methodology used in EPRI 1018243, Revision 2-A of EPRI 1009325 (Reference 11).
Details of the SNGS risk assessment, providing an assessment of the risk associated with implementing a permanent extension of the SNGS containment Type A ILRT interval from ten years to fifteen years, is contained in Attachment 2 of this submittal.
Revisions to 10CFR50, Appendix J (Option B) allowed individual plants to extend the ILRT Type A surveillance testing requirements from three-in-ten years to at least once per ten years. The revised Type A frequency is based on an acceptable performance history defined as two consecutive periodic Type A tests at least 24 months apart in which the calculated performance leakage was less than limiting containment leakage of 1.0La (allowable leakage).
The basis for the current 10-year test interval is provided in Section 11.0 of NEI 94-01, Revision 0, and was established in 1995 during development of the performance-based Option B to Appendix J. Section 11.0 of NEI 94-01 states that NUREG-1493, Performance-Based Containment Leak Test Program, September 1995 (Reference 6), provides the technical basis to support rulemaking to revise leakage rate testing requirements contained in Option B to Appendix J. The basis consisted of qualitative and quantitative assessments of the risk impact (in terms of increased public dose) associated with a range of extended leakage rate test intervals. To supplement the NRCs rulemaking basis, NEI undertook a similar study. The results of that study are documented in Electric Power Research Institute (EPRI) Research Project Report TR-104285 (Reference 34).
The NRC report on performance-based leak testing, NUREG-1493, analyzed the effects of containment leakage on the health and safety of the public and the benefits realized from the containment leak rate testing. In that analysis, it was determined that for a representative PWR plant (i.e., Surry) that containment isolation failures contribute less than 0.1 percent to the latent risks from reactor accidents. Consequently, it is desirable to show that extending the ILRT interval will not lead to a substantial increase in risk from containment isolation failures for Salem Units 1
& 2.
NEI 94-01 Revision 3-A supports using EPRI Report No. 1009325 Revision 2-A (EPRI 1018243 (Reference 11)). The guidance provided in Appendix H of EPRI 1018243 builds on the earlier EPRI TR-104285 risk assessment methodology. This more recent methodology is followed to determine the appropriate risk information for use in evaluating the impact of the proposed ILRT changes.
It is also noted that containment leak-tight integrity is also verified through periodic in-service inspections conducted in accordance with the requirements of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code Section XI. More specifically, Subsection IWE provides the rules and requirements for in-service inspection of Class MC pressure-retaining components and their integral attachments, and of metallic shell and penetration liners of Class CC pressure-retaining components and their integral attachments in light-water cooled plants. Furthermore, NRC regulations 10 CFR 50.55a(b)(2)(ix)(E) require licensees to conduct visual inspections of the accessible areas of the interior of the containment.
The associated change to NEI 94-01 requires that visual examinations be conducted during at least three other outages, and in the outage during which the ILRT is being conducted. These 29

LR-N23-0005                                                                           LAR S22-04 Enclosure requirements are not changed as a result of the extended ILRT interval. In addition, Appendix J, Type B local leak tests performed to verify the leak-tight integrity of containment penetration bellows, airlocks, seals, and gaskets are also not affected by the change to the Type A test frequency.
In the Safety Evaluation (SE) issued by the NRC {{letter dated|date=June 25, 2008|text=letter dated June 25, 2008}} (Reference 9), the NRC concluded that the methodology in EPRI TR-1009325, Revision 2 (Reference 11), was acceptable for referencing by licensees proposing to amend their TS to permanently extend the ILRT surveillance interval to 15 years, subject to the limitations and conditions noted in Section 4.0 of the SE. Table 3.4.1-1 below addresses each of the four (4) limitations and conditions from Section 4.2 of the SE for the use of EPRI 1009325, Revision 2.
Table 3.4.1-1, EPRI Report No. 1009325, Revision 2, Limitations and Conditions Limitation and Condition                                  SNGS Response (From Section 4.2 of SE)
: 1. The licensee submits documentation                 SNGS PRA technical adequacy is addressed in indicating that the technical adequacy of their   Section 3.4.2 of this LAR and Attachment 2, PRA is consistent with the requirements of        "Risk Impact Assessment of Extending Salem RG 1.200 relevant to the ILRT extension           ILRT Interval, Appendix A, "PRA Technical application.                                      Acceptability" 2.a The licensee submits documentation                Since the ILRT does not impact core damage indicating that the estimated risk increase       frequency (CDF) for SNGS, the relevant criterion associated with permanently extending the         is large early release frequency (LERF). The ILRT surveillance interval to 15 years is small, increase in internal events (including internal and consistent with the clarification provided    flooding) LERF resulting from a change in the in Section 3.2.4.5 of this SE.                    Type A ILRT test interval from 3-in-10 years to 1-in-15 years is estimated as 3.2E-08/yr (i.e., in the very small change region using the acceptance guidelines of RG 1.174) using the EPRI Guidance (Reference 11) and including the risk impact of corrosion induced leakage. Without the corrosion impact, the increase in internal events LERF resulting from a change in the Type A ILRT test interval from 3-in-10 years to 1-in-15 years decreases slightly to 3.1E-08/yr. When external event risk is included, the increase in LERF resulting from a change in the Type A ILRT test interval from 3-in-10 years to 1-in-15 years is estimated as 7.6E-07/yr (i.e., in the small change region using the acceptance guidelines of RG 1.174) and the total LERF is 6.8E-06/yr using the EPRI Guidance and including the risk impact of corrosion induced leakage. Therefore, the risk increase is small using the acceptance guidelines of RG 1.174. (See Attachment 2, Section 7 of this submittal) 30

LR-N23-0005                                                                           LAR S22-04 Enclosure Table 3.4.1-1, EPRI Report No. 1009325, Revision 2, Limitations and Conditions Limitation and Condition                                 SNGS Response (From Section 4.2 of SE) 2.b Specifically, a small increase in population      With regards to population dose risk, the EPRI dose should be defined as an increase in          Guidance states that a very small population population dose of less than or equal to either dose is defined as an increase of <1.0 person-1.0 person-rem per year or 1% of the total        rem/yr or <1% of the total population dose, population dose, whichever is less restrictive. whichever is less restrictive. For a change in Salem Type A test frequency from 3-in-10 years to 1-in-15 years for those accident sequences influenced by Type A testing and including the risk impact of corrosion induced leakage, the increase in dose risk from internal events (including internal flooding) is 7.0E-2 person-rem/yr, which is 2% of the population dose risk.
This meets the EPRI criterion for very small (i.e.,
                                                        <1.0 person-rem/yr). (See Attachment 2, Section 7 of this submittal) 2.c In addition, a small increase in CCFP should      The increase in the conditional containment be defined as a value marginally greater than     failure frequency from the 3-in-10 year interval to that accepted in a previous one-time 15-year      a 1-in-15 year interval is about 0.88% using the ILRT extension requests. This would require       EPRI Guidance, and decreases to about 0.09%
that the increase in CCFP be less than or         using the EPRI Expert Elicitation methodology.
equal to 1.5 percentage point.                    Per the EPRI Guidance, increases of CCFP<1.5% are considered to be very small.
(See Attachment 2, Section 7 of this submittal.)
: 3. The methodology in EPRI Report No.                 The representative containment leakage for 1009325, Revision 2, is acceptable except for      Class 3b sequences used by SNGS is 100 La, the calculation of the increase in expected        based on the guidance provided in EPRI Report population dose (per year of reactor               No. 1009325, Revision 2-A. (See Attachment 2, operation). In order to make the methodology       Section 3 of this submittal.)
acceptable, the average leak rate accident case (accident case 3b) used by the licensees shall be 100 La instead of 35 La.
: 4. A licensee amendment request (LAR) is              SNGS does not rely upon containment over-required in instances where containment over- pressure for ECCS performance. (Refer to pressure is relied upon for ECCS performance. Section 3.2 of this submittal.)
3.4.2    PRA Technical Acceptability Regulatory Guide 1.200 (Reference 15) provides guidance for determining the technical acceptability of Probabilistic Risk Assessment (PRA) results for risk-informed activities. The majority of the items identified in RG 1.200 (i.e., Section C.3) pertain to the alignment and use of the PRA to support the application and are addressed in the main portion of the risk assessment and through the implementation of industry methodologies (e.g., Reference 11). RG 1.200 Section C.3.3 identifies two aspects to demonstrating the acceptability of the portions of the PRA used to support an application. The first aspect is the assurance that the portions of the PRA used in the application have been developed and performed in a technically correct manner. The second aspect is the assurance that the assumptions and approximations used in developing the PRA are appropriate. These two aspects are primarily addressed through the application of industry standards for PRA development, a PRA model configuration control program, and peer review of the PRA models and configuration control program. Portions of the second aspect are 31

LR-N23-0005                                                                     LAR S22-04 Enclosure also addressed via the sensitivity cases performed for the ILRT risk assessment using the EPRI methodology as documented in the main report.
Note that for this application, the accepted methodology involves a bounding approach to estimate the change in LERF from extending the ILRT interval. Rather than exercising the PRA model itself, it involves the establishment of separate calculations that are linearly related to the plant CDF contribution that is not already LERF. Consequently, a reasonable representation of the plant CDF that is not LERF is all that is required for the application. The analysis included several sensitivity studies and factored in the potential impacts from external events in a bounding fashion. Since the accepted process utilizes a bounding analysis approach which is mostly driven by that CDF contribution which does not already lead to LERF, there are no identified key assumptions or sources of uncertainty for this application other than those already incorporated using the industry methodology.
This ILRT risk assessment uses recently completed Internal Event (including Internal Flooding) and Fire PRA models. There are no other approved PRA models (e.g., seismic) for SNGS. Other external events were evaluated as discussed in the main report.
Internal Events and Internal Flood PRA The latest Salem Internal Events and Internal Flood model (SA121A) was used for this risk assessment as documented in the Level 1 and Level 2 PRA quantification notebooks (Reference 44 and 45). This model update was completed in October 2022. The SNGS PRA modeling is highly detailed, including a wide variety of initiating events, modeled systems, operator actions, and common cause events. The PRA model quantification process used for the SNGS PRA is based on the event tree / fault tree methodology, which is a well-known methodology in the industry.
This latest model is a successor model of a previously peer reviewed PRA model. In November 2008, a Pressurized Water Reactors Owners Group (PWROG) team completed a peer review (Reference 46) of the Salem Revision 4.1 PRA Model using the Nuclear Energy Institute (NEI) process for performing follow-on PRA peer reviews to determine compliance with Part 2 and Part 3 of the ASME PRA Standard (Reference 41) and RG 1.200 (Reference 21). The peer review identified Finding-level Facts and Observations (F&O) and by January 2019, all open F&Os were resolved and considered closed by the F&O Closure Team, which was documented in the F&O Closure Teams independent assessment and focused-scope peer review report (Reference 49).
Changes after the Revision 4.1 internal events (and internal flooding) model through the previous periodic update (SA112A) included the following:
* Revision 4.2 (March 2009) - Refined failure modes for service water valves to support local operation credit when permissible.
* Revision 4.3 (December 2009) - Refined AC power modeling, Heating Ventilation and Air Conditioning (HVAC) procedure improvements, and resolved some peer review findings such as scrubbing to reduce LERF and more detailed modeling of offsite power recovery.
* Revision SA112A (September 2014) - Periodic update. Modeling changes included offsite power recovery logic refinements to ensure non-recovery probabilities applied, verification of annualized basis for support system fault tree initiator logic, additional credit for Control Area Ventilation based on operator interviews and pruning of unused gates.
32

LR-N23-0005                                                                    LAR S22-04 Enclosure
* Revision SA115A (December 2016) - Periodic update. Modeling changes included credit for 4th Auxiliary Feedwater (AFW) pump to support Mitigating System Performance Index (MSPI) and Station Blackout (SBO) event tree enhancements to model use of FLEX equipment.
All of the changes made between the Revision 4.2 model and the SA115A model are considered PRA maintenance activities, including changes made to support closure of the 2008 Peer Review F&Os.
The changes made to the internal events (including internal flooding) PRA model (SA121A) as part of the 2022 periodic update included the following:
* Modeling refinements to reflect recent plant modifications (e.g., Service Water (SW) valves)
* Updating of internal flood modeling (e.g., including aging factors, refinement of spray scenarios)
* Inclusion of additional suction sources for AFW
* Unit cross-tie credit refinements (e.g., CVCS)
* Refinements to support the Fire PRA model development (which is built upon the internal events model)
* Refinements to human actions credit based on revised plant procedures and operator interviews
* Refinements to support FLEX modeling
* Revised modeling of SGTR based on PWROG-21024-P (Reference 47) which is based on the updated NRC induced SGTR research in NUREG-2195.
All of the above model changes except that associated with the SGTR modeling are considered PRA maintenance activities (i.e., not an upgrade to the PRA which would require a follow-on focused scope peer review). The revised SGTR modeling was considered a method change that warranted a Focused Scope Peer Review (FSPR). The FSPR was conducted in October 2022 and the results indicated that 100% of the LERF supporting requirements were met at Capability Category II or higher (Reference 33). There was one suggestion and one note of an Unreviewed Analysis Method pertaining to the Temperature Induced-SGTR methodology from the PWROG.
It was noted that the method was implemented appropriately and that this issue has low significance provided the method passes the newly developed method peer review. As such, there is no immediate impact on the ILRT application.
The Salem PRA model is controlled in accordance with station procedures which defines the process for implementing regularly scheduled and interim PRA model updates, for tracking issues identified as potentially affecting the PRA models (e.g., due to changes in the plant, errors or limitations identified in the model, industry operating experience), and for controlling the model 33

LR-N23-0005                                                                     LAR S22-04 Enclosure and associated computer files. To ensure that the current PRA model remains an accurate reflection of the as-built, as-operated plants, the following activities are routinely performed:
* Design changes and procedure changes are reviewed for their impact on the PRA model.
* New engineering calculations and revisions to existing calculations are reviewed for their impact on the PRA model.
* Plant specific initiating event frequencies, failure rates, and maintenance unavailabilities are updated via periodic model updates.
A PRA updating requirements evaluation (URE), a PRA model update tracking database item is created for all issues that are identified that could impact the PRA model. The URE database includes the identification of those plant changes that could impact the PRA model. A review of the current open items in the URE database identified no items with significant potential impact upon the ILRT risk assessment as the latest PRA model was just recently completed. The majority of the open UREs related to tracking model rollout activities, the online risk models, suggestions for minor refinements, documentation related items, and tracking of expected future plant modifications (i.e., not yet installed). A few UREs reflected model changes that would be expected to lower the quantified CDF/LERF thereby making the current model used for the ILRT assessment potentially conservative.
Based on the above, the internal events (including internal flooding) PRA model is deemed acceptable to perform this ILRT risk evaluation Fire PRA Model A Unit 1 Fire PRA model (SA121A-F) was just recently completed for Salem as documented in the Fire Quantification Notebook (Reference 51). This Fire PRA model contains highly detailed modeling commensurate with the internal events model, but including the phenomenology associated with internal fire events.
Similar to the Internal Events PRA, the Fire PRA is controlled in accordance with station procedures which defines the process for implementing regularly scheduled and interim PRA model updates, for tracking issues identified as potentially affecting the PRA models, and for controlling the model and associated computer files. A URE item is created for all issues that are identified that could impact the Fire PRA model. A review of the current open items in the URE database identified no items with significant potential impact upon the ILRT risk assessment as the latest Fire PRA model was just recently completed. The majority of the open Fire PRA UREs related to tracking of expected future plant modifications (i.e., not yet installed). A few UREs reflected model changes that would be expected to have minimal impact on CDF/LERF.
As noted previously, a reasonable representation of the plant CDF that is not LERF is all that is required for the application. The analysis included several sensitivity studies and factored in the potential impacts from external events in a bounding fashion. Since the accepted process utilizes a bounding analysis approach which is mostly driven by that CDF contribution which does not already lead to LERF, a peer review of the Fire PRA is not necessarily required for the ILRT application.
In any event, this Fire PRA model received a peer review in October 2022 against the ASME PRA Standard (Reference 30). The peer review indicated that ~90% of the applicable supporting 34

LR-N23-0005                                                                     LAR S22-04 Enclosure requirements are met at Category II or higher. This provides a high level of confidence that the results used for the bounding ILRT assessment provide a reasonable approximation of the fire risk at the site. The peer review identified Finding-level Facts and Observations (F&Os) as documented in the Peer Review Report (Reference 52). For completeness, Attachment 2 of this submittal, Table A-1 summarizes the Unit 1 Fire PRA findings and their potential impact upon this ILRT risk assessment.
Based on the above, the Salem Fire PRA is deemed acceptable to perform this ILRT risk evaluation.
Summary A PRA technical acceptability evaluation was performed consistent with the requirements of RG-1.200 (Reference 15). This evaluation combined with the details of the results of this analysis demonstrate with reasonable assurance that the proposed permanent extension to the ILRT interval for Salem to fifteen years satisfies the risk acceptance guidelines in RG 1.174 (Reference 3).
3.4.3    Summary of Plant-Specific Risk Assessment Results The findings of the SNGS Risk Assessment contained in Attachment 2 of this submittal confirm the general findings of previous studies that the risk impact associated with extending the ILRT interval from three in ten years to one in 15 years is small.
Based on the results from Attachment 2 of this submittal, Section 5 and the sensitivity calculations presented in Section 6, the following conclusions regarding the assessment of the plant risk are associated with extending the Type A ILRT test frequency to fifteen years:
* RG 1.174 (Reference 3) provides guidance for determining the risk impact of plant-specific changes to the licensing basis. RG 1.174 defines very small changes in risk as resulting in increases of CDF less than 10-6/yr and increases in LERF less than 10-7/yr.
Small changes in risk are defined as increases in CDF between 10-6/yr and 10-5/yr and increases in LERF between 10-7/yr and 10-6/yr. Since the ILRT does not impact CDF for Salem, the relevant criterion is LERF. The increase in internal events (including internal flooding) LERF resulting from a change in the Type A ILRT test interval from 3-in-10 years to 1-in-15 years is estimated as 3.2E-08/yr (i.e., in the very small change region using the acceptance guidelines of RG 1.174) using the EPRI Guidance (Reference 11) and including the risk impact of corrosion induced leakage. Without the corrosion impact, the increase in internal events LERF resulting from a change in the Type A ILRT test interval from 3-in-10 years to 1-in-15 years decreases slightly to 3.1E-08/yr.
* When external event risk is included, the increase in LERF resulting from a change in the Type A ILRT test interval from 3-in-10 years to 1-in-15 years is estimated as 7.6E-07/yr (i.e., in the small change region using the acceptance guidelines of RG 1.174) and the total LERF is 6.8E-06/yr using the EPRI Guidance and including the risk impact of corrosion induced leakage. Therefore, the risk increase is small using the acceptance guidelines of RG 1.174.
* With regards to population dose risk, the EPRI Guidance (Reference 11) states that a very small population dose is defined as an increase of <1.0 person-rem/yr or <1% of the total population dose, whichever is less restrictive. For a change in Salem Type A test 35

LR-N23-0005                                                                    LAR S22-04 Enclosure frequency from 3-in-10 years to 1-in-15 years for those accident sequences influenced by Type A testing and including the risk impact of corrosion induced leakage, the increase in dose risk from internal events (including internal flooding) is 7.0E-2 person-rem/yr, which is 2% of the population dose risk. This meets the EPRI criterion for very small (i.e., <1.0 person-rem/yr).
* The increase in the conditional containment failure frequency from the 3-in-10 year interval to a 1-in-15 year interval is about 0.88% using the EPRI Guidance (Reference 11),
and decreases to about 0.09% using the EPRI Expert Elicitation methodology. Per the EPRI Guidance, increases of CCFP<1.5% are considered to be very small.
Based on the application of the conservative EPRI methodology for Salem, increasing the ILRT interval to 15 years is not considered to be significant since it represents a small change to the Salem risk profile.
3.4.4    Previous Assessments The NRC in NUREG-1493 (Reference 6) has previously concluded that:
* Reducing the frequency of Type A tests (i.e., ILRTs) from three per 10 years to one per 20 years was found to lead to an imperceptible increase in risk. The estimated increase in risk is very small because ILRTs identify only a few potential containment leakage paths that cannot be identified by Types B and C testing, and the leaks that have been found by Type A tests have been only marginally above existing requirements.
* Given the insensitivity of risk to containment leakage rate and the small fraction of leakage paths detected solely by Type A testing, increasing the interval between integrated leakage-rate tests is possible with minimal impact on public risk. The impact of relaxing the ILRT frequency beyond one in 20 years has not been evaluated. Beyond testing the performance of containment penetrations, ILRTs also test the integrity of the containment structure.
The findings for SNGS, Units 1 and 2 confirm these general findings on a plant specific basis considering the severe accidents evaluated for SNGS, the SNGS containment failure modes, and the local population surrounding SNGS.
Details of the SNGS, Units 1 and 2, risk assessment are contained in Attachment 2 of this submittal.
3.4.5    RG 1.174 Revision 3 Defense in Depth Evaluation RG 1.174, Revision 3 (Reference 3), describes an approach that is acceptable for developing riskinformed applications for a licensing basis change that considers engineering issues and applies risk insights. One of the considerations included in RG 1.174 is Defense in Depth.
Defense in Depth is a safety philosophy that employs successive compensatory measures to prevent accidents or mitigate damage if a malfunction, accident, or naturally caused event occurs at a nuclear facility. The following seven considerations, as presented in RG 1.174, Revision 3, Section C.2.1.1.2, Considerations for Evaluating the Impact of the Proposed Licensing Basis Change on Defense in Depth, will serve to evaluate the proposed licensing basis change for overall impact on Defense in Depth for SNGS.
36

LR-N23-0005                                                                  LAR S22-04 Enclosure
: 1. Preserve a reasonable balance among the layers of defense.
A reasonable balance of the layers of defense (i.e., minimizing challenges to the plant, preventing any events from progressing to core damage, containing the radioactive source term, and emergency preparedness) helps to ensure an apportionment of the plants capabilities between limiting disturbances to the plant and mitigating their consequences. The term reasonable balance is not meant to imply an equal apportionment of capabilities. The NRC recognizes that aspects of a plants design or operation might cause one or more of the layers of defense to be adversely affected. For these situations, the balance between the other layers of defense becomes especially important when evaluating the impact of the proposed licensing basis change and its effect on defense in depth.

===Response===
Several layers of defense are in place to ensure the SNGS containment structure(s);
penetrations, isolation valves and mechanical seal systems; continue(s) to perform their intended safety function. The purpose of the proposed change is to extend the testing frequencies of the Type A Integrated Leakage Rate Test (ILRT) from 10 years to 15 years and Type C Local Leakage Rate Tests (LLRTs) for selected components from 60-months to 75-months.
As shown in NUREG-1493, Performance-Based Containment Leak-Test Program (Reference 6), increasing the test frequency of ILRTs up to a 20-year test interval was found to lead to an imperceptible increase in risk. The estimated increase in risk is very small because ILRTs identify only a few potential containment leakage paths that cannot be identified by Type B or Type C testing. The study also concluded that extending the frequency of Type B tests is possible with no adverse impact on risk as identified leakage through Type B mechanical penetrations are both infrequent and small. Finally, the study concluded that Types B and C tests could identify the vast majority (greater than 95 percent) of all potential leakage paths.
Several programmatic factors can also be cited as layers of defense ensuring the continued safety function of the SNGS containment pressure boundary. NEI 94-01 Revisions 2-A and 3-A require sites adopting the 15-year extended ILRT interval perform visual examinations of the accessible interior and exterior surfaces of the containment structure for structural degradation that may affect the containment leak-tight integrity at the frequency prescribed by the guidance or, if approved through a TS amendment, at the frequencies prescribed by ASME Section XI, which is not the case for SNGS Units 1 and
: 2. Additionally, several measures are put in place to ensure integrity of the Types B and C tested components. NEI 94-01 limits large containment penetrations such as airlocks, purge and vent valves, BWR main steam and feedwater isolation valves, to a maximum 30-month testing interval. For those valves that meet the performance standards defined in NEI 94-01, Revision 3-A and are selected for test intervals greater than 60 months, a leakage understatement penalty is added to the MNPLR prior to the frequency being extended beyond 60-months. Finally, identification of adverse trends in the overall Types B and C leakage rate summations and available margin between the Type B and Type C leakage rate summation and its regulatory limit are required by NEI 94-01, Revision 3-A to be shown in the SNGS post-outage report(s). Therefore, the proposed change does not challenge or limit the layers of defense available to assess the ability of the SNGS containment structure to perform its safety function.
37

LR-N23-0005                                                                     LAR S22-04 Enclosure PRA Response:
The usage of the risk metrics of large early release frequency (LERF), population dose, and conditional containment failure probability (CCFP) collectively ensure the balance between prevention of core damage, prevention of containment failure, and consequence mitigation is preserved. The change in LERF is assessed as very small with respect to internal events and small when including external events per RG 1.174, and the change in population dose and CCFP are very small as defined in the EPRI methodology (Reference 11).
: 2. Preserve adequate capability of design features without an overreliance on programmatic activities as compensatory measures.
Nuclear power plant licensees implement a number of programmatic activities, including programs for quality assurance, testing and inspection, maintenance, control of transient combustible material, foreign material exclusion, containment cleanliness, and training. In some cases, activities that are part of these programs are used as compensatory measures; that is, they are measures taken to compensate for some reduced functionality, availability, reliability, redundancy, or other feature of the plants design to ensure safety functions (e.g., reactor vessel inspections that provide assurance that reactor vessel failure is unlikely). NUREG-2122, Glossary of Risk-Related Terms in Support of Risk-Informed Decision Making, (Reference 19), defines safety function as those functions needed to shut down the reactor, remove the residual heat, and contain any radioactive material release.
A proposed licensing basis change might involve or require compensatory measures.
Examples include hardware (e.g., skid-mounted temporary power supplies); human actions (e.g., manual system actuation); or some combination of these measures. Such compensatory measures are often associated with temporary plant configurations. The preferred approach for accomplishing safety functions is through engineered systems.
Therefore, when the proposed licensing basis change necessitates reliance on programmatic activities as compensatory measures, the licensee should justify that this reliance is not excessive (i.e., not overly reliant). The intent of this consideration is not to preclude the use of such programs as compensatory measures but to ensure that the use of such measures does not significantly reduce the capability of the design features (e.g.,
hardware).

===Response===
The purpose of the proposed change is to extend the testing frequencies of the Type A ILRT from 10 years to 15 years and select Type C LLRTs from 60-months to 75-months.
Several programmatic factors were defined in the response to Question 1 above, which are required when adopting NEI 94-01, Revisions 2-A and 3-A. These factors are conservative in nature and are designed to generate corrective actions if the required testing or inspections are deemed unsatisfactory well in advance to ensure the continued safety function of the containment is maintained. The programmatic factors are designed to provide differing ways to test and/or examine the containment pressure boundary in a manner that verifies the SNGS containment pressure boundary will perform its intended safety function. Since the proposed change does not alter the configuration of the SNGS containment pressure boundary, continued performance of the tests and inspections 38

LR-N23-0005                                                                     LAR S22-04 Enclosure associated with NEI 94-01 will only serve to ensure the continued safety function of the containment without affecting any margin of safety.
PRA Response:
The adequacy of the design feature (the containment boundary subject to Type A testing) is preserved as evidenced by the overall small change in risk associated with the Type A test frequency change.
: 3. Preserve system redundancy, independence, and diversity commensurate with the expected frequency and consequences of challenges to the system, including consideration of uncertainty.
As stated in RG 1.174, Revision 3, Section C.2.1.1.1, Background, the defense-in-depth philosophy has traditionally been applied in plant design and operation to provide multiple means to accomplish safety functions. System redundancy, independence, and diversity result in high availability and reliability of the function and also help ensure that system functions are not reliant on any single feature of the design. Redundancy provides for duplicate equipment that enables the failure or unavailability of at least one set of equipment to be tolerated without loss of function. Independence of equipment implies that the redundant equipment is separate such that it does not rely on the same supports to function. This independence can sometimes be achieved by the use of physical separation or physical protection. Diversity is accomplished by having equipment that performs the same function rely on different attributes such as different principles of operation, different physical variables, different conditions of operation, or production by different manufacturers which helps reduce common-cause failure (CCF).
A proposed change might reduce the redundancy, independence, or diversity of systems.
The intent of this consideration is to ensure that the ability to provide the system function is commensurate with the risk of scenarios that could be mitigated by that function. The consideration of uncertainty, including the uncertainty inherent in the PRA, implies that the use of redundancy, independence, or diversity provides high reliability and availability and also results in the ability to tolerate failures or unanticipated events.

===Response===
The proposed change to extend the testing frequencies of the Type A ILRT from 10 years to 15 years and select Type C LLRTs from 60-months to 75-months does not reduce the redundancy, independence or diversity of systems. As shown in NUREG-1493, increasing the test frequency of ILRTs up to a 20-year test interval was found to lead to an imperceptible increase in risk. The estimated increase in risk is very small because ILRTs identify only a few potential containment leakage paths that cannot be identified by Type B or Type C testing. The study also concluded that extending the frequency of Type B tests is possible with no adverse impact on risk as identified leakage through Type B mechanical penetrations are both infrequent and small. Additionally, the study concluded that Type B and C tests could identify the vast majority (greater than 95 percent) of all potential leakage paths.
Despite the change in test interval, containment isolation diversity remains unaffected and will continue to provide the inherent isolation, as designed. In addition, NEI 94-01 Revisions 2-A and 3-A, Section 11.3.2 requires a schedule of tests be developed, for 39

LR-N23-0005                                                                   LAR S22-04 Enclosure components on a test interval greater than 60 months, such that unanticipated random failures and unexpected common-mode failures are avoided. This is typically accomplished by implementing test intervals at approximately evenly distributed intervals.
Therefore, the proposed change preserves system redundancy, independence, and diversity and ensures a high reliability and availability of the containment structure to perform its safety function in the event of unanticipated events.
PRA Response:
The redundancy, independence, and diversity of the containment subject to the Type A test is preserved, commensurate with the expected frequency and consequences of challenges to the system, as evidenced by the overall small change in risk associated with the Type A test frequency change. An assessment for uncertainty did not result in a change in the conclusions of this risk assessment.
: 4. Preserve adequate defense against potential common-cause failures (CCFs).
An important aspect of ensuring defense in depth is to guard against CCF. Multiple components may fail to function because of a single specific cause or event that could simultaneously affect several components important to risk. The cause or event may include an installation or construction deficiency, accidental human action, extreme external environment, or an unintended cascading effect from any other operation or failure within the plant. CCFs can also result from poor design, manufacturing, or maintenance practices.
Defenses can prevent the occurrence of failures from the causes and events that could allow simultaneous multiple component failures. Another aspect of guarding against CCF is to ensure that an existing defense put in place to minimize the impact of CCF is not significantly reduced; however, a reduction in one defense can be compensated for by adding another.

===Response===
As part of the proposed change, SNGS will be required to adopt the performance-based testing standards outlined in NEI 94-01, Revisions 2-A and 3-A along with ANSI/ANS 56.8-2002. NEI 94-01, Revisions 2-A and 3-A, Section 11.3.2 requires a schedule of tests be developed, for components on test intervals greater than 60 months, such that unanticipated random failures and unexpected common-mode failures are avoided. This is typically accomplished by implementing test intervals at approximately evenly distributed intervals. In addition, components considered to be risk-significant from a PRA standpoint are required to be limited to a testing interval less than the maximum allowable limit of 75-months. For those components that have demonstrated satisfactory performance and have had their testing limits extended, administrative testing limits are assigned on a component-by-component basis and are used to identify potential valve or penetration degradation. Administrative limits are established at a value low enough to identify and should allow early correction in advance of total valve failure. Should a component exceed its administrative limit during testing, NEI 94-01, Revisions 2-A and 3-A, require cause determinations be performed designed to reinforce achieving acceptable performance. The cause determination is designed to identify and address common-mode failure mechanisms through appropriate corrective actions. The proposed change also imposes a requirement to address margin management (i.e., margin between the 40

LR-N23-0005                                                                  LAR S22-04 Enclosure current containment leakage rate and its pre-established limit). As a result, adoption of the performance-based testing standards proposed by this change ensures adequate barriers exist to preclude failure of the containment pressure boundary due to common-mode failures and therefore continues to guard against CCF.
PRA Response:
Adequate defense against CCFs is preserved. The Type A test detects problems in the containment which may or may not be the result of a CCF; such a CCF may affect failure of another portion of containment (i.e., local penetrations) due to the same phenomena.
Adequate defense against CCFs is preserved via the continued performance of the Type B and C tests and the performance of inspections. The change to the Type A test interval, which bounds the risk associated with containment failure modes including those involving CCFs, does not degrade adequate defense as evidenced by the overall small change in risk associated with the Type A test frequency change.
: 5. Maintain multiple fission product barriers.
Fission product barriers include the physical barriers themselves (e.g., the fuel cladding, reactor coolant system pressure boundary, and containment) and any equipment relied on to protect the barriers (e.g., containment spray). In general, these barriers are designed to perform independently so that a complete failure of one barrier does not disable the next subsequent barrier. For example, one barrier, the containment, is designed to withstand a double-ended guillotine break of the largest pipe in the reactor coolant system, another barrier.
A plants licensing basis might contain events that, by their very nature, challenge multiple barriers simultaneously. Examples include interfacing-system loss-of-coolant accidents, steam generator tube rupture, or crediting containment accident pressure. Therefore, complete independence of barriers, while a goal, might not be achievable for all possible scenarios.

===Response===
The purpose of the proposed change is to extend the testing frequencies of the Type A ILRT from 10 years to 15 years and select Type C LLRTs from 60-months to 75-months.
As part of the proposed change, SNGS will be required to adopt the performance-based testing standards outlined in NEI 94-01, Revisions 2-A and 3-A along with ANSI/ANS 56.8-2002. The overall containment leakage rate calculations associated with the testing standards contain inherent conservatisms through the use of margin. Plant TS require the overall primary containment leakage rate to be less than or equal to 1.0 La. NEI 94-01 requires the as-found Type A test leakage rate must be less than the acceptance criterion of 1.0 La given in the plant TS. Prior to entering a mode where containment integrity is required, the as-left Type A leakage rate shall not exceed 0.75 La. The as-found and as-left values are as determined by the appropriate testing methodology specifically described in ANSI/ANS 56.8-2002. Additionally, the combined leakage rate for all Type B and Type C tested penetrations shall be less than or equal to 0.6 La, determined on a maximum pathway basis from the as-left LLRT results prior to entering a mode where containment integrity is required. This regulatory approach results in a 25% and 40%
margin, respectively, to the 1.0 La requirements. For those local leak rate tested components that have demonstrated satisfactory performance and have had their testing 41

LR-N23-0005                                                                   LAR S22-04 Enclosure limits extended, administrative testing limits are assigned on a component-by-component basis and are used to identify potential valve or penetration degradation. Administrative limits are established at a value low enough to identify and allow early correction in advance of total valve failure. Should a component exceed its administrative limit during testing, NEI 94-01, Revisions 2-A and 3-A require cause determinations be performed designed to reinforce achieving acceptable performance. The cause determination is designed to identify and address common-mode failure mechanisms through appropriate corrective actions. Therefore, the proposed change adopts requirements with inherent conservatisms to ensure the margin to safety limit is maintained, thereby, preserving the containment fission product barrier.
PRA Response:
Multiple Fission Product barriers are maintained. The portion of the containment affected by the Type A test extension is still maintained as an independent fission product barrier, albeit with an overall small change in the reliability of the barrier.
: 6. Preserve sufficient defense against human errors.
Human errors include the failure of operators to correctly and promptly perform the actions necessary to operate the plant or respond to off-normal conditions and accidents, errors committed during test and maintenance, and incorrect actions by other plant staff. Human errors can result in the degradation or failure of a system to perform its function, thereby significantly reducing the effectiveness of one of the layers of defense or one of the fission product barriers. The plant design and operation include defenses to prevent the occurrence of such errors and events. These defenses generally involve the use of procedures, training, and human engineering; however, other considerations (e.g.,
communication protocols) might also be important.

===Response===
Sufficient defense against human errors is preserved. Errors committed during testing and maintenance may be reduced by the less frequent performance of the Type A, Type B and Type C tests (less opportunity for errors to occur).
PRA Response:
Sufficient defense against human errors is preserved. The probability of a human error to operate the plant, or to respond to off-normal conditions and accidents is not affected by the change to the Type A testing frequency. Errors committed during test and maintenance may be reduced by the less frequent performance of the Type A test (less opportunity for errors to occur). An EPRI study (Reference 16) for shutdown risk (in which human errors generally have greater risk impacts) concluded that a small but measurable safety benefit is realized from extending the test intervals.
: 7. Continue to meet the intent of the plants design criteria.
For plants licensed under 10 CFR Part 50 or 10 CFR Part 52, the plants design criteria are set forth in the current licensing basis of the plant. The plants design criteria define minimum requirements that achieve aspects of the defense-in-depth philosophy; as a consequence, even a compromise of the intent of those design criteria can directly result in a significant reduction in the effectiveness of one or more of the layers of defense.
42

LR-N23-0005                                                                   LAR S22-04 Enclosure When evaluating the effect of the proposed licensing basis change, the licensee should demonstrate that it continues to meet the intent of the plants design criteria.

===Response===
The purpose of the proposed change is to extend the testing frequencies of the Type A ILRT from 10 years to 15 years and select Type C LLRTs from 60-months to 75-months.
The proposed extensions do not involve either a physical change to the plant or a change in the manner in which the plant is operated or controlled. As part of the proposed change, SNGS will be required to adopt the performance-based testing standards outlined in NEI 94-01, Revisions 2-A and 3-A along with ANSI/ANS 56.8-2002. The leakage limits imposed by plant TS remain unchanged when adopting the performance-based testing standards outlined in NEI 94-01, Revision 3-A and ANSI/ANS 56.8-2002. Plant design limits imposed by the Updated Final Safety Analysis Report (UFSAR) also remain unchanged as a result of the proposed change. Therefore, the proposed change continues to meet the intent of the plants design criteria to ensure the integrity of the SNGS containment pressure boundary.
PRA Response:
The intent of the plants design criteria continues to be met. The extension of the Type A test does not change the configuration of the plant or the way the plant is operated.

==
Conclusion:==

The responses to the seven Defense in Depth questions above conclude that the existing Defense in Depth has not been diminished; rather, in some instances has been increased.
Therefore, the proposed change does not comprise a reduction in safety.
3.5   Non-Risk Based Assessment Consistent with the defense-in-depth philosophy discussed in RG 1.174, SNGS has assessed other non-risk-based considerations relevant to the proposed amendment. SNGS has multiple inspection and testing programs that ensure the containment structure continues to remain capable of meeting its design functions and is designed to identify any degrading conditions that might affect that capability. These programs are discussed below.
3.5.1   Monitoring the Performance of Service Level I Coating Systems The Protective Coating Monitoring and Maintenance Program is an existing program that provides for aging management of Service Level I coatings inside the containment structure.
Service Level I coatings are used in areas where coating failure could adversely affect the operation of post-accident fluid systems and thereby impair safe shutdown. The Protective Coating Monitoring and Maintenance Program provides for inspections, assessments, and repairs for any condition that adversely affects the ability of Service Level I coatings to function as intended.
43

LR-N23-0005                                                                     LAR S22-04 Enclosure 3.5.2    Recent Service Level I Coatings Inspection Reports 1R27 (Fall 2020)
The purpose of this inspection report is to document the SNGS Unit 1 containment coating condition monitoring activities performed during 1R27. This coating assessment was performed in accordance with CC-SA-6006, Monitoring the Performance of Service Level I Coating Systems. The documentation of the containment coating conditions meets the requirements of the License Renewal Protective Coatings Monitoring and Maintenance Aging Management Program (AMP).
Prior to performing the walkdowns, the qualified individuals reviewed past notifications.
The following is a list of Notifications, follow-up actions and their respective Status from previous outage walk-downs.
Table 3.5.2 Notifications from Previous Outage - 1R26 Notification    Created On                    Description                 Work            Status Order 20824129       4/12/2019        Loose Coatings in RX Sump               60138419     Work Complete (WC) 20778116       10/16/2017       Bio-shield areas coatings work          60131819     WC 20725596       4/18/2016        *(81) Coatings need to be scraped back  60128711     WC 20666735       10/24/2014       Repair Coatings on Bioshield Wall       60114540     WC 20666213       10/23/2014       Broken Studs and Coating, Cont. Liner   60113828     WC 20646188       4/9/2014         Minor Surface Corrosion on CAN Liner    60120251     WC The Service Level I Coatings inside the SNGS Unit 1 Containment Building were inspected by the qualified individual and notifications were initiated to correct minor coating degradation. Overall, the Service Level I coatings were found to be in good condition.
1R28 (Spring 2022)
The purpose of this inspection report is to document the SNGS Unit 1 containment coating condition monitoring activities performed during 1R28.
As similar to the 1R27 walkdown, the qualified individuals reviewed past notifications. The following is a list of Notifications, follow-up actions and their respective status from previous outage walk-downs.
Table 3.5.2 Notifications from Previous Outage - 1R27 Notification Created On                        Description                   Work Order       Status 20864437** 12/30/2020          Regen Room, LD Heat Exch. Coating R.       60150604           WC*
20862643       10/17/2020      1CA475 Piping Restoration                  60150643           WC*
20886097       10/13/2021      Replace 1CC285/1CC286 Coatings Appl.       60152398           WC*
20861365       10/03/2020      Coatings work in Regen Room                60147783           WC 20824129       4/12/2019       Loose Coatings in RX Sump                  60138419           WC 20778116       10/16/2017      Bio-shield areas coatings work             60131819           WC
* Work completed during S1R28
  ** From Notification 20861365 44

LR-N23-0005                                                                     LAR S22-04 Enclosure The Service Level I Coatings inside the SNGS Unit 1 Containment Building were inspected by the qualified individual and notifications were initiated to correct minor coating degradation. Overall, the Service Level I coatings were found to be in good condition.
2R25 (Fall 2021)
The purpose of this inspection report is to document the SNGS Unit 2 containment coating condition monitoring activities performed during 2R25.
Prior to performing the walkdowns, the qualified individuals reviewed past notifications. The following is a list of Notifications, follow-up actions and their respective status from previous outage walk-downs.
Table 3.5.2 Notifications from Previous Outage - 2R24 Notification    Created On                  Description                 Work Order           Status 20807735        10/15/2018       Scraping Loose Coatings             60135577             WC 20807736        10/15/2018       Touch-up Liner                      60135577             WC 20762315        04/17/2017       Scraping Delaminated Coatings       60129662             WC The Service Level I Coatings inside the SNGS Unit 2 Containment Building were inspected by the qualified individual and notifications were initiated to correct minor coating degradation. Overall, the Service Level I coatings were found to be in good condition.
2R26 (Spring 2023)
The purpose of this inspection report is to document the SNGS Unit 2 containment coating condition monitoring activities performed during 2R26.
Prior to performing the walkdowns, the qualified individuals reviewed past notifications. The following is a list of Notifications, follow-up actions and their respective status from previous outage walk-downs.
Table 3.5.2 Notifications from Previous Outage - 2R25 Notification     Created On               Description             Work Order            Status 20885165        10/02/2021       Boric Acid White Stains         None           WC (per Notification Transfer Canal Area                            Update)
Coatings 20884756        10/03/2021       Regen Hx Room Floor             None           WC (per Notification Coatings                                       Update) 20807735        10/15/2018       Scraping Loose Coatings         60135577       WC 20807736        10/15/2018       Touch-up Liner                  60135577       WC The Service Level I Coatings inside the SNGS Unit 2 Containment Building were inspected by the qualified individual and notifications were initiated to correct minor coating degradation. Overall, the Service Level I coatings were found to be in good condition.
3.5.3   SNGS Units 1 and 2, 3rd Interval Containment Inservice Inspection Program Plan Introduction This Containment Inservice Inspection (CISI) Program Plan details the requirements for examination and testing of ISI Class MC and CC components and their integral attachments at SNGS Units 1 and 2. This CISI Program also includes Augmented Inservice Inspections 45

LR-N23-0005                                                                   LAR S22-04 Enclosure including those established by IWE-1240 and Owner Elected requirements imposed on or committed to by SNGS Units 1 and 2.
Pursuant to the Code of Federal Regulations, Title 10, Part 50, Section 55a, Codes and Standards, (10 CFR 50.55a), Paragraph (g), Inservice inspection requirements, licensees are required to update their ISI Programs to meet the requirements of ASME Section XI once every ten years or inspection interval. The CISI Program is required to comply with the latest Edition and Addenda of the Code incorporated by reference in 10 CFR 50.55a(b) twelve (12) months prior to the start of the interval per 10 CFR 50.55a(g)(4)(ii).
The Third CISI Interval for both units are effective from January 1, 2021 through December 31, 2030. The ASME Code of Record for the Third 10-Year CISI Interval is the 2013 Edition with no addenda of ASME Section XI.
The inspection interval may be reduced or extended by as much as one year and may be reduced without restriction, provided the examinations required for the interval have been completed. Successive intervals shall not extend more than 1 year beyond the original pattern of 10-year intervals and shall not exceed 11 years in length. If an inspection interval is extended, neither the start and end dates nor the inservice inspection program for the successive interval need be revised [IWA-2430(c)(1)].
Examinations may be performed to satisfy the requirements of the extended period or interval in conjunction with examinations performed to satisfy the requirements of the successive period or interval or the successive interval shall not be credited to both periods or intervals [IWA-2430(c)(2)].
Previous Interval CISI Program SNGS Units 1 and 2 First Ten-Year Interval CISI Program The first inspection interval commenced on April 22, 2000 in accordance with the requirements of Federal Register Vol. 64, No. 183, pages 51370-51400-Final Rule-10 CFR Part 50-Industry Codes and Standards, Amended Requirements, September 22, 1999. The ASME Code Edition and Addenda for the first inspection interval was the 1998 Edition with the 1998 Addenda as approved by the NRC via Request for Alternatives RR-E1 and RR-L1.
SNGS Units 1 and 2 Second Ten-Year Interval CISI Program The second ten-year CISI program was effective from April 22, 2010 through April 21, 2020. The code of record for the second ten-year interval was the ASME Section XI, 2004 Edition with no addenda. The CISI Program Plan was developed in accordance with the requirements of 10 CFR 50.55a including all published changes through October 19, 2009 and ASME Section XI, 2004 Edition with no addenda, subject to the conditions contained within paragraph (b) of 10 CFR 50.55a. The inspection interval was extended to coincide with refueling outages as shown in Tables 3.5.3-1 and 3.5.3-2.
46

LR-N23-0005                                                                 LAR S22-04 Enclosure Table 3.5.3-1, CISI/IWE Second Ten-Year Interval/Period/Outage Matrix Unit 1 Interval                  Periods                         Outages Start Date           Start Date to End     Outage Dates and/or          Outage To End Date                    Date                Durations            Numbers 1st Period       10/23/11 - 11/22/11          S1R21 04/22/2010 To           04/14/13 - 05/27/13          S1R22 04/21/2013 2nd Period       10/19/14 - 11/23/14          S1R23 04/22/2010 04/22/2013 To                                      04/14/16 - 07/30/16         S1R24 To 12/31/2020 12/31/2017        10/12/17 - 11/12/17         S1R25(1) 3rd Period       04/12/19 - 06/18/19          S1R26 01/01/2018 To          10/03/20 - 12/19/20          S1R27(2) 12/31/2020 Note 1: 2nd Period was extended per IWA-2430(d)(3) to coincide with 1R25 Note 2: 3rd Period was extended per IWA-2430(d)(3) to coincide with new Interval end date and added 1R27 outage to 2nd Interval.
Note 3: Bolded outages were when the IWL examinations were completed Table 3.5.3-2, CISI/IWE Second Ten-Year Interval/Period/Outage Matrix Unit 2 Interval                 Periods                          Outages Start Date to        Start Date to End      Outage Dates and/or           Outage End Date                   Date                Durations               Numbers 04/22/2010                1st Period       04/09/11 - 05/08/11            S2R18 To                  04/22/2010 12/31/2020                    To           10/14/12 - 11/18/12            S2R19 04/21/2013 2nd Period        04/12/14 -07/14/14            S2R20 04/22/2013 To          10/22/15 -12/01/15              S2R21 05/30/2017       04/14/17-05/30/17              S2R22(1) 3rd Period         10/11/18 - 11/13/18          S2R23 05/31/2017 To           04/11/20 - 05/12/20           S2R24(2) 12/31/2020 Note 1: 2nd Period was extended per IWA-2430(d)(3) to coincide with 2R22 Note 2: 2nd Interval was extended per IWA-2430(d)(1) to include with new end date of 12/31/2020.
Note 3: Bolded outages were when the IWL examinations were completed 47

LR-N23-0005                                                                          LAR S22-04 Enclosure SNGS Units 1 and 2 Third Ten-Year CISI Program The third CISI Interval commenced on January 1, 2021. The CISI Program is developed utilizing the ASME Code, Section XI, 2013 Edition and supplemented with NRC approved Code Cases.
The SNGS Unit 1 and 2 Third Ten-Year CISI Program Plan is developed in accordance with the requirements of 10 CFR 50.55a including all published changes through Federal Register, Vol.
85, No. 107, dated June 3, 2020, and ASME Section XI, 2013 Edition, subject to the conditions contained in paragraph (b) of 10 CFR 50.55a. These conditions are included in Table 3.5.3-5.
The CISI Program Plan addresses Subsections IWE and IWL, Mandatory Appendices, approved ASME Code Cases, approved alternatives through requests and associated SERs.
Table 3.5.3-3, SNGS Third Ten-Year CISI Interval Schedule Interval                   Periods                                SNGS Outages Start Date To Start Date To End Date              Unit 1 Outages               Unit 2 Outages End Date S2R25 Fall 2021 S1R28 Spring 2022         10/02/2021 - 11/12/2021 04/09/2022 - 05/18/2022        S2R26 Spring 2023 1st 01/01/21 to 12/31/24(1)                                  04/01/2023 - 04/28/2023 3rd CISI                                             S1R29 Fall 2023              S2R27 Fall 2024(1)
Interval S1R30 Spring 2025            S2R28 Spring 2026 01/01/2021                     2nd To                 01/01/25 to 12/31/27           S1R31 Fall 2026              S2R29 Fall 2027 12/31/2030 S1R32 Spring 2028            S2R30 Spring 2029 3rd 01/01/28 to 12/31/30           S1R33 Fall 2029               S2R31 Fall 2030 Note 1: The 1st period of the 3rd CISI Interval is extended to 12/31/24 to accommodate the S2R27 outage in the Fall of 2024 per IWA-2430(c)(3).
Note 2: Bolded outages are when the IWL examinations are scheduled.
48

LR-N23-0005                                                                              LAR S22-04 Enclosure The fourth CISI Interval will commence on January 1, 2031. The following is the proposed fourth CISI interval schedule.
Table 3.5.3-4, SNGS Fourth Ten Year CISI Interval Schedule Interval                 Periods                                     SNGS Outages Start Date To Start Date To End Date                   Unit 1 Outages                Unit 2 Outages End Date S1R34 Spring 2031              S2R32 Spring 2032 1st 01/01/31 to 12/31/33 4th CISI                                                S1R35 Fall 2032               S2R33 Fall 2033 Interval1 S1R36 Spring 2034              S2R34 Spring 2035 2nd 01/01/2031 01/01/34 to 12/31/37                S1R37 Fall 2035               S2R36 Fall 2036 To 12/31/2040 S1R38 Spring 20373              S2R37 Spring 2038 3rd 01/01/38 to 12/31/40                S1R39 Fall 20383              S2R38 Fall 2039 Note 1: The schedule for the 4th Interval CISI Schedule is proposed as the 4th interval schedule has yet to be developed.
Note 2: Bolded outages are when the IWL examinations would be scheduled.
Note 3: Unit 1 outages S1R38 and S1R39 are beyond the current Operating License expiration date.
Code of Federal Regulations - CISI Applicability There are certain paragraphs in 10 CFR 50.55a that list conditions imposed upon the 2013 Edition of ASME Section XI. These paragraphs that are applicable to SNGS Units 1 and 2 are detailed in Table 3.5.3-4 with updates in 10 CFR 50.55a effective in April 2022.
TABLE 3.5.3-5, Code of Federal Regulations 10 CFR 50.55a Requirements 10 CFR 50.55a                                               Conditions Paragraphs 10 CFR 50.55a(b)(2)(viii)     (H) Concrete containment examinations: Eighth provision. For each (H)               inaccessible area of concrete identified for evaluation under IWL-2512(a) or identified as susceptible to deterioration under IWL-2512(b), the licensee must provide the applicable information specified in paragraphs (b)(2)(viii)(E)(1), (2),
and (3) of this section in the ISI Summary Report required by IWA-6000.
10 CFR50.55a(b)(2)(viii)      (I) Concrete containment examinations: Ninth provision. During the period of (I)              extended operation of a renewed license under part 54 of this chapter, the licensee must perform the technical evaluation under IWL-2512(b) of inaccessible below-grade concrete surfaces exposed to foundation soil, backfill, or groundwater at periodic intervals not to exceed 5 years. In addition, the licensee must examine representative samples of the exposed portions of the below-grade concrete, when such below-grade concrete is excavated for any reason.
49

LR-N23-0005                                                                           LAR S22-04 Enclosure 10 CFR 50.55a(b)(2)(ix) (2) For each inaccessible area identified for evaluation, the applicant or (A)(2)         licensee must provide the following in the ISI Summary Report as required by IWA-6000:
(i) A description of the type and estimated extent of degradation, and the conditions that led to the degradation; (ii) An evaluation of each area, and the result of the evaluation; and (iii) A description of necessary corrective actions 10CFR50.55a(2)(ix)    (B) Metal containment examinations: Second provision. When performing (B)          remotely the visual examinations required by Subsection IWE, the maximum direct examination distance specified in Table IWA-2210-1 (2001 Edition through 2004 Edition) or Table IWA-2211-1 (2005 Addenda through the latest edition and addenda incorporated by reference in paragraph (a)(1) of this section) may be extended and the minimum illumination requirements specified may be decreased provided that the conditions or indications for which the visual examination is performed can be detected at the chosen distance and illumination.
10 CF50.55a(2)(ix)   (J) Metal containment examinations: Tenth provision. In general, a (J)          repair/replacement activity such as replacing a large containment penetration, cutting a large construction opening in the containment pressure boundary to replace steam generators, reactor vessel heads, pressurizers, or other major equipment; or other similar modification is considered a major containment modification. When applying IWE-5000 to Class MC pressure-retaining components, any major containment modification or repair/replacement must be followed by a Type A test to provide assurance of both containment structural integrity and leak-tight integrity prior to returning to service, in accordance with 10 CFR part 50, Appendix J, Option A or Option B on which the applicant's or licensee's Containment Leak-Rate Testing Program is based. When applying IWE-5000, if a Type A, B, or C Test is performed, the test pressure and acceptance standard for the test must be in accordance with 10 CFR part 50, Appendix J.
10CFR50.55a(2)(ix)    (K) Metal Containment Examinations: Eleventh provision. A general visual (K)           examination of containment leak chase channel* moisture barriers must be performed once each interval, in accordance with the completion percentages in Table IWE 2411-1 of the 2017 Edition. Examination shall include the moisture barrier materials (caulking, gaskets, coatings, etc.) that prevent water from accessing the embedded containment liner within the leak chase channel system. Caps of stub tubes extending to or above the concrete floor interface may be inspected, provided the configuration of the cap functions as a moisture barrier as described previously. Leak chase channel system closures need not be disassembled for performance of examinations if the moisture barrier material is clearly visible without disassembly, or coatings are intact. The closures are acceptable if no damage or degradation exists that would allow intrusion of moisture against inaccessible surfaces of the metal containment shell or liner within the leak chase channel system.
Examinations that identify flaws or relevant conditions shall be extended in accordance with paragraph IWE 2430 of the 2017 Edition.
* The leak chase channels are the same as the previously described liner plate monitor channels.
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LR-N23-0005                                                                  LAR S22-04 Enclosure CODE CASES The use of Code Cases is in accordance with ASME Section XI, IWA-2440, 10 CFR 50.55a, and Regulatory Guide 1.147. As permitted by ASME Section XI and Regulatory Guide 1.147 or 10 CFR 50.55a, ASME Section XI Code Cases may be adopted and used as described below:
Adoption of Code Cases Listed for Generic Use in Regulatory Guide 1.147 Code Cases that are listed for generic use in the latest revision of Regulatory Guide 1.147 may be included in the ISI program provided any additional conditions specified in the Regulatory Guide are also incorporated.
Adoption of Code Cases Not Approved in Regulatory Guide 1.147 Certain Code Cases that have been approved by the ASME Board of Nuclear Codes and Standards may not have been reviewed and approved by the NRC Staff for generic use and listed in Regulatory Guide 1.147. Use of such Code Cases may be requested in the form of a Request for Alternative in accordance with 10 CFR 50.55a (z). Once authorized/approved, these Requests for Alternatives will be available for use until such time that the Code Cases are adopted into Regulatory Guide 1.147, at which time compliance with the provisions contained in the Regulatory Guide are required.
Adoption of Code Cases Mandated by 10 CFR 50.55a Code Cases required by rule in 10 CFR 50.55a are incorporated into the ISI Program and implemented at the specified schedule.
Use of Annulled Code Cases As permitted by Regulatory Guide 1.147, Code Cases that have been adopted for use in the current inspection interval that are subsequently annulled by ASME may be used for the remainder of the interval.
Code Case Revisions Initial adoption of a Code Case requires use of the latest revision of that Code Case listed in Regulatory Guide 1.147. However, if an adopted Code Case is later revised and approved by the NRC, then either the earlier or later revision may be used as permitted by Regulatory Guide 1.147. An exception to this provision would be the inclusion of any conditions on the later revision necessary to enhance safety. In this situation, the conditions imposed on the later revision must be incorporated into the program.
Any subsequent Code Cases shall be incorporated into the program and identified as applicable, prior to their use.
Code Cases Not Approved for Generic Use by the NRC Code Cases that have been approved by the ASME Board of Nuclear Codes and Standards may not be approved by the NRC Staff for generic use. These Code Cases are listed in Regulatory Guide 1.193, ASME Code Cases Not Approved for Use. However, the NRC may approve their use in specific cases. Code Cases listed in Regulatory Guide 1.193 will not be used at SNGS 51

LR-N23-0005                                                                 LAR S22-04 Enclosure Units 1 and 2 without an approved Request for Alternative in accordance with 10 CFR 50.55a(z).
Relief Requests and Requests for Alternatives Throughout this CISI Program Plan, the term Relief Request is used interchangeably referring to submittals to the NRC requesting permission to deviate from either an ASME Section XI requirement, a 10 CFR 50.55a rule, or to use provisions from editions of Section XI not approved by the NRC as referenced in 10 CFR 50.55a(b). However, when communicating with the NRC and in written requests to deviate, the terms as defined below must be used for clarity and to satisfy 10 CFR 50.55a. Submittals to the NRC must clearly identify which of the below rules are being used to request the deviation.
Requests for Alternatives When seeking an alternative to the rules contained in 10 CFR 50.55a(b) through (h) the request is submitted under the provision of 10 CFR 50.55a(z). Once approved by the Director, Office of Nuclear Reactor Regulation, the alternative may be incorporated into the CISI program. These types of requests are typically used to request use of Code Cases, Code Editions, or Addenda not yet approved by the NRC. Request for Alternatives must be approved by the NRC prior to their implementation or use. Within the provisions of 10 CFR 50.55a(z) there are two specific methods of submittal:
* 10 CFR 50.55a(z)(1) Acceptable level of quality and safety. The proposed alternative would provide an acceptable level of quality and safety.
* 10 CFR 50.55a(z)(2) Hardship without a compensating increase in quality and safety.
Compliance with the specified requirements of this section would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety.
For IWE and IWL no code cases or relief requests are currently envoked.
ASME for Containment Inservice Inspection Program As required by the 10 CFR 50.55a, this program was developed in accordance with the requirements detailed in the 2013 Edition of ASME Boiler and Pressure Vessel Code, Section XI, Division 1, Subsections IWA, IWE and IWL, Mandatory Appendices, Inspection Program of IWA-2400, approved ASME Code Cases, and approved alternatives through relief requests and Safety Evaluation Reports (SERs).
Augmented Examination Requirements This Third Ten-Year CISI Program Plan Section, including its pressure testing requirements, contains augmented examinations that may be inside or outside the scope of 10 CFR 50.55a.
These augmented examinations may result from activities including, but not limited to meeting the requirements of 10 CFR 50.55a or commitments made outside of 10 CFR 50.55a, or those made based on other document requirements, internal commitments, license renewal commitments, or industry initiatives. Augmented examinations may be required to use ASME Section XI techniques and procedures or those as defined in the commitment, however, the requirements of ASME Section XI, including reporting, do not apply when these examinations are required outside of 10 CFR 50.55a.
52

LR-N23-0005                                                                 LAR S22-04 Enclosure For other augmented examinations that are not required by 10 CFR 50.55a and ASME Code requirements such as Section XI and its Code Cases, they are NOT required to be included in the summary totals for a specific examination category. These augmented examinations may be required to use ASME Section XI techniques and procedures or those as defined in the commitment, however, the requirements of ASME Section XI, including reporting, do NOT apply when these examinations are required outside of 10 CFR 50.55a. Changes to these examination requirements and schedules that are outside of 10 CFR 50.55a may be required to be evaluated using the 10 CFR 50.59 screening/review process unless otherwise specified. Augmented examinations are considered in one of the following four categories:
* Augmented Examinations Required by 10 CFR 50.55a;
* Augmented Examinations for External Commitments;
* Owner Elected Examinations for Internal Commitments; and
* License Renewal Examinations for Aging Management Commitments Augmented Programs for External Commitments This type of augmented examination is conducted to meet a commitment made to a source outside the utility. Typically, these are commitments made to the NRC in response to regulatory documents such as Generic Letters, Bulletins and NUREGs or other Industry Groups such as NEI or Materials Reliability Program (MRP).
Type A Test This augmented inspection is a requirement of 10 CFR Part 50, Appendix J - Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors.
This requires that a General Visual Examination of 100% of the accessible interior and exterior surfaces of the containment structures and components shall be performed prior to any Type A test to uncover any evidence of structural deterioration which may affect either the containment structural integrity or leak-tightness.
License Renewal Programs This augmented program is to ensure that the requirements of ASME Section XI, Subsection IWE and the added License Renewal (LR) Enhancement (1) and Owner Elected LR Enhancement (4) discussed below provide an Aging Management Program (AMP) that will be applied for the Metal Containment Liners at both SNGS Units 1 and 2 prior to and during the Period of Extended Operation (PEO). For the Third Ten-Year CISI Interval, only examinations to be performed during the PEO are included in this plan. All prior to the PEO examinations have been completed.
License Renewal Commitment A.2.1.28 Enhancements 1 and 4:
LR Enhancement (1):
The ASME Section XI, Subsection IWE CISI program will be enhanced to include General Visual inspection of a sample of the inaccessible liner covered by insulation and lagging every 10 years.
One containment liner insulation panel will be selected, at random for removal from each 53

LR-N23-0005                                                                  LAR S22-04 Enclosure quadrant, during each of the three periods in an inspection interval. Therefore, a total of 12 containment liner insulation panels will be selected, in each unit, during each 10-year inspection interval, to allow for examination of the containment liner behind the containment liner insulation.
The randomly selected containment liner insulation panels in each quadrant will not include containment liner insulation panels previously selected. Should unacceptable degradation be found, additional insulation will be removed as necessary to determine extent of condition in accordance with the corrective action process.
LR Enhancement (4):
ASME Section XI, Subsection IWE CISI program will be enhanced to include General Visual inspection of the containment liner under the fuel transfer canal and behind the containment liner insulation, which are subjected to leaks from the reactor cavity. These inspections will be performed on a frequency of once per inspection period. These inspections will continue as long as leakage from the reactor cavity is observed between the containment liner and the containment liner insulation.
Technical Approach and Positions The requirements of ASME Section XI are not easily interpreted in some instances. ASME Section XI provides a method of obtaining interpretations, but these generally are in response to generic code application, and do not necessarily address specific site situations. SNGS has reviewed general licensing/regulatory requirements and industry practices to determine the practical methods of implementing the Code requirements for the site. The Technical Approach and Position (TAP) documents contained in this section have been provided to clarify SNGS's implementation of ASME Section XI requirements, when a difficult code interpretation is encountered for a site-specific situation. TAPs may be added throughout the interval, when required.
54

LR-N23-0005                                                                             LAR S22-04 Enclosure Table 3.5.3-5, Technical Approach and Position Index Position Revision Date2         Status3             Description of Technical Approach Number1 1                           (CISI) Containment Liner Insulation Panel SMC-I5T-04                                   Active 01/01/2020                        Inspection - License Renewal Credit Note 1: The nomenclature of the position number identifies which SNGS Unit is applies to and whether it is for the ISI or CISI Program. Example SM1-I5T-01 would apply to SNGS Unit 1 ISI Program or SM2-C3T-01 would apply to the SNGS Unit 2 CISI Program.
Note 2: The revision listed is the latest revision of the subject technical approach and position. The date noted in the second column is the date of the ISI Program Plan revision when the technical approach and position was incorporated into the document Note 3: Technical Approach and Position Status Options: Active - current ISI Program technical approach and position is being utilized at SNGS; Deleted - Technical approach and position is no longer being utilized at SNGS.
Technical Approach and Position: SMC-I5T-04 Component Identification:
Code Class:                         MC

==Reference:==
Commitment #28 (License Renewal Commitment List)
Examination Category:               E-A Item Number:                        N/A

==
Description:==
Inspection of a sample of the inaccessible liner covered by insulation and lagging once prior to the period of extended operation and every 10 years thereafter.
Component Number: Containment Liner Code Requirement:
The commitment prior to the period of extended operation shall include a sample size of 57 randomly selected containment liner insulation panels per unit.
POSITION:
The 57 random panel sample locations were derived from the assumption that the inaccessible liner panel square footage was 50 square feet per panel. For Unit 1 the actual panel size was found to be 35 square feet per panel location and for Unit 2 the actual panel size was found to be 40 square feet per panel location. The calculation to determine the number of insulation panels to be removed assumed the size of 50 square feet per panel location, and that assumption was found to be incorrect in the field. As such, to maintain the sample size of inaccessible liner square footage, it was necessary to increase the number of panel locations to be removed. For Unit 1 the number of insulation panels to be removed equivalent to the original 57 panel locations is 82, and for Unit 2 is 72. All other aspects of the commitment remain the same. No change has been made to the square footage inspection sample and this position only clarifies the difference between the commitment requirement and the actual program inspection sample.
Additionally, for random expanded samples due to unsatisfactory conditions the Unit 1 1st expansion would be 40 panels, 2nd expansion would be 34 panels and 3rd expansion would be 55

LR-N23-0005                                                                  LAR S22-04 Enclosure 31 panels. For Unit 2 the 1st expansion would be 35 panels, 2nd expansion would be 30 panels and 3rd expansion would be 27 panels. Expanded samples should not include previously inspection locations.
Unit 1 and Unit 2 have completed their required 1st random samples due to the initial random samples having unsatisfactory conditions. Unit 2 had identified an additional sample with unsatisfactory conditions in the 1st random sample and as of November 2021 is implementing the 2nd random sample of 30 additional liner panels to be complete in the next 2 cycles.
System Pressure Testing (CISI)
The requirements of IWA-5000 are not applicable to Class MC or Class CC components 1.0     Test Following Repair/Replacement Activities 1.1    General (a)     Except as noted in 1.3, a pneumatic leakage test shall be performed following repair/replacement activities performed by welding or brazing, prior to returning the component to service.
(b)     The following are exempt from the requirements of pressure testing
* Attachments (e.g., as defined in NE-1132) and nonpressure-retaining items
* Welding or brazing on pressure-retaining portions of components, when the remaining wall thickness after metal removal is at least 90% of the minimum design wall thickness.
1.2    Pneumatic Leakage Test (a)     Pressure - The pneumatic leakage test shall be conducted at a pressure between 0.96Pa and 1.10Pa, except when otherwise limited by plant technical specifications, where Pa is the design basis accident pressure.
(b)     Boundaries - The test boundary may be limited to brazed joints and welds affected by the repair/replacement activity.
(c)     Test Medium and Temperature
* The test medium shall be nonflammable
* The test may be conducted with the vessel partially filled with water, provided the vessel stresses resulting from the test do not exceed the limits of the Construction Code.
* The test shall be conducted at a temperature that will preclude brittle fracture of the component.
56

LR-N23-0005                                                                 LAR S22-04 Enclosure (d)      Examination - During the pneumatic leakage test, the leak tightness of brazed joints and welds affected by the repair/replacement activity shall be verified by performing one of the following:
* A bubble test - direct pressure technique in accordance with ASME Section V, Article 10, Appendix I, or any other ASME Section V, Article 10 leak test that can be performed in conjunction with the pneumatic leakage test.
* A Type A, B, or C Test, as applicable, in accordance with 10 CFR 50, Appendix J (e)      Leakage - The test area is acceptable if the acceptance standards of ASME Section V, Article 10 are met or if the measured leakage is less than can be detected by the bubble test-direct pressure technique.
1.3  Bubble Test-Vacuum Box Technique (a)      As an alternative to the requirements of 1.2, a bubble test-vacuum box technique may be performed following repair/replacement activities performed by welding or brazing on the following:
* Metallic shell and penetration liners of Class CC components
* Nonstructural pressure-retaining metallic liners of Class MC Components embedded in, or backed by concrete.
(b)      The bubble test shall be performed in accordance with ASME Section V, Article 10, Appendix II at a partial vacuum of at least 5 psi below atmospheric pressure.
(c)      Only brazed joints and welds made in the course of the repair/replacement activity require testing.
1.4  Visual examination requirements of IWE-2200(c) shall be met.
1.5  Corrective Action - if the leakage test requirement cannot be satisfied, the source of leakage shall be located and the area shall be examined to the extent necessary to establish the requirements for corrective action. Repair/replacement activities shall be performed in accordance with the requirements of IWA-4000.
Leakage testing shall be re-performed as required by 1.1, prior to returning the component to service.
57

LR-N23-0005                                                                      LAR S22-04 Enclosure Containment ISI Plan This section details the inservice inspection requirements for the Class MC and CC components and integral attachments at SNGS Units 1 & 2.
10 CFR 50.55a(g)(4) states in part Components that are classified as Class MC pressure retaining components and their integral attachments, and components that are classified as Class CC pressure retaining components and their integral attachments, must meet the requirements, except design and access provisions and preservice examination requirements, set forth in Section XI of the ASME BPV Code and addenda that are incorporated by reference in paragraph (a)(1)(ii) of this section and the conditions listed in paragraphs (b)(2)(viii) and (ix) of this section, to the extent practical within the limitation of design, geometry, and materials of construction of the components.
ASME Section XI, 2013 Edition, subparagraph IWE-1231 Accessible Surface Areas require as a minimum, the following portions of the Class CC metallic shell and penetration liners to remain accessible for either direct or remote visual examination from at least one side of the vessel, for the life of the plant:
* Openings and penetrations
* Structural discontinuities
* 80% of the pressure-retaining boundary (excluding attachments, structural reinforcement, and areas made inaccessible during construction); and
* Surface areas identified in IWE-1240 For those portions of the Class CC containment liner that is only accessible from the interior surface the following requirements of IWE-1232 shall be met:
* All welded joints that are inaccessible for examination are examined in accordance with CC-5520 and prior to being covered or otherwise obstructed by adjacent structures, components, parts, or appurtenances, are test for leak tightness in accordance with CC5536; and
* The containment is leak rate tested after completion of construction or repair/replacement activities to the leak rate requirements of the Design Specification.
Subparagraph IWE-1232(c) provides guidance for what areas are defined as inaccessible.
Surface areas of Class CC metallic shell and penetration liners may be considered inaccessible if visual access by line of sight with adequate lighting from permanent vantage points is obstructed by permanent plant structures, equipment, or components, provided these surface areas do not require examination in accordance with the inspection plan or IWE-1240.
Class MC and CC Components The SNGS Unit 1 & 2 CISI Class MC Components identified are those not exempted in accordance with IWE-1220 in the 2013 Edition of ASME Section XI.
The identification of the SNGS Unit 1 & 2 Class MC components for inclusion into the CISI Plan is included in the CISI 3rd Interval Classification Basis Document. This basis document includes a listing and detailed basis for inclusion of the Class MC components.
58

LR-N23-0005                                                                   LAR S22-04 Enclosure Components that were classified as Class MC shall meet the requirements of ASME Section XI in accordance with 10 CFR 50.55a(g)(4). Although containment supports are not strictly required to be examined in accordance with 10 CFR 50.55a(g)(4), the Basis Document includes identification of Class MC supports that should be examined. SNGS Units 1 & 2 have elected to perform these examinations in accordance with ASME Section XI, Subsection IWF.
Identification of CISI Class MC and CC Nonexempt Components CISI Nonexempt Class MC Components are identified in SNGS CISI Drawings. These drawings are identified with special prefixes of E. The accessible areas are identified on the drawings with a
* and the inaccessible areas are identified with an x.
CISI Nonexempt Class CC Components include the conventional reinforced concrete of the Containment Structure. These components consist of the concrete dome, cylindrical wall, and concrete base slab. The Containment Structure is reinforced with mild reinforcing steel with no unbonded post tensioning system.
Identification of CISI Class MC and CC Exempt Components The process of identification of CISI Exempt Class MC Components per IWE-1220 is included in the Basis Document.
Component Accessibility As discussed above, the accessible Class MC Pressure retaining areas are identified on the IWE Boundary Drawings with a *. These areas shall remain accessible for either direct or indirect visual examination from at least one side in accordance with paragraph IWE-1231 of the ASME Section XI Code.
Portions of the containment pressure retaining areas that were embedded in concrete or otherwise made inaccessible during construction are exempted from examinations, provided the requirements of IWE-1232 of the ASME Section XI Code were met.
In addition, inaccessible surfaces areas exempted from examination include those surface areas where visual access by line of sight with adequate lighting from permanent vantage points is obstructed by permanent plant structures, equipment, or components, provided these surface areas do not require examination in accordance with the inspection plan, or augmented examination in accordance with IWE-1240 Successive Inspections Class MC Components will be performed in accordance with IWE-2420 which included the following criteria:
: 1.      When examination results detect flaws, areas of degradation, or conditions that require an engineering evaluation in accordance with IWE-3000 or IWE-2500(d),
and the component is acceptable for continued service, the areas containing the flaws, areas of degradation, or conditions shall be reexamined during the next inspection period listed in the schedule of the Inspection Program of IWE-2411, in accordance with Table IWE-2500-1 (E-C).
59

LR-N23-0005                                                                   LAR S22-04 Enclosure
: 2.      When the evaluation of examinations results identifies conditions that could indicate the presence of, or result in, flaws or degradation in inaccessible areas [as defined in IWE-1232(c)] the inaccessible areas shall be examined, to the extent possible, for evidence of flaws and degradation. If the examination results detect flaws or areas of degradation requiring engineering evaluation in accordance with IWE-3000, and the component is acceptable for continued service, the requirement of 6.5.1 shall be met.
: 3.      When the reexaminations required by 1 above reveal that the flaws or areas of degradation remain essentially unchanged for the next inspection period, these areas no longer require augmented examination in accordance with Table IWE-2500-1 (E- C).
ISI Class MC and CC Components Examination Category E-A - Containment Surfaces This category applies to the accessible surface areas of the containment liner and requires 100%
to be examined with a General Visual examination each inspection period. The examination shall include all accessible interior and exterior surfaces of Class MC Components, parts, and appurtenances. In addition, the moisture barriers shall be examined with a General Visual examination each inspection period. The moisture barrier materials are those intended to prevent intrusion of moisture against inaccessible areas of the pressure retaining shell or liner.
Examination Category E-C - Containment Surfaces Requiring Augmented Examination This category applies to those surface areas subject to accelerated degradation and aging to be examined with a Visual VT-1 examination or Ultrasonic Thickness examination once per inspection period. VT-1 may be performed in locations where E4.12 UT Thickness examinations are restricted by moisture barrier sealant.
Unit 1 Ultrasonic Thickness Measurements on the Metal Liner at Elevation 78 above the containment floor and below the horizontal liner plate monitor channel. (4 Quadrants). Ultrasonic Thickness Measurements on the Metal Liner above vertical liner plate monitor channel number C14 at 90 degrees.
Unit 2 Ultrasonic Thickness Measurements on the Metal Liner at Elevation 78 above the containment floor and below the horizontal leak liner plate monitor channel (4 Quadrants).
Examination Category E-G - Pressure Retaining Bolting This category applies to the pressure retaining bolting and requires a VT-1 visual examination.
The examination includes bolts, studs, nuts, bushings, washers, and threads in base material and flange ligaments between fastener holes.
60

LR-N23-0005                                                               LAR S22-04 Enclosure Note 2 states Examination may be performed with the connection assembled and bolting in place under tension, provided the connection is not disassembled during the interval. If the bolted connection is disassembled for any reason during the interval, the examination shall be performed with the connection disassembled.
Examination Category L-A - Concrete Surfaces This category applies to the accessible concrete surfaces and required a General Visual examination once every 5 years. If there are any suspect areas, these are examined with a Detailed Visual every inspection interval. SNGS currently does not have any suspect areas.
Per IWL-2512 the Responsible Engineer shall evaluate suspect conditions and shall specify the type and extent of examinations, if any, required to be performed on inaccessible surface areas exempted by IWL-1220(c) and IWL- 1220(d).
61

LR-N23-0005                                                                                 LAR S22-04 Enclosure Table 3.5.3-6, Containment Inservice Inspection Summary Table -Unit 1, Interval 3 Number of       Required to be    Examination      Number      Number to be    Number to be     Number to be Item                                                                                                     Examined or Category                             Description     Exam Method       Components in       Examined         Percentage                   Examined in     Examined in      Examined in Number                                                                                                    Scheduled During Item No.      During Interval     Required     the Interval    First Period  Second Period     Third Period E-A        Containment Surfaces 100% per E-A        E1.11       Accessible Surface Areas       General Visual          152             152                            152(1)           152            152              152 period 100%
Accessible caulking,                                                                     per E-A        E1.31                                     General Visual            8                8                            8(1)(2)            8             8                 8 flashing, and sealants                                                                  period 100%
Accessible Leak Chase                                                                    per E-A        E1.32                                     General Visual           54              54 (4) 54(4)             54            54                54 Channel System Closures                                                                interval Category Total           214             214                             214             214            214              214 Cumulative Percentage                                                                            100%           100%             100%
Note 1: Examination shall include all accessible interior and exterior surfaces of Class MC components, parts, and appurtenances, and metallic shell and penetration liners of Class CC components. The following items shall be examined: (a) integral attachments and structures that are parts of reinforcing structure, such as stiffening rings, manhole frames, and reinforcement around openings, (b) surfaces of attachment welds between structural attachments and the pressure retaining boundary or reinforcing structure, except for nonstructural or temporary attachments as defined in Notes for Cat. E-A         NE-4435 and minor permanent attachments as defined in CC-4543.4, (c) surfaces of containment structural and pressure boundary welds, including longitudinal welds (Category A), circumferential welds (Category B), flange welds (Category C), and nozzle-to-shell welds (Category D) as define din NE-3351 for Class MC and CC-3840 for Class CC; and surfaces of Flued Head and Bellows Seal Circumferential Welds joined to the Penetration, (d) pressure-retaining bolted connections, including bolts, studs, nuts, bushings, washers, and threads in base material and flange ligaments between fastener holes. Bolted connections need not be disassembled for performance of examinations.
62

LR-N23-0005                                                                              LAR S22-04 Enclosure Note 2: Examination shall include moisture barrier materials intended to prevent intrusion of moisture against inaccessible areas of the pressure retaining metal containment shell or liner at concrete-to-metal interfaces and at metal-to-metal interfaces which are not seal-welded. Containment moisture barrier materials include caulking, flashing, and other sealants used for this application.
Note 3: Examination shall include the moisture barrier materials (caulking, flashing, and other sealants) installed in leak chase channel system enclosures at concrete floor interfaces, or caps of stub tubes terminating within the leak chase channel system enclosure, that prevent water from accessing the embedded containment liner within the leak chase channel system. Leak chase channel system closures need not be disassembled (e.g., removal of covers, plugs, caps, or coatings) for performance of examinations if the moisture barrier material is clearly visible without disassembly, coatings are intact, or there is no evidence of damage or degradation that would allow intrusion of moisture into inaccessible areas of the metal containment shell or liner within the leak chase channel system. If disassembled, the exposed threads, moisture barrier materials, and related surface areas shall be examined.
Note 4: Metal Containment Examinations: A general visual examination of containment leak chase channel moisture barriers must be performed once each interval, in accordance with the completion percentages in Table IWE 2411-1 of the 2017 Edition. Examination shall include the moisture barrier materials (caulking, gaskets, coatings, etc.) that prevent water from accessing the embedded containment liner within the leak chase channel system.
Caps of stub tubes extending to or above the concrete floor interface may be inspected, provided the configuration of the cap functions as a moisture barrier. Leak chase channel system closures need not be disassembled for performance of examinations if the moisture barrier material is clearly visible without disassembly, or coatings are intact. The closures are acceptable if no damage or degradation exists that would allow intrusion of moisture against inaccessible surfaces of the metal containment shell or liner within the leak chase channel system. Examinations that identify flaws or relevant conditions shall be extended in accordance with paragraph IWE 2430 of the 2017 Edition. 100% of these examinations are scheduled each period.
63

LR-N23-0005                                                                                  LAR S22-04 Enclosure Table 3.5.3-6, Containment Inservice Inspection Summary Table -Unit 1, Interval 3 Number Number of       Required to be   Examination       Examined or    Number to be    Number to be    Number to be Item                                                    Components in       Examined        Percentage     Scheduled During Examined in      Examined in     Examined in Category     Number        Description                 Exam Method          Item No.      During Interval    Required         the Interval   First Period   Second Period     Third Period E-C        Containment Surfaces Requiring Augmented Examination 100% per E-C        E4.11          Visible Surfaces           Visual, VT-1           0(1)             0                                   0              0              0                0 period Surface Area Grid Minimum          Ultrasonic                                         100% per E-C        E4.12     Wall Thickness Locations           thickness            5               5             period               5(2)            5              5                5 Category Total            5               5                                   5              5              5                5 Cumulative Percentage                                                                                 100%           100%             100%
Note 1: There is no Item No. E4.11 examinations for SNGS Unit 1.
Notes for Cat. E-C  Note 2: Containment surface areas requiring augmented examination are those identified in IWE-1240.
E-G        Pressure Retaining Bolting 100% per E-G           E8.10   Bolted Connections              Visual, VT-1                  5       5                                    5(1)(2)           0              0                5 Interval Category Total                5       5                                       5              0              0                5 Cumulative Percentage                                                                                  0%             0%              100%
Note 1: Examination shall include bolts, studs, nuts, bushings, washers, and threads in base material and flange ligaments between fastener holes.
Note 2: Examination may be performed with the connection assembled and bolting in place under tension, provided the connection is not disassembled during Notes for Cat. E-G           the interval. If the bolted connection is disassembled for any reason during the interval, the examination shall be performed with the connection disassembled.
64

LR-N23-0005                                                                                LAR S22-04 Enclosure Table 3.5.3-6, Containment Inservice Inspection Summary Table -Unit 1, Interval 3 Number of       Required to be   Examination      Number      Number to be        Number to be  Number to be Item                                                                                                   Examined or Category                             Description     Exam Method     Components in        Examined       Percentage                   Examined in         Examined in  Examined in Number                                                                                                  Scheduled During Item No.       During Interval    Required     the Interval   First Period       Second Period  Third Period L-A        Concrete 100% per L-A        L1.11       All accessible surface areas   General Visual 8               8              5 Year          8(1)                     8                       8 period Detailed                                         100% per L-A        L1.12       Suspect areas Visual              0               0              5 Year           0                       0                       0 period Inaccessible Below-Grade L-A        L1.13                                        IWL-2512(c)         (2)(3)            (3)             (3)             (3)                     (3)                     (3)
Areas Category Total          8               8                               8                       8                       8 Cumulative Percentage                                                                                  100%                    100%
Note 1: Includes concrete surfaces at tendon anchorage areas not selected by IWL-2521 or exempted by IWL-1220(a)
Notes for Cat. L-A Note 2: Concrete surfaces exposed to foundation soil, backfill, or ground water.
Note 3: Areas and method of examination as defined by the Responsible Engineer, based on IWL-2512(b) evaluation (to date none are identified).
65

LR-N23-0005                                                                             LAR S22-04 Enclosure Table 3.5.3-7, Augmented Inspection Summary Table -Unit 1, Interval 3 Number of      Required to be    Examination      Number      Number to be  Number to be  Number to be Item                                                                                               Examined or Category                    Description          Exam Method     Components in       Examined       Percentage                    Examined in   Examined in  Examined in Number                                                                                             Scheduled During Item No.       During Interval   Required      the Interval   First Period Second Period  Third Period Type A            Appendix J - Primary Reactor Containment Leakage Test (2)          (2)            (2)
A-E          OWN    Containment Type A Test     Visual                  4                4            100%(1)            4 (2)          (2)            (2)
Category Total          4                4                               4 Note 1: General Visual examination performed prior to the Type A Test.
Notes for Type A Note 2: Program Owner to schedule to coincide with the Type A Test.
66

LR-N23-0005                                                                                  LAR S22-04 Enclosure Table 3.5.3-8, License Renewal Inspection Summary Table -Unit 1, Interval 3 Number of      Required to be     Examination         Number        Number to be    Number to be      Number to be Item                                                                                                        Examined or Category                           Description       Exam Method       Components in       Examined        Percentage                         Examined in     Examined in       Examined in Number                                                                                                       Scheduled During Item No.      During Interval     Required         the Interval     First Period   Second Period      Third Period LRC               License Renewal Commitments (LRC), ASME Section XI, Subsection IWE with Enhancements Enhancement A-E        OWN
                         #1(1) Containment              Visual              348               12                (2) 12            3             3                  3 Liners Enhancement #4(4)
Containment Liners                                                                  100% Each A-E          OWN                                      Visual               4                 4             Inspection                4            4             4                  4 under Fuel Transfer                                                                  Period(5)
Canal Category Total Note 1: ASME Section XI, Subsection IWE program will be enhanced to include inspection of a sample of the inaccessible liner covered by insulation and lagging every 10 years.
Note 2: One containment liner insulation panel will be selected, at random for removal from each quadrant, during each of the three periods in an inspection interval. Therefore, a total of 12 containment liner insulation panels will be selected, in each unit, during each 10-year inspection interval, to allow for Notes for LRC           examination of the containment liner behind the containment liner insulation Note 3: NA Note 4: ASME Section XI, Subsection IWE program will be enhanced to include inspection of the containment liner under the fuel transfer canal and behind the containment liner insulation, which are subjected to leaks from the reactor cavity.
Note 5: These inspections will continue as long as leakage from the reactor cavity is observed between the containment liner and the containment liner insulation.
67

LR-N23-0005                                                                                 LAR S22-04 Enclosure Table 3.5.3-9, Containment Inservice Inspection Summary Table -Unit 2, Interval 3 Number of                        Examination      Number       Number to be    Number to be    Number to be Item                                                                    Required to be Examined or Category                             Description      Exam Method      Components in       Examined       Percentage                     Examined in     Examined in     Examined in Number                                                                                                   Scheduled During Item No. During Interval    Required      the Interval    First Period   Second Period    Third Period E-A        Containment Surfaces 100% per E-A        E1.11       Accessible Surface Areas      General Visual           152             152                       152(1)               152             152             152 period 100%
Accessible caulking,                                                                    per E-A        E1.31                                     General Visual            8               8                         8(1)(2)               8              8                8 flashing, and sealants                                                                 period 100%
E-A        E1.32       Accessible Leak Chase         General Visual           54             54(4)                       54(4) per                            54             54               54 Channel System Closures                                                               interval Category Total           214             214                        214                 214             214             214 Cumulative Percentage                                                                           100%            100%            100%
Note 1: Examination shall include all accessible interior and exterior surfaces of Class MC components, parts, and appurtenances, and metallic shell and penetration liners of Class CC components. The following items shall be examined: (a) integral attachments and structures that are parts of reinforcing structure, such as stiffening rings, manhole frames, and reinforcement around openings, (b) surfaces of attachment welds between structural attachments and the pressure retaining boundary or reinforcing structure, except for nonstructural or temporary attachments as defined Notes for Cat. E-A in NE-4435 and minor permanent attachments as defined in CC-4543.4, (c) surfaces of containment structural and pressure boundary welds, including longitudinal welds (Category A), circumferential welds (Category B), flange welds (Category C), and nozzle-to-shell welds (Category D) as define din NE-3351 for Class MC and CC-3840 for Class CC; and surfaces of Flued Head and Bellows Seal Circumferential Welds joined to the Penetration, (d) pressure-retaining bolted connections, including bolts, studs, nuts, bushings, washers, and threads in base material and flange ligaments between fastener holes. Bolted connections need not be disassembled for performance of examinations.
68

LR-N23-0005                                                                               LAR S22-04 Enclosure Note 2: Examination shall include moisture barrier materials intended to prevent intrusion of moisture against inaccessible areas of the pressure retaining metal containment shell or liner at concrete0to-metal interfaces and at metal-to-metal interfaces which are not seal-welded. Containment moisture barrier materials include caulking, flashing, and other sealants used for this application.
Note 3: Examination shall include the moisture barrier materials (caulking, flashing, and other sealants) installed in leak chase channel system enclosures at concrete floor interfaces, or caps of stub tubes terminating within the leak chase channel system enclosure, that prevent water from accessing the embedded containment liner within the leak chase channel system. Leak chase channel system closures need not be disassembled (e.g., removal of covers, plugs, caps, or coatings) for performance of examinations if the moisture barrier material is clearly visible without disassembly, coatings are intact, or there is no evidence of damage or degradation that would allow intrusion of moisture into inaccessible areas of the metal containment shell or liner within the leak chase channel system. If disassembled, the exposed threads, moisture barrier materials, and related surface areas shall be examined.
Note 4: Metal Containment Examinations: A general visual examination of containment leak chase channel moisture barriers must be performed once each interval, in accordance with the completion percentages in Table IWE 2411-1 of the 2017 Edition. Examination shall include the moisture barrier materials (caulking, gaskets, coatings, etc.) that prevent water from accessing the embedded containment liner within the leak chase channel system. Caps of stub tubes extending to or above the concrete floor interface may be inspected, provided the configuration of the cap functions as a moisture barrier. Leak chase channel system closures need not be disassembled for performance of examinations if the moisture barrier material is clearly visible without disassembly, or coatings are intact. The closures are acceptable if no damage or degradation exists that would allow intrusion of moisture against inaccessible surfaces of the metal containment shell or liner within the leak chase channel system. Examinations that identify flaws or relevant conditions shall be extended in accordance with paragraph IWE 2430 of the 2017 Edition. 100% of these examinations are scheduled each period.
69

LR-N23-0005                                                                                  LAR S22-04 Enclosure Table 3.5.3-9, Containment Inservice Inspection Summary Table -Unit 2, Interval 3 Number of                       Examination          Number      Number to be    Number to be     Number to be Item                                                                     Required to be Examined or Category                  Description                  Exam Method      Components in      Examined       Percentage                        Examined in     Examined in      Examined in Number                                                                                                       Scheduled During Item No. During Interval   Required          the Interval   First Period   Second Period     Third Period E-C    Containment Surfaces Requiring Augmented Examination 100% per E-C        E4.11         Visible Surfaces            Visual, VT-1           0(1)            0                                   0              0              0                0 period Surface Area Grid Minimum          Ultrasonic                                        100% per E-C        E4.12   Wall Thickness Locations           thickness              5              5             period               5(2)            5              5                5 Category Total            5              5                                   5              5              5                5 Cumulative Percentage                                                                               100%            100%             100%
Note 1: There are no Item No. E4.11 examinations for SNGS Unit 2.
Notes for Cat. E-C  Note 2: Containment surface areas requiring augmented examination are those identified in IWE-1240.
E-G        Pressure Retaining Bolting E-G           E8.10   Bolted Connections                 Visual, VT-1           5              5           100% per             5(1)(2)           0              0                5 Interval Category Total            5              5                                   5              0              0                5 Cumulative Percentage                                                                                 0%             0%              100%
Note 1: Examination shall include bolts, studs, nuts, bushings, washers, and threads in base material and flange ligaments between fastener holes.
Note 2: Examination may be performed with the connection assembled and bolting in place under tension, provided the connection is not disassembled during Notes for Cat. E-G           the interval. If the bolted connection is disassembled for any reason during the interval, the examination shall be performed with the connection disassembled.
70

LR-N23-0005                                                                                 LAR S22-04 Enclosure Table 3.5.3-9, Containment Inservice Inspection Summary Table -Unit 2, Interval 3 Number of                        Examination      Number      Number to be        Number to be  Number to be Item                                                                    Required to be Examined or Category                             Description      Exam Method    Components in       Examined       Percentage                    Examined in         Examined in  Examined in Number                                                                                                  Scheduled During Item No.      During Interval    Required      the Interval   First Period       Second Period  Third Period L-A        Concrete 100% per L-A        L1.11       All accessible surface areas  General Visual 8               8             5 Year           8(1)                     8                       8 period Detailed                                         100% per L-A        L1.12       Suspect areas Visual              0               0             5 Year             0                      0                       0 period Inaccessible Below-Grade L-A        L1.13                                     IWL-2512(c)            (2)(3)            (3)            (3)              (3)                     (3)                     (3)
Areas Category Total          8               8                                8                      8                       8 Cumulative Percentage                                                                                  100%                    100%
Note 1: Includes concrete surfaces at tendon anchorage areas not selected by IWL-2521 or exempted by IWL-1220(a)
Notes for Cat. L-A Note 2: Concrete surfaces exposed to foundation soil, backfill, or ground water.
Note 3: Areas and method of examination as defined by the Responsible Engineer, based on IWL-2512(b) evaluation (to date none are identified).
71

LR-N23-0005                                                                             LAR S22-04 Enclosure Table 3.5.3-10, Augmented Inspection Summary Table -Unit 2, Interval 3 Number Number of      Required to be    Examination Examined or Number to be  Number to be  Number to be Item Category                    Description          Exam Method     Components in       Examined       Percentage   Scheduled   Examined in   Examined in  Examined in Number Item No.       During Interval   Required    During the  First Period Second Period  Third Period Interval Type A         Appendix J - Primary Reactor Containment Leakage Test (2)          (2)            (2)
A-E          OWN    Containment Type A Test     Visual                  5                5            100%(1)        5 (2)          (2)            (2)
Category Total          5                5                           5 Note 1: General Visual examination performed prior to the Type A Test.
Notes for Type A Note 2: Program Owner to schedule to coincide with the Type A Test.
72

LR-N23-0005                                                                                  LAR S22-04 Enclosure Table 3.5.3-11, License Renewal Inspection Summary Table -Unit 2, Interval 3 Number Number of      Required to be     Examination       Examined or     Number to be    Number to be      Number to be Item Category                            Description      Exam Method       Components in       Examined        Percentage         Scheduled       Examined in     Examined in       Examined in Number Item No.      During Interval     Required          During the      First Period   Second Period      Third Period Interval LRC             License Renewal Commitments (LRC), ASME Section XI, Subsection IWE with Enhancements Enhancement A-E          OWN
                          #1(1) Containment             Visual               318              12                (2) 12                 3             3                  3 Liners A-E          OWN            Enhancement                 Visual                                              100% Each
                       #4(4)Containment Liners                                5                5             Inspection           5                 5             5                  5 under Fuel Transfer Canal                                                                Period(5)
Category Total Note 1: ASME Section XI, Subsection IWE program will be enhanced to include inspection of a sample of the inaccessible liner covered by insulation and lagging every 10 years.
Note 2: One containment liner insulation panel will be selected, at random for removal from each quadrant, during each of the three periods in an inspection interval. Therefore, a total of 12 containment liner insulation panels will be selected, in each unit, during each 10-year inspection interval, to allow for Notes for LRC           examination of the containment liner behind the containment liner insulation Note 3: NA Note 4: ASME Section XI, Subsection IWE program will be enhanced to include inspection of the containment liner under the fuel transfer canal and behind the containment liner insulation, which are subjected to leaks from the reactor cavity.
Note 5: These inspections will continue as long as leakage from the reactor cavity is observed between the containment liner and the containment liner insulation.
73

LR-N23-0005                                                                 LAR S22-04 Enclosure 3.5.4   Supplemental Inspection Requirements The need for Supplemental Inspections has been addressed in Section 3.5.3, Tables 3.5.3-7 and 3.5.3-10, Augmented Inspection Summary Table -Unit 1 and Unit 2 respectively.
3.5.5   Results of Recent Containment Examinations The following tables identify conditions that were not acceptable, required evaluation or comments were noted during recent IWE and IWL inspection activities.
74

LR-N23-0005                                                     LAR S22-04 Enclosure Table 3.5.5-1: SNGS Unit 1 IWE / IWL Examination, Outage S1R26 Report No.
ASME Item No. Method     Accept            Description of Abnormal Conditions                  Comments Component VT-19-302      VT-G        Yes      None                                          Coating and caulk removed to facilitate UT. Evidence of some E-C/E4.12                                                                         pitting and corrosion. UT results do LRN-S1-QUAD-000A 078                                                                     not show any min wall violations.
BELOW LEAK CHASE CHANNEL TO FLOOR VT-19-305      VT-G        Yes      None                                          New caulk and paint applied E-C/E4.12 LRN-S1-QUAD-000B 078 BELOW LEAK CHASE CHANNEL TO FLOOR VT-19-306      VT-G        Yes      None                                          Coating and caulk removed to facilitate UT. Evidence of some E-C/E4.12                                                                         pitting and corrosion. UT results do LRN-S1-QUAD-000B 078                                                                     not show any min wall violations.
BELOW LEAK CHASE CHANNEL TO FLOOR 75

LR-N23-0005                                                     LAR S22-04 Enclosure Table 3.5.5-1: SNGS Unit 1 IWE / IWL Examination, Outage S1R26 Report No.
ASME Item No. Method     Accept            Description of Abnormal Conditions                  Comments Component VT-19-308      VT-G        Yes      None                                          Coating and caulk removed to facilitate UT. Evidence of some E-C/E4.12                                                                         pitting and corrosion. UT results do LRN-S1-QUAD-000C 078                                                                     not show any min wall violations.
BELOW LEAK CHASE CHANNEL TO FLOOR VT-19-309      VT-G        Yes      None                                          New caulk and paint applied E-C/E4.12 LRN-S1-QUAD-000C 078 BELOW LEAK CHASE CHANNEL TO FLOOR VT-19-311      VT-G        Yes      None                                          Coating and caulk removal to facilitate UT. Evidence of some E-CI/E4.12                                                                        pitting and corrosion. UT results do LRN-S1-QUAD-000D 078                                                                     not show any min wall violations.
BELOW LEAK CHASE CHANNEL TO FLOOR VT-19-312      VT-G        Yes      None                                          New caulk and paint applied.
E-CI/E4.12 LRN-S1-QUAD-000D 078 BELOW LEAK CHASE CHANNEL TO FLOOR 76

LR-N23-0005                                                       LAR S22-04 Enclosure Table 3.5.5-1: SNGS Unit 1 IWE / IWL Examination, Outage S1R26 Report No.
ASME Item No. Method     Accept              Description of Abnormal Conditions                            Comments Component VT-19-317      VT-G        Yes      None                                                      Coating and caulk removed to facilitate UT. No evidence of water E-A/E1.30                                                                                     intrusion below moisture barrier.
MBR-S1-QUAD-000A-078 VT-19-318      VT-G        Yes      None                                                      New caulk and paint applied.
E-A/E1.30 MBR-S1-QUAD-000A-078 VT-19-328      VT-G        No       Multiple small holes in insulation package, caulk missing Notification 20825114 on patch plates.
E-A/E1.30 QUAD A INSULATION SYSTEM 78 -110 EL.
VT-19-359      VT-G        Yes      None                                                      VT-G Performed on insulation package post repairs.
E-A/E1.30 QUAD A INSULATION SYSTEM 78 -110 EL.
VT-19-319      VT-G        Yes      None                                                      Coating and caulk removed to facilitate UT. No evidence of water E-A/E1.30                                                                                     intrusion below moisture barrier.
MBR-S1-QUAD-000B-078 77

LR-N23-0005                                                       LAR S22-04 Enclosure Table 3.5.5-1: SNGS Unit 1 IWE / IWL Examination, Outage S1R26 Report No.
ASME Item No. Method     Accept              Description of Abnormal Conditions                            Comments Component VT-19-320      VT-G        Yes      None                                                      New caulk and paint applied.
E-A/E1.30 MBR-S1-QUAD-000B-078 VT-19-329      VT-G        No       Multiple small holes in insulation package, caulk missing Notification 20825114 on patch plates.
E-A/E1.30 QUAD B INSULATION SYSTEM 78 -110 EL.
VT-19-358      VT-G        Yes      None                                                      VT-G Performed on insulation package post repairs.
E-A/E1.30 QUAD B INSULATION SYSTEM 78 -110 EL.
VT-19-321      VT-G        Yes      None                                                      Coating and caulk removed to facilitate UT. No evidence of water E-A/E1.30                                                                                     intrusion below moisture barrier.
MBR-S1-QUAD-000C-078 VT-19-322      VT-G        Yes      None                                                      New caulk and paint applied.
E-A/E1.30 MBR-S1-QUAD-000C-078 78

LR-N23-0005                                                       LAR S22-04 Enclosure Table 3.5.5-1: SNGS Unit 1 IWE / IWL Examination, Outage S1R26 Report No.
ASME Item No. Method     Accept              Description of Abnormal Conditions                            Comments Component VT-19-330      VT-G        No       Multiple small holes in insulation package, caulk missing Notification 20825114 on patch plates.
E-A/E1.30 QUAD C INSULATION SYSTEM 78 -110 EL.
VT-19-357      VT-G        Yes      None                                                      VT-G Performed on insulation package post repairs.
E-A/E1.30 QUAD C INSULATION SYSTEM 78 -110 EL.
VT-19-323      VT-G        Yes      None                                                      Coating and caulk removed to facilitate UT. No evidence of water E-A/E1.30                                                                                     intrusion below moisture barrier.
MBR-S1-QUAD-000D-078 VT-19-324      VT-G        Yes      None                                                      New caulk and coating applied.
E-A/E1.30 MBR-S1-QUAD-000D-078 VT-19-331      VT-G        No       Multiple small holes in insulation package, caulk missing Notification 20825114 on patch plates.
E-A/E1.30 QUAD D INSULATION SYSTEM 78 -110 EL.
79

LR-N23-0005                                                     LAR S22-04 Enclosure Table 3.5.5-1: SNGS Unit 1 IWE / IWL Examination, Outage S1R26 Report No.
ASME Item No. Method     Accept            Description of Abnormal Conditions                  Comments Component VT-19-356      VT-G        Yes      None                                          VT-G Performed on insulation package post repairs.
E-A/E1.30 QUAD D INSULATION SYSTEM 78 -110 EL.
VT-19-043      VT-G        Yes      None                                          Examination of both inside and outside (light rust) satisfactory.
E-A/E1.11 PEN-S1-M-12 VT-19-044      VT-G        Yes      None                                          Examination of both inside and outside (light rust) satisfactory.
E-A/E1.11 PEN-S1-M-13 VT-19-045      VT-G        Yes      None                                          Examination of both inside and outside (light rust) satisfactory.
E-A/E1.11 PEN-S1-M-14 VT-19-046      VT-G        Yes      None                                          Examination of both inside and outside (light rust) satisfactory.
E-A/E1.11 PEN-S1-M-15 80

LR-N23-0005                                                  LAR S22-04 Enclosure Table 3.5.5-1: SNGS Unit 1 IWE / IWL Examination, Outage S1R26 Report No.
ASME Item No. Method     Accept            Description of Abnormal Conditions                  Comments Component VT-19-082   VT-G        Yes      None                                          Examination of both inside and outside (light rust) satisfactory.
E-A/E1.11 PEN-S1-M-56 VT-19-083   VT-G        Yes      None                                          Examination of both inside and outside (light rust) satisfactory.
E-A/E1.11 PEN-S1-M-57 VT-19-084   VT-G        Yes      None                                          Examination of both inside and outside (light rust) satisfactory.
E-A/E1.11 PEN-S1-M-58 VT-19-085   VT-G        Yes      None                                          Examination of both inside and outside (light rust) satisfactory.
E-A/E1.11 PEN-S1-M-59 VT-19-089   VT-G        Yes      None                                          Examination of both inside and outside (light rust) satisfactory.
E-A/E1.11 PEN-S1-M-63 81

LR-N23-0005                                                            LAR S22-04 Enclosure Table 3.5.5-1: SNGS Unit 1 IWE / IWL Examination, Outage S1R26 Report No.
ASME Item No.       Method     Accept               Description of Abnormal Conditions                         Comments Component VT-19-130         VT-G        Yes      None                                                   Outside (light rust) and inside satisfactory.
E-A/E1.11 PEN-S1-E-39 VT-19-159         VT-G        Yes      None                                                   Outside and inside satisfactory (light rust).
E-A/E1.11 PEN-S1-E-58 VT-19-325         VT-1        No       After aggressive cleaning holes were found in channels Notification 20824284 7, 9, and 14. Holes were fiber scope, no evidence of A-E/Own                               further corrosion noted.
Vert Leak Channels 1-14 VT-19-332         VT-1        Yes      Coating was removed to facilitate UT. Channel steel integrity was intact.
A-E/Own Vert Leak Channels 15-28 VT-19-326         VT-1        Yes      Coating was removed to facilitate UT. Channel steel integrity was intact.
A-E/Own Vert Leak Channels 29-41 82

LR-N23-0005                                                           LAR S22-04 Enclosure Table 3.5.5-1: SNGS Unit 1 IWE / IWL Examination, Outage S1R26 Report No.
ASME Item No.       Method     Accept             Description of Abnormal Conditions                         Comments Component VT-19-327          VT-1        No       After aggressive cleaning a hole was found in channel Notification 20824284
: 48. Hole was fiber scoped; no evidence of further A-E/Own                                corrosion noted.
Vert Leak Channels 42-54 VT-19-269          VT-G        No       Coating evaluated at grade-2G.                        Notification 20824284 A-E/Own Liner Panel 78-034 VT-19-353          VT-1        Yes      VT-1 Performed on post weld build up area A-E/Own Liner Panel 78-034 VT-19-262          VT-G        No       Coating evaluated at grade-2G.                        Notification 20824284 A-E/Own Liner Panel 78-035 VT-19-354          VT-1        Yes      VT-1 Performed on post weld build up area A-E/Own Liner Panel 78-084 83

LR-N23-0005                                                       LAR S22-04 Enclosure Table 3.5.5-1: SNGS Unit 1 IWE / IWL Examination, Outage S1R26 Report No.
ASME Item No. Method     Accept             Description of Abnormal Conditions                 Comments Component VT-19-255       VT-G        No       Coating evaluated at grade-5G.                Notification 20824284 A-E/Own Liner Panel 88-033 VT-19-256       VT-G        No       Coating evaluated at grade-5G.                Notification 20824284 A-E/Own Liner Panel 88-034 VT-19-257       VT-G        No       Coating evaluated at grade-5G.                Notification 20824284 A-E/Own Liner Panel 88-035 VT-19-270       VT-G        No       Coating evaluated at grade-5G.                Notification 20824284 A-E/Own Liner Panel 98-020 VT-19-271       VT-G        No       Coating evaluated at grade-5G.                Notification 20824284 A-E/Own Liner Panel 98-021 84

LR-N23-0005                                                       LAR S22-04 Enclosure Table 3.5.5-1: SNGS Unit 1 IWE / IWL Examination, Outage S1R26 Report No.
ASME Item No. Method     Accept             Description of Abnormal Conditions                 Comments Component VT-19-272       VT-G        No       Coating evaluated at grade-5G.                Notification 20824284 A-E/Own Liner Panel 98-022 VT-19-274       VT-G        No       Coating evaluated at grade-2G.                Notification 20824284 A-E/Own Liner Panel 98-033 VT-19-276       VT-G        No       Coating evaluated at grade-2G.                Notification 20824284 A-E/Own Liner Panel 98-034 VT-19-278       VT-G        No       Coating evaluated at grade-6G.                Notification 20824284 A-E/Own Liner Panel 98-044 VT-19-279       VT-G        No       Coating evaluated at grade-5G.                Notification 20824284 A-E/Own Liner Panel 98-045 85

LR-N23-0005                                                       LAR S22-04 Enclosure Table 3.5.5-1: SNGS Unit 1 IWE / IWL Examination, Outage S1R26 Report No.
ASME Item No. Method     Accept             Description of Abnormal Conditions                  Comments Component VT-19-280       VT-G        No       Coating evaluated at grade-5G.                 Notification 20824284 A-E/Own Liner Panel 98-046 VT-19-283       VT-G        No       Coating evaluated at grade-6G.                 Notification 20824284 A-E/Own Liner Panel 98-074 VT-19-288       VT-G        No       Coating evaluated at grade-6G.                 Notification 20824284 A-E/Own Liner Panel 98-079 VT-19-289       VT-G        No       Coating evaluated at grade-2G.                 Notification 20824284 A-E/Own                             Grinding gauge noted in panel approx. 4" long. Notification 20823999 Liner Panel 98-080 VT-19-355       VT-1        Yes      VT-1 Performed on post weld build up areas A-E/Own Liner Panel 98-080 86

LR-N23-0005                                                        LAR S22-04 Enclosure Table 3.5.5-1: SNGS Unit 1 IWE / IWL Examination, Outage S1R26 Report No.
ASME Item No. Method     Accept             Description of Abnormal Conditions                              Comments Component VT-19-299       VT-G        No       Coating evaluated at grade-5G.                             Notification 20824284 A-E/Own Liner Panel 98-111 VT-19-300       VT-G        No       Coating evaluated at grade-5G.                             Notification 20824284 A-E/Own Liner Panel 98-116 VT-19-340       VT-G        Yes      General pattern cracking, cold join lines, mortar patching degradations and small passive inactive cracks have L-A/L1.11                           remained the same size and shape.
CON-S1-QUAD-D ROWS 26-46 VT-19-339       VT-G        Yes      General pattern cracking, cold join lines, mortar patching degradations and small passive inactive cracks have L-A/L1.11                           remained the same size and shape.
CON-S1-QUAD-C ROWS 26-46 VT-19-336       VT-G        Yes      General pattern cracking, cold join lines, mortar patching degradations and small passive inactive cracks have L-A/L1.11                           remained the same size and shape.
CON-S1-QUAD-D ROWS 01-25 87

LR-N23-0005                                                        LAR S22-04 Enclosure Table 3.5.5-1: SNGS Unit 1 IWE / IWL Examination, Outage S1R26 Report No.
ASME Item No. Method     Accept            Description of Abnormal Conditions                  Comments Component VT-19-338       VT-G        Yes      General pattern cracking, cold join lines, mortar patching degradations and small passive inactive cracks have L-A/L1.11                            remained the same size and shape.
CON-S1-QUAD-B ROWS 26-46 VT-19-335       VT-G        Yes      General pattern cracking, cold join lines, mortar patching degradations and small passive inactive cracks have L-A/L1.11                            remained the same size and shape.
CON-S1-QUAD-C ROWS 01-25 VT-19-333       VT-G        Yes      General pattern cracking, cold join lines, mortar patching degradations and small passive inactive cracks have L-A/L1.11                            remained the same size and shape.
CON-S1-QUAD-A ROWS 01-25 VT-19-337       VT-G        Yes      General pattern cracking, cold join lines, mortar patching degradations and small passive inactive cracks have L-A/L1.11                            remained the same size and shape.
CON-S1-QUAD-A ROWS 26-46 VT-19-334       VT-G        Yes      General pattern cracking, cold join lines, mortar patching degradations and small passive inactive cracks have L-A/L1.11                            remained the same size and shape.
CON-S1-QUAD-B ROWS 01-25 88

LR-N23-0005                                                  LAR S22-04 Enclosure Table 3.5.5-2: SNGS Unit 1 IWE Examination, Outage S1R28 Report No.
ASME Item No. Method   Accept      Description of Abnormal Conditions                  Comments Component S1-VT-22-001    VT-G     Yes        None                                130 AIRLOCK TEST TUBING A-E/Own ALK-S1-130-TUBING S1-VT-22-002    VT-G     Yes        None                                100 AIRLOCK TEST TUBING A-E/Own ALK-S1-100-TUBING S1-VT-22-003    VT-G     Yes        None                                TUBING FROM FUEL XFER TUBE TO PNL 343-1 A-E/Own PNL-S1-343-1 S1 -VT-22-004   VT-G     Yes        None                                ACCESSIBLE SURFACE AREAS - GENERAL VT A-E/Own CVI-0500 89

LR-N23-0005                                                       LAR S22-04 Enclosure Table 3.5.5-3: SNGS Unit 2 IWE/IWL Examination, Outage S2R23 Report No.
ASME Item No. Method     Accept      Description of Abnormal Conditions                             Comments Component VEN-18-004                          Cracks, degraded patches or repairs and The VT-G pattern cracking noted as 0.020" and cold joint lines were identified.       Typical Pattern Cracking noted as-0.050" was L-A/L1.11                                                                 performed using a Visual Comparator Card and did CON-S2-QUAD-A ROWS                                                                not take into account crack edge spalling or 01-25                                                                   shadows. These cracks should be better represented as 0.015" and 0.040" which would be in line with the evaluation criteria in ACI 349.3R002s.
A review of photos and the-Visual Examination VT-G        Yes Records was made. It appears that the recorded indications are cold joint line, minor mortar patching degradations, or small passive and inactive cracks.
SNGS Containment has exterior concrete cover of 3-3/8" nominal thickness. There is no evidence of rebar corrosion.
No changes from previous inspection, during SNGS 2R22 Outage, noted.
90

LR-N23-0005                                                       LAR S22-04 Enclosure Table 3.5.5-3: SNGS Unit 2 IWE/IWL Examination, Outage S2R23 Report No.
ASME Item No. Method     Accept      Description of Abnormal Conditions                            Comments Component VEN-18-008    VT-G        Yes       General pattern cracking and Typical    The General pattern cracking noted as 0.020" and pattern cracking                        Typical Pattern Cracking as 0.050" was performed L-A/L1.11                                                                 using Visual Comparator Card and did not take into CON-S2-QUAD-A ROWS                                                                account crack edge spalling or shadows. These 26-46                                                                   cracks should be better represented as 0.015" and 0.040" which would be in line with the evaluation criteria in ACI 349.3R002s.
A review of photos and the Visual Examination records was made. It appears that the recorded indications are cold joint line, minor mortar patching degradations or small passive and inactive cracks.
SNGS Containment has exterior concrete cover of 3-3/8" nominal thickness (Drawings 201109 & 201125).
There is no evidence of rebar corrosion.
No changes from previous inspection, during SNGS 2R22 Outage, noted.
VEN-18-005                          Cracks, degraded patches or repairs and The General pattern cracking noted as 0.020" and cold joint lines were identified.       Typical Pattern Cracking as 0.050" was performed L-A/L1.11                                                                 using Visual Comparator Card and did not take into CON-S2-QUAD-B ROWS                                                                account crack edge spalling or shadows. These 1-25                                                                   cracks should be better represented as 0.015" and 0.040" which would be in line with the evaluation VT-G        Yes criteria in ACI 349.3R002s.
A review of photos and the Visual Examination records was made. It appears that the recorded indications are cold joint line, minor mortar patching degradations or small passive and inactive cracks.
SNGS Containment has exterior concrete cover of 3-91

LR-N23-0005                                                    LAR S22-04 Enclosure Table 3.5.5-3: SNGS Unit 2 IWE/IWL Examination, Outage S2R23 Report No.
ASME Item No. Method     Accept       Description of Abnormal Conditions                          Comments Component 3/8" nominal thickness (Drawings 201109 & 201125).
There is no evidence of rebar corrosion.
No changes from previous inspection, during SNGS 2R22 Outage, noted.
VEN-18-009    VT-G        Yes       Spalling.                              Coating shows-minor cracking, there were no significant cracks greater than hairline in concrete L-A/L1.11                                                                surface.
CON-S2-QUAD-B ROWS                                                               Spalling located in interface of rows 45 and 46.
26-46                                                                  Spalling is 6" X 3" in size. There is no evidence of exposed rebar.
VEN-18-006                          Cracks, settlements or deflections and The General pattern cracking noted as 0.020" and degraded patches or repairs were       Typical Pattern Cracking as 0.050" was performed L-A/L1.11                         identified.                            using Visual Comparator Card and did not take into CON-S2-QUAD-C ROWS                                                               account crack edge spalling or shadows. These 1-25                                                                  cracks should be better represented as 0.015" and 0.040" which would be in line with the evaluation criteria in ACI 349.3R002s.
A review of photos and the Visual Examination VT-G        Yes records was made. It appears that the recorded indications are cold joint line, minor mortar patching degradations or small passive and inactive cracks.
SNGS Containment has exterior concrete cover of 3-3/8" nominal thickness (Drawings 201109 & 201125).
There is no evidence of rebar corrosion.
No changes from previous inspection, during SNGS 2R22 Outage, noted.
92

LR-N23-0005                                                    LAR S22-04 Enclosure Table 3.5.5-3: SNGS Unit 2 IWE/IWL Examination, Outage S2R23 Report No.
ASME Item No. Method     Accept       Description of Abnormal Conditions                          Comments Component VEN-18-010                          None                                   Coating shows minor cracking; there were no significant cracks greater than hairline in concrete L-A/L1.11                                                                surface.
VT-G        Yes CON-S2-QUAD-C ROWS 26-46 VEN-18-007    VT-G        Yes       Cracks, settlements or deflections and The General pattern cracking noted as 0.020" and degraded patches or repairs were       Typical Pattern Cracking as 0.050" was performed L-A/L1.11                         identified.                            using Visual Comparator Card and did not take into CON-S2-QUAD-D ROWS                                                               account crack edge spalling or shadows. These 1-25                                                                  cracks should be better represented as 0.015" and 0.040" which would be in line with the evaluation criteria in ACI 349.3R002s.
A review of photos and the Visual Examination records was made. It appears that the recorded indications are cold joint line, minor mortar patching degradations or small passive and inactive cracks.
SNGS Containment has exterior concrete cover of 3-3/8" nominal thickness (Drawings 201109 & 201125).
There is no evidence of rebar corrosion.
No changes from previous inspection, during SNGS 2R22 Outage, noted.
VEN-18-011                          None                                   Coating shows minor cracking; there were no significant cracks greater than hairline in concrete L-A/L1.11                                                                surface.
VT-G        Yes CON-S2-QUAD-D ROWS 26-46 93

LR-N23-0005                                                                 LAR S22-04 Enclosure Table 3.5.5-3: SNGS Unit 2 IWE/IWL Examination, Outage S2R23 Report No.
ASME Item No.          Method     Accept      Description of Abnormal Conditions                          Comments Component VEN-18-227 E-C/E4.12 QUADRANT B 78 below Leak Chase Channel to Floor LNR-S2-QUAD-000A-078        VT-G        Yes       General visual examinations revealed    Notifications 20807503.
recordable indications on the area LNR-S2-QUAD-000B-078        VT-G        Yes       between the bottom horizontal test LNR-S2-QUAD-000C-078        VT-G        Yes       channel and moisture barrier. A VT-1 was performed on this area which resulted in notifications 20807503.
VT-G        Yes LNR-S2-QUAD-000D-078 LNR-S2-QUAD-000D-078        VT-1        Yes       VT-1 shows no relevant indications. None VEN-18-052 E-C/E4.12 QUADRANT B 78 below Leak Chase Chan 820001 Quad A 78 below-                           Examinations conducted due to IWE       Notification 20807503 leak chase channel to floor                        General visual noted damaging coating, corrosion and bulging caulk.
820101 Quad B 78 below-leak chase channel to floor   UT         No 820201 Quad C 78 below-                            Significant corrosion and wall loss at-leak chase channel to floor                        panels 90, 91, and 92.                  Notification 20808656 94

LR-N23-0005                                                              LAR S22-04 Enclosure Table 3.5.5-3: SNGS Unit 2 IWE/IWL Examination, Outage S2R23 Report No.
ASME Item No.         Method      Accept      Description of Abnormal Conditions                        Comments Component Corrosion at panel 82.
Notification 20808931 VEN-18-231 A-E/OWN QUADRANT-000A Vertical Leak Test Channels 840000 QUADRANT-000A                              Corrosion / Pitting                 Through wall hole discovered, no noticeable Vertical Leak Test Channel  Direct       No                                            corrosion noted on containment liner; Channel was 3                                                                         cut and capped per DCP: 80123367 840000 QUADRANT-000A                    No        Coating Damaged                     Coating failure. Notification 20807503 Vertical Leak Test Channel  Direct 8
840100 QUADRANT-000A                    No        Coating Damaged                     Coating failure. Notification 20807503 Vertical Leak Test Channel  Direct 44 840100 QUADRANT-000A                    No        Coating Damaged                     Coating failure. Notification 20807503 Vertical Leak Test Channel  Direct 45 840100 QUADRANT-000A                    No        Corrosion / Pitting                 Through wall hole discovered, no noticeable Vertical Leak Test Channel  Direct                                                     corrosion noted on containment liner; Channel was 50                                                                         cut and capped per DCP: 80123367 VEN-18-069                                 None                                Notification 20807783 was generated to clean and VT-G         Yes                                           coat Mechanical Pen #2 and #4 on 100' elevation E-A/E1.11 95

LR-N23-0005                                                                     LAR S22-04 Enclosure Table 3.5.5-3: SNGS Unit 2 IWE/IWL Examination, Outage S2R23 Report No.
ASME Item No.           Method          Accept      Description of Abnormal Conditions                          Comments Component PEN-S2-M-01                                                                               and Mechanical Pen #12, 13, 14 and 15 on 78' elevation.
VEN-18-051         Examination performed for IWE License Renewal Commitment, UT thickness of containment liner beneath Insulation system at selected locations noted below. Scope added 870000 liner panel 98-001, 870360 liner panel 98-037, 870810 liner panel A-E/OWN           98-082, and 871050 liner panel 98-106. Notification 20804760.
Liner Panel 98-005 Additional readings taken. in bracket   Notification 20808113 was generated for panel 98-removal area of liner panel 98-001 due  001.
870000 Liner panel 98-001       UT             No to corrosion noted by IWE General Visual.
VEN-18-033         Examination performed for IWE License Renewal Commitment, General Visual of containment liner beneath Insulation system at selected locations noted below. Scope added 870000 liner panel 98-001, 870360 liner panel 98-037, 870810 liner panel A-E/OWN           98-082, and 871050 liner panel 98-106. Notification 20804760.
Liner Panel 98-005 Corrosion / Pitting, Coating Damaged    General Rusting Grade 1-G ASTM D610 and OU-870000/ Liner Panel 98-001                                                                       AA-335 018 Attachment 1 VT-G            No QUAD A98'-110'                                                                              Under Construction Bracket, Approx. 8"X8" area.
Notification: 20808113 96

LR-N23-0005                                                       LAR S22-04 Enclosure Table 3.5.5-4: SNGS Unit 2 IWE Examination, Outage S2R25 Report No.
ASME Item No.      Method   Accept       Description of Abnormal Conditions                     Comments Component S2-VT-21-850       VT-G      No        Rust grade 1-G in various areas     Notification 20886028 E-C/E4.12 QUADRANT A 78 below Leak Chase Channel to Floor S2-VT-21-853       VT-G      No        Rust grade 2-P in various areas     Notification 20886028 E-C/E4.12 QUADRANT B 78 below Leak Chase Channel to Floor S2-VT-21-854       VT-G      No        Missing insulation metal at various Notification: 20885077 locations.
E-A/E1.30 QUAD A INSULATION SYSTEM 78 -110 EL.
S2-VT-21-855       VT-G      No        Missing insulation metal at various Notification: 20885077 locations.
E-A/E1.30 QUAD B INSULATION SYSTEM 78 -110 EL.
97

LR-N23-0005                                                      LAR S22-04 Enclosure Table 3.5.5-4: SNGS Unit 2 IWE Examination, Outage S2R25 Report No.
ASME Item No. Method   Accept       Description of Abnormal Conditions                              Comments Component S2-VT-21-869     VT-G      No        Missing insulation metal at various          Notification: 20885077 locations.
E-A/E1.30 QUAD B INSULATION SYSTEM 78 -110 EL.
S2-VT-21-856     VT-G      No        Missing insulation metal at various          Notification: 20885077 locations.
E-A/E1.30 QUAD C INSULATION SYSTEM 78 -110 EL.
S2-VT-21-857     VT-G      No        Missing insulation metal at various          Notification: 20885077 locations.
E-A/E1.30 QUAD D INSULATION SYSTEM 78 -110 EL.
S2-VT-21-858     VT-G      No        2 through wall holes on channels 4 and       Notification 20886113
: 10. Boroscoping showed no signs of A-E/OWN                           corrosion, or water intrusion to interior of QUADRANT-000A                          channel.
VERTICAL LEAK TEST CHANNELS 98

LR-N23-0005                                                    LAR S22-04 Enclosure Table 3.5.5-4: SNGS Unit 2 IWE Examination, Outage S2R25 Report No.
ASME Item No. Method   Accept      Description of Abnormal Conditions                      Comments Component S2-VT-21-862     VT-G      No        Rust Grade 1-G                      Notification 20886028 A-E/OWN Liner Panel 78-018 S2-VT-21-827     VT-G      No        Rust Grade 1-G                      Notification 20886028 A-E/OWN Liner Panel 78-004 S2-VT-21-826     VT-G      No        Rust Grade 1-G                      Notification 20886028 A-E/OWN Liner Panel 78-005 S2-VT-21-818     VT-G      No        Rust Grade 1-G                      Notification 20886028 A-E/OWN Liner Panel 78-006 S2-VT-21-817     VT-G      No        Rust Grade 1-G                      Notification 20886028 A-E/OWN Liner Panel 78-007 99

LR-N23-0005                                                       LAR S22-04 Enclosure Table 3.5.5-4: SNGS Unit 2 IWE Examination, Outage S2R25 Report No.
ASME Item No. Method   Accept      Description of Abnormal Conditions                            Comments Component S2-VT-21-863     VT-G      No        Rust Grade 1-G                            Notification 20886028 A-E/OWN Liner Panel 78-019 S2-VT-21-838     VT-G      No        2 areas identified with rust greater than Notification 20886028 1-G. Each area approx. 4"x4".
A-E/OWN Liner Panel 78-082 S2-VT-21-842     VT-G      No        panel rusted approx. grade 2-G.           Notification 20886028 A-E/OWN Liner Panel 78-093 S2-VT-21-816     VT-G      No        Rusted grade 6-S                          Notification 20886307 A-E/OWN Liner Panel 88-085 S2-VT-21-806     VT-G      No        Rusted grade 6-P                          Notification 20886307 A-E/OWN Liner Panel 88-102 100

LR-N23-0005                                                          LAR S22-04 Enclosure Table 3.5.5-4: SNGS Unit 2 IWE Examination, Outage S2R25 Report No.
ASME Item No.         Method   Accept      Description of Abnormal Conditions                          Comments Component S2-VT-21-807         VT-G      No        Rusted grade 6-P                     Notification 20886307 A-E/OWN Liner Panel 88-103 S2-VT-21-821         VT-G      No        Rusted grade 3-G                     Notification 20886307 A-E/OWN Liner Panel 98-093 Panel 78' #5 1" grid at   UT       No        License Renewal inspection of        S2-850040 expanded 1" grid bottom B & C                             containment liner beneath insulation system was found corroded just below Notification 20886113 Orders #60142730 &                           design minimum wall thickness, not 60146726                                                                    Performed weld overlay of 6 inch by 6 inch area to through wall. ASME Failure.          restore liner plate to nominal thickness.
Repair/Replacement Plan Number 60142730.
101

3.5.6    Containment Leakage Rate Testing Program - Type B and Type C Testing Program SNGS Types B and C testing program requires testing of electrical penetrations, airlocks, hatches, flanges and CIVs in accordance with 10 CFR 50, Appendix J, Option B and RG 1.163 (Reference 1). The results of the test program are used to demonstrate that proper maintenance and repairs are made on these components throughout their service life. The Types B and C testing program provides a means to protect the health and safety of plant personnel and the public by maintaining leakage from these components below appropriate limits. In accordance with TS 6.8.4.f, the allowable maximum pathway total Types B and C leakage is 0.6 La (129,770 standard cubic centimeters per minute (sccm)) where La equals 216,284 sccm.
As discussed in NUREG-1493 (Reference 6), Type B and Type C tests can identify the vast majority of all potential containment leakage paths. Type B and Type C testing will continue to provide a high degree of assurance that containment integrity is maintained.
A review of the As-Found (AF) / As-Left (AL) test values for SNGS Units 1 and 2 can be summarized as follows:
* SNGS Unit 1 As-Found minimum pathway leak rate shows an average of 0.04 La with a high of 0.07 La.
* SNGS Unit 1 As-Left maximum pathway leak rate shows an average of 0.13 La with a high of 0.17 La.
* SNGS Unit 2 As-Found minimum pathway leak rate shows an average of 0.05 La with a high of 0.09 La.
* SNGS Unit 2 As-Left maximum pathway leak rate shows an average of 0.14 La with a high of 0.24 La.
102

Table 3.5.6-1 SNGS Unit 1 Type B and C LLRT Combined As-Found/As-Left Trend Summary Outage &        1R21     1R22      1R23      1R24        1R25    1R26     1R27       1R28 Year         2011     2013      2014      2016        2017    2019     2020       2022 AF Min Path        4930.1   4450.5    4538.6    11314.2     8958.2  6188.0  15071.7    13361.5 (sccm) 1.0La        0.02     0.02      0.02       0.05        0.04    0.03     0.07      0.06 AL Max Path       16271.0  15318.7   27033.3    35385.7     33793.7 36318.1 28598.2    32258.5 (sccm) 1.0 La       0.08     0.07      0.13       0.16        0.16    0.17     0.13      0.15 Table 3.5.6-2 SNGS Unit 2 Type B and C LLRT Combined As-Found/As-Left Trend Summary Outage &        2R18      2R19      2R20       2R21       2R22   2R23     2R24       2R25   2R26 Year          2011     2012      2014       2015       2017   2018      2020      2021   2023 AF Min Path       4887.4   14864.9   13313.0     6662.3    19130.0 17855.5  5988.3     6625.1 12628.4 (sccm) 1.0La         0.02     0.07      0.06       0.03       0.09    0.08     0.03      0.03    0.06 AL Max Path      51128.7   27207.7   27280.6    20373.1    39762.3 36836.8 20626.3    16305.6 26290.4 (sccm) 1.0 La        0.24     0.13      0.13       0.09       0.18    0.17     0.10      0.08    0.12 The As-Found minimum pathway summations represent the high quality of maintenance of Type B and Type C tested components while the As-Left maximum pathway summations represent the effective management of the Containment Leakage Rate Testing Program by the program owner.
3.5.7    Type B and Type C Local Leak Rate Testing Program Implementation Review Tables 3.5.7-1 and 3.5.7-2 (below) identify SNGS, Units 1 and 2 components, respectively, which were on Appendix J, Option B performance-based extended test intervals, but have not demonstrated acceptable performance during the previous two outages. The component test intervals for the components shown have been reduced to 18 months.
103

Table 3.5.7-1 SNGS Unit 1 Types B and C LLRT Program Implementation Review 1R27 - 2020 Admin As-        Limit As-left      Cause of     Corrective    Scheduled Component         found        Alert sccm          Failure       Action         Interval sccm       /Action sccm Extended frequency1, a
frequency Leakage was Scoped        change is 11SJ44 hatch                                         evaluated and 17           16         17                     60150644 in         in the (Type B)                                           accepted for 1R28           review the cycle.
process under 70215558-0020.
: 1. Extended frequency for 11SJ44 hatch (S1AUX-1DOOR-AUXAH10-1) is 2R to align with other work that requires the valve room cover to be removed, The as-found LLRT in 1R28 was satisfactory at 0 sccm leakage, below the action limit.
1R28 - 2022 Admin As-      Limit Alert   As-left      Cause of     Corrective    Scheduled Component         found       /Action     sccm          Failure       Action         Interval sccm sccm None1
: 1. There were no Type B or Type C LLRT failures in 1R28 of components on Extended frequency.
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Table 3.5.7-2 SNGS Unit 2 Types B and C LLRT Program Implementation Review 2R25 - 2021 Admin Limit As-Alert          As-left      Cause of       Corrective       Scheduled Component         found
                                 /Action          sccm          Failure           Action          Interval sccm sccm Extended frequency2, a frequency Leakage was       Scope CM change is in evaluated and          order S2CAN-2-25          216             5.0            411                                         the review accepted for       60157233 process the cycle            in 2R26 under 70219473-0110.
: 1. Work was performed on Electrical penetration S2CAN-2-25 under CM 60149188, which included replacing the N2 fill/test valve; and the as-left LLRT was still unsatisfactory.
: 2. The as-found LLRT in 1R28 was satisfactory at 0 sccm leakage, below the administrative limit.
2R26 - 2023 Extended Frequency, a Leakage was frequency evaluated and     Reset S2CAN-2-10        12            5.0               12                                         change accepted for      Interval required per the cycle 70228794-0120.
Extended Replaced        Frequency, a containmen      frequency Containment t side          return to 18-S2CAN-2-31        13            5.0               0        side bushing bushings. /     months leakage Reset           required per Interval        70228794-0210.
Frequency Tubing leak                       return to 18-Accepted upstream of                       months S2RC -2PR17       2,094         340               2,031                      leakage for 2PR17 inside                      required per cycle1 containment                       70228794-0410.
: 1. 70228794-0420 has been created and assigned to scope an order to perform troubleshooting on the upstream tubing from 2PR17 and boundary valve 2PR29 in 2R27.
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Performance Summary
* For Unit 1, 80.7% of all penetrations eligible for extended intervals are on extended intervals.
* For Unit 2, 77.3% of all penetrations eligible for extended intervals are on extended intervals.
3.6    Operating Experience (OE)
During the conduct of the various examinations and tests conducted in support of the containment related programs previously mentioned, issues that do not meet established criteria or that provide indication of degradation, are identified, placed into the site's corrective action program, and corrective actions are planned and performed.
For the SNGS Primary Containment, the following site specific and industry events have been evaluated for impact:
* Information Notice (IN) 1992-20, Inadequate Local Leak Rate Testing
* IN 2004-09, Corrosion of Steel Containment and Containment Liner
* IN 2010-12, Containment Liner Corrosion
* IN 2011-15, Steel Containment Degradation and Associated License Renewal Aging Management Issues
* IN 2014-07, Degradation of Leak-Chase Channel Systems for Floor Welds of Metal Containment Shell and Concrete Containment Metallic Liner
* RIS 2016-07, Containment Shell or Liner Moisture Barrier Inspection Each of these areas is discussed in detail in Sections 3.6.1 through 3.6.3, respectively.
3.6.1    IN 1992-20, Inadequate Local Leak Rate Testing The NRC issued IN 92-20 to alert licensees of problems with local leak rate testing of two-ply stainless steel bellows used on piping penetrations at four different plants: Quad Cities, Dresden Nuclear Station, Perry Nuclear Plant, and the Clinton Station. Specifically, LLRTs could not be relied upon to accurately measure the leakage rate that would occur under accident conditions, because, during testing, the two plies in the bellows were in contact with each other, restricting the flow of the test medium to the crack locations. Any two-ply bellows of similar construction may be susceptible to the problem. The common issue in the four events was the failure to adequately perform local leak rate testing on different penetration configurations leading to problems that were discovered during ILRT tests in the first three cases.
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In the event at Quad Cities, the two-ply bellows design was not properly subjected to LLRT pressure and the conclusion of the utility was that the two-ply bellows design could not be Type B LLRT tested as configured.
In the events at both Dresden and Perry, flanges were not considered a leakage path when the Type C LLRT test was designed. This omission led to a leakage path that was not discovered until the plant performed an ILRT test.
In the event at Clinton, relief valve discharge lines that were assumed to terminate below the suppression pool minimum drawdown level were discovered to terminate at a level above that datum. These lines needed to be reconfigured and the valves should have been Type C LLRT tested.
Discussion:
Containment piping penetrations designed for SNGS are not required to be type "B" tested for 10CFR50 Appendix J. The type "B" test is applicable to piping penetrations that utilize expansion bellows as the leakage limiting boundary. The piping penetrations at SNGS rely on partial/full penetration seal welds inside containment as the leakage limiting boundary, which are leak rate tested as part of the Appendix J type "A" containment Integrated Leak Rate Test (ILRT).
3.6.2    IN 2004-09, Corrosion of Steel Containment and Containment Liner As discussed in Information Notice 97-10, Liner Plate Corrosion in Concrete Containments, the containment liners have safety factors well above the theoretically calculated strains. Any corrosion (metal thinning) of the liner plate or freestanding metallic containment could change the failure threshold of the containment under a challenging environmental or accident condition. Thinning changes the geometry of the containment shell or liner plate, which may reduce the design margin of safety against postulated accident and environmental loads.
Recent experience has shown that the integrity of the moisture barrier seal at the floor-to-liner or floor-to-containment junction is important in avoiding conditions favorable to corrosion and thinning of the containment liner plate material.
Inspections of containment at the floor level, as well as at higher elevations, have identified various degrees of corrosion and containment plate thinning.
An amendment to Section 50.55a of Title 10 of the Code of Federal Regulations (10 CFR 50.55a) (61 FR 41303) became effective September 9, 1996. This amendment requires the use of Subsections IWE and IWL of Section XI of the ASME Boiler and Pressure Vessel Code to perform inservice inspections of containment components. These subsections provide detailed requirements for inservice inspection of Class MC pressure-retaining components and their integral attachments and of metallic shells and penetration liners of Class CC pressure retaining components and their integral attachments. Inspection of concrete containment shell and steel liner plate in accordance with 10 CFR 50.55a involves consideration of potential corrosion areas. Such inspection includes examination, evaluation, repair, and replacement of corroded areas of the liner plate.
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As a result of these required containment inservice inspections, licensees have found that over time, the existing floor-to-containment seal can degrade, allowing moisture into the crevice between the containment liner plate and floor. Small amounts of stagnant water behind the floor seal area promote pitting corrosion. To identify corrosion in this area, licensees have had to remove the original floor seal and either excavate the concrete or do a visual inspection aided by fiber optics. Licensee corrective actions for this condition have typically included inspections to determine the extent of corrosion, evaluations of containment integrity, and installation of new floor-to-containment moisture seal barriers.
In some instances, corrosion has been found at higher elevations of the liner plates. Generally, the instances of such corrosion have been associated with foreign objects (wooden pieces, workers gloves, wire brush handles, etc.) lodged between the liner plate and the concrete. As the corrosion is initiated in the areas not visible during visual examinations, such instances of corrosion were found when corrosion had penetrated through the liner thickness. Some licensees have performed ultrasonic examination of the suspect areas (areas of obvious bulging, hollow sound, etc.) to detect such corroded areas.
Discussion:
PSEG original design/licensing basis did not take credit for the liner plate monitor channels and assumed the liner welds as the boundary. When the May 23, 1983 (Unit 2) and November 8, 1984 (Unit 1) PSEG performed the ILRTs without venting the plugged liner plate monitor channels. PSEG submitted the justification for testing with the liner plate monitor channels plugged in the letter dated 1/26/1990. In the NRC SER dated 12/17/1990 the NRC specifically stated: It is the staffs position that the channels need not be vented and may remain plugged if the licensee can demonstrate that:
(a)      the channel welds are qualitatively equivalent to or better than those for primary containment liner welds (b)      the channel would maintain their integrity when subjected to the loading conditions of a postulated design basis accident as well as during normal operation, and (c)      the inspection and reporting of tests are in accordance with the requirements of a visual inspection of the accessible interior and exterior surfaces of the containment structures and components performed prior to any Type A test.
PSEG committed to perform a visual inspection of the accessible interior and exterior surfaces of the containment structure and components prior to a Type A test as required by 10 CFR Part 50, Appendix J; and to emphasize that since the plugged liner plate monitor channels serve as a pressure retaining boundary, they should be considered as part of the interior surfaces of containment for the purposes of the pre-test inspection.
In 1990 as part of the resolution of the above Testing issues a walkdown was performed (NCR inspection report 272/311-90-81-Q0057, Reference 34) and prompted an evaluation for liner corrosion identified.
Initial NDE inspections (UT) of the liner at SNGS, in locations where signs of degradation have been observed, have yielded results within the acceptable criteria and did not warrant any 108

engineering evaluations for reduction in thickness. The SNGS liner has insulation and therefore is removed as warranted for inspection purposes.
SNGS Unit 1 & 2 Containment inspections between 2000 and 2017 had identified surface corrosion at several locations due to Service Water entering the liner insulation system through the top of flashing and at 78 floor elevation. Most repairs up to 1R24 and 2R22 were limited to coating, insulation stud replacement and test channel removal.
Under the License Renewal commitment, SNGS Unit 1 committed to inspect 82 random Liner Panel locations during outages 1R22, 1R23 and 1R24. Of the original 82 locations no Liner Weld Repairs were required. There are a total of 348 Liner Panel locations, 116 on 3 elevations
- 78, 88 & 100. Although, during Extent of Condition (EOC) liner panel inspection during 1R24 (S2016) corrosion was noted at bottom corner of Panel #100-2 leading to removing Panel #100-3 where severe corrosion was identified which required Containment Liner weld build-up.
Under the License Renewal commitment, SNGS Unit 2 committed to inspect 72 random Liner Panel locations during outages S2R19, S2R20 and S2R21. Of the initial original 72 locations no Liner Weld Repairs were required with No expanded sample required for Unit 2 at that time.
Please refer to Section 3.1.5, Appendix J Liner Issues, of this license amendment for additional descriptions of SNGS Unit 1 and Unit 2 liner corrosion issues.
3.6.3   IN 2010-12, Containment Liner Corrosion The NRC issued IN 2010-12 to inform addressees of recent issues involving corrosion of the steel reactor containment building liner.
This IN provided three examples of containment liner degradation caused by corrosion of which SNGS was one. Concrete reactor containments are typically lined with a carbon steel liner to ensure a high degree of leak tightness during operating and accident conditions. The reactor containment is required to be operable as specified in plant technical specifications to limit the leakage of fission product radioactivity from the containment to the environment. The regulations at 10 CFR 50.55a, Codes and Standards, require the use of Subsection IWE of ASME Section XI to perform inservice inspections of containment components. The required inservice inspections include periodic visual examinations and limited volumetric examinations using ultrasonic thickness measurements. The containment components include the steel containment liner and integral attachments for the concrete containment, containment personnel airlock and equipment hatch, penetration sleeves, moisture barriers, and pressure-retaining bolting. The NRC also requires licensees to perform leak rate testing of the containment pressure-retaining components and isolation valves according to 10 CFR Part 50, Appendix J, Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors, as specified in plant technical specifications. This operating experience highlights the importance of good quality assurance, housekeeping and high quality construction practices during construction operations in accordance with 10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plants.
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SNGS Nuclear Generating Station In October 2009, at SNGS Nuclear Generating Station Unit 2, the licensee inspected the containment moisture barrier (the silicone RTV [room temperature vulcanizing] seal between the concrete floor and containment liner) and found heavy corrosion on the containment liner within 6 inches of the concrete floor. This area of the containment liner was considered inaccessible because it was normally covered by an insulation package that consisted of a layer of sheet metal, a layer of plastic sheeting, and a layer of insulation. The licensee had not inspected the containment liner areas covered by this insulation because ASME Code Section XI allowed an exemption for inaccessible areas. In response to this discovery, and as a conservative approach to the license renewal process, the licensee decided to enhance inspections of the containment liner above the moisture barrier within about 6 inches of the concrete floor and to randomly inspect several other areas that were covered by the insulation package. To perform the inspections, the licensee removed that portion of the insulation package that extended below the lower leak detection channel for the entire containment liner circumference and cut through and removed the insulation package for four other randomly selected areas. Licensee inspections in these four areas identified some corrosion but subsequent ultrasonic measurements did not indicate significant wall loss.
To evaluate the effect of the identified general corrosion on the safety function of the containment boundary and to meet the expanded inspection requirements of ASME Code Section XI, the licensee performed ultrasonic testing of 440 locations on the bottom 6 inches of the cylindrical portion of the containment liner. Based on the results of the measurements at these locations, the licensee determined that the liner remained operable because the lowest thickness measured was 0.677 inches, which was above the design-required minimum wall thickness of 0.43 inches. The actual safety significance of this general corrosion was minor because there was significant design margin for the liner in this area.
The licensee reviewed the circumstances that led to the identified areas of heavy corrosion on the liner and determined that previous containment liner inspections were not performed adequately. Specifically, examinations should have identified evidence of corrosion (rust on floor) and prompted removal of lagging to determine the source of the corrosion products.
The licensee determined that the source of the moisture that caused the liner corrosion at the joint between the containment liner and concrete floor was service water leakage from the containment fan coil units and associated piping. Licensee corrective actions included conducting frequent containment walk-downs to identify, isolate, and repair any identified service water leaks; verifying that the leakage from existing service water leaks did not reach the containment liner; and, until the base of the containment liner is re-coated during a future refueling outage, revising procedures to ensure liner inspections were performed when containment service water leaks were identified. In addition, the licensee stated in its license renewal submittals that it would perform supplemental and augmented examinations of the liner plates at random and non-random locations.
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3.6.4    IN 2011-15, Steel Containment Degradation and Associated License Renewal Aging Management Issues The U.S. Nuclear Regulatory Commission (NRC) issued this information notice (IN) to inform addressees of recent issues identified by the NRC staff concerning degradation of nuclear power plant steel containments that could impact aging management of the containment structures during the period of extended operation of a renewed license. For the issues described below, specific commitments were made by applicants during license renewal reviews. The NRC expects recipients to review the information for applicability to their facilities and consider actions, as appropriate, to avoid similar problems.
Discussion:
The identified subject in IN 2011-15 has been addressed at SNGS during license renewal process and has committed to enhance the Containment In-Service Inspection (CISI) plan. The enhancements are discussed in Section 3.7, License Renewal Aging Management, of this License Amendment.
Enhancements include;
* Inspections of containment steel liner that is covered by insulation and lagging prior to period of extended operation (PEO) and every ten years thereafter.
* Visual inspections of 100% of moisture barrier in accordance with IWE.
* Examine the accessible liner knuckle plate, if degradation is observed then perform repairs and perform extent of condition examinations on areas that are inaccessible (i.e.
area below concrete).
* Perform inspection of containment steel liner that is covered by insulation underneath fuel transfer canal each period starting with the current IWE period throughout the PEO.
A plant-specific aging management plan of the inaccessible areas of the SNGS Containment liner plates in addition to the visual inspection recommended in NUREG-1801 has been developed in the IWE Augmented Inspection Plan CISI plan. Initial inspections, examinations and required repairs have been completed on both SNGS Unit 1 and 2.
Please refer to Section 3.1.5, Appendix J Liner Issues, of this license amendment for additional descriptions of SNGS Unit 1 and Unit 2 liner corrosion issues 111

3.6.5    IN 2014-07, Degradation of Leak-Chase Channel Systems for Floor Welds of Metal Containment Shell and Concrete Containment Metallic Liner The NRC issued this IN to inform addressees of issues identified by the NRC staff concerning degradation of floor weld leak-chase channel systems of steel containment shell and concrete containment metallic liner that could affect leak-tightness and aging management of containment structures.
The containment floor weld leak-chase channel system forms a metal-to-metal interface with the containment shell or liner, the test connection end of which is at the containment floor level.
Therefore, the leak-chase system provides a pathway for potential intrusion of moisture that could cause corrosion degradation of inaccessible embedded areas of the pressure-retaining boundary of the basemat containment shell or liner within it. In addition to protecting the test connection, the cover plates and plugs and accessible components of the leak-chase system within the access box are also intended to prevent intrusion of moisture into the access box and into the inaccessible areas of the shell/liner within the leak-chase channels, thereby protecting the shell and liner from potential corrosion degradation that could affect leak-tightness.
The containment ISI program required by 10 CFR 50.55a to be implemented in accordance with Subsection IWE, of the ASME Code, Section XI, subject to regulatory conditions, requires special consideration of areas susceptible to accelerated corrosion degradation and aging, and barriers intended to prevent intrusion of moisture and water accumulation against inaccessible areas of the containment pressure-retaining metallic shell or liner. The containment floor weld leak-chase channel system is one such area subject to accelerated degradation and aging if moisture intrusion and water accumulation is allowed on the embedded shell and liner within it.
Therefore, the leak-chase channel system is subject to ISI requirements of 10 CFR 50.55a(g)(4) and aging management requirements of 10 CFR 54.29(a)(1).
This IN provided examples of OE at some plants of water accumulation and corrosion degradation in the leak-chase channel system that has the potential to affect the leak-tight integrity of the containment shell or liner plate. In each of the examples, the licensee had no provisions in its ISI plan to inspect any portion of the leak-chase channel system for evidence of moisture intrusion and degradation of the containment metallic shell or liner within it. Therefore, these cases involved the licensees failure to perform required visual examinations of the containment shell or liner plate leak-chase systems in accordance with the ASME Code Section XI, Subsection IWE, as required by 10 CFR 50.55a(g)(4). The moisture intrusion and associated degradation found within leak-chase channels, if left uncorrected, could have resulted in more significant corrosion degradation of the containment shell or liner and associated seam welds. These examples and other similar previous industry operating experiences highlight the importance of licensees recognizing the existence of leak-chase channel systems in their containment floor. These experiences also highlight the importance of understanding the system configuration and how the leak-chase system components interact with the containment pressure-retaining metallic shell or liner plate within it to ensure that these systems are appropriately included for required examinations in the containment ISI program and the Subsection IWE aging management program.
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For containments in which basemat shell/liner leak-chase channel systems exist with accessible interface at the containment floor level, licensees are required to comply with the containment ISI requirements of 10 CFR 50.55a(g)(4).
Discussion:
SNGS Containment Liner contains originally installed liner plate monitor channels that were installed to test the liner plate butt welds for leak tightness during construction. The liner plate monitor channels for the liner beneath the containment concrete floor contains test piping that runs up through the bio shield wall and connects to 3 separate test headers. This test header piping comes out of the wall approximately 3 feet above the 78' floor and is accessible for visual inspection. There is an additional area of liner plate monitor channels for the liner beneath the containment concrete floor that is at the outer most circumference, this area is connected to the first horizontal liner plate monitor channels just above the concrete floor by vertical liner plate monitor channels on the knuckle liner plates. Some of these knuckle plate monitor channels had been identified during License Renewal inspections to contain through wall holes and upon further inspection it was identified that moisture had in fact entered the liner plate monitor channel sections below the concrete.
The CISI Program was enhanced to include additional inspections of all these areas including areas below the concrete floor exposed by removing concrete and opening the floor liner plate monitor channels. The CISI program has been enhanced to include inspection plans for periodic inspections of all the noted test headers, all vertical liner plate monitor channels at outer most circumference of 78' containment as well as locations beneath the concrete where moisture had been identified.
Degraded areas have been corrected to ensure a moisture seal is maintained to ensure moisture is prevented from entering into areas below the concrete floor. These inspections will be on going for the remaining life of the plant on a periodic basis IAW ASME section XI subsection IWE.
The failure to identify this condition earlier was due to inaccessibility, the containment liner between 78' and 100' elevation has an insulation system installed with the original insulation lagging extending to the floor preventing access to the degraded areas. The lagging at 78' have been trimmed to allow unobstructed access for inspections.
A plant-specific aging management plan of the inaccessible areas of the SNGS liner plates in addition to the visual inspection recommended in NUREG-1801 has been developed in the IWE Augmented Inspection Plan CISI plan. Initial inspections, examinations and required repairs have been completed on both SNGS Unit 1 and 2.
Corrective actions to correct the degraded plant conditions have been complete as well as programmatic changes have been implemented to prevent recurrence at PSEG Nuclear.
Please refer to Section 3.1.5, Appendix J Liner Issues, of this license amendment for additional descriptions of SNGS Unit 1 and Unit 2 liner corrosion issues.
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3.6.6    RIS 2016-07, Containment Shell or Liner Moisture Barrier Inspection The NRC staff identified several instances in which containment shell or liner moisture barrier materials were not properly inspected in accordance with ASME Code Section XI, Table IWE-2500-1, Item E1.30. Note 4 (Note 3 in editions before 2013) for Item E1.30 under the "Parts Examined" column states that "Examination shall include moisture barrier materials intended to prevent intrusion of moisture against inaccessible areas of the pressure retaining metal containment shell or liner at concrete-to-metal interfaces and at metal-to-metal interfaces which are not seal-welded. Containment moisture barrier materials include caulking, flashing, and other sealants used for this application."
The NRC staff expects licensees to inspect 100 percent of accessible moisture barriers during each inspection period, in accordance with Table IWE-2500-1, Item E1.30, as required by 10 CFR 50.55a(g). Items within the scope of E1.30 inspections shall be identified based on the function of the item as described in the associated Table IWE-2500-1 note rather than relying on the name given to the material or the similarity to Figure IWE-2500-1. As noted previously, Figure IWE-2500-1 represents one typical moisture barrier geometry; however, it is not all-inclusive. If a material prevents intrusion of moisture against inaccessible areas of the pressure retaining metal containment shell or liner at concrete-to-metal interfaces or at metal-to-metal interfaces that are not seal-welded, the material shall be inspected as a moisture barrier. If the material is used as a basis for not performing augmented examinations of a shell or liner interface location per IWE-1241, the material is serving the purpose as described above, and shall be inspected as a moisture barrier. Furthermore, if the Item E1.11 and Item E1.30 inspections are addressed in the same procedures, the inspection scope and acceptance criteria should identify the different surfaces. Items E1.11 and E1.30 address different materials with different geometries and acceptance criteria.
Discussion:
This OE is applicable to SNGS. In the process of implementing the license renewal program commitments related to the containment structure, SNGS had identified similar conditions to those described in RIS 2016-07. To correct this condition SNGS has performed modifications to its containment liner insulation system and performed required examinations. Additional augmented inspection plans were also developed to manage issues related to this issue, all deficiencies identified have been corrected and potential operability issues were addressed.
The failure to identify this condition earlier was due to inaccessibility, the containment liner between 78' and 100' elevation has an insulation system installed with the original insulation lagging extending to the floor preventing access to the moisture barrier and other items that act as moisture barriers (i.e., vertical test channel that extends below the concrete floor). SNGS Unit 1 and 2 had the lagging at 78' trimmed to allow unobstructed access for the required moisture barrier and related item inspections.
SNGS Containment Liner contains originally installed liner plate monitor channels that were installed to test the liner plate butt welds for leak tightness during construction. The liner plate monitor channels for the liner beneath the containment concrete floor contains test piping that 114

runs up through the bio shield wall and connects to 3 separate test headers. This test header piping comes out of the wall approximately 3 feet above the 78' floor and is accessible for visual inspection. There is an additional area of liner plate monitor channels for the liner beneath the containment concrete floor that is at the outer most circumference, this area is connected to the first horizontal test channels just above the concrete floor by vertical liner plate monitor channels on the knuckle liner plates. Some of these knuckle plate monitor channels had been identified during License Renewal inspections to contain through wall holes and upon further inspection it was identified that moisture had in fact entered the liner plate monitor sections below the concrete.
The Containment Inservice Inspection (CISI) Program was enhanced to include additional inspections of all these areas including areas below the concrete floor exposed by removing concrete and opening the floor liner plate monitor channels. The CISI program has been enhanced to include inspection plans for periodic inspections of all the noted test headers, all vertical liner plate monitor channels at outer most circumference of 78' containment well as locations beneath the concrete where moisture had been identified. Degraded areas have been corrected to ensure a moisture seal is maintained to ensure moisture is prevented from entering into areas below the concrete floor. These inspections will be on going for the remaining life of the plant on a periodic basis IAW ASME section XI subsection IWE.
A plant-specific aging management plan of the inaccessible areas of the SNGS Containment liner plates in addition to the visual inspection recommended in NUREG-1801 has been developed in the IWE Augmented Inspection Plan CISI plan. Initial inspections, examinations and required repairs have been completed on both SNGS Units 1 and 2.
3.7    License Renewal Aging Management The integrated plant assessment for license renewal identified new and existing aging management programs necessary to provide reasonable assurance that systems, structures, and components within the scope of license renewal will continue to perform their intended functions consistent with the Current Licensing Basis (CLB) for the period of extended operation. The period of extended operation is defined as 20 years from the units' original operating license expiration dates of August 13, 2016, for Unit 1, and April 18, 2020, for Unit 2.
License renewal commitments are currently tracked in Appendix B to the SNGS UFSAR. The NUREG-1801 Chapter XI Aging Management Programs (AMPs) associated with this license amendment are described in the following sections. The AMPs are either consistent with generally accepted industry methods as discussed in NUREG-1801 or required enhancements.
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3.7.1  ASME Section XI, Subsection IWE (A.2.1.28)
The ASME Section XI, Subsection IWE aging management program is an existing program based on ASME Code and complies with the provisions of 10 CFR 50.55a. The program consists of periodic inspection of the containment structure liner plate, including its integral attachments, penetration sleeves, pressure retaining bolting, personnel airlock and equipment hatches, moisture barrier, and other pressure retaining components for cracking, loss of material, loss of preload, and loss of sealing (of the moisture barrier). The moisture barrier is a sealant installed at the junction of the Containment concrete floor and the carbon steel Containment liner.
Examination methods include visual and volumetric testing as required by ASME Section XI, Subsection IWE. Observed conditions that have the potential for impacting an intended function are evaluated for acceptability in accordance with ASME requirements or corrected in accordance with corrective action process.
The ASME Section XI, Subsection IWE aging management program will be enhanced to include:
: 1. Inspection of a sample of the inaccessible liner covered by insulation and lagging prior to the period of extended operation and every 10 years thereafter. Should unacceptable degradation be found, additional insulation will be removed as necessary to determine extent of condition in accordance with the corrective action process.
Prior to the period of extended operation
* The samples shall include 57 randomly selected containment liner insulation panels per unit.
NOTE: See section 3.5.3 Technical Position SMC-I5T-04 for clarification on liner panel sample scope.
* The randomly selected containment liner insulation panels will not include containment liner insulation panels previously removed to allow for inspection.
* The examination will be performed by either removing the containment liner insulation panels and performing a visual inspection, or by using a pulsed eddy current (PEG) remote inspection, with the containment liner insulation left in place, to detect evidence of loss of material. If evidence of loss of material is detected using PEG, the containment liner insulation panel will be subsequently removed to allow for visual and UT examinations.
* All inspections will be completed by August 2016 for both SNGS Units.
Approximately one third of the 57 inspections will be completed during each refueling outage (SNGS Unit 1 involves the following refuel outages: Spring 2013, Fall 2014, and Spring 2016. SNGS Unit 2 involves the following refuel outages: Fall 2012, Spring 2014, and Fall 2015.). It is acceptable to perform greater than one third of the inspections in any refuel outage to accelerate the inspection schedule.
During the period of extended operation 116
* One containment liner insulation panel will be selected, at random, for removal from each quadrant, during each of the three Periods in an Inspection Interval. Therefore, a total of 12 containment liner insulation panels will be selected, in each unit, during each ten-year Inspection Interval, to allow for examination of the containment liner behind the containment liner insulation.
* The randomly selected containment liner insulation panels in each quadrant will not include containment liner insulation panels previously selected.
The results of these inspections are provided in Section 3.1.5, Appendix J Liner Issues, Subsections SNGS Unit 1 and SNGS Unit 2, License Renewal Inspections.
: 2. Visual inspection of 100% of the moisture barrier, at the junction between the containment concrete floor and the containment liner, will be performed in accordance with ASME Section XI, Subsection IWE program requirements, to the extent practical within the limitation of design, geometry, and materials of construction of the components. The bottom edge of the stainless steel insulation lagging will be trimmed, if necessary, to perform the moisture barrier inspections. This inspection will be performed prior to the period of extended operation, and on a frequency consistent with IWE inspection requirements thereafter. Should unacceptable degradation be found, corrective actions, including extent of condition, will be addressed in accordance with the corrective action process.
As a follow up to inspections performed during the 2009 refueling outage, the following specific corrective actions will be performed on Unit 2 prior to entry into the period of extended operation:
* Examine the accessible 3/4" knuckle plate. If corrosion is observed to extend below the surface of the moisture barrier, excavate the moisture barrier to sound metal below the floor level and perform examinations as required by IWE.
* Perform remote visual inspections, of the six capped vertical liner plate monitor channels, below the containment floor to determine extent of condition.
* Remove the concrete floor and expose 1/4" containment liner plate (floor) for a minimum of two of the vertical liner plate monitor channels with holes. Perform examination of exposed 1/4" containment liner plate (floor) as required by IWE.
Additional excavations will be performed, if necessary, depending upon conditions found at the first two channels.
* Remove 1/2" containment liner insulation panels, adjacent to accessible areas where there are indications of corrosion, to determine the extent of condition of the existing corroded areas of the containment liner plate.
* Perform augmented examinations of the area of the 1/2" containment liner plate behind insulation panels, where loss of material was previously identified, in accordance with IWE-2420.
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* Examine 100% of the moisture barrier in accordance with IWE-2310 and replace or repair the moisture barrier to meet the acceptance standard in IWE-3510.
As a follow-up to inspections performed during the 2010 refueling outage, the following specific corrective actions will be performed on Unit 1 prior to entry into the period of extended operation:
* Perform augmented examinations of the 3/4" containment liner (knuckle plate) at 78' elevation in accordance with IWE-2420.
* Perform augmented examinations of the areas of the 1/2" containment liner plate behind insulation panels, where loss of material was previously identified, in accordance with IWE-2420.
* Remove 1/2" containment liner insulation panels, adjacent to accessible areas where there are indications of corrosion, to determine the extent of condition of the existing corroded areas of the containment liner plate.
The results of these inspections are provided in Section 3.1.5, Appendix J Liner Issues, Subsection SNGS Unit 2, License Renewal Inspections.
: 3. ASME Section XI, Subsection IWE program scope will be revised to include the following welds that are currently exempted from Subsection IWE and governed under ASME Section XI, Subsection IWB or IWC. The scope of the revision will include the cap plate to penetrating pipe pressure boundary welds, for penetrating pipe constructed of stainless steel for those penetrations with a normal operating temperature greater than 140 degrees F.
: 4. Owner augmented inspections will be performed at the SNGS Unit 1 and Unit 2 area of the Containment liner, under the fuel transfer canal and behind the Containment liner insulation, which are subjected to leaks from the reactor cavity. These owner augmented inspections will be performed on a frequency of once per Containment lnservice Inspection Period, starting with the current Period. These owner augmented inspections will continue, under the IWE program, as long as leakage from the reactor cavity or fuel transfer canal is observed between the Containment liner and the Containment liner insulation, including during the PEO.
These enhancements will be implemented prior to the period of extended operation, with the inspections performed in accordance with the schedule described above.
3.7.2  ASME Section XI, Subsection IWL (A.2.1.29)
The ASME Section XI, Subsection IWL aging management program is an existing program based on ASME Code and complies with the provisions of 10 CFR 50.55a. The program requires periodic inspection of Containment Structure concrete surfaces to identify areas of 118

deterioration and distress such as defined in ACI 201.1, including loss of material, cracks and distortion, and loss of bond.
Inspection methods, inspected parameters, and acceptance criteria are in accordance with ASME Section XI, Subsection IWL as approved by 10 CFR 50.55a. Observed conditions that have the potential for impacting an intended function are evaluated for acceptability in accordance with ASME Section XI, Subsection IWL requirements or corrected in accordance with the corrective action process.
The ASME Section XI, Subsection IWL, aging management program will be enhanced to include:
: 1.       Examination and acceptance criteria in accordance with the guidance contained in ACI 349.3R.
3.7.3    10 CFR 50, Appendix J (A.2.1.31)
The 10 CFR 50, Appendix J aging management program is an existing program that monitors leakage rates through the containment pressure boundary, including penetrations, fittings, and other access openings, in order to detect age related degradation of the containment pressure boundary. Corrective actions are taken if leakage rates exceed acceptance criteria. The Primary Containment Leakage Rate Testing Program (LRT) provides for aging management of pressure boundary degradation due to aging effects from cracking, loss of leakage tightness, loss of sealing, loss of material, or loss of preload in various systems penetrating containment.
The 10 CFR 50 Appendix J program also detects age related degradation in material properties of gaskets, a-rings and packing materials for the containment pressure boundary access points.
Consistent with the current licensing basis, the containment leakage rate tests are performed in accordance with the regulations and guidance provided in 10 CFR 50 Appendix J Option B, Regulatory Guide 1.163, "Performance-Based Containment Leak-Testing Program," NEI 94-01 "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50 Appendix J", and ANSI/ANS 56.8, "Containment System Leakage Testing Requirements."
3.7.4    Protective Coating Monitoring and Maintenance Program (A.2.1.35)
The Protective Coating Monitoring and Maintenance Program is an existing program that provides for aging management of Service Level I coatings inside the containment structure.
Service Level I coatings are used in areas where coating failure could adversely affect the operation of post-accident fluid systems and thereby impair safe shutdown. The Protective Coating Monitoring and Maintenance Program provides for inspections, assessments, and repairs for any condition that adversely affects the ability of Service Level I coatings to function as intended.
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3.8    NRC SER Limitations and Conditions 3.8.1    Limitations and Conditions Applicable to NEI 94-01, Revision 2-A The NRC staff found that the use of NEI TR 94-01, Revision 2, was acceptable for referencing by licensees proposing to amend their TS to permanently extend the ILRT surveillance interval to 15 years, provided the following conditions as listed in Table 3.8.1-1 were satisfied:
Table 3.8.1-1 NEI 94-01 Revision 2-A Limitations and Condition Limitation/Condition SNGS Response (From Section 4.0 of SE)
For calculating the Type A leakage rate, the           SNGS will utilize the definition in NEI 94-01 licensee should use the definition in the NEI TR       Revision 3-A, Section 5.0. This definition has 94-01, Revision 2, in lieu of that in ANSI/ANS-        remained unchanged from Revision 2-A to 56.8-2002. (Refer to SE Section 3.1.1.1.)              Revision 3-A of NEI 94-01.
The licensee submits a schedule of containment         Reference Section 3.5.3 (Table 3.5.3-3 and 3.5.3-inspections to be performed prior to and between       4) of this LAR submittal.
Type A tests. (Refer to SE Section 3.1.1.3.)
The licensee addresses the areas of the                Reference Section 3.5.3 (Tables 3.5.3-8 and containment structure potentially subjected to         3.5.3-11) of this LAR submittal.
degradation. (Refer to SE Section 3.1.3.)
The licensee addresses any tests and inspections       Steam Generator replacements were performed performed following major modifications to the         using the installed equipment hatches. There are containment structure, as applicable. (Refer to SE     no major modifications planned that would require Section 3.1.4.)                                        the performance of a Type A test.
The normal Type A test interval should be less         SNGS will follow the requirements of NEI 94-01 than 15 years. If a licensee has to utilize the        Revision 3-A, Section 9.1. This requirement has provision of Section 9.1 of NEI TR 94-01, Revision     remained unchanged from Revision 2-A to 2, related to extending the ILRT interval beyond       Revision 3-A of NEI 94-01.
15 years, the licensee must demonstrate to the NRC staff that it is an unforeseen emergent condition. (Refer to SE Section 3.1.1.2.)              In accordance with the requirements of NEI 94-01, Revision 2-A, SER Section 3.1.1.2, SNGS will also demonstrate to the NRC staff that an unforeseen emergent condition exists in the event an extension beyond the 15-year interval is required.
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Table 3.8.1-1 NEI 94-01 Revision 2-A Limitations and Condition Limitation/Condition SNGS Response (From Section 4.0 of SE)
For plants licensed under 10 CFR Part 52,              Not applicable. SNGS was not licensed under 10 applications requesting a permanent extension of       CFR Part 52.
the ILRT surveillance interval to 15 years should be deferred until after the construction and testing of containments for that design have been completed and applicants have confirmed the applicability of NEI 94-01, Revision 2, and EPRI Report No. 1009325, Revision 2, including the use of past containment ILRT data.
3.8.2    Limitations and Conditions Applicable to NEI 94-01, Revision 3-A The NRC staff found that the guidance in NEI TR 94-01, Revision 3, was acceptable for referencing by licensees in the implementation of the optional performance-based requirements of Option B to 10 CFR 50, Appendix J. However, the NRC staff identified two conditions on the use of NEI TR 94-01, Revision 3 (Reference NEI 94-01, Revision 3-A, NRC SER 4.0, Limitations and Conditions):
Topical Report Condition 1 NEI TR 94-01, Revision 3, is requesting that the allowable extended interval for Type C LLRTs be increased to 75 months, with a permissible extension (for non-routine emergent conditions) of nine months (84 months total). The staff is allowing the extended interval for Type C LLRTs be increased to 75 months with the requirement that a licensee's post-outage report include the margin between the Type B and Type C leakage rate summation and its regulatory limit. In addition, a corrective action plan shall be developed to restore the margin to an acceptable level. The staff is also allowing the non-routine emergent extension out to 84-months as applied to Type C valves at a site, with some exceptions that must be detailed in NEI TR 94-01, Revision 3. At no time shall an extension be allowed for Type C valves that are restricted categorically (e.g., BWR MSIVs), and those valves with a history of leakage, or any valves held to either a less than maximum interval or to the base refueling cycle interval. Only non-routine emergent conditions allow an extension to 84 months.
Response to Condition 1 Condition 1 presents the following three (3) separate issues that are required to be addressed:
* ISSUE 1 - The allowance of an extended interval for Type C LLRTs of 75 months carries the requirement that a licensee's post-outage report include the margin between the Type B and Type C leakage rate summation and its regulatory limit.
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* ISSUE 2 - In addition, a corrective action plan shall be developed to restore the margin to an acceptable level.
* ISSUE 3 - Use of the allowed 9-month extension for eligible Type C valves is only authorized for non-routine emergent conditions with exceptions as detailed in NEI 94-01, Revision 3-A, Section 10.1.
Response to Condition 1, ISSUE 1 The post-outage report shall include the margin between the Type B and Type C Minimum Pathway Leak Rate (MNPLR) summation value, as adjusted to include the estimate of applicable Type C leakage understatement, and its regulatory limit of 0.60 La.
Response to Condition 1, ISSUE 2 When the potential leakage understatement adjusted Types B and C MNPLR total is greater than the SNGS, Units 1 and 2, administrative leakage summation limit of 0.5 La, but less than the regulatory limit of 0.6 La, then an analysis and determination of a corrective action plan shall be prepared to restore the leakage summation margin to less than the SNGS leakage limit. The corrective action plan shall focus on those components which have contributed the most to the increase in the leakage summation value and what manner of timely corrective action, as deemed appropriate, best focuses on the prevention of future component leakage performance issues so as to maintain an acceptable level of margin.
Response to Condition 1, ISSUE 3 SNGS, Units 1 and 2 will apply the 9-month allowable interval extension period only to eligible Type C components and only for non-routine emergent conditions. Such occurrences will be documented in the record of tests.
Topical Report Condition 2 The basis for acceptability of extending the ILRT interval out to once per 15 years was the enhanced and robust primary containment inspection program and the local leakage rate testing of penetrations. Most of the primary containment leakage experienced has been attributed to penetration leakage and penetrations are thought to be the most likely location of most containment leakage at any time. The containment leakage condition monitoring regime involves a portion of the penetrations being tested each refueling outage, nearly all LLRTs being performed during plant outages. For the purposes of assessing and monitoring or trending overall containment leakage potential, the as-found minimum pathway leakage rates for the just tested penetrations are summed with the as-left minimum pathway leakage rates for penetrations tested during the previous 1 or 2 or even 3 refueling outages. Type C tests involve valves, which in the aggregate, will show increasing leakage potential due to normal wear and tear, some predictable and some not so predictable. Routine and appropriate maintenance may extend this increasing leakage potential. Allowing for longer intervals between LLRTs means 122

that more leakage rate test results from farther back in time are summed with fewer just tested penetrations and that total is used to assess the current containment leakage potential. This leads to the possibility that the LLRT totals calculated understate the actual leakage potential of the penetrations. Given the required margin included with the performance criterion and the considerable extra margin most plants consistently show with their testing, any understatement of the LLRT total using a 5-year test frequency is thought to be conservatively accounted for.
Extending the LLRT intervals beyond 5 years to a 75-month interval should be similarly conservative provided an estimate is made of the potential understatement and its acceptability determined as part of the trending specified in NEI TR 94-01, Revision 3, Section 12.1.
When routinely scheduling any LLRT valve interval beyond 60-months and up to 75-months, the primary containment leakage rate testing program trending or monitoring must include an estimate of the amount of understatement in the Types B and C total leakage and must be included in a licensee's post-outage report. The report must include the reasoning and determination of the acceptability of the extension, demonstrating that the LLRT totals calculated represent the actual leakage potential of the penetrations.
Response to Condition 2 Condition 2 presents the following two (2) separate issues that are required to be addressed:
* ISSUE 1 - Extending the LLRT intervals beyond 5 years to a 75-month interval should be similarly conservative provided an estimate is made of the potential understatement and its acceptability determined as part of the trending specified in NEI TR 94-01, Revision 3, Section 12.1.
* ISSUE 2 - When routinely scheduling any LLRT valve interval beyond 60 months and up to 75 months, the primary containment leakage rate testing program trending or monitoring must include an estimate of the amount of understatement in the Types B and C total and must be included in a licensee's post-outage report. The report must include the reasoning and determination of the acceptability of the extension, demonstrating that the LLRT totals calculated represent the actual leakage potential of the penetrations.
Response to Condition 2, ISSUE 1 The change in going from a 60-month extended test interval for Type C tested components to a 75-month interval, as authorized under NEI 94-01, Revision 3-A, represents an increase of 25%
in the LLRT periodicity. As such, SNGS, Units 1 and 2 will conservatively apply a potential leakage understatement adjustment factor of 1.25 to the actual As-Left leak rate, which will increase the As-Left leakage total for each Type C component currently on greater than a 60-month test interval up to the 75-month extended test interval. This will result in a combined conservative Type C total for all 75-month LLRTs being "carried forward" and will be included whenever the total leakage summation is required to be updated (either while on-line or following an outage).
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When the potential leakage understatement adjusted leak rate total for those Type C components being tested on greater than a 60-month test interval up to the 75-month extended test interval is summed with the non-adjusted total of those Type C components being tested at less than or equal to a 60-month test interval, and the total of the Type B tested components, results in the MNPLR being greater than the SNGS administrative leakage summation limit of 0.50 La, but less than the regulatory limit of 0.6 La, then an analysis and corrective action plan shall be prepared to restore the leakage summation value to less than the SNGS leakage limit.
The corrective action plan should focus on those components which have contributed the most to the increase in the leakage summation value and what manner of timely corrective action, as deemed appropriate, best focuses on the prevention of future component leakage performance issues.
Response to Condition 2, ISSUE 2 If the potential leakage understatement adjusted leak rate MNPLR is less than the SNGS administrative leakage summation limit of 0.50 La, then the acceptability of the greater than a 60-month test interval up to the 75-month LLRT extension for all affected Type C components has been adequately demonstrated and the calculated local leak rate total represents the actual leakage potential of the penetrations.
In addition to Condition 1, ISSUES 1 and 2, which deal with the MNPLR Types B and C summation margin, NEI 94-01, Revision 3-A, also has a margin-related requirement as contained in Section 12.1, Report Requirements.
A post-outage report shall be prepared presenting results of the previous cycles Type B and Type C tests, and Type A, Type B and Type C tests, if performed during that outage. The technical contents of the report are generally described in ANSI/ANS-56.8-2002 and shall be available on-site for NRC review. The report shall show that the applicable performance criteria are met and serve as a record that continuing performance is acceptable. The report shall also include the combined Type B and Type C leakage summation, and the margin between the Type B and Type C leakage rate summation and its regulatory limit. Adverse trends in the Type B and Type C leakage rate summation shall be identified in the report and a corrective action plan developed to restore the margin to an acceptable level.
At SNGS, in the event an adverse trend in the aforementioned potential leakage understatement adjusted Types B and C summation is identified, then an analysis and determination of a corrective action plan shall be prepared to restore the trend and associated margin to an acceptable level. The corrective action plan shall focus on those components, which have contributed the most to the adverse trend in the leakage summation value and what manner of timely corrective action, as deemed appropriate, best focuses on the prevention of future component leakage performance issues.
At SNGS, an adverse trend is defined as three (3) consecutive increases in the final pre-mode change Types B and C MNPLR leakage summation values, as adjusted to include the estimate of applicable Type C leakage understatement, as expressed in terms of La.
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3.9    Conclusion NEI 94-01, Revision 3-A, dated July 2012, and the limitations and conditions specified in NEI 94-01, Revision 2-A, dated October 2008, describe an NRC-accepted approach for implementing the performance-based requirements of 10 CFR 50, Appendix J, Option B. It incorporated the regulatory positions stated in RG 1.163 and includes provisions for extending Type A intervals to 15 years and Type C test intervals to 75 months. NEI 94-01, Revision 3-A, delineates a performance-based approach for determining Type A, Type B, and Type C containment leakage rate surveillance test frequencies. SNGS is adopting the guidance of NEI 94-01, Revision 3-A, and the limitations and conditions specified in NEI 94-01, Revision 2-A, for the SNGS, Units 1 and 2, 10 CFR 50, Appendix J testing program plan.
Based on the previous ILRTs conducted at SNGS, Units 1 and 2, PSEG concludes that the permanent extension of the containment ILRT interval from 10 to 15 years represents minimal risk to increased leakage. The risk is minimized by continued Type B and Type C testing performed in accordance with Option B of 10 CFR 50, Appendix J, and the overlapping inspection activities performed as part of the following SNGS inspection programs:
* Containment Inservice Inspection Program, Subsection IWE
* Containment Inservice Inspection Program, Subsection IWL
* SNGS Coatings Program This experience is supplemented by risk analysis studies, including the SNGS risk analysis provided in Attachment 2 of this activity. The risk assessment concludes that increasing the ILRT interval on a permanent basis to a one-in-fifteen year frequency is not considered to be significant because it represents only a small change in the SNGS risk profile.

==4.0    REGULATORY EVALUATION==

4.1    Applicable Regulatory Requirements/Criteria The proposed change has been evaluated to determine whether applicable regulations and requirements continue to be met.
10 CFR 50.54(o) requires primary reactor containments for water-cooled power reactors to be subject to the requirements of Appendix J to 10 CFR 50, Leakage Rate Testing of Containment of Water Cooled Nuclear Power Plants. Appendix J specifies containment leakage testing requirements, including the types required to ensure the leak-tight integrity of the primary reactor containment and systems and components which penetrate the containment. In addition, Appendix J discusses leakage rate acceptance criteria, test methodology, frequency of testing and reporting requirements for each type of test.
The adoption of the Option B performance-based containment leakage rate testing for Type A, Type B and Type C testing did not alter the basic method by which Appendix J leakage rate testing is performed; however, it did alter the frequency at which Type A, Type B, and Type C 125

containment leakage tests must be performed. Under the performance-based option of 10 CFR 50, Appendix J, the test frequency is based upon an evaluation that reviewed "as-found" leakage history to determine the frequency for leakage testing which provides assurance that leakage limits will be maintained. The change to the Type A test frequency did not directly result in an increase in containment leakage. Similarly, the proposed change to the Type C test frequencies will not directly result in an increase in containment leakage.
EPRI TR-1009325, Revision 2-A, provided a risk impact assessment for optimized ILRT intervals up to 15 years, utilizing current industry performance data and risk informed guidance.
NEI 94-01, Revision 3-A, Section 9.2.3.1 (Reference 2), states that Type A ILRT intervals of up to 15 years are allowed by this guideline. The Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals, EPRI Report 1018243 (formerly TR-1009325, Revision 2-A)
(Reference 11), indicates that, in general, the risk impact associated with ILRT interval extensions for intervals up to 15 years is small. However, plant-specific confirmatory analyses are required.
The NRC staff reviewed NEI TR 94-01, Revision 2, and EPRI Report No. 1009325, Revision 2.
For NEI TR 94-01, Revision 2, the NRC staff determined that it described an acceptable approach for implementing the optional performance-based requirements of Option B to 10 CFR 50, Appendix J. This guidance includes provisions for extending Type A ILRT intervals up to 15 years and incorporates the regulatory positions stated in RG 1.163. The NRC staff finds that the Type A testing methodology, as described in ANSI/ANS-56.8-2002 (Reference 37), and the modified testing frequencies recommended by NEI TR 94-01, Revision 2, serve to ensure continued leakage integrity of the containment structure. Type B and Type C testing ensures that individual penetrations are essentially leak tight. In addition, aggregate Type B and Type C leakage rates support the leakage tightness of primary containment by minimizing potential leakage paths.
For EPRI Report No. 1009325, Revision 2, a risk-informed methodology using plant-specific risk insights and industry ILRT performance data to revise ILRT surveillance frequencies, the NRC staff finds that the proposed methodology satisfies the key principles of risk-informed decision making applied to changes to TS as delineated in RG 1.174 (Reference 3) and RG 1.177, An Approach for Plant-Specific, Risk-Informed Decision making: Technical Specifications (Reference 50). The NRC staff, therefore, found that this guidance was acceptable for referencing by licensees proposing to amend their TS in regards to containment leakage rate testing, subject to the limitations and conditions noted in Section 4.2 of the SE.
The NRC staff reviewed NEI TR 94-01, Revision 3, and determined that it described an acceptable approach for implementing the optional performance-based requirements of Option B to 10 CFR 50, Appendix J, as modified by the limitations and conditions summarized in Section 4.0 of the associated SE. This guidance included provisions for extending Type C LLRT intervals up to 75 months. Type C testing ensures that individual CIVs are essentially leak tight. In addition, aggregate Type C leakage rates support the leakage tightness of primary containment by minimizing potential leakage paths. The NRC staff, therefore, found that this guidance, as modified to include two limitations and conditions, was acceptable for referencing by licensees proposing to amend their TS in regards to containment leakage rate testing. Any applicant may reference NEI TR 94-01, Revision 3, as modified by the associated SER and approved by the NRC, and the limitations and conditions specified in NEI 94-01, Revision 2-A, 126

dated October 2008, in a licensing action to satisfy the requirements of Option B to 10 CFR 50, Appendix J.
4.2   Precedent This LAR is similar in nature to the following license amendments to extend the Type A Test Frequency to 15 years and the Type C test frequency to 75 months as previously authorized by the NRC in the associated referenced SERs:
* Braidwood Station, Units 1 and 2, and Byron Station, Units 1 and 2, issued September 10, 2020 (Reference 31)
* McGuire Nuclear Station, Units 1 and 2, issued January 31, 2018 (Reference 24)
* Vogtle Electric Generating Plant, Units 1 and 2, issued October 29, 2018 (Reference 25) 4.3   No Significant Hazards Consideration PSEG Nuclear LLC (PSEG) proposes to amend the Technical Specifications (TS) for SNGS Nuclear Generating Station (SNGS) Units 1 and 2, to allow extension of the Type A and Type C leakage test intervals. The extension is based on the adoption of the Nuclear Energy Institute (NEI) 94-01, Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J, Revision 3-A, and the conditions and limitations set forth in Revision 2-A.
Specifically, the proposed change revises SNGS Units 1 and 2 TS 6.8.4.f, Containment Leakage Rate Testing Program, paragraph a., by replacing the reference to Regulatory Guide (RG) 1.163, Performance-Based Containment Leak-Test Program, with a reference to NEI 94-01, Revision 3-A and the conditions and limitations specified in NEI 01, Revision 2-A.
In addition, the proposed change also deletes the exceptions in TS 6.8.4.f.a, which were previously approved by the NRC in TS Amendment 296 for Unit 1 and Amendment 232 for Unit 2 to allow one-time extensions of the ILRT test frequency for SNGS Units 1 and 2. These exceptions were for activities that have already taken place; therefore, their deletion is solely an administrative action.
PSEG has evaluated whether or not a significant hazards consideration is involved with the proposed amendment by focusing on the three standards set forth in 10 CFR 50.92, Issuance of amendment, as discussed below:
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: 1. Does the proposed amendment involve a significant increase in the probability or consequences of an accident previously evaluated?
Response: No.
The proposed activity involves the revision of Salem Nuclear Generating Station (SNGS),
Units 1 and 2, Technical Specification (TS) Section 6.8.4.f, Containment Leakage Rate Testing Program, to allow the extension of the Type A integrated leakage rate test (ILRT) containment test interval to 15 years, and the extension of the Type C local leakage rate test (LLRT) interval to 75 months for selected components. The current Type A test interval of 120 months (10 years) would be extended on a permanent basis to no longer than 15 years from the last Type A test. Extensions of up to nine months are permissible only for non-routine emergent conditions. The current Type C test interval of 60 months for selected components would be extended on a performance basis to no longer than 75 months.
Extensions of up to nine months (total maximum interval of 84 months for Type C tests) are permissible only for non-routine emergent conditions.
The proposed test interval extensions do not involve either a physical change to the plant or a change in the manner in which the plant is operated or controlled. The containment is designed to provide an essentially leak tight barrier against the uncontrolled release of radioactivity to the environment for postulated accidents. As such, the containment and the testing requirements invoked to periodically demonstrate the integrity of the containment exist to ensure the plant's ability to mitigate the consequences of an accident, and do not involve the prevention or identification of any precursors of an accident.
The change in Type A test frequency to once-per-fifteen years, measured as an increase to the total integrated plant risk for those accident sequences influenced by Type A testing, based on the internal events probabilistic risk analysis is 7.0E-2 person-rem/yr, which is 2%
of the population dose risk for Units 1 and 2. Electric Power Research Institute (EPRI)
Report No. 1009325, Revision 2-A states that a very small population dose is defined as an increase of  1.0 person-rem per year or  1% of the total population dose, whichever is less restrictive for the risk impact assessment of the extended ILRT intervals. This is consistent with the Nuclear Regulatory Commission (NRC) Final Safety Evaluation for Nuclear Energy Institute (NEI) 94-01 and EPRI Report No. 1009325. Moreover, the risk impact when compared to other severe accident risks is negligible. Therefore, this proposed extension does not involve a significant increase in the probability of an accident previously evaluated.
In addition, as documented in NUREG-1493, Performance-Based Containment Leak-Test Program, dated September 1995, Types B and C tests have identified a very large percentage of containment leakage paths, and the percentage of containment leakage paths that are detected only by Type A testing is very small. The SNGS Type A test history supports this conclusion.
The integrity of the containment is subject to two types of failure mechanisms that can be categorized as: (1) activity based, and (2) time based. Activity-based failure mechanisms are defined as degradation due to system and/or component modifications or maintenance.
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The LLRT requirements and administrative controls such as configuration management and procedural requirements for system restoration ensure that containment integrity is not degraded by plant modifications or maintenance activities. The design and construction requirements of the containment structure combined with the containment inspections performed in accordance with American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel (BPV) Code, Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components; the station Containment Coatings Program; and TS requirements, serve to provide a high degree of assurance that the containment would not degrade in a manner that is detectable only by a Type A test. Based on the above, the proposed test interval extensions do not significantly increase the consequences of an accident previously evaluated.
The proposed amendment also deletes the exceptions in TS 6.8.4.f.a, which were previously approved by the NRC in TS Amendment 296 for Unit 1 and Amendment 232 for Unit 2 to allow one-time extensions of the ILRT test frequency for SNGS Units 1 and 2.
These exceptions were for activities that have already taken place; therefore, their deletion is solely an administrative action that has no effect on any component and no impact on how the unit is operated.
Therefore, the proposed changes do not result in a significant increase in the probability or consequences of an accident previously evaluated.
: 2. Does the proposed change create the possibility of a new or different kind of accident from any accident previously evaluated?
Response: No.
The proposed amendment to the TS 6.8.4.f, Containment Leakage Rate Testing Program, involves the extension of the SNGS Type A containment test interval to 15 years and the extension of the Type C test interval to 75 months for selected components. The containment and the testing requirements to periodically demonstrate the integrity of the containment exist to ensure the plants ability to mitigate the consequences of an accident do not involve any accident precursors or initiators. The proposed change does not involve a physical change to the plant (i.e., no new or different type of equipment will be installed) nor does it alter the design, configuration, or change the manner in which the plant is operated or controlled beyond the standard functional capabilities of the equipment.
The proposed amendment also deletes the exceptions in TS 6.8.4.f.a, which were previously approved by the NRC in TS Amendment 296 for Unit 1 and Amendment 232 for Unit 2 to allow one-time extensions of the ILRT test frequency for SNGS Units 1 and 2.
These exceptions were for activities that have already taken place; therefore, their deletion is solely an administrative action that does not result in any change in how the unit is operated or controlled.
Therefore, the proposed changes do not create the possibility of a new or different kind of accident from any previously evaluated.
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: 3. Does the proposed change involve a significant reduction in a margin of safety?
Response: No.
The proposed amendment to the SNGS Units 1 and 2 TS 6.8.4.f. involves the extension of the Type A containment test interval to 15 years and the extension of the Type C test interval to 75 months for selected components. This amendment does not alter the manner in which safety limits, limiting safety system set points, or limiting conditions for operation are determined. The specific requirements and conditions of the TS Containment Leak Rate Testing Program exist to ensure that the degree of containment structural integrity and leak-tightness that is considered in the plant safety analysis is maintained. The overall containment leak rate limit specified by TS is maintained.
The proposed change involves only the extension of the interval between Type A containment leak rate tests and Type C tests for SNGS, Units 1 and 2. The proposed surveillance interval extension is bounded by the 15-year ILRT interval, and the 75-month Type C test interval currently authorized within NEI 94-01, Revision 3-A. Industry experience supports the conclusions that Types B and C testing detects a large percentage of containment leakage paths and that the percentage of containment leakage paths that are detected only by Type A testing is small. The containment inspections performed in accordance with ASME Section Xl, the station Containment Coatings Program; and TS serve to provide a high degree of assurance that the containment would not degrade in a manner that is detectable only by Type A testing. The combination of these factors ensures that the margin of safety in the plant safety analysis is maintained. The design, operation, testing methods and acceptance criteria for Types A, B, and C containment leakage tests specified in applicable codes and standards would continue to be met, with the acceptance of this proposed change, since these are not affected by changes to the Type A and Type C test intervals.
The proposed amendment also deletes the exceptions in TS 6.8.4.f.a, which were previously approved by the NRC in TS Amendment 296 for Unit 1 and Amendment 232 for Unit 2 to allow one-time extensions of the ILRT test frequency for SNGS Units 1 and 2.These exceptions were for activities that have already taken place; therefore, the deletion is solely an administrative action and does not change how the unit is operated and maintained. Thus, there is no reduction in any margin of safety as a result of this administrative change.
Therefore, the proposed changes do not involve a significant reduction in a margin of safety.
Based on the above, PSEG concludes that the proposed amendment does not involve a significant hazards consideration under the standards set forth in 10 CFR 50.92(c), and, accordingly, a finding of no significant hazards consideration is justified.
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4.4    Conclusion In conclusion, based on the considerations discussed above, (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) such activities will be conducted in compliance with the Commissions regulations, and (3) the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public.

==5.0    ENVIRONMENTAL CONSIDERATION==

A review has determined that the proposed amendment would change a requirement with respect to installation or use of a facility component located within the restricted area, as defined in 10 CFR 20, or would change an inspection or surveillance requirement. However, the proposed amendment does not involve (i) a significant hazards consideration, (ii) a significant change in the types or significant increase in the amounts of any effluent that may be released offsite, or (iii) a significant increase in individual or cumulative occupational radiation exposure.
Accordingly, the proposed amendment meets the eligibility criterion for categorical exclusion set forth in 10 CFR 51.22(c)(9). Therefore, pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the proposed amendment.

==6.0    REFERENCES==
: 1. Regulatory Guide 1.163, Performance-Based Containment Leak-Test Program, September 1995 (ML003740058)
: 2. NEI 94-01, Revision 3-A, Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J, July 2012 (ML12221A202)
: 3. RG 1.174, Revision 3, An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis, January 2018 (ML17317A256)
: 4. RG 1.200, Revision 2, An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities, March 2009 (ML090410014)
: 5. NEI 94-01, Revision 0, Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J, dated July 21, 1995 (ML11327A025)
: 6. NUREG-1493, Performance-Based Containment Leak-Test Program - Final Report, September 1995 (ML20098D498)
: 7. Electric Power Research Institute (EPRI) Topical Report No. 104285, Risk Impact Assessment of Revised Containment Leak Rate Testing Intervals, August 1994
: 8. NEI 94-01, Revision 2-A, Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J, October 2008 (ML100620847) 131
: 9. Letter from NRC (M. J. Maxin) to NEI (J. C. Butler), Final Safety Evaluation for Nuclear Energy Institute (NEI) Topical Report (TR) 94-01, Revision 2, Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J and Electric Power Research Institute (EPRI) Report No. 1009325, Revision 2, August 2007, Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals (TAC No.
MC9663), dated June 25, 2008 (ML081140105)
: 10. Letter from NRC (S. Bahadur) to NEI (B. Bradley), Final Safety Evaluation of Nuclear Energy Institute (NEI) Report, 94-01, Revision 3, Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J (TAC No. ME2164), dated June 8, 2012 (ML121030286)
: 11. EPRI TR-1018243, Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals: Revision 2-A of 1009325, October 2008
: 12. Letter from NRC (R. B. Ennis) to PSEG Nuclear (T. Joyce), Salem Nuclear Generating Station, Unit No. 1, Issuance of Amendment Re: One-Time Extension of the Type A Integrated Leakage Test Interval (TAC No. ME2258), dated August 16, 2010 (ML102000445)
: 13. Letter from NRC (R. J. Fretz) to PSEG Nuclear (H. W. Keiser), Salem Nuclear Generating Station, Unit No. 2, Issuance of Amendment Re: Containment Leakage Rate Testing Program (TAC No. MB3838), dated April 11, 2002 (ML020720154)
: 14. Letter from NRC (P. D. Milano) to PSEG Nuclear (H. W. Keiser), Salem Nuclear Generating Station Unit, Nos. 1 and 2 - Issuance of Amendments Re: 10 CFR Part 50, Appendix J, Option B (TAC NOS. MA0289 and MA0290), dated February 27, 1998 (ML011720334)
: 15. RG 1.200, Revision 3, Acceptability of Probabilistic Risk Assessment Results for Risk-Informed Activities, December 2020 (ML20238B871)
: 16. ERIN Engineering and Research, Shutdown Risk Impact Assessment for Extended Containment Leakage Testing Intervals Utilizing ORAMTM, EPRI TR-105189, Final Report, May 1995.
: 17. NUREG-2101, Safety Evaluation Report Related to the License Renewal of Salem Nuclear Generating Station, Docket Numbers 50-272 and 50-311, PSEG Nuclear LLC, June 2011 (ML11166A135)
: 18. ASTM D 5163-05a, Standard Guide for Establishing Procedures to Monitor the Performance of Service Level I Coating Systems in an Operating Nuclear Power Plant
: 19. NUREG-2122, Glossary of Risk-Related Terms in Support of Risk-Informed Decision Making, November 2013 (ML13311A353)
: 20. Interim Guidance for Performing Risk Impact Assessments In Support of One-Time Extensions for Containment Integrated Leakage Rate Test Surveillance Intervals, Rev. 4, Developed for NEI by EPRI and Data Systems and Solutions, November 2001.
132
: 21. RG 1.200, Revision 0, An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities, February 2004 (ML040630078)
: 22. RG 1.147, Revision 17, Inservice Inspection Code Case Acceptability, ASME Section XI, Division 1, August 2014 (ML13339A689)
: 23. NRC Safety Evaluation Report, Plugging of Containment Liner Plate Monitor Channels, Salem Generating Station Units 1 and 2 (TAC Nos. 74140 and 74141), December 17, 1990 (ML18095A648 and ML18095A651)
: 24. Letter from NRC (M. Mahoney) to Duke Energy (T. D. Ray), "McGuire Nuclear Station, Units 1 and 2 - Issuance of Amendments to Extend the Containment Type A Leak Rate Test Frequency to 15 Years and Type C Leak Rate Test Frequency to 75 Months (CAC Nos. MF9020 and MF9021; EPID L-2016-LLA-0032)," January 31, 2018 (ML18009A842)
: 25. Letter from NRC (M. Orenak) to Southern Nuclear Operating Company, Inc. (C. A.
Gayheart), "Vogtle Electric Generating Plant, Units 1 and 2, Issuance of Amendments to Extend the Containment Type A Leak Rate Test Frequency to 15 Years and Type C Leak Rate Test Frequency to 75 Months (CAC Nos. MG0240 and MG0241; EPID L-2017-LLA-0295)," October 29, 2018 (ML18263A039)
: 26. Regulatory Guide 1.11, Revision 0, Instrument Lines Penetrating the Primary Reactor Containment, March 1971 (ML003739934)
: 27. ANSI N18.2-1973, Nuclear Safety Criteria for the Design of Stationary Pressurized Water Reactor Plants
: 28. Regulatory Guide 1.29, Revision 1, Seismic Design Classification, August 1973 (ML13350A198)
: 29. NEI 00-02, Revision A3, Probabilistic Risk Assessment (PRA) Peer Review Process Guidance, March 20, 2000 (ML003728023)
: 30. ASME/ANS, Standard for Level 1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications, ASME/ANS RA-Sa-2009, dated March 2009. Addendum A to RA-S-2008
: 31. Letter from NRC (J. S. Wiebe) to Exelon Generation Co. (B. C. Hanson), Braidwood Station, Units 1 and 2, and Byron Station, Unit Nos. 1 and 2 - Issuance of Amendment Nos. 215, 215, 219, and 219 Re: Permanent Extension of Type A and Type C Containment Leak Rate Test Frequencies (EPID L-2019-LLA-0208), September 10, 2020 (ML20149K698)
: 32. Letter from Constellation Nuclear (C. H. Cruse) to NRC (Document Control Desk), Calvert Cliffs Nuclear Power Plant, Unit No. 1; Docket No. 50-317 - Response to Request for Additional Information Concerning the License Amendment Request for a One-Time Integrated Leakage Rate Test Extension, March 27, 2002 (ML020920100)
: 33. Jensen Hughes, Salem Generating Station, Focused Scope Peer Review of Level 2 ISGTR Analysis (PRA Standard Element LE), SA-MISC-030, October 2022 133
: 34. NRC Region I Inspection Report Nos. 50-272/90-81; 50-311/90 Integrated Performance Assessment Team Inspection, July 3, 1990 (ML18095A334)
: 35. RIE-001, Generation and Maintenance of Probabilistic Risk Assessment Models and Associated Updates
: 36. Letter from Entergy Operations, Inc. (K. Mulligan) to NRC (Document Control Desk),
Grand Gulf Nuclear Station Response to Request for Additional Information Regarding License Amendment Request to Revise Technical Specifications for Containment Leak Rate Testing, Grand Gulf Nuclear Station, Unit 1, Docket No. 50-416, License No. NPF-29, October 28, 2015 (ML15302A042)
: 37. American Nuclear Society, ANSI/ANS 56.8-2002, Containment System Leakage Testing Requirements, LaGrange Park, Illinois, November 2002
: 38. ASME Boiler & Pressure Vessel Code, Section XI, Subsection IWE, Requirements for Class MC and Metallic Liners of Class CC Components of Light-Water Cooled Plants, 2013 Edition with no addenda
: 39. ASME B&PV Code, Section XI, Subsection IWL, Requirements for Class CC Concrete Components of Light-Water Cooled Plant, 2013 Edition with no addenda
: 40. ASTM D 1186-01, Standard Test Methods for Nondestructive Measurement of Dry Film Thickness of Nonmagnetic Coatings Applied to a Ferrous Base
: 41. American Society of Mechanical Engineers, Standard for Probabilistic Risk Assessment for Nuclear Power Plant Applications, ASME RA-S-2002, Addenda RA-Sb-2005, December 2005.
: 42. U.S. Nuclear Regulatory Commission, Regulatory Guide 1.200, Revision 1, An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities, January 2007 (ML070240001).
: 43. SSPC-PA 2, Measurement of Dry Coating Thickness with Magnetic Gages
: 44. Salem Generating Station PRA Notebook - Quantification Notebook, SA-PRA-014, Revision 3, October 2022.
: 45. Salem Generating Station Probabilistic Risk Analysis - Level 2 Analysis Notebook, SA-PRA-015, Revision 4, September 2022.
: 46. Westinghouse, RG 1.200 PRA Peer Review Against the ASME PRA Standard Requirements for the Salem Generating Station, Units 1 and 2 Probabilistic Risk Assessment, LTR-RAM-II-09-001, June 2009.
: 47. PWR Owners Group, PWROG LERF/ Simplified Level 2 PRA Methodology, PWROG-21024-P Revision 0-A, December 2021.
: 48. Letter to NRC from PSEG (S. LaBruna), Response to Request for Additional Information, Containment Monitor Channels, January 26, 1990 (ML18094B277) 134
: 49. Jensen Hughes, PRA Finding-Level Fact and Observation Independent Assessment &
Focused Scope Peer Review, 003059-RPT-02, Revision 0.
: 50. RG 1.177, An Approach for Plant-Specific, Risk-Informed Decision making: Technical Specifications, (ML20164A034)
: 51. Salem Generating Station Fire Probabilistic Risk Assessment, Summary, Quantification, and Uncertainty Notebook, SA-PRA-104, Rev. 0, October 2022.
: 52. PWROG, Peer Review of the Salem Units 1 and 2 Fire Probabilistic Risk Assessment, PWROG-22025-P, Revision 0, January 2023.
135

LR-N23-0005                                                                       LAR S22-04 Attachment 1 Mark-up of Proposed Technical Specification Pages The following Technical Specifications pages for Renewed Facility Operating License DPR-70 are affected by this change request:
Technical Specification                                                  Page 6.8.4.f, Primary Containment Leakage Rate Testing Program                6-19 The following Technical Specifications pages for Renewed Facility Operating License DPR-75 are affected by this change request:
Technical Specification                                                  Page 6.8.4.f, Primary Containment Leakage Rate Testing Program                6-19 1

ADMINISTRATIVE CONTROLS (vi)    A procedure identifying (a) the authority responsible for the interpretation of the data, and (b) the sequence and timing of administrative events required to initiate corrective action.
: d. Backup Method for Determining Subcooling Margin A program which will ensure the capability to accurately monitor the Reactor Coolant System Subcooling Margin. This program shall include the following:
(i)     Training of personnel, and (ii)    Procedures for monitoring
: e. Deleted 6.8.4.f. Primary Containment Leakage Rate Testing Program A program shall be established, implemented, and maintained to comply with the leakage rate testing of the containment as required by 10CFR50.54( o) and NEI 94-01, 10CFR50, Appendix J, Option B, as modified by approved exemptions. This "Industry               program shall be in accordance with the guidelines contained in Regulatory Guideline for           Guide 1.163, "Performance-Based Containment Leak-Test Program", dated Implementing            September 1995, as modified by the following exception to NEI 94-01, Rev. 0, Performance-            "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Based Option of         Appendix J":
10 CFR 50, Appendix J,"            a.      Section 9.2.3: The first Type A test performed after May 7, 2001, shall be performed no later than May 7, 2016.
Revision 3-A, dated July 2012,        The peak calculated containment internal pressure for the design basis loss of and the                 coolant accident, Pa, is 47.0 psig.
conditions and limitations             The maximum allowable containment leakage rate, La, at P8 , shall be 0.1% of specified in NEI        primary containment air weight per day.
94-01, Revision 2-Leakage Rate Acceptance Criteria are:
A, dated October 2008.                   a.      Primary containment leakage rate acceptance criterion is less than or equal to 1.0 L8 . During the first unit startup SALEM - UNIT 1                                6-19                         Amendment No. 296

Provided for Information Only ADMINISTRATIVE CONTROLS following testing in accordance with this program, the leakage rate acceptance criteria are less than or equal to 0.6 La for Type B and Type C tests and less than or equal to 0.75 La for Type A tests;
: b.      Air lock testing acceptance criteria are:
: 1)      Overall air lock leakage rate is less than or equal to 0.05 La when tested at greater than or equal to Pa,
: 2)      Seal leakage rate less than or equal to 0.01 La per hour when the gap between the door seals is pressurized to 10.0 psig.
Test frequencies and applicable extensions will be controlled by the Primary Containment Leakage Rate Testing Program.
The provisions of Specification 4.0.3 will be applied to the Primary Containment Leakage Rate Testing Program.
6.8.4.g         Radioactive Effluent Controls Program A program shall be provided conforming with 10 CFR 50.36a for the control of radioactive effluents and for maintaining the doses to the members of the public from radioactive effluents as low as reasonable achievable. The program (1) shall be contained in the ODCM, (2) shall be implemented by operating procedures, and (3) shall include remedial actions to be taken whenever the program limits are exceeded. The program shall include the following elements:
: 1) Limitations on the operability of radioactive liquid and gaseous monitoring instrumentation including surveillance tests and setpoint determination in accordance with the methodology in the ODCM,
: 2) Limitations on the concentrations of radioactive material released in liquid effluents to unrestricted areas conforming to 10 CFR 20, Appendix B, Table II, Column 2,
: 3) Monitoring, sampling, and analysis of radioactive liquid and gaseous effluents in accordance with 10 CFR 20.106 and with the methodology and parameters in the ODCM,
: 4) Limitations on the annual and quarterly doses or dose commitment to a member of the public from radioactive materials in liquid effluents released from each unit to unrestricted areas conforming to Appendix I to 10 CFR Part 50,
: 5) Determination of cumulative and projected dose contributions from radioactive effluents for the current calendar quarter and current calendar year in accordance with the methodology and parameters in the ODCM at least every 31 days.
: 6) Limitations on the operability and use of the liquid and gaseous effluent treatment systems to ensure that the appropriate portions of these systems are used to reduce releases of radioactivity when the projected doses in a 92-day period would exceed a suitable fraction of the guidelines for the annual dose or dose commitment conforming to Appendix I to 10 CFR Part 50, SALEM - UNIT 1                                   6-19a                          Amendment No. 342

                                    ~
ADMINISTRATIVE CONTROLS (vi)   A procedure identifying (a) the authority responsible for the interPtetetton ot the date, end lb) the sequence end timing of administrative events required to initiate corrective action.
: d. Backup Method !or Petermininp Subcoolinp Merqin A program which will en1ure the capability to accurately monitor the Reactor Coolant SYstem Subcooling Margin. This program shall include the following:
lil    Training ot personnel, and Iii>   Procedures tor monitoring
: e. Deleted 6.8.4.f. Primary Containment Leakaqe Rate Testinp Propram A program ehall be established, implemented, end maintained to compl~
with the leakage rate telting of the containment as required by 10CFRSO.S4(o) and 10CFRSO. Appendix J, Option a. as modified by approved exemptions. This program shall be in accordance with the guidelines contained in Regulatory Guide l.l6J, "Performance*Based Containment Lea~-Teet Program*, dated Sept.mber 1995, as modified by the following except1on:
NEI 94-01, "Industry
: a. N!I 94*01-1995, Section 9.2.3: The tirst Type A test performed after Guideline for              March 24, 1992 shell be performed no later then March 24, ~007.
Implementing Performance-Based     The peak calculated containment internal pressure for the design basis loss of coolant accident, P0
* is 47.0 psig.
Option of 10 CFR 50, Appendix J,"          The maximum allowable containment leakage rata. L*. at P0
* shall be O.l%
Revision 3-A, dated   ot primary containment   ei~ weight per day.
July 2012, and the    Leakage Rete Acceptance   C~iteria  are:
conditions and limitations specified a. Primary containmant leakage rate aeceptence criterion i; less than in NEI 94-01,              or equal to 1.0 ~ *. During the first unit startup following testing in accordance with thi; program, the leakage rete Revision 2-A, dated October 2008.
SALEM
* UNIT 2                         6-19                    Amendment No. 7.35

Provided for Information Only ADMINISTRATIVE CONTROLS acceptance criteria are less than or equal to 0.6 La for Type B and Type C tests and less than or equal to 0.75 La for Type A tests;
: b.      Air lock testing acceptance criteria are:
: 1)      Overall air lock leakage rate is less than or equal to 0.05 La when tested at greater than or equal to Pa,
: 2)      Seal leakage rate less than or equal to 0.01 La per hour when the gap between the door seals is pressurized to 10.0 psig.
Test frequencies and applicable extensions will be controlled by the Primary Containment Leakage Rate Testing Program.
The provisions of Specification 4.0.3 will be applied to the Primary Containment Leakage Rate Testing Program.
6.8.4.g         Radioactive Effluent Controls Program A program shall be provided conforming with 10 CFR 50.36a for the control of radioactive effluents and for maintaining the doses to the members of the public from radioactive effluents as low as reasonable achievable. The program (1) shall be contained in the ODCM, (2) shall be implemented by operating procedures, and (3) shall include remedial actions to be taken whenever the program limits are exceeded. The program shall include the following elements:
: 1) Limitations on the operability of radioactive liquid and gaseous monitoring instrumentation including surveillance tests and setpoint determination in accordance with the methodology in the ODCM,
: 2) Limitations on the concentrations of radioactive material released in liquid effluents to unrestricted areas conforming to 10 CFR 20, Appendix B, Table II, Column 2,
: 3) Monitoring, sampling, and analysis of radioactive liquid and gaseous effluents in accordance with 10 CFR 20.106 and with the methodology and parameters in the ODCM,
: 4) Limitations on the annual and quarterly doses or dose commitment to a member of the public from radioactive materials in liquid effluents released from each unit to unrestricted areas conforming to Appendix I to 10 CFR Part 50,
: 5) Determination of cumulative and projected dose contributions from radioactive effluents for the current calendar quarter and current calendar year in accordance with the methodology and parameters in the ODCM at least every 31 days.
: 6) Limitations on the operability and use of the liquid and gaseous effluent treatment systems to ensure that the appropriate portions of these systems are used to reduce releases of radioactivity when the projected doses in a 92-day period would exceed a suitable fraction of the guidelines for the annual dose or dose commitment conforming to Appendix I to 10 CFR Part 50, SALEM - UNIT 2                                   6-19a                          Amendment No. 323

LR-N23-0005                                                            LAR S22-04 Attachment 2 Risk Assessment for the Type A Permanent Extension Request 1

RM DOCUMENTATION NO:                      SA-LAR-021             REV: 1          PAGE NO.      i STATION: Salem Generating Station UNIT(S) AFFECTED: 1 & 2 TITLE: Risk Assessment to Support ILRT (Type A) Interval Extension Request

==SUMMARY==
: The purpose of this revision is to clarify discussion in Section 4.2 and to correct typographical errors in the references for SA-PRA-014 in Section 8 and Appendix A.
This is a Category 1 document. IAW ER-AA-600-1012 requires approval of the Corporate Engineering Programs Manager.
[ ] Review required after periodic Update
[ X ] Internal RM Documentation                                 [ ] External RM Documentation Electronic Calculation Data Files:
Microsoft Excel File Salem ILRT-2022-111122.xls, 11/11/2022, 10:27 AM, 470 KB Method of Review:       [ X ] Detailed    [ ] Alternate  [ ] Review of External Document This RM documentation supersedes: _________________N/A__________in its entirety.
Prepared by:                  Brian Burgio         /                               /   03/16/2023 Print                          Sign                      Date Accepted by:                 Gary DeMoss           /  80126544 Operation 0610      /   03/16/2023 Print                          Sign                      Date Approved by:                   Ali Fakhar             80126544 Operation 0610          03/16/2023 Print                          Sign                      Date

REVISION 

==SUMMARY==

REVISION      DATE                          

==SUMMARY==

0     January 2023 Original Issue Revision 1 was issued to correct an editorial 1      March 2023  error in Section 8, as well as to make an editorial wording change in Section 4.2.

Risk Impact Assessment of Extending Salem ILRT Interval TABLE OF CONTENTS Section                                                                                                                Page 1.0   PURPOSE OF ANALYSIS................................................................................. 1-1 1.1  Purpose .................................................................................................. 1-1 1.2  Background............................................................................................. 1-1 1.3  Acceptance Criteria ................................................................................ 1-3 2.0   METHODOLOGY .............................................................................................. 2-1 3.0   GROUND RULES.............................................................................................. 3-1 4.0   INPUTS ............................................................................................................. 4-1 4.1  General Resources Available ................................................................. 4-1 4.2  Plant-Specific Inputs ............................................................................... 4-7 4.3  Impact of Extension on Detection of Component Failures That Lead to Leakage (Small and Large)................................................................... 4-14 4.4  Impact of Extension on Detection of Steel Liner Corrosion that Leads to Leakage ................................................................................................ 4-16 5.0   RESULTS .......................................................................................................... 5-1 5.1  Step 1 - Quantify the Base-Line Risk in Terms of Frequency per Reactor Year ........................................................................................................ 5-3 5.2  Step 2 - Develop Plant-Specific Person-Rem Dose (Population Dose) per Reactor Year........................................................................................... 5-8 5.3  Step 3 - Evaluate Risk Impact of Extending Type A Test Interval From 10-to-15 Years ........................................................................................... 5-12 5.4  Step 4 - Determine the Change in Risk in Terms of Large Early Release Frequency ............................................................................................. 5-17 5.5  Step 5 - Determine the Impact on the Conditional Containment Failure Probability ............................................................................................. 5-18 5.6  Summary of Internal Events Results ..................................................... 5-18 5.7  External Events Contribution ................................................................ 5-20 5.8  defense-in-depth impact ....................................................................... 5-23 6.0   SENSITIVITIES ................................................................................................. 6-1 6.1  Sensitivity to Corrosion Impact Assumptions .......................................... 6-1 ii                                                     SA-LAR-021

Risk Impact Assessment of Extending Salem ILRT Interval 6.2   EPRI Expert Elicitation Sensitivity ........................................................... 6-3

==7.0 CONCLUSION==
S ................................................................................................ 7-1

==8.0 REFERENCES==
 .................................................................................................. 8-1 APPENDIX A PRA TECHNICAL ADEQUACY iii                                                     SA-LAR-021

Risk Impact Assessment of Extending Salem ILRT Interval List of Tables Table 4.1-1 EPRI Containment Failure Classifications [22] .......................................... 4-6 Table 4.2-2 Calculation of SGS Population Dose Risk at 50 Miles ............................ 4-13 Table 4.4-1 Steel Liner Corrosion Base Case ............................................................ 4-18 Table 5.0-1 EPRI Accident Class Definitions ............................................................... 5-2 Table 5.1-1 Calculation of SGS Population Dose RiSk at 50 Miles .............................. 5-3 Table 5.1-2 Containment Release Class Dose ............................................................ 5-4 Table 5.1-3 Accident Class 7 Failure Frequencies And Population Doses (Salem Base Case Level 2 Model) .............................................................................................. 5-7 Table 5.1-4 Radionuclide Release Frequencies As A Function Of Accident Class (Salem Base Case)................................................................................................ 5-8 Table 5.2-1 Salem 50-mile Population Dose Estimates ............................................... 5-9 Table 5.2-2 Salem Annual Dose As A Function Of Accident Class; Characteristic Of Conditions For ILRT Required 3/10 Years ........................................................... 5-10 Table 5.3-1 Salem Annual Dose As A Function Of Accident Class; Characteristic Of Conditions For ILRT Required 1/10 Years ........................................................... 5-13 Table 5.3-2 Salem Annual Dose As A Function Of Accident Class; Characteristic Of Conditions For ILRT Required 1/15 Years ........................................................... 5-15 Table 5.6-1 Salem ILRT Cases: Base, 3 to 10, and 3 to 15 Yr Extensions ............... 5-19 TABLE 5.7-1 Other external events Contributors ...................................................... 5-21 Table 5.7-2 class 3b (LERF) as a function of ILRT Frequency for Internal and External Events.................................................................................................................. 5-22 Table 5.7-3 Impact of 15-yr ILRT Extension on LERF (3b) ........................................ 5-23 Table 6.1-1 Steel Liner Corrosion Sensitivity Cases .................................................... 6-2 Table 6.2-1 EPRI Expert Elicitation Results ................................................................. 6-4 Table 6.2-2 Salem ILRT Cases: Base, 3 to 10, and 3 to 15 Yr Extensions (Based on EPRI [22] Expert Elicitation Leakage Probabilities) ............................................... 6-5 Table A-1 Summary of Findings Applicable to the Unit 1 Salem Fire PRA Model ........A-8 iv                                                      SA-LAR-021

Risk Impact Assessment of Extending Salem ILRT Interval 1.0    PURPOSE OF ANALYSIS 1.1    PURPOSE The purpose of this analysis is to provide a risk assessment of permanently extending the Salem Generating Station, Units 1 & 2 containment Type A integrated leak rate test (ILRT) interval from ten years to fifteen years. The risk assessment follows the guidelines from NEI 94-01 Revision 3-A [1], the NEI Interim Guidance for Performing Risk Impact Assessments In Support of One-Time Extensions for Containment Integrated Leakage Rate Test Surveillance Intervals [3, 21], the NRC regulatory guidance on the use of Probabilistic Risk Assessment (PRA) as stated in Regulatory Guide (RG) 1.200 [25] as applied to ILRT interval extensions, risk insights in support of a request for a plants licensing basis as outlined in RG 1.174 [4], the methodology used for Calvert Cliffs to estimate the likelihood and risk implications of corrosion-induced leakage of steel liners going undetected during the extended test interval [19], and the methodology used in EPRI 1018243, Revision 2-A of EPRI 1009325 [22].

==1.2    BACKGROUND==

Revisions to 10CFR50, Appendix J (Option B) allow individual plants to extend the ILRT Type A surveillance testing requirements from three-in-ten years to at least once per ten years. The revised Type A frequency is based on an acceptable performance history defined as two consecutive periodic Type A tests at least 24 months apart in which the calculated performance leakage was less than limiting containment leakage of 1.0La (allowable leakage).
The basis for the current 10-year test interval is provided in Section 11.0 of NEI 94-01, Revision 0, and was established in 1995 during development of the performance-based Option B to Appendix J.          Section 11.0 of NEI 94-01 states that NUREG-1493, Performance-Based Containment Leak Test Program, September 1995 [5], provides the technical basis to support rulemaking to revise leakage rate testing requirements contained in Option B to Appendix J. The basis consisted of qualitative and quantitative assessments of the risk impact (in terms of increased public dose) associated with a 1-1                                 SA-LAR-021

Risk Impact Assessment of Extending Salem ILRT Interval range of extended leakage rate test intervals. To supplement the NRCs rulemaking basis, NEI undertook a similar study. The results of that study are documented in Electric Power Research Institute (EPRI) Research Project Report TR-104285 [2].
The NRC report on performance-based leak testing, NUREG-1493, analyzed the effects of containment leakage on the health and safety of the public and the benefits realized from the containment leak rate testing. In that analysis, it was determined that for a representative PWR plant (i.e., Surry) that containment isolation failures contribute less than 0.1 percent to the latent risks from reactor accidents. Consequently, it is desirable to show that extending the ILRT interval will not lead to a substantial increase in risk from containment isolation failures for Salem Units 1&2.
NEI 94-01 Revision 3-A [1] supports using EPRI Report No. 1009325 Revision 2-A (EPRI 1018243 [22]). The guidance provided in Appendix H of EPRI 1018243 builds on the earlier EPRI TR-104285 [2] risk assessment methodology. This more recent methodology is followed to determine the appropriate risk information for use in evaluating the impact of the proposed ILRT changes.
It is also noted that containment leak-tight integrity is also verified through periodic in-service inspections conducted in accordance with the requirements of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code Section XI.
More specifically, Subsection IWE provides the rules and requirements for in-service inspection of Class MC pressure-retaining components and their integral attachments, and of metallic shell and penetration liners of Class CC pressure-retaining components and their integral attachments in light-water cooled plants. Furthermore, NRC regulations 10 CFR 50.55a(b)(2)(ix)(E) require licensees to conduct visual inspections of the accessible areas of the interior of the containment. The associated change to NEI 94-01 requires that visual examinations be conducted during at least three other outages, and in the outage during which the ILRT is being conducted. These requirements are not changed as a result of the extended ILRT interval. In addition, Appendix J, Type B local leak tests performed to verify the leak-tight integrity of containment penetration bellows, 1-2                                   SA-LAR-021

Risk Impact Assessment of Extending Salem ILRT Interval airlocks, seals, and gaskets are also not affected by the change to the Type A test frequency.
1.3    ACCEPTANCE CRITERIA The acceptance guidelines in RG 1.174 [4] are used to assess the acceptability of this permanent extension of the Type A test interval beyond that established during the Option B rulemaking of Appendix J. RG 1.174 defines very small changes in the risk-acceptance guidelines as increases in core damage frequency (CDF) less than 10 -6 per reactor year and increases in large early release frequency (LERF) less than 10-7 per reactor year. Since the Type A test does not impact CDF for Salem Units 1 & 2, the relevant criterion is the change in LERF. RG 1.174 also defines small changes in LERF as below 10-6 per reactor year provided that the total from all contributors (including external events) can be reasonably shown to be less than 10-5 per reactor year. RG 1.174 discusses defense-in-depth and encourages the use of risk analysis techniques to help ensure and show that key principles, such as the defense-in-depth philosophy, are met.
Therefore, the increase in the conditional containment failure probability (CCFP) that helps to ensure that the defense-in-depth philosophy is maintained is also calculated.
Regarding the CCFP, the EPRI guidance [22] notes that changes of up to 1.1% have been accepted by the NRC for the one-time requests for extension of ILRT intervals. In context, it is noted that a CCFP of 10% has been approved for application to evolutionary light water designs. Given these perspectives, a change in the CCFP of up to 1.5% is assumed to be small.
In addition, the total annual risk (person-rem/yr population dose) is examined to demonstrate the relative change in this parameter. While no acceptance guidelines for population dose are published, examinations of NUREG-1493 [5] and NRC Safety Evaluations (SEs) for one-time interval extensions (summarized in Appendix G of the EPRI guidance [22]) indicate a range of incremental increases in population dose that have been accepted by the NRC. The range of incremental population dose increase is from <0.01 to 0.2 person-rem/year and/or 0.002% to 0.46% of the total accident dose
[22]. The total doses for the spectrum of all accidents (NUREG-1493 [5] Figure 7-2) result 1-3                                SA-LAR-021

Risk Impact Assessment of Extending Salem ILRT Interval in health effects that are at least two orders of magnitude less than the NRC Safety Goal Risk. Given these perspectives, a very small population dose is defined as an increase from the baseline interval (3 tests per 10 years) dose of <1.0 person-rem per year or 1%
of the total baseline dose, whichever is less restrictive for the risk impact assessment of the proposed extended ILRT interval [22].
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Risk Impact Assessment of Extending Salem ILRT Interval 2.0    METHODOLOGY A simplified bounding analysis approach consistent with the EPRI approach [22] is used for evaluating the change in risk associated with increasing the test interval to fifteen years. The approach is consistent with that presented in EPRI TR-104285 [2], NUREG-1493 [5] and the Calvert Cliffs liner corrosion analysis [19]. The analysis uses results from a Level 2 analysis of core damage scenarios from the current Salem Units 1 & 2 PRA model and the subsequent containment responses for the various fission product release categories including no or negligible release.
The six general steps of this assessment are as follows:
: 1. Quantify the baseline risk in terms of the frequency of events (per reactor year) for each of the eight containment release scenario types identified in the EPRI report.
: 2. Develop plant-specific person-rem (population dose) per reactor year for each of the eight containment release scenario types from plant specific consequence analyses.
: 3. Evaluate the risk impact (i.e., the change in containment release scenario type frequency and population dose) of extending the ILRT interval to fifteen years.
: 4. Determine the change in risk in terms of Large Early Release Frequency (LERF) in accordance with RG 1.174 [4] and compare this change with the acceptance guidelines of RG 1.174.
: 5. Determine the impact on the Conditional Containment Failure Probability (CCFP)
: 6. Evaluate the sensitivity of the results to assumptions in the liner corrosion analysis, external events and to the fractional contribution of increased large isolation failures (due to liner breach) to LERF.
This approach is based on the information and approaches contained in the previously mentioned studies. Furthermore,
* Consistent with the other industry containment leak risk assessments, the Salem assessment uses LERF and delta LERF in accordance with the risk acceptance guidance of RG 1.174 [4]. Changes in population dose and the conditional containment failure probability (CCFP) are also considered to show that defense-in-depth and the balance of prevention and mitigation is preserved.
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Risk Impact Assessment of Extending Salem ILRT Interval
* This evaluation for Salem uses ground rules and methods to calculate changes in risk metrics that are similar to those used in the EPRI approach [22].
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Risk Impact Assessment of Extending Salem ILRT Interval 3.0    GROUND RULES The following ground rules are used in the analysis:
* The Salem Unit 1 Level 1 and Level 2 Internal Events PRA models [16, 17] provide representative results for this ILRT risk assessment. The Unit 1 model adequately represents Unit 2, as discussed in Section 4.2.
The Internal Events PRA results used include internal flood risk. The technical acceptability of the PRA is consistent with the requirements of Regulatory Guide 1.200 [25], as detailed in Appendix A.
* It is appropriate to use the Salem Internal Events PRA model as a gauge to effectively describe the risk change attributable to the ILRT extension.
Since containment overpressure is not required in support of ECCS performance to mitigate design basis accidents for the Salem plants, the ILRT extension does not impact CDF. Therefore, the relevant risk metric is LERF. An analysis is performed in Section 5.7 to show the effect of including external event risk upon the ILRT extension. Internal fire risk has been assessed using the internal fire model [24] and other external hazards have been accounted for based on the available information from the Salem IPEEE [18]. It should be noted that if the fire risk results from the IPEEE were utilized as was done for the prior one-time ILRT extension assessments for Salem [23, 30] the results would also be acceptable. However, this assessment is based on the most recent fire risk assessment [24].
* Dose results for the ILRT risk assessment can be characterized by information provided in the Salem license renewal Severe Accident Mitigations Alternatives (SAMA) analysis submitted to the NRC in 2009
[9] and approved by the NRC as documented in NUREG-1437 Supplement 45 [26].
* Accident classes describing radionuclide release end states are defined consistent with EPRI methodology [2] and are summarized in Section 4.2.
* The representative containment leakage for Class 1 sequences is 1La.
Class 3 accounts for increased leakage due to Type A inspection failures.
* The representative containment leakage for Class 3a sequences is 10La, based on the previously approved methodology performed for Indian Point Unit 3 [6, 7].
* The representative containment leakage for Class 3b sequences is 100La, based on the recommendations in the latest EPRI report [22].
* The Class 3b can be very conservatively categorized as LERF based on the previously approved methodology [6, 7]. The Class 3b category 3-1                                  SA-LAR-021

Risk Impact Assessment of Extending Salem ILRT Interval increase is used as a surrogate for LERF in this application even though the releases associated with a 100La release would not necessarily be consistent with a Large release for Salem.
* The impact on population doses from containment bypass scenarios is not altered by the proposed ILRT extension but is accounted for in the EPRI methodology as a separate entry for comparison purposes. Since the containment bypass contribution to population dose is fixed, no changes to the conclusions from this analysis will result from this separate categorization.
* The reduction in ILRT frequency does not impact the reliability of containment isolation valves to close in response to a containment isolation signal.
* The use of the Salem SAMA dose results, which are based on year 2040 population estimates is adequate for this analysis.
* An evaluation of the risk impact of the ILRT on shutdown risk is qualitatively addressed in Section 4.1 using the generic results from EPRI TR-105189 [8].
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Risk Impact Assessment of Extending Salem ILRT Interval 4.0     INPUTS This section summarizes the general resources available as input (Section 4.1) and the plant specific resources required (Section 4.2).
4.1     GENERAL RESOURCES AVAILABLE Various industry studies on containment leakage risk assessment are briefly summarized here:
: 1. NUREG/CR-3539 [10]
: 2. NUREG/CR-4220 [11]
: 3. NUREG-1273 [12]
: 4. NUREG/CR-4330 [13]
: 5. EPRI TR-105189 [8]
: 6. NUREG-1493 [5]
: 7. EPRI TR-104285 [2]
: 8. NEI Interim Guidance [3, 21]
: 9. Calvert Cliffs liner corrosion analysis [19]
: 10. EPRI 1018243 [22]
The first study is applicable because it provides one basis for the threshold that could be used in the Level 2 PRA for the size of containment leakage that is considered significant and to be included in the model. The second study is applicable because it provides a basis of the probability for significant pre-existing containment leakage at the time of a core damage accident. The third study is applicable because it is a subsequent study to NUREG/CR-4220 [11] that undertook a more extensive evaluation of the same database.
The fourth study provides an assessment of the impact of different containment leakage rates on plant risk. The fifth study provides an assessment of the impact on shutdown risk from ILRT test interval extension. The sixth study is the NRCs cost-benefit analysis of various alternative approaches regarding extending the test intervals and increasing the allowable leakage rates for containment integrated and local leak rate tests. The seventh study is an EPRI study of the impact of extending ILRT and local leak rate test (LLRT) intervals on at-power public risk. The eighth study includes the NEI recommended 4-1                                 SA-LAR-021

Risk Impact Assessment of Extending Salem ILRT Interval methodology for evaluating the risk associated with obtaining a one-time extension of the ILRT interval. The ninth study addresses the impact of age-related degradation of the containment liners on ILRT evaluations. Finally, the last study complements the previous EPRI report [2], integrates the NEI interim guidance, and provides the results of an expert elicitation process to determine the relationship between pre-existing containment leakage probability and magnitude.
NUREG/CR-3539 [10]
Oak Ridge National Laboratory (ORNL) documented a study of the impact of containment leak rates on public risk in NUREG/CR-3539. This study uses information from WASH-1400 [15] as the basis for its risk sensitivity calculations. ORNL concluded that the impact of leakage rates on LWR accident risks is relatively small.
NUREG/CR-4220 [11]
NUREG/CR-4220 is a study performed by Pacific Northwest Laboratories for the NRC in 1985. The study reviewed over two thousand LERs, ILRT reports and other related records to calculate the unavailability of containment due to leakage. It assessed the large containment leak probability to be in the range of 1E-3 to 1E-2, with 5E-3 identified as the point estimate based on 4 events in 740 reactor years and conservatively assuming a one-year duration for each event.
NUREG-1273 [12]
A subsequent NRC study, NUREG-1273, performed a more extensive evaluation of the NUREG/CR-4220 [11] database. This assessment noted that about one-third of the reported events were leakages that were immediately detected and corrected.                 In addition, this study noted that local leak rate tests can detect essentially all potential degradations of the containment isolation system.
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Risk Impact Assessment of Extending Salem ILRT Interval NUREG/CR-4330 [13]
NUREG/CR-4330 is a study that examined the risk impacts associated with increasing the allowable containment leakage rates. The details of this report have no direct impact on the modeling approach of the ILRT test interval extension, as NUREG/CR-4330 focuses on leakage rate and the ILRT test interval extension study focuses on the frequency of testing intervals. However, the general conclusions of NUREG/CR-4330 are consistent with NUREG/CR-3539 [10] and other similar containment leakage risk studies:
the effect of containment leakage on overall accident risk is small since risk is dominated by accident sequences that result in failure or bypass of containment.
EPRI TR-105189 [8]
The EPRI study TR-105189 is useful to the ILRT test interval extension risk assessment because this EPRI study provides insight regarding the impact of containment testing on shutdown risk. This study performed a quantitative evaluation (using the EPRI ORAM software) for two reference plants (a BWR-4 and a PWR) of the impact of extending ILRT and LLRT test intervals on shutdown risk.
The result of the study concluded that a small but measurable safety benefit (shutdown CDF reduced by 1E-8/yr to 1E-7/yr) is realized from extending the test intervals from 3-in-10 years to 1-in-10 years. Extending the test interval to 1-in-15 years would further increase this benefit.
NUREG-1493 [5]
NUREG-1493 is the NRCs cost-benefit analysis for proposed alternatives to reduce containment leakage testing intervals and/or relax allowable leakage rates. The NRC conclusions are consistent with other similar containment leakage risk studies:
* Reduction in ILRT frequency from 3-in-10 years to 1-in-20 years results in an imperceptible increase in risk.
* Given the insensitivity of risk to the containment leak rate and the small fraction of leak paths detected solely by Type A testing, increasing the 4-3                                SA-LAR-021

Risk Impact Assessment of Extending Salem ILRT Interval interval between integrated leak rate tests is possible with minimal impact on public risk.
EPRI TR-104285 [2]
Extending the risk assessment impact beyond shutdown (the earlier EPRI TR-105189 [8]
study), the EPRI TR-104285 study is a quantitative evaluation of the impact of extending ILRT and LLRT intervals on at-power public risk. This study combined IPE Level 2 models with NUREG-1150 [14] Level 3 population dose models to perform the analysis. The study also used the approach of NUREG-1493 [5] in calculating the increase in pre-existing leakage probability due to extending the ILRT and LLRT intervals.
EPRI TR-104285 used a simplified Containment Event Tree to subdivide representative core damage sequences into eight categories of containment response to a core damage accident:
: 1.      Containment intact and isolated
: 2.      Containment isolation failures due to support system or active failures
: 3.      Type A (ILRT) related containment isolation failures
: 4.      Type B (LLRT) related containment isolation failures
: 5.      Type C (LLRT) related containment isolation failures
: 6.      Other penetration related containment isolation failures
: 7.      Containment failure due to core damage accident phenomena
: 8.      Containment bypass Consistent with the other containment leakage risk assessment studies, this study concluded:
These study results show that the proposed CLRT [containment leak rate tests] frequency changes would have a minimal safety impact. The change in risk determined by the analyses is small in both absolute and relative terms. For example, for the PWR analyzed, the change is about 0.02 person-rem per year...
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Risk Impact Assessment of Extending Salem ILRT Interval NEI Interim Guidance [3, 21]
NEI Interim Guidance for Performing Risk Impact Assessments in Support of One-Time Extensions of Containment Integrated Leakage Rate Test Surveillance Intervals [3] was developed to provide utilities with revised guidance regarding licensing submittals.
Additional information from NEI on the Interim Guidance was supplied in Reference [21].
The NEI Interim Guidance builds on the earlier EPRI risk impact assessment methodology [2] and the NRC performance-based containment leakage test program [5],
and considers approaches utilized in various submittals, including Indian Point 3 [6] (and associated NRC SER [7]) and Crystal River [20]. The NEI guidance included changes in the following areas of the previous EPRI guidance [2]:
* Impact of extending surveillance intervals on dose
* Method used to calculate the frequencies of leakages detectable only by ILRTs
* Provisions for using NUREG-1150 [14] dose calculations to support the population dose determination.
Calvert Cliffs Liner Corrosion Analysis [19]
This submittal to the NRC describes a method for determining the change in likelihood, due to extending the ILRT, of detecting liner corrosion, and the corresponding change in risk. The methodology was developed for Calvert Cliffs in response to a request for additional information regarding how the potential leakage due to age-related degradation mechanisms were factored into the risk assessment for the ILRT one-time extension. The Calvert Cliffs analysis was performed for a concrete cylinder and dome and a concrete basemat, each with a steel liner. Salem has a similar type of containment.
EPRI 1018243 [22]
This report presents a risk impact assessment for extending ILRT intervals to 15 years on a permanent basis and is consistent in nature with the NEI interim guidance. This newer EPRI guidance complements the previous EPRI TR-104285 [2] report. The earlier report considered changes to local leak rate testing intervals as well as changes to ILRT 4-5                                SA-LAR-021

Risk Impact Assessment of Extending Salem ILRT Interval intervals. The original EPRI assessment considered the change in risk based on population dose, whereas the revision considers dose as well as large early release frequency (LERF) and conditional containment failure probability (CCFP).
The risk impact assessment using the Jeffreys Non-Informative Prior statistical method is further supplemented with a sensitivity case using expert elicitation performed to address conservatisms. The expert elicitation is used to determine the relationship between pre-existing containment leakage probability and magnitude. The results of the expert elicitation process from this report are used as a separate sensitivity investigation for the Salem analysis presented in Section 6.2.
Table 4.1-1 defines the accident classes used in the ILRT extension evaluation, which is consistent with the EPRI methodology [22]. These containment failure classifications are used in this Salem analysis to determine the risk impact of extending the Containment Type A test interval as described in Section 5 of this report.
TABLE 4.1-1 EPRI CONTAINMENT FAILURE CLASSIFICATIONS [22]
CLASS                                                DESCRIPTION 1      Containment remains intact including accident sequences that do not lead to containment failure in the long term. The release of fission products (and attendant consequences) is determined by the maximum allowable leakage rate values La, under Appendix J for that plant 2      Containment isolation failures (as reported in the IPEs) include those accidents in which there is a failure to isolate the containment.
3      Independent (or random) isolation failures include those accidents in which the pre-existing isolation failure to seal (i.e. provide a leak-tight containment) is not dependent on the sequence in progress.
4      Independent (or random) isolation failures include those accidents in which the pre-existing isolation failure to seal is not dependent on the sequence in progress. This class is similar to Class 3 isolation failures, but is applicable to sequences involving Type B tests and their potential failures. These are the Type B-tested components that have isolated but exhibit excessive leakage.
5      Independent (or random) isolation failures include those accidents in which the pre-existing isolation failure to seal is not dependent on the sequence in progress. This class is similar to Class 4 isolation failures, but is applicable to sequences involving Type C tests and their potential failures.
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Risk Impact Assessment of Extending Salem ILRT Interval TABLE 4.1-1 EPRI CONTAINMENT FAILURE CLASSIFICATIONS [22]
CLASS                                           DESCRIPTION 6      Containment isolation failures include those leak paths covered in the plant test and maintenance requirements or verified per in service inspection and testing (ISI/IST) program.
7      Accidents involving containment failure induced by severe accident phenomena. Changes in Appendix J testing requirements do not impact these accidents.
8      Accidents in which the containment is bypassed (either as an initial condition or induced by phenomena) are included in Class 8. Changes in Appendix J testing requirements do not impact these accidents.
4.2     PLANT-SPECIFIC INPUTS For this Salem Unit 1 & 2 ILRT permanent interval extension risk assessment, Unit 1 specific information is used and includes the following:
* Level 1 Internal Events Model results [16]
* Level 2 Internal Events Model results [17]
* Population dose within a 50-mile radius [9]
* Fire PRA model results [24]
* IPEEE results [18]
The Salem Internal Events PRA model [16, 17] is a single unit model based mainly on the Salem Unit 1 plant configuration. The differences between the two units are such that use of a single unit model is adequate for the purposes of an average maintenance model since none of the plant differences are risk-significant. Similarly, the internal flooding risk between the two units is judged similar such that a separate Unit 2 flood model has not been developed. In this ILRT risk assessment, internal flooding risk is included in the internal events reported CDF and LERF.
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Risk Impact Assessment of Extending Salem ILRT Interval Salem Unit 1 Internal Events Level 1 PRA Model The current Level 1 PRA model is an event tree / linked fault tree model characteristic of the as-built, as-operated plant. The total internal events (i.e., full power random failures and internal flooding) core damage frequency (CDF) reported in the Salem Quantification Notebook is 2.99E-06/yr [16].
Salem Unit 1 Internal Events Level 2 PRA Model The Level 2 Model [17] that is used for Salem Unit 1 was developed to calculate the LERF contribution as well as the other release categories. The quantified Level 2 LERF gate is 1.20E-07/yr. Table 4.2-1 summarizes the pertinent Salem Unit 1 Level 2 results in terms of end-states. The total LERF in Table 4.2-1 based on summation of the individually quantified Level 2 end states is 1.34E-7/yr with a total release frequency of 3.65E-06/yr.
Note that the sum of the individual release categories (including intact containment) is approximately 22% higher than the Level 1 reported CDF (i.e., 2.99E-06/yr) due to the use of a lower truncation for the Level 2 model quantifications. The individual release category frequencies are conservatively utilized in this ILRT risk assessment to provide the necessary delineation for the EPRI methodology. The release categories are described after the table. The conservative treatment of total CDF used in this analysis will not significantly affect the overall results.
TABLE 4.2-1 RESULTS FOR DETAILED RELEASE CATEGORIES RELEASE CATEGORY           EPRI CLASS      FREQUENCY        CONTRIBUTION INTACT                              1          2.56E-06            70%
LATE-BMMT-AFW                       7          3.62E-10           0.01%
LATE-BMMT-NOAFW                     7          4.35E-08            1.2%
LATE-CHR-AFW                        7          4.29E-07            12%
LATE-CHR-NOAFW                      7          3.24E-07            8.9%
LERF-CFE                            7          3.15E-09            0.1%
LERF-CI                             2          7.62E-08            2.1%
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Risk Impact Assessment of Extending Salem ILRT Interval TABLE 4.2-1 RESULTS FOR DETAILED RELEASE CATEGORIES RELEASE CATEGORY         EPRI CLASS      FREQUENCY       CONTRIBUTION LERF-ISGTR                     8            2.22E-08           0.6%
LERF-ISLOCA                    8            1.39E-08           0.4%
LERF-SGTR-AFW                  8            1.60E-08           0.4%
LERF-SGTR-NOAFW                8            2.05E-09           0.1%
SERF                           8            1.58E-07           4.3%
Total (All Releases)           -            3.65E-06           100%
LERF only Total                -            1.34E-07           3.7%
Detailed Release Categories The detailed release categories consider the initiating event, availability of auxiliary feedwater during the event, and the ultimate containment failure or bypass mode (if applicable). Each Level 2 sequence is mapped into one of these detailed release categories.
INTACT This release category captures all of the INTACT sequences. Because the containment is intact, sequence variations have a negligible impact on the release characteristics.
Releases to the environment are via normal containment leakage.
LATE-BMMT-AFW This release category captures sequences that result in basemat melt-through with feedwater available to the steam generators. Because basemat melt-through takes many days to erode the thick basemat at Salem, containment failure is assumed at 100 hours in the fission product release determination.
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Risk Impact Assessment of Extending Salem ILRT Interval LATE-BMMT-NOAFW This release category captures sequences that result in basemat melt-through without feedwater available to the steam generators. Because basemat melt-through takes many days to erode the thick basemat at Salem, containment failure is assumed at 100 hours in the fission product release determination.
LATE-CHR-AFW This release category captures sequences that result in containment failure due to late overpressure with feedwater available to the steam generators.
LATE-CHR-NOAFW This release category captures sequences that result in containment failure due to late overpressure without feedwater available to the steam generators.
LERF-CFE This release category captures sequences that result in early containment failure due to steam explosion, hydrogen burn, and/or direct containment heating at the time of vessel breach.
LERF-CI This release category captures sequences that result in containment isolation failure due to either valve failure or excessive pre-existing containment leakage. Containment failure due to pre-existing leakage is assumed at the start time of the scenario for the release calculations.
LERF-ISGTR This release category captures sequences that result in either a pressure-induced or thermally-induced steam generator tube rupture that bypasses containment.
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Risk Impact Assessment of Extending Salem ILRT Interval LERF-ISLOCA This release category captures sequences caused by an unisolated ISLOCA. Those sequences from LERF with ISLOCA initiating events contribute to this category.
LERF-SGTR-AFW This release category captures sequences caused by a steam generator tube rupture that have successful operation of auxiliary feedwater. With or without isolation of the ruptured steam generator, SGTR sequences with core damage provide a direct release path to the environment through the steam generator relief valves. Those sequences from LERF with SGTR initiating events and successful AFW contribute to this category.
LERF-SGTR-NOAFW This release category captures sequences caused by a steam generator tube rupture that also have failed auxiliary feedwater. With or without isolation of the ruptured steam generator, SGTR sequences with core damage provide a direct release path to the environment through the steam generator relief valves. Those sequences from LERF with SGTR initiating events and failure of AFW contribute to this category.
SERF This release category captures one small early path in which releases to the environment bypass containment through the steam generators but are scrubbed by an overlying pool of water.
Population Dose Calculations The population dose is calculated using the Salem SAMA Evaluation for Units 1 & 2 submitted to the NRC in 2009 [9] (see Table E.3-7 of the Environmental Report) and approved via the NRC as documented in NUREG-1437 Supplement 45 [26]. These dose results are combined with the most recent Level 2 Analysis results [17] for this ILRT risk assessment.
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Risk Impact Assessment of Extending Salem ILRT Interval At the time of the SAMA evaluation, the Salem L2 did not include the small early release end state (SERF). For this ILRT risk assessment, a surrogate dose result from the SAMA evaluation was chosen for use. Given that the SERF release occurs in the early time frame, early releases are judged preferred to capture potential public impacts prior to the completion of emergency response actions (e.g., evacuation). Of the early release sequences available, the LERF-ISGTR release category has the lowest dose, and also reflects a similar mechanistic release (via the steam generator tube rupture). Therefore, the LERF-ISGTR was chosen as the surrogate dose for the SERF release category.
As part of the EPRI methodology, adjustments can be made to dose results to account for changes in reactor power level and population distribution. For the 2009 Salem one-time request for ILRT extension [23], a population dose adjustment was made based on the SAMA 2040 population projection to an earlier year (i.e., 2015) more reflective of the time period of interest for the one-time extension. For this current ILRT risk assessment, no population adjustment is made. Therefore, the Salem doses used in this current risk assessment reflect the projected population for the year 2040. Details regarding the population projection methods may be found in the SAMA analysis [9].
The 2009 SAMA evaluation was based on a reactor power level of 3632 MWt which is approximately 5% higher than the licensed thermal power level of 3459 MWt. This higher reactor power level was included to account for a potential power uprate as discussed in the 2009 ILRT one-time extension request RAI responses [27]. That power uprate has not yet been pursued for Salem, but is included in case it is pursued in the future.
Table 4.2-2 summarizes the information from the SAMA analysis that is used to calculate the population dose for each release category for this ILRT risk assessment.
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Risk Impact Assessment of Extending Salem ILRT Interval TABLE 4.2-2 CALCULATION OF SGS POPULATION DOSE RISK AT 50 MILES RELEASE                       RELEASE             POPULATION DOSE               POPULATION DOSE CATEGORY                (PERSON-REM)                        RISK CATEGORIES FREQUENCIES                                           (PERSON-REM/YR)
(PER YEAR)
INTACT                        2.56E-06                   1.64E+04                    4.20E-02 LATE-BMMT-AFW                      3.62E-10                   8.33E+04                    3.01E-05 LATE-BMMT-NOAFW                      4.35E-08                   2.31E+04                    1.00E-03 LATE-CHR-AFW                      4.29E-07                   2.52E+06                    1.08E+00 LATE-CHR-NOAFW                      3.24E-07                   1.25E+06                    4.05E-01 LERF-CFE                       3.15E-09                   1.09E+07                    3.44E-02 LERF-CI                       7.62E-08                   1.04E+07                    7.93E-01 LERF-ISGTR                      2.22E-08                   3.91E+06                    8.69E-02 LERF-ISLOCA                      1.39E-08                   2.07E+07                    2.88E-01 LERF-SGTR-AFW                      1.60E-08                   9.10E+06                    1.45E-01 LERF-SGTR-NOAFW                      2.05E-09                   3.95E+06                    8.11E-03 SERF                        1.58E-07                   3.91E+06                    6.16E-01 Total                      3.65E-06                  9.59E+05(1)                      3.50 (1)
Obtained by dividing the total population dose risk shown in the fourth column by the release category frequency total in the second column.
Salem Unit 1 Fire PRA Model A Unit 1 Fire PRA model [24] was completed in 2022 and is used in this ILRT risk assessment to estimate the impact of including external event risk. A Unit 2 model has not yet been completed. Additional discussion is provided in the beginning of this section and in Section 5.7.
Salem IPEEE Results The Salem IPEEE [18] provides input to other external event risk and is used in this ILRT risk assessment.
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Risk Impact Assessment of Extending Salem ILRT Interval 4.3     IMPACT OF EXTENSION ON DETECTION OF COMPONENT FAILURES THAT LEAD TO LEAKAGE (SMALL AND LARGE)
The ILRT can detect a number of component failures such as liner breach, failure of certain bellows arrangements and failure of some sealing surfaces, which can lead to leakage. The proposed ILRT test interval extension may influence the conditional probability of detecting these types of failures. To ensure that this effect is properly accounted for, the EPRI Class 3 accident class as defined in Table 4.1-1 is divided into two sub-classes, Class 3a and Class 3b, representing small and large leakage failures respectively.
The probability of the EPRI Class 3a and 3b failures is determined, consistent with the EPRI guidance [22]. For Class 3a, the probability is based on the maximum likelihood estimate of failure (arithmetic average) from the available data (i.e., 2 small failures that could only have been discovered by the ILRT in 217 tests which leads to 2/217=0.0092).
For Class 3b, the probability is based on the Jeffreys non-informative prior for no large failures in 217 tests (i.e., 0.5/(217+1) = 0.0023).
In a follow-on letter [21] to their ILRT guidance document [3], NEI issued additional information concerning the potential that the calculated delta LERF values for several plants may fall above the very small change guidelines of the NRC regulatory guide 1.174 [4]. This additional NEI information includes a discussion of conservatisms in the quantitative guidance for delta LERF. NEI describes ways to demonstrate that, using plant-specific calculations, the delta LERF is smaller than that calculated by the simplified method.
The supplemental information states:
The methodology employed for determining LERF (Class 3b frequency) involves conservatively multiplying the CDF by the failure probability for this class (3b) of accident. This was done for simplicity and to maintain conservatism. However, some plant-specific accident classes leading to core damage are likely to include individual sequences that either may already (independently) cause a LERF or could never cause a LERF, and are thus not associated with a postulated large Type A containment leakage path (LERF). These contributors can be removed from Class 3b 4-14                                    SA-LAR-021

Risk Impact Assessment of Extending Salem ILRT Interval in the evaluation of LERF by multiplying the Class 3b probability by only that portion of CDF that may be impacted by type A leakage.
The application of this additional guidance to the analysis for Salem (as detailed in Section
: 5) means that the Class 2 (containment isolation failures), Class 7-LERF (release category LERF-CFE), and Class 8 (containment bypass) sequences are subtracted from the CDF that is applied to Class 3b (large leakage failures). To be consistent, the same change is made to the Class 3a (small leakage failures) CDF, even though these Class 3a events are not considered LERF. Class 2 and Class 8 events refer to sequences with either large pre-existing containment isolation failures or containment bypass events.
Class 2 and most Class 8 sequences (i.e., all except SERF) are already considered to contribute to LERF in the Salem Level 2 PRA analysis. Additionally, the LERF-CFE category assigned to release category Class 7 from Table 4.2-1 (referred to as Class 7-LERF in this report) is excluded since it also already contributes to LERF. Although the Class 8 SERF sequence is not LERF, it is excluded on the basis that the containment bypass sequences are not mitigated by the ILRT test frequency.
The EPRI guidance [22] permits the exclusion of sequences involving the successful operation of containment sprays from the Class 1 frequency. For the Salem risk assessment, no adjustment to Class 1 was made on this basis.
Consistent with the NEI Guidance [3], the change in the leak detection probability can be estimated by comparing the average time that a leak could exist without detection. For example, the average time that a leak could go undetected with a three-year test interval is 1.5 years (3 yr/2), and the average time that a leak could exist without detection for a ten-year interval is 5 years (10 yr/2). This change would lead to a non-detection probability that is a factor of 3.33 (5.0/1.5) higher for the probability of a leak that is detectable only by ILRT testing, given a 10-year vs. a 3-yr interval. Correspondingly, an extension of the ILRT interval to fifteen years can be estimated to lead to about a factor of 5.0 ((15 yr/2)/1.5) increase in the non-detection probability of a leak.
Salem Unit 1 & 2 Past ILRT Results 4-15                                    SA-LAR-021

Risk Impact Assessment of Extending Salem ILRT Interval The surveillance frequency for Type A testing in NEI 94-01 under option B criteria is at least once per ten years based on an acceptable performance history (i.e., two consecutive periodic Type A tests at least 24 months apart where the calculated performance leakage rate was less than 1.0 La) and consideration of the performance factors in NEI 94-01 [1], Section 11.3.
Based on completion of two successful ILRTs at each Salem unit, the current ILRT interval is once per ten years. Note that the probability of pre-existing leakage due to extending the ILRT interval is based on the industry wide historical results as discussed in the EPRI Guidance [22], and the only portion of Salem specific information utilized is the fact that the current ILRT interval is once per ten years based on successful prior Type A tests.
4.4     IMPACT OF EXTENSION ON DETECTION OF STEEL LINER CORROSION THAT LEADS TO LEAKAGE An estimate of the likelihood and risk implications of corrosion-induced leakage of the steel liners occurring and going undetected during the extended test interval is evaluated using the methodology from the Calvert Cliffs liner corrosion analysis [19]. The Calvert Cliffs analysis was performed for a concrete cylinder and dome and a concrete basemat, each with a steel liner. Salem Units 1&2 have a similar containment type.
The following approach is used to determine the change in likelihood, due to extending the ILRT, of detecting corrosion of the containment steel liner. This likelihood is then used to determine the resulting change in risk. Consistent with the Calvert Cliffs analysis, the following issues are addressed:
* Differences between the containment basemat and the containment cylinder and dome
* The historical steel liner flaw likelihood due to concealed corrosion
* The impact of aging
* The corrosion leakage dependency on containment pressure
* The likelihood that visual inspections will be effective at detecting a flaw 4-16                                  SA-LAR-021

Risk Impact Assessment of Extending Salem ILRT Interval Assumptions
* Consistent with the Calvert Cliffs analysis, a half failure is assumed for the basemat concealed liner corrosion due to lack of identified failures (see Table 4.4-1, Step 1).
* The two corrosion events used to estimate the liner flaw probability in the Calvert Cliffs analysis are assumed to be applicable to the Salem Unit 1 containment analysis. These events, one at North Anna Unit 2 and one at Brunswick Unit 2, were initiated from the non-visible (backside) portion of the containment liner.
* For consistency with the Calvert Cliffs analysis, the estimated historical flaw probability is limited to 5.5 years to reflect the years from September 1996 when 10 CFR 50.55a started requiring visual inspection to that addressed by Calvert Cliffs. Additional data that is available since the time of the Calvert analysis has not been factored into this analysis to maintain consistency with other submittals and since it is judged to have a minimal impact on the results (See Table 4.4-1, Step 1).
* Consistent with the Calvert Cliffs analysis, the steel liner flaw likelihood is assumed to double every five years. This is based solely on judgment and is included in this analysis to address the increased likelihood of corrosion as the steel liner ages. (See Table 4.4-1, Steps 2 and 3.)
Sensitivity studies are included that address doubling this rate every two years and every ten years.
* In the Calvert Cliffs analysis, the likelihood of the containment atmosphere reaching the outside atmosphere given that a liner flaw exists was estimated as 1.1% for the cylinder and dome region, and 0.11% (10% of the cylinder failure probability) for the basemat. These values were determined from an assessment of the probability versus containment pressure. For Salem, the ILRT maximum test pressure is approximately 46 psig [28, 29]. Probabilities of 1% for the cylinder and dome, and 0.1% for the basemat are used in this Salem analysis.
Sensitivity studies are included that increase and decrease the probabilities by an order of magnitude. (See Table 4.4-1, Step 4.)
* In the Calvert Cliff analysis, approximately 85% of the interior walls surface was accessible for visible inspections. Additionally, a 5% visual inspection detection failure likelihood was assumed given that the flaw was visible. For Salem it is estimated that approximately 34% of the liner is visually inaccessible for inspection as discussed in a previous Salem Unit 2 ILRT extension report [30]. This 34% is conservatively applied to the walls and dome, although that estimate may have also included the basemat. In addition, a 5% visual inspection detection failure likelihood is assumed (consistent with Calvert Cliff analysis) giving a visual inspection failure probability total of 39%. To date, all liner corrosion events have been detected through visual inspection. (See Table 4.4-4-17                                  SA-LAR-021

Risk Impact Assessment of Extending Salem ILRT Interval 1, Step 5.) Sensitivity studies are included that evaluate total detection failure likelihood of 34% and 44%, respectively.
* Consistent with the Calvert Cliffs analysis, all non-detectable containment failures are assumed to result in early releases. This approach avoids a detailed analysis of containment failure timing and operator recovery actions.
TABLE 4.4-1 STEEL LINER CORROSION BASE CASE STEP            DESCRIPTION                CONTAINMENT CYLINDER              CONTAINMENT BASEMAT AND DOME 1   Historical Steel Liner Flaw        Events: 2                          Events: 0 (assume half a Likelihood                                                            failure)
Failure Data: Containment          2 / (70
* 5.5) = 5.2E-3            0.5 / (70
* 5.5) = 1.3E-3 location specific (consistent with Calvert Cliffs analysis).
2   Age Adjusted Steel Liner           Year_______ Failure Rate_          Year________ Failure Rate Flaw Likelihood 1                2.1E-3            1                  5.1E-4 During 15-year interval, assume avg 5-10         5.2E-3            avg 5-10           1.3E-3 failure rate doubles every five years (14.9% increase per          15               1.4E-2            15                 3.6E-3 year). The average for 5th to 10th year is set to the historical failure rate (consistent with      15 year average =                  15 year average =
Calvert Cliffs analysis).          6.4E-3                             1.6E-3 3   Flaw Likelihood at 3, 10, and      0.71% (1 to 3 years)               0.18% (1 to 3 years) 15 years 4.1% (1 to 10 years)               1.0% (1 to 10 years)
Uses age adjusted liner flaw 9.7% (1 to 15 years)               2.4% (1 to 15 years) likelihood (Step 2), assuming failure rate doubles every five years.
4   Likelihood of Breach in            1%                                 0.1%
Containment Given Steel Liner Flaw 5   Visual Inspection Detection        39%                                100%
Failure Likelihood 34% failure to identify flaws      Cannot be visually inspected.
due to inaccessibility plus 5%
likelihood the visible flaw is not detected.
4-18                                          SA-LAR-021

Risk Impact Assessment of Extending Salem ILRT Interval TABLE 4.4-1 STEEL LINER CORROSION BASE CASE STEP           DESCRIPTION           CONTAINMENT CYLINDER       CONTAINMENT BASEMAT AND DOME 6   Likelihood of Non-Detected     0.0028% (at 3 years)       0.00018% (at 3 years)
Containment Leakage 0.71%
* 1%
* 39%         =0.18%
* 0.1%
* 100%
(Steps 3
* 4
* 5) 0.016% (at 10 years)       0.0010% (at 10 years) 4.1%
* 1%
* 39%          =1.0%
* 0.1%
* 100%
0.038% (at 15 years)       0.0024% (at 15 years) 9.7%
* 1%
* 39%          =2.4%
* 0.1%
* 100%
The total likelihood of the corrosion-induced, non-detected containment leakage is the sum of Step 6 for the containment cylinder and dome, and the containment basemat:
At 3 years: 0.0028% + 0.00018% = 0.0030%
At 10 years: 0.016% + 0.0010% = 0.017%
At 15 years: 0.038% + 0.0024% = 0.040%
4-19                                  SA-LAR-021

Risk Impact Assessment of Extending Salem ILRT Interval 5.0    RESULTS The application of the approach based on the EPRI methodology [22] and previous risk assessment submittals on this subject [6, 7, 19, 20] have led to the following results. The results are displayed according to the eight accident classes defined in the EPRI report, as reproduced in Table 5.0-1.
The analysis performed examined Salem-specific accident sequences in which the containment remains intact or the containment is impaired. Specifically, the breakdown of the severe accidents contributing to risk was considered in the following manner:
* Core damage sequences in which the containment remains intact initially and in the long term (EPRI Class 1 sequences).
* Core damage sequences in which containment integrity is impaired due to random isolation failures of plant components other than those associated with Type B or Type C test components. For example, liner breach or bellows leakage. (EPRI Class 3 sequences).
* Core damage sequences in which containment integrity is impaired due to containment isolation failures of pathways left opened following a plant post-maintenance test. (For example, a valve failing to close following a valve stroke test. (EPRI Class 6 sequences). Consistent with the guidance, this class is not specifically examined since it will not significantly influence the results of this analysis.
* Accident sequences involving containment bypassed (EPRI Class 8 sequences), large containment isolation failures (EPRI Class 2 sequences), and small containment isolation failure-to-seal events (EPRI Class 4 and 5 sequences) are accounted for in this evaluation as part of the baseline risk profile. However, they are not affected by the ILRT frequency change.
* EPRI Class 4 and 5 sequences are impacted by changes in Type B and C test intervals; therefore, changes in the Type A test interval do not impact these sequences.
5-1                                 SA-LAR-021

Risk Impact Assessment of Extending Salem ILRT Interval TABLE 5.0-1 EPRI ACCIDENT CLASS DEFINITIONS ACCIDENT CLASSES (CONTAINMENT RELEASE TYPE)                                   DESCRIPTION 1           No Containment Failure 2           Large Isolation Failures (Failure to Close) 3a           Small Isolation Failures (liner breach) 3b           Large Isolation Failures (liner breach) 4           Small Isolation Failures (Failure to seal -Type B) 5           Small Isolation Failures (Failure to sealType C) 6           Other Isolation Failures (e.g. dependent failures) 7           Failures Induced by Severe Accident Phenomena (Early and Late) 8           Bypass (SGTR and Interfacing System LOCA)
CDF           All CET End states (including very low and no release)
The steps taken to perform this risk assessment evaluation are as follows:
Step 1   Quantify the base-line risk in terms of frequency per reactor year for each of the eight accident classes presented in Table 5.0-1.
Step 2   Develop plant-specific person-rem dose (population dose) per reactor year for each of the eight accident classes.
Step 3   Evaluate risk impact of extending Type A test interval from 3-in-10 years to 1-in-15, and from 1-in-10 years to 1-in-15 years.
Step 4   Determine the change in risk in terms of Large Early Release Frequency (LERF) in accordance with RG 1.174 [4].
Step 5   Determine the impact on the Conditional Containment Failure Probability (CCFP)
Step 6   Evaluate the sensitivity of the results to various assumptions.
5-2                                   SA-LAR-021

Risk Impact Assessment of Extending Salem ILRT Interval 5.1     STEP 1 - QUANTIFY THE BASE-LINE RISK IN TERMS OF FREQUENCY PER REACTOR YEAR As previously described, the extension of the Type A interval does not influence those accident progressions that involve large containment isolation failures, Type B or Type C testing, or containment failure induced by severe accident phenomena because the containment function is independently failed.
As described in Section 4.2, the release categories were assigned to the EPRI classes as shown in Table 4.2-1.
For the assessment of ILRT impacts on the risk profile, the potential for pre-existing leakage is included in the model. These events are represented by the EPRI Class 3 sequences. Two failure modes were considered for the Class 3 sequences. These are Class 3a (small breach) and Class 3b (large breach).
The initial set of containment release class frequencies as shown in Table 4.2-4 are developed consistent with the definitions in Table 5.0-1 and have been reproduced below in Table 5.1-1.
TABLE 5.1-1 CALCULATION OF SGS POPULATION DOSE RISK AT 50 MILES RELEASE         EPRI CLASS        RELEASE         POPULATION     POPULATION CATEGORY                          CATEGORY             DOSE        DOSE RISK FREQUENCIES       (PERSON-REM)      (PERSON-(PER YEAR)                          REM/YR)
INTACT              1             2.56E-06         1.64E+04        4.20E-02 LATE-BMMT-AFW            7             3.62E-10         8.33E+04        3.01E-05 LATE-BMMT-NOAFW            7             4.35E-08         2.31E+04        1.00E-03 LATE-CHR-AFW            7             4.29E-07         2.52E+06       1.08E+00 LATE-CHR-NOAFW            7             3.24E-07         1.25E+06        4.05E-01 LERF-CFE            7(1)           3.15E-09         1.09E+07        3.44E-02 LERF-CI             2             7.62E-08         1.04E+07        7.93E-01 LERF-ISGTR            8             2.22E-08         3.91E+06        8.69E-02 LERF-ISLOCA            8             1.39E-08         2.07E+07        2.88E-01 LERF-SGTR-AFW            8             1.60E-08         9.10E+06        1.45E-01 5-3                                 SA-LAR-021

Risk Impact Assessment of Extending Salem ILRT Interval LERF-SGTR-NOAFW                    8                 2.05E-09                3.95E+06              8.11E-03 SERF                      8                 1.58E-07                3.91E+06              6.16E-01 Total                      -                3.65E-06               9.59E+05(2)              3.50 (1) LERF-CFE is the only Class 7 release category that contributes to LERF.
(2) The total dose is calculated as the total dose risk of the fifth column divided by the total frequency of the third column.
In order to group the release categories by EPRI class the summation of the dose risks for a given class is divided by the total frequency for that class. This yields a frequency weighted average dose for the class. The doses or weighted average doses (when applicable) are shown in Table 5.1-2.
TABLE 5.1-2 CONTAINMENT RELEASE CLASS DOSE EPRI CONTAINMENT RELEASE CLASS TYPE                                 DOSE (PERSON-REM) 1                                1.64E+04 2                                1.04E+07 7                                1.87E+06 7-LERF                                1.09E+07 8                                5.41E+06 The frequencies for the severe accident classes defined in Table 5.0-1 are developed for Salem based on the assignments shown above in Table 5.1-2, determining the frequencies for Classes 3a and 3b, and then determining the remaining frequency for Class 1. Furthermore, adjustments are made to the Class 3b and hence Class 1 frequencies to account for the impact of undetected corrosion of the steel liner per the methodology described in Section 4.4.
5-4                                               SA-LAR-021

Risk Impact Assessment of Extending Salem ILRT Interval Class 1 Sequences This group consists of all core damage accident sequences for which the containment remains intact (modeled as Technical Specification Leakage). The frequency for these sequences is 2.52E-06/yr and is determined by subtracting the EPRI Class 3a and 3b frequency calculated below, from the Level 2 Class 1 frequency to preserve total CDF (i.e., 2.56E-06/yr for Class 1 from Table 5.1-1 minus 3.09E-08/yr (Class 3a) minus 7.72E-09/yr (Class 3b)). For this analysis, the associated maximum containment leakage for this group is 1La, consistent with an intact containment evaluation.
Class 2 Sequences This group consists of core damage accident sequences with large containment isolation failures. For Salem this frequency is 7.62E-08/yr.
Class 3 Sequences This group consists of core damage accident sequences with pre-existing leakage in the containment structure (e.g., containment liner) that can only be detected by performing a Type A ILRT. The containment leakage for these sequences can be either small (in excess of design allowable leakage but <10La) or large (>100La).
The respective frequencies per year are determined as follows:
PROBClass_3a       = probability of small pre-existing containment liner leakage
                       = 0.0092 [see Section 4.3]
PROBClass_3b       = probability of large pre-existing containment liner leakage
                       = 0.0023 [see Section 4.3]
As described in Section 4.3, additional consideration is made to not apply these failure probabilities on those cases that are already LERF scenarios (i.e., the Class 2, Class 7-LERF and Class 8 LERF contributions) and also Class 8 non-LERF contributions (i.e.,
SERF release) given containment bypass.
5-5                                  SA-LAR-021

Risk Impact Assessment of Extending Salem ILRT Interval Class_3a           = 0.0092 * (CDF - Class 2 - Class 7LERF - Class 8)
                      = 0.0092 * (3.65E 7.62E 3.15E 2.12E-07)
                      = 3.09E-08/yr Class_3b           = 0.0023 * (CDF - Class 2 - Class 7LERF - Class 8)
                      = 0.0023 * (3.65E 7.62E 3.15E 2.12E-07)
                      = 7.72E-09/yr For this analysis, the associated containment leakage for Class 3a is 10La and for Class 3b is 100La. These assignments are consistent with the EPRI Guidance [22].
Class 4 Sequences This group consists of all core damage accident sequences with containment isolation failure-to-seal of Type B test components. Because these failures are detected by Type B tests which are unaffected by the Type A ILRT, this group is not evaluated any further in the analysis, consistent with the EPRI Guidance [22].
Class 5 Sequences This group consists of all core damage accident sequences with containment isolation failure-to-seal of Type C test components. Because these failures are detected by Type C tests which are unaffected by the Type A ILRT, this group is not evaluated any further in this analysis, consistent with the EPRI Guidance [22].
Class 6 Sequences This group is similar to Class 2 and consists of core damage accident sequences with a failure-to-seal containment leakage due to failure to isolate the containment. These sequences are dominated by misalignment of containment isolation valves following a test/maintenance evolution. Consistent with the EPRI Guidance [22], however, this accident class is not explicitly considered since it has a negligible impact on the results.
5-6                                   SA-LAR-021

Risk Impact Assessment of Extending Salem ILRT Interval Class 7 Sequences This group consists of all core damage sequences in which containment failure is induced by severe accident phenomena (e.g., containment overpressure). The failure frequency for non-LERF and LERF sequences is shown below in Table 5.1-3, based upon the individual Class 7 frequencies provided in Table 5.1-1.
TABLE 5.1-3 ACCIDENT CLASS 7 FAILURE FREQUENCIES AND POPULATION DOSES (SALEM BASE CASE LEVEL 2 MODEL)
POPULATION        POPULATION DOSE ACCIDENT CLASS                 RELEASE                  DOSE (50 MILES)       RISK (50 MILES)
FREQUENCY/YR                 PERSON-REM (1)     (PERSON-REM/YR) (2) 7 (non-LERF)                       7.97E-07                     1.87E+06               1.49E+00 7 LERF                             3.15E-09                     1.09E+07               3.44E-02 (1) Population dose values obtained from Table 4.2-2 (2) Obtained by multiplying the release frequency value from the second column of this table by the population dose value from the third column of this table.
Class 8 Sequences This group consists of all core damage accident sequences in which containment bypass occurs. For Salem this frequency is 2.12E-07/yr and is composed of ISLOCA and SGTR sequences.
Summary of Accident Class Frequencies In summary, the accident sequence frequencies that can lead to radionuclide release to the public have been derived consistent with the definition of Accident Classes defined in the EPRI Guidance [22] and are shown in Table 5.1-4.
5-7                                         SA-LAR-021

Risk Impact Assessment of Extending Salem ILRT Interval TABLE 5.1-4 RADIONUCLIDE RELEASE FREQUENCIES AS A FUNCTION OF ACCIDENT CLASS (SALEM BASE CASE)
ACCIDENT                             DESCRIPTION                      FREQUENCY CLASSES                                                              (PER RX-YR)
(CONTAINMENT RELEASE TYPE) 1        No Containment Failure                                    2.52E-06 2        Large Isolation Failures (Failure to Close)               7.62E-08 3a        Small Isolation Failures (liner breach)                   3.09E-08 3b        Large Isolation Failures (liner breach)                   7.72E-09 4        Small Isolation Failures (Failure to seal -Type B)           N/A 5        Small Isolation Failures (Failure to sealType C)            N/A 6        Other Isolation Failures (e.g. dependent failures)           N/A 7        Failures Induced by Severe Accident Phenomena             7.97E-07 7-LERF      Failures Induced by Severe Accident Phenomena (LERF)      3.15E-09 8        Containment Bypass (ISLOCA & SGTR)                        2.12E-07 CDF        All CET End states (including very low and no release)    3.65E-06 5.2    STEP 2 - DEVELOP PLANT-SPECIFIC PERSON-REM DOSE (POPULATION DOSE) PER REACTOR YEAR Plant-specific release analyses were performed to estimate the person-rem doses to the population within a 50-mile radius from the plant. The releases are based on information provided in the Salem SAMA Analysis [9] submitted for license renewal and the Level 2 Analysis [17] as described in Section 4.2 and summarized in Table 4.2-4. The results of applying these releases to the EPRI containment failure classification are as follows:
Class 1   = 1.64E+04 person-rem (at 1.0La)
Class 2   = 1.04E+07 person-rem Class 3a = 1.64E+04 person-rem x 10La = 1.64E+05 person-rem Class 3b = 1.64E+04 person-rem x 100La = 1.64E+06 person-rem Class 4   = Not analyzed Class 5   = Not analyzed Class 6   = Not analyzed 5-8                               SA-LAR-021

Risk Impact Assessment of Extending Salem ILRT Interval Class 7   = 1.87E+06 person-rem Class 7-LERF = 1.09E+07 person-rem Class 8   = 5.41E+06 person-rem In summary, the population dose estimates derived for use in the risk evaluation per the EPRI methodology [22] containment failure classifications are provided in Table 5.2-1.
TABLE 5.2-1 SALEM 50-MILE POPULATION DOSE ESTIMATES ACCIDENT                   CLASS DESCRIPTION                     50-MILE DOSE CLASSES                                                        (PERSON-REM)
(CONTAINMENT RELEASE TYPE) 1       No Containment Failure (1 La)                          1.64E+04 2       Large Isolation Failures (Failure to Close)            1.04E+07 3a       Small Isolation Failures (liner breach)                1.64E+05 3b       Large Isolation Failures (liner breach)                1.64E+06 4       Small Isolation Failures (Failure to seal -Type B)        NA 5       Small Isolation Failures (Failure to sealType C)         NA 6       Other Isolation Failures (e.g. dependent failures)        NA 7       Failures Induced by Severe Accident Phenomena          1.87E+06 7-LERF     Failures Induced by Severe Accident Phenomena          1.09E+07 (LERF) 8       Containment Bypass (ISLOCA & SGTR)                     5.41E+06 The above dose estimates when multiplied by the frequency results presented in Table 5.1-4 yield the Salem baseline mean consequence measures for each accident class.
These results are presented in Table 5.2-2.
5-9                                     SA-LAR-021

Risk Impact Assessment of Extending Salem Unit 1 ILRT Interval TABLE 5.2-2 SALEM ANNUAL DOSE AS A FUNCTION OF ACCIDENT CLASS; CHARACTERISTIC OF CONDITIONS FOR ILRT REQUIRED 3/10 YEARS ACCIDENT     DESCRIPTION         50-MILE DOSE      EPRI METHODOLOGY           EPRI METHODOLOGY PLUS       CORROSION CLASSES                        (PERSON-REM)                                          CORROSION             DOSE RISK (CONTAINMENT                                                                                                   CHANGE FREQUENCY      50-MILE DOSE    FREQUENCY 50-MILE DOSE RELEASE                                                                                                       (PER-(PER RX-YR)       RISK (PER-   (PER RX-YR)     RISK (PER-TYPE)                                                                                                     REM/YR(1))
REM/YR)                      REM/YR) 1     No Containment           1.64E+04    2.52E-06         4.14E-02      2.52E-06       4.14E-02       -1.6E-06 Failure (2) 2     Large Isolation          1.04E+07    7.62E-08         7.93E-01      7.62E-08       7.93E-01           --
Failures (Failure to Close) 3a     Small Isolation          1.64E+05    3.09E-08         5.07E-03      3.09E-08       5.07E-03           --
Failures (liner breach) 3b     Large Isolation          1.64E+06    7.72E-09         1.27E-02      7.82E-09       1.28E-02        1.6E-04 Failures (liner breach) 4     Small Isolation             NA          N/A              N/A           N/A            N/A            N/A Failures (Type B) 5     Small Isolation             NA          N/A              N/A           N/A            N/A            N/A Failures (Type C) 6     Other Isolation             NA          N/A              N/A           N/A            N/A            N/A Failures 7     Failures Induced         1.87E+06    7.97E-07         1.49E+00      7.97E-07       1.49E+00           --
by Phenomena 7-LERF   Failures Induced         1.09E+07    3.15E-09         3.44E-02      3.15E-09       3.44E-02           --
by Phenomena (LERF) 5-10                                              SA-LAR-021

Risk Impact Assessment of Extending Salem Unit 1 ILRT Interval TABLE 5.2-2 SALEM ANNUAL DOSE AS A FUNCTION OF ACCIDENT CLASS; CHARACTERISTIC OF CONDITIONS FOR ILRT REQUIRED 3/10 YEARS ACCIDENT            DESCRIPTION           50-MILE DOSE                EPRI METHODOLOGY                     EPRI METHODOLOGY PLUS               CORROSION CLASSES                                  (PERSON-REM)                                                                CORROSION                  DOSE RISK (CONTAINMENT                                                                                                                                          CHANGE FREQUENCY            50-MILE DOSE         FREQUENCY 50-MILE DOSE RELEASE                                                                                                                                             (PER-(PER RX-YR)            RISK (PER-          (PER RX-YR)         RISK (PER-TYPE)                                                                                                                                          REM/YR(1))
REM/YR)                                 REM/YR) 8           Containment                5.41E+06             2.12E-07             1.14E+00              2.12E-07          1.14E+00                --
Bypass CDF           All CET end states             --               3.65E-06             3.52E+00              3.65E-06          3.52E+00            1.6E-04 (1)  Only release Classes 1 and 3b are affected by the corrosion analysis. During the 15-year interval, the failure rate is assumed to double every five years.
(2)  Characterized as 1La release magnitude consistent with the derivation of the ILRT non-detection failure probability for ILRTs. Release classes 3a and 3b include failures of containment to meet the Technical Specification leak rate. Class 1 frequency is reduced by the Class 3a and 3b frequencies to preserve total CDF.
5-11                                                              SA-LAR-021

Risk Impact Assessment of Extending Salem Unit 1 ILRT Interval 5.3      STEP 3 - EVALUATE RISK IMPACT OF EXTENDING TYPE A TEST INTERVAL FROM 10-TO-15 YEARS The next step is to evaluate the risk impact of extending the test interval from its current 10-year interval to a 15-year interval. To do this, an evaluation must first be made of the risk associated with the 10-year interval since the base case applies to a 3-year interval (i.e., a simplified representation of a 3-in-10 year interval).
Risk Impact Due to 10-year Test Interval As previously stated, Type A tests impact only Class 3 sequences. For Class 3 sequences, the release magnitude is not impacted by the change in test interval (a small or large breach remains the same, even though the probability of not detecting the breach increases). Thus, only the frequency of Class 3a and 3b sequences is impacted. The risk contribution is changed based on the EPRI Guidance [22] as described in Section 4.3 by a factor of 3.33 compared to the base case values. The results of the calculation for a 10-year interval are presented in Table 5.3-1.
Risk Impact Due to 15-Year Test Interval The risk contribution for a 15-year interval is calculated in a manner similar to the 10-year interval. The difference is in the increase in probability of not detecting a leak in Classes 3a and 3b. For this case, the value used in the analysis is a factor of 5.0 compared to the 3-year interval value, as described in Section 4.3. The results for this calculation are presented in Table 5.3-2.
5-12                                  SA-LAR-021

Risk Impact Assessment of Extending Salem Unit 1 ILRT Interval TABLE 5.3-1 SALEM ANNUAL DOSE AS A FUNCTION OF ACCIDENT CLASS; CHARACTERISTIC OF CONDITIONS FOR ILRT REQUIRED 1/10 YEARS ACCIDENT    DESCRIPTION      50-MILE DOSE    EPRI METHODOLOGY             EPRI METHODOLOGY PLUS        CORROSION CLASSES                       (PER-REM)                                         CORROSION              DOSE RISK (CONTAINMENT                                                                                                CHANGE FREQUENCY          50-MILE    FREQUENCY      50-MILE DOSE RELEASE                                                                                                    (PER-(PER RX-YR)      DOSE RISK    (PER RX-YR)     RISK (PER-TYPE)                                                                                                  REM/YR(1))
(PER-                       REM/YR)
REM/YR) 1     No Containment       1.64E+04    2.43E-06         3.99E-02     2.43E-06        3.99E-02        -9.5E-06 Failure (2) 2     Large Isolation      1.04E+07    7.62E-08         7.93E-01     7.62E-08        7.93E-01            --
Failures (Failure to Close) 3a     Small Isolation      1.64E+05    1.03E-07         1.69E-02     1.03E-07        1.69E-02            --
Failures (liner breach) 3b     Large Isolation      1.64E+06    2.57E-08         4.22E-02     2.63E-08        4.31E-02         9.5E-04 Failures (liner breach) 4     Small Isolation         NA          N/A              N/A          N/A             N/A             N/A Failures (Type B) 5     Small Isolation         NA          N/A              N/A          N/A             N/A             N/A Failures (Type C) 6     Other Isolation         NA          N/A              N/A          N/A             N/A             N/A Failures 7     Failures Induced     1.87E+06    7.97E-07        1.49E+00      7.97E-07        1.49E+00            --
by Phenomena 7-LERF   Failures Induced     1.09E+07    3.15E-09         3.44E-02     3.15E-09        3.44E-02            --
by Phenomena (LERF) 5-13                                             SA-LAR-021

Risk Impact Assessment of Extending Salem Unit 1 ILRT Interval TABLE 5.3-1 SALEM ANNUAL DOSE AS A FUNCTION OF ACCIDENT CLASS; CHARACTERISTIC OF CONDITIONS FOR ILRT REQUIRED 1/10 YEARS ACCIDENT            DESCRIPTION          50-MILE DOSE              EPRI METHODOLOGY                     EPRI METHODOLOGY PLUS                  CORROSION CLASSES                                     (PER-REM)                                                              CORROSION                    DOSE RISK (CONTAINMENT                                                                                                                                           CHANGE FREQUENCY             50-MILE         FREQUENCY             50-MILE DOSE RELEASE                                                                                                                                             (PER-(PER RX-YR)         DOSE RISK         (PER RX-YR)            RISK (PER-TYPE)                                                                                                                                         REM/YR(1))
(PER-                                   REM/YR)
REM/YR) 8           Containment               5.41E+06             2.12E-07          1.14E+00             2.12E-07             1.14E+00                --
Bypass CDF            All CET end                                    3.65E-06          3.56E+00             3.65E-06             3.56E+00             9.4E-04 states (1) Only  release classes 1 and 3b are affected by the corrosion analysis. During the 15-year interval, the failure rate is assumed to double every five years.
(2) Characterized as 1La release magnitude consistent with the derivation of the ILRT non-detection failure probability for ILRTs. Release classes 3a and 3b include failures of containment to meet the Technical Specification leak rate. Class 1 frequency is reduced by the Class 3a and 3b frequencies to preserve total CDF.
5-14                                                               SA-LAR-021

Risk Impact Assessment of Extending Salem Unit 1 ILRT Interval TABLE 5.3-2 SALEM ANNUAL DOSE AS A FUNCTION OF ACCIDENT CLASS; CHARACTERISTIC OF CONDITIONS FOR ILRT REQUIRED 1/15 YEARS ACCIDENT   DESCRIPTION       50-MILE DOSE      EPRI METHODOLOGY             EPRI METHODOLOGY PLUS        CORROSION CLASSES                    (PERSON-REM)                                            CORROSION             DOSE RISK (CONTAINMENT                                                                                                  CHANGE FREQUENCY       50-MILE DOSE     FREQUENCY      50-MILE DOSE RELEASE                                                                                                      (PER-(PER RX-YR)       RISK (PER-     (PER RX-YR)     RISK (PER-TYPE)                                                                                                    REM/YR(1))
REM/YR)                         REM/YR) 1     No                   1.64E+04    2.37E-06         3.88E-02        2.37E-06        3.88E-02       -2.2E-05 Containment Failure (2) 2     Large Isolation      1.04E+07    7.62E-08         7.93E-01        7.62E-08        7.93E-01           --
Failures (Failure to Close) 3a     Small Isolation      1.64E+05    1.54E-07         2.53E-02        1.54E-07        2.53E-02           --
Failures (liner breach) 3b     Large Isolation      1.64E+06    3.86E-08         6.33E-02        4.00E-08        6.55E-02        2.2E-03 Failures (liner breach) 4     Small Isolation         NA          N/A              N/A             N/A             N/A            N/A Failures (Type B) 5     Small Isolation         NA          N/A              N/A             N/A             N/A            N/A Failures (Type C) 6     Other Isolation         NA          N/A              N/A             N/A             N/A            N/A Failures 7     Failures             1.87E+06    7.97E-07         1.49E+00        7.97E-07        1.49E+00           --
Induced by Phenomena 5-15                                             SA-LAR-021

Risk Impact Assessment of Extending Salem Unit 1 ILRT Interval TABLE 5.3-2 SALEM ANNUAL DOSE AS A FUNCTION OF ACCIDENT CLASS; CHARACTERISTIC OF CONDITIONS FOR ILRT REQUIRED 1/15 YEARS ACCIDENT          DESCRIPTION         50-MILE DOSE                EPRI METHODOLOGY                      EPRI METHODOLOGY PLUS                CORROSION CLASSES                              (PERSON-REM)                                                                CORROSION                    DOSE RISK (CONTAINMENT                                                                                                                                       CHANGE FREQUENCY            50-MILE DOSE          FREQUENCY           50-MILE DOSE RELEASE                                                                                                                                           (PER-(PER RX-YR)            RISK (PER-           (PER RX-YR)          RISK (PER-TYPE)                                                                                                                                       REM/YR(1))
REM/YR)                                   REM/YR) 7-LERF          Failures                1.09E+07            3.15E-09             3.44E-02              3.15E-09            3.44E-02                --
Induced by Phenomena (LERF) 8           Containment             5.41E+06            2.12E-07             1.14E+00              2.12E-07            1.14E+00                --
Bypass CDF           All CET end                                 3.65E-06             3.59E+00              3.65E-06            3.59E+00            2.2E-03 states (1)  Only release classes 1 and 3b are affected by the corrosion analysis. During the 15-year interval, the failure rate is assumed to double every five years.
(2)  Characterized as 1La release magnitude consistent with the derivation of the ILRT non-detection failure probability for ILRTs. Release classes 3a and 3b include failures of containment to meet the Technical Specification leak rate. Class 1 frequency is reduced by the Class 3a and 3b frequencies to preserve total CDF.
5-16                                                             SA-LAR-021

Risk Impact Assessment of Extending Salem Unit 1 ILRT Interval 5.4     STEP 4 - DETERMINE THE CHANGE IN RISK IN TERMS OF LARGE EARLY RELEASE FREQUENCY The risk increase associated with extending the ILRT interval involves the potential that a core damage event that normally would result in only a small radioactive release from an intact containment could, in fact, result in a larger release due to the increase in probability of failure to detect a pre-existing leak. With strict adherence to the EPRI guidance, 100% of the Class 3b contribution would be considered LERF.
Regulatory Guide 1.174 [4] provides guidance for determining the risk impact of plant-specific changes to the licensing basis. RG 1.174 defines very small changes in risk as resulting in increases of CDF less than 1E-6/yr and increases in LERF less than 1E-7/yr, and small changes in LERF as less than 1E-6/yr. Since containment overpressure is not required in support of ECCS performance to mitigate design basis accidents for the Salem plants, the ILRT extension does not impact CDF. Therefore, the relevant risk metric is LERF.
For Salem, 100% of the frequency of Class 3b sequences can be used as a conservative first-order estimate to approximate the potential increase in LERF from the ILRT interval extension (consistent with the EPRI Guidance [22]). Based on the original 3-in-10 year test interval assessment from Table 5.2-2, the Class 3b frequency is 7.82E-09/yr, which includes the corrosion effect of the containment liner. Based on a ten-year test interval from Table 5.3-1, the Class 3b frequency is 2.63E-08/yr; and, based on a 15-year test interval from Table 5.3-2, it is 4.00E-08/yr. Thus, the increase in the overall probability of LERF due to Class 3b sequences that is due to increasing the ILRT test interval from 3-in-10 years to 15 years (including corrosion effects) is 3.21E-08/yr. Similarly, the increase due to increasing the interval from 10 years to 15 years (including corrosion effects) is 1.37E-08/yr. As can be seen, even with the conservatisms included in the evaluation (per the EPRI methodology), the estimated change in LERF is below the threshold criteria for a very small change in risk (i.e., <1E-07/yr) when comparing the 15-year results to the current 10-year requirement, and even to the original 3-in-10 year requirement.
5-17                                   SA-LAR-021

Risk Impact Assessment of Extending Salem Unit 1 ILRT Interval 5.5    STEP 5 - DETERMINE THE IMPACT ON THE CONDITIONAL CONTAINMENT FAILURE PROBABILITY Another parameter that the NRC guidance in RG 1.174 [4] states can provide input into the decision-making process is the change in the conditional containment failure probability (CCFP). The change in CCFP is indicative of the effect of the ILRT on all radionuclide releases, not just LERF. One of the difficult aspects of this calculation is providing a definition of the failed containment. In this assessment, the CCFP is defined consistent with the EPRI Guidance [4] such that containment failure includes all radionuclide release end states other than the intact state (i.e., all except Class 1 and Class 3a). The conditional part of the definition is conditional given a severe accident (i.e.,
core damage).
CCFP = [1 - (Class 1 frequency + Class 3a frequency) / CDF]
* 100%
The change in CCFP is calculated by using the method specified in the EPRI Guidance
[22]. The following table shows the CCFP values that result from the assessment for the various testing intervals including corrosion effects in which the flaw rate is assumed to double every five years.
CCFP             CCFP             CCFP CCFP15-3     CCFP15-10 3-IN-10 YRS      1-IN-10 YRS      1-IN-15 YRS 30.03%           30.54%           30.91%         0.88%          0.37%
The change in CCFP of less than 1% as a result of extending the test interval to 15 years from the original 3-in-10 year requirement is judged to be insignificant.
5.6    

==SUMMARY==
OF INTERNAL EVENTS RESULTS The results from this ILRT extension risk assessment for Salem internal events (including internal flooding) are summarized in Table 5.6-1.
5-18                                 SA-LAR-021

Risk Impact Assessment of Extending Salem Unit 1 ILRT Interval TABLE 5.6-1 SALEM ILRT CASES:
BASE, 3 TO 10, AND 3 TO 15 YR EXTENSIONS (INCLUDING AGE ADJUSTED STEEL LINER CORROSION LIKELIHOOD)
EPRI          DOSE                 BASE CASE                        EXTEND TO                    EXTEND TO CLASS       (PER-REM)              3-IN-10 YEARS                   1-IN-10 YEARS                1-IN-15 YEARS CDF/YR              PER-          CDF/YR           PER-         CDF/YR          PER-REM/YR                         REM/YR                        REM/YR 1        1.64E+04         2.52E-06         4.14E-02         2.43E-06       3.99E-02      2.37E-06       3.88E-02 2        1.04E+07         7.62E-08         7.93E-01         7.62E-08       7.93E-01      7.62E-08       7.93E-01 3a        1.64E+05         3.09E-08         5.07E-03         1.03E-07       1.69E-02      1.54E-07       2.53E-02 3b        1.64E+06         7.82E-09         1.28E-02         2.63E-08       4.31E-02      4.00E-08       6.55E-02 7        1.87E+06         7.97E-07         1.49E+00         7.97E-07       1.49E+00      7.97E-07       1.49E+00 7-LERF       1.09E+07         3.15E-09         3.44E-02         3.15E-09       3.44E-02      3.15E-09       3.44E-02 8        5.41E+06         2.12E-07         1.14E+00         2.12E-07       1.14E+00      2.12E-07       1.14E+00 Total                        3.65E-06         3.52E+00         3.65E-06       3.56E+00      3.65E-06       3.59E+00 ILRT Dose Rate from                    1.79E-02                         6.00E-02                    9.09E-02 3a and 3b Delta        From 3 yr                    ---                          4.06E-02                    7.04E-02 Total Dose        From 10 yr                    ---                             ---                      2.98E-02 Rate(1) 3b Frequency (LERF)                    7.82E-09                         2.63E-08                    4.00E-08 Delta       From 3 yr                     ---                          1.85E-08                    3.21E-08 LERF From 10 yr                    ---                             ---                      1.37E-08 CCFP %                           30.03%                           30.54%                      30.91%
Delta       From 3 yr                     ---                           0.51%                        0.88%
CCFP %
From 10 yr                    ---                             ---                        0.37%
: 1. The overall difference in total dose rate is less than the difference of only the 3a and 3b categories between two testing intervals. This is because the overall total dose rate includes contributions from other categories that do not change as a function of time, e.g., the EPRI Class 2 and 8 categories, and also due to the fact that the Class 1 person-rem/yr decreases when extending the IRLT frequency.
5-19                                              SA-LAR-021

Risk Impact Assessment of Extending Salem Unit 1 ILRT Interval 5.7    EXTERNAL EVENTS CONTRIBUTION Since the risk acceptance guidelines in RG-1.174 are intended for comparison with a full-scope assessment of risk, including internal and external events, a bounding analysis of the potential impact from external events is presented here. The primary purpose for this investigation is the determination of the total LERF following an increase in the ILRT testing interval from 3-in-10 years to 1-in-15 years.
Fire Contribution Salem has a Fire PRA [24] for Unit 1 that provides CDF and LERF results which may be used to estimate the EPRI Class 3b frequency. The Unit 1 Fire PRA is judged to adequately represent the fire risk with Unit 2 for the purposes of this ILRT assessment.
The Fire CDF is 7.28E-05/yr and Fire LERF is 5.50E-6/yr [24]. Consistent with the EPRI methodology, severe accident frequency associated with Fire LERF sequences are subtracted from the Fire CDF to estimate the bounding CDF that is associated with intact containment sequences. The CDF estimate is bounding because some portions of this CDF would be due to sequences involving containment failure but in a non-early time frame or with a release magnitude (e.g., CsI) that is less than large. Such non-LERF containment failure sequences would not be impacted by the ILRT frequency. The following shows the calculation for fire frequency Class 3b for the three different test intervals:
3-in-10 years Freqclass3b = Pclass3b x (CDF-LERF) = 0.0023 x (7.28E-05/yr - 5.50E-6/yr) = 1.55E-07/yr 1-in-10 years Freqclass3b = Pclass3b x (CDF-LERF) = 0.0023 x 3.33 x (7.28E-05/yr - 5.50E-6/yr) = 5.15E-07/yr 5-20                                 SA-LAR-021

Risk Impact Assessment of Extending Salem Unit 1 ILRT Interval 1-in-15 years Freqclass3b = Pclass3b x (CDF-LERF) = 0.0023 x 5.0 x (7.28E-05/yr - 5.50E-6/yr) = 7.74E-07/yr Other External Event Contributions For other external events hazards LERF has not been quantified. The method chosen to account for these other external event contributions is that used in the previous one-time ILRT submittal [23] to use a multiplier on the internal events Class 3b results based on the Salem IPEEE results [18] or other pertinent results. Notably, the seismic CDF is taken from GI-199 [31]. The contributions of the relevant external events and their source are summarized in Table 5.7-1.
TABLE 5.7-1 OTHER EXTERNAL EVENTS CONTRIBUTORS EXTERNAL EVENT                                  CDF                          SOURCE HAZARD                                   (/YR)
Seismic                                1.1E-05                      GSI-199 [31]
Table D-1, weakest link model External Floods                           3E-07 (1)                      IPEEE [18]
Transportation and Nearby                        6.7E-08                       IPEEE [18]
Facility Accidents Detritus                            up to 9.2E-07                    IPEEE [18]
High Winds                  Not Applicable (progressive                IPEEE [18]
screening method used)
Chemical Release                Not Applicable (progressive                IPEEE [18]
screening method used)
Total                            1.2E-05 per yr                          --
(1) A progressive screening method used for the IPEEE and an overall CDF was not calculated, but three potential water ingress paths were estimated to contribute CDFs of about 1E-07 each. These are conservatively included.
From Table 5.7-1 an external events multiplier can be calculated as external events CDF divided by the internal events CDF as (1.2E-05/yr) / (3.65E-06/yr) = 3.3. This multiplier is used to estimate the impact of external event risk for contributors other than internal fires.
5-21                                            SA-LAR-021

Risk Impact Assessment of Extending Salem Unit 1 ILRT Interval Table 5.7-2 shows the internal and external event contributions to the EPRI Category 3b frequency for the 3-in-10 year, 1-in-10 year, and 1-in-15 year ILRT intervals, along with the change in the LERF risk measure due to extending the ILRT from 3-in-10 years to 1-in-15 years (including corrosion).
TABLE 5.7-2 CLASS 3B (LERF) AS A FUNCTION OF ILRT FREQUENCY FOR INTERNAL AND EXTERNAL EVENTS (INCLUDING AGE ADJUSTED STEEL LINER CORROSION LIKELIHOOD)
CLASS 3B               CLASS 3B             CLASS 3B         CLASS 3B FREQUENCY               FREQUENCY            FREQUENCY             LERF (3-IN-10 YR           (1-IN-10 YEAR        (1-IN-15 YEAR INCREASE(1)
ILRT)                   ILRT)               ILRT)
Internal Events Contribution           7.82E-09                2.63E-08            4.00E-08         3.21E-08 Fire Contribution                      1.55E-07                5.15E-07            7.74E-07         6.19E-07 Other External Events Contribution                           2.58E-08                8.68E-08            1.32E-07         1.06E-07 (Internal Events CDF x 3.3)
Combined (Internal +
1.88E-07                6.29E-07            9.46E-07         7.57E-07 External Events)
(1)  Associated with the change from the original 3-in-10 year frequency to the proposed 1-in-15 year frequency.
Thus, the total increase in LERF (measured from the original 3-in-10 years required to the proposed 1-in-15 years performance of the ILRT) due to the combined internal and external events contribution is estimated as 7.57E-07/yr. This LERF increase falls within Region II (i.e., small change in risk) of the RG 1.174 [4] acceptance guidelines (i.e.,
between 1E-7 to 1E-6 per reactor year). Per RG 1.174, when the calculated increase in LERF due to the proposed plant change is in the small range, the risk assessment must also reasonably show that the total LERF is less than 1E-5/yr.                                 Similar bounding assumptions regarding the external event contributions that were made above are used for the total LERF estimate.
Table 5.7-3 provides the total LERF estimate. From Table 4.2-1, the LERF due to postulated internal event accidents is 1.34E-07/yr. The Fire LERF is from the latest Fire 5-22                                             SA-LAR-021

Risk Impact Assessment of Extending Salem Unit 1 ILRT Interval PRA [24]. The LERF for the other external events for which quantified results are not available is estimated assuming that the IE/EE CDF multiplier (i.e., 3.3) previously calculated is a reasonable multiplier to apply to LERF. The additional LERF associated with extending the ILRT test interval from 3-in-10 years to 1-in-15 years for each of the contributing categories is taken from Table 5.7-2.
TABLE 5.7-3 IMPACT OF 15-YR ILRT EXTENSION ON LERF (3B)
Internal Events LERF (3-in-10 ILRT)                            1.34E-07/yr Fire LERF (3-in-10 ILRT)                                       5.50E-06/yr Other External Event LERF (3-in-10 ILRT) 4.41E-07/yr (Internal Events LERF x 3.3)
Additional Internal Events LERF due to ILRT 3.21E-08/yr extension (at 15 years)(1)
Additional Fire LERF due to ILRT extension 6.19E-07/yr (at 15 years)(1)
Additional External Events LERF due to ILRT 1.06E-07/yr (at 15 years)(1)
Total                                                          6.83E-06/yr (1)
Including age adjusted steel liner corrosion likelihood.
As can be seen, the estimated upper bound LERF for Salem is estimated at 6.83E-06/yr, which is less than the RG 1.174 requirement to demonstrate that the total LERF of internal events and external events is less than 1E-5/yr.
5.8    DEFENSE-IN-DEPTH IMPACT Regulatory Guide 1.174 [4] describes an acceptable approach for developing risk-informed applications for a licensing basis change that considers engineering issues and applies risk insights. One of the considerations included in RG 1.174 is defense-in-depth, which is a safety philosophy that employs successive compensatory measures to prevent accidents or mitigate damage if a malfunction, accident, or naturally caused event occurs at a nuclear facility. The following seven considerations as presented in RG 1.174 Section C.2.1.1.2 are used to evaluate the proposed licensing basis change for overall impact on defense-in-depth.
5-23                          SA-LAR-021

Risk Impact Assessment of Extending Salem Unit 1 ILRT Interval
: 1. Preserve a reasonable balance among the layers of defense. The use of the risk metrics of LERF, population dose, and conditional containment failure probability collectively ensure the balance between prevention of core damage, prevention of containment failure, and consequence mitigation is preserved. The change in LERF is assessed as very small with respect to internal events and small when including external events per RG 1.174, and the change in population dose and CCFP are very small as defined in the EPRI methodology [22].
: 2. Preserve adequate capability of design features without an overreliance on programmatic activities as compensatory measures. The adequacy of the design feature (the containment boundary subject to Type A testing) is preserved as evidenced by the overall small change in risk associated with the Type A test frequency change.
: 3. Preserve system redundancy, independence, and diversity commensurate with the expected frequency and consequences of challenges to the system, including consideration of uncertainty.      The redundancy, independence, and diversity of the containment subject to the Type A test is preserved, commensurate with the expected frequency and consequences of challenges to the system, as evidenced by the overall small change in risk associated with the Type A test frequency change. An assessment for uncertainty did not result in a change in the conclusions of this risk assessment.
: 4. Preserve adequate defense against potential CCFs. Adequate defense against common cause failures (CCFs) is preserved. The Type A test detects problems in the containment which may or may not be the result of a CCF; such a CCF may affect failure of another portion of containment (i.e., local penetrations) due to the same phenomena.
Adequate defense against CCFs is preserved via the continued performance of the Type B and C tests and the performance of inspections. The change to the Type A test interval, which bounds the risk associated with containment failure modes including those involving CCFs, does not degrade adequate defense as evidenced by the overall small change in risk associated with the Type A test frequency change.
5-24                                 SA-LAR-021

Risk Impact Assessment of Extending Salem Unit 1 ILRT Interval
: 5. Maintain multiple fission product barriers. Multiple Fission Product barriers are maintained. The portion of the containment affected by the Type A test extension is still maintained as an independent fission product barrier, albeit with an overall small change in the reliability of the barrier.
: 6. Preserve sufficient defense against human errors. Sufficient defense against human errors is preserved. The probability of a human error to operate the plant, or to respond to off-normal conditions and accidents is not affected by the change to the Type A testing frequency. Errors committed during test and maintenance may be reduced by the less frequent performance of the Type A test (less opportunity for errors to occur). As discussed in Section 4.1, an EPRI study [8] for shutdown risk (in which human errors generally have greater risk impacts) concluded that a small but measurable safety benefit is realized from extending the test intervals.
: 7. Continue to meet the intent of the plants design criteria. The intent of the plants design criteria continues to be met. The extension of the Type A test does not change the configuration of the plant or the way the plant is operated.
5-25                                   SA-LAR-021

Risk Impact Assessment of Extending Salem Unit 1 ILRT Interval 6.0     SENSITIVITIES 6.1     SENSITIVITY TO CORROSION IMPACT ASSUMPTIONS The results in Tables 5.2-2, 5.3-1, and 5.3-2 show that including corrosion effects calculated using the assumptions described in Section 4.4 does not significantly affect the results of the ILRT extension risk assessment.
Sensitivity cases were developed to gain an understanding of the sensitivity of the results to the key parameters in the corrosion risk analysis. The time for the flaw likelihood to double was adjusted from every five years to every two years and every ten years. The failure probabilities for the cylinder, dome and basemat were increased and decreased by an order of magnitude. The total detection failure likelihood was adjusted from 39% to 44% and 34%. The results are presented in Table 6.1-1. In almost every case, the impact from including the corrosion effects is small (e.g., less than 10%). Only the containment breach assumption has the potential to meaningfully increase the Class 3b LERF. Given this and the other conservative assumptions associated with the ILRT analysis, it is judged that the conclusions of this risk assessment should not change based on the corrosion impacts.
6-1                                  SA-LAR-021

Risk Impact Assessment of Extending Salem Unit 1 ILRT Interval TABLE 6.1-1 STEEL LINER CORROSION SENSITIVITY CASES VISUAL         INCREASE IN CLASS 3B FREQUENCY (LERF)
INSPECTION                  FOR ILRT EXTENSION CONTAINMENT            & NON-               FROM 3-IN-10 TO 1-IN-15 YEARS AGE (STEP 3 IN THE       BREACH             VISUAL CORROSION         (STEP 4 IN THE CORROSION           FLAWS ANALYSIS)                          (STEP 5 IN THE      TOTAL       INCREASE DUE ANALYSIS)                                                               %
CORROSION       INCREASE      TO CORROSION ANALYSIS)
CORROSION (PER YEAR)       (PER YEAR)
Base Case          Base Case Base Case (1.0% Cylinder-    (39% Cylinder-Doubles every                                           3.21E-08         1.25E-09          3.9%
Dome,              Dome, 5 yrs 0.1% Basemat)      100% Basemat)
Doubles every Base               Base          3.37E-08         2.77E-09          8.2%
2 yrs Doubles every Base               Base          3.19E-08         1.02E-09          3.2%
10 yrs 44% Cylinder-Base               Base                             3.23E-08         1.40E-09          4.3%
Dome 34% Cylinder-Base               Base                             3.20E-08         1.10E-09          3.4%
Dome 10% Cylinder-Base              Dome,               Base          4.33E-08         1.25E-08          29%
1% Basemat 0.1% Cylinder-Base              Dome,               Base          3.10E-08         1.25E-10          0.4%
0.01% Basemat LOWER BOUND 1.0% Cylinder-     34% Cylinder-Doubles every Dome,             Dome           3.10E-08         8.98E-11          0.3%
10 yrs 0.1% Basemat     100% Basemat UPPER BOUND 10% Cylinder-     44% Cylinder-Doubles every Dome,             Dome           6.19E-08         3.10E-08          50%
2 yrs 1% Basemat      100% Basemat 6-2                                 SA-LAR-021

Risk Impact Assessment of Extending Salem Unit 1 ILRT Interval 6.2      EPRI EXPERT ELICITATION SENSITIVITY An expert elicitation was performed to reduce excess conservatisms in the data associated with the probability of undetected leaks within containment [22]. Since the risk impact assessment of the extensions to the ILRT interval is sensitive to both the probability of the leakage as well as the magnitude, it was decided to perform the expert elicitation in a manner to solicit the probability of leakage as a function of leakage magnitude. In addition, the elicitation was performed for a range of failure modes which allowed experts to account for the range of failure mechanisms, the potential for undiscovered mechanisms, un-inspectable areas of the containment as well as the potential for detection by alternate means.          The expert elicitation process has the advantage of considering the available data for small leakage events, which have occurred in the data, and extrapolate those events and probabilities of occurrence to the potential for large magnitude leakage events.
The basic difference in the application of the ILRT interval methodology using the expert elicitation is a change in the probability of pre-existing leakage in the containment. The base case methodology uses the Jeffreys non-informative prior for the large leak size and the expert elicitation sensitivity study uses the results of the expert elicitation. In addition, given the relationship between leakage magnitude and probability, larger leakage that is more representative of large early release frequency can be reflected. For the purposes of this sensitivity, the same leakage magnitudes that are used in the base case methodology (i.e., 10 La for small and 100 La for large) are used here. Table 6.2-1 illustrates the magnitudes and probabilities of a pre-existing leak in containment associated with the base case leakage magnitudes and the expert elicitation statistical treatments. This sensitivity addresses releases from internal events (including internal flooding) but not the corrosion risk (which is assessed in separate sensitivities). Details of the expert elicitation process, and the input to expert elicitation as well as the results of the expert elicitation are available in the various appendices of the EPRI Guidance [22].
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Risk Impact Assessment of Extending Salem Unit 1 ILRT Interval TABLE 6.2-1 EPRI EXPERT ELICITATION RESULTS LEAKAGE SIZE (LA)           BASE CASE          EXPERT ELICITATION       PERCENT MEAN PROBABILITY        REDUCTION OF OCCURRENCE 10                    9.2E-03              3.88E-03               58%
100                    2.3E-03              2.47E-04               89%
A summary of the results using the expert elicitation values for probability of containment leakage is provided in Table 6.2-2. As mentioned previously, probability values are those associated with the magnitude of the leakage used in the base case evaluation (i.e., 10La for small and 100La for large). The expert elicitation process produces a probability versus leakage magnitude relationship in which it is possible to assess higher leakage magnitudes more reflective of large early releases but these evaluations are not performed in this study.
The net effect is that the reduction in the multipliers shown above has the same impact on the calculated increases in the LERF values. The increase in the overall probability of LERF (i.e., delta LERF) due to Class 3b sequences that is due to increasing the ILRT test interval from 3-in-10 years to 1-in-15 years is 3.32E-09/yr. Similarly, the delta LERF increase due to increasing the interval from 1-in-10 years to 1-in-15 years is 1.39E-09/yr.
As such, if the expert elicitation mean probabilities of occurrence are used instead of the non-informative prior estimates, the change in LERF for Salem is approximately an order of magnitude lower in the region of very small change in risk when compared to the current 1-in-10 or original 3-in-10 year requirement. The results of this sensitivity study are judged to be more indicative of the actual risk associated with the ILRT extension than the results from the base case assessment as dictated by the EPRI methodology values, and yet are still conservative given the assumption that all of the Class 3b contribution is considered to be LERF.
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Risk Impact Assessment of Extending Salem Unit 1 ILRT Interval TABLE 6.2-2 SALEM ILRT CASES:
BASE, 3 TO 10, AND 3 TO 15 YR EXTENSIONS (BASED ON EPRI [22] EXPERT ELICITATION LEAKAGE PROBABILITIES)
BASE CASE                    EXTEND TO                    EXTEND TO EPRI         DOSE             3-IN-10 YEARS                1-IN-10 YEARS                 1-IN-15 YEARS CLASS      PER-REM                          PER-                           PER-                       PER-CDF/YR                        CDF/YR                       CDF/YR REM/YR                         REM/YR                     REM/YR 1        1.64E+04      2.55E-06        4.18E-02       2.51E-06        4.12E-02     2.49E-06      4.09E-02 2        1.04E+07      7.62E-08        7.93E-01       7.62E-08        7.93E-01     7.62E-08      7.93E-01 3a        1.64E+05      1.30E-08        2.14E-03       4.34E-08        7.12E-03     6.51E-08      1.07E-02 3b        1.64E+06      8.29E-10        1.36E-03       2.76E-09        4.53E-03     4.15E-09      6.80E-03 7        1.87E+06      7.97E-07        1.49E+00       7.97E-07        1.49E+00     7.97E-07     1.49E+00 7-LERF       1.09E+07      3.15E-09        3.44E-02       3.15E-09        3.44E-02     3.15E-09      3.44E-02 8        5.41E+06      2.12E-07        1.14E+00       2.12E-07        1.14E+00     2.12E-07     1.14E+00 Total           --       3.65E-06        3.50E+00       3.65E-06        3.51E+00     3.65E-06     3.52E+00 ILRT Dose Rate from 3a and 3b                     3.50E-03                      1.16E-02                    1.75E-02 Delta      From 3 yr                 ---                        7.62E-03                    1.31E-02 Total Dose      From 10 yr
                                       ---                            ---                     5.46E-03 Rate(1) 3b Frequency (LERF)                 8.29E-10                      2.76E-09                    4.15E-09 Delta      From 3 yr                 ---                        1.93E-09                    3.32E-09 LERF From 10 yr                 ---                            ---                     1.39E-09 CCFP %                        29.84%                        29.89%                      29.93%
Delta      From 3 yr                 ---                         0.053%                      0.091%
CCFP %
From 10 yr                 ---                            ---                      0.038%
: 1. The overall difference in total dose rate is less than the difference of only the 3a and 3b categories between two testing intervals. This is because the overall total dose rate includes contributions from other categories that do not change as a function of time, e.g., the EPRI Class 2, Class 7-LERF and Class 8 categories, and also due to the fact that the Class 1 person-rem/yr decreases when extending the ILRT frequency.
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Risk Impact Assessment of Extending Salem Unit 1 ILRT Interval

==7.0    CONCLUSION==
S Based on the results from Section 5 and the sensitivity calculations presented in Section 6, the following conclusions regarding the assessment of the plant risk are associated with extending the Type A ILRT test frequency to fifteen years:
* RG 1.174 [4] provides guidance for determining the risk impact of plant-specific changes to the licensing basis. RG 1.174 defines very small changes in risk as resulting in increases of CDF less than 10-6/yr and increases in LERF less than 10-7/yr. Small changes in risk are defined as increases in CDF between 10-6/yr and 10-5/yr and increases in LERF between 10-7/yr and 10-6/yr. Since the ILRT does not impact CDF for Salem, the relevant criterion is LERF. The increase in internal events (including internal flooding) LERF resulting from a change in the Type A ILRT test interval from 3-in-10 years to 1-in-15 years is estimated as 3.2E-08/yr (i.e., in the very small change region using the acceptance guidelines of RG 1.174) using the EPRI Guidance [22] and including the risk impact of corrosion induced leakage. Without the corrosion impact, the increase in internal events LERF resulting from a change in the Type A ILRT test interval from 3-in-10 years to 1-in-15 years decreases slightly to 3.1E-08/yr.
* When external event risk is included, the increase in LERF resulting from a change in the Type A ILRT test interval from 3-in-10 years to 1-in-15 years is estimated as 7.6E-07/yr (i.e., in the small change region using the acceptance guidelines of RG 1.174) and the total LERF is 6.8E-06/yr using the EPRI Guidance and including the risk impact of corrosion induced leakage. Therefore the risk increase is small using the acceptance guidelines of RG 1.174.
* With regards to population dose risk, the EPRI Guidance [22] states that a very small population dose is defined as an increase of <1.0 person-rem/yr or <1% of the total population dose, whichever is less restrictive.
For a change in Salem Type A test frequency from 3-in-10 years to 1-in-15 years for those accident sequences influenced by Type A testing and including the risk impact of corrosion induced leakage, the increase in dose risk from internal events (including internal flooding) is 7.0E-2 person-rem/yr, which is 2% of the population dose risk. This meets the EPRI criterion for very small (i.e., <1.0 person-rem/yr).
* The increase in the conditional containment failure frequency from the 3-in-10 year interval to a 1-in-15 year interval is about 0.88% using the EPRI Guidance [22], and decreases to about 0.09% using the EPRI Expert Elicitation methodology. Per the EPRI Guidance, increases of CCFP<1.5% are considered to be very small.
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Risk Impact Assessment of Extending Salem Unit 1 ILRT Interval Based on the application of the conservative EPRI methodology for Salem, increasing the ILRT interval to 15 years is not considered to be significant since it represents a small change to the Salem risk profile.
Previous Assessments The NRC in NUREG-1493 [5] has previously concluded that:
* Reducing the frequency of Type A tests (ILRTs) from 3-in-10 years to 1-in-20 years was found to lead to an imperceptible increase in risk. The estimated increase in risk is very small because ILRTs identify only a few potential containment leakage paths that cannot be identified by Type B and C testing, and the leaks that have been found by Type A tests have been only marginally above existing requirements.
* Given the insensitivity of risk to containment leakage rate and the small fraction of leakage paths detected solely by Type A testing, increasing the interval between integrated leakage-rate tests is possible with minimal impact on public risk. The impact of relaxing the ILRT frequency beyond 1-in-20 years has not been evaluated. Beyond testing the performance of containment penetrations, ILRTs also test the integrity of the containment structure.
The findings for Salem confirm these general findings on a plant specific basis considering the severe accidents evaluated for Salem, the Salem containment failure modes, and the local population surrounding Salem.
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Risk Impact Assessment of Extending Salem Unit 1 ILRT Interval

==8.0  REFERENCES==

[1]  Nuclear Energy Institute, Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J, NEI 94-01, Revision 3-A, July 2012.
[2]  Electric Power Research Institute, Risk Impact Assessment of Revised Containment Leak Rate Testing Intervals, EPRI TR-104285, August 1994.
[3]  Letter from A. Pietrangelo (NEI) to NEI Administrative Points of Contact, Interim Guidance for Performing Risk Impact Assessments in Support of One-Time Extensions for Containment Integrated Leak Rate Test Surveillance Intervals, November 13, 2001.
[4]  U.S. Nuclear Regulatory Commission, An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis, Regulatory Guide 1.174, Revision 3, January 2018.
[5]  U.S. Nuclear Regulatory Commission, Performance-Based Containment Leak-Test Program, NUREG-1493, September 1995.
[6]  Letter from R.J. Barrett (Entergy) to U.S. Nuclear Regulatory Commission, IPN-01-007, dated January 18, 2001.
[7]  United States Nuclear Regulatory Commission, Indian Point Nuclear Generating Unit No. 3 - Issuance of Amendment Re: Frequency of Performance-Based Leakage Rate Testing (TAC No. MB0178), April 17, 2001.
[8]  ERIN Engineering and Research, Shutdown Risk Impact Assessment for Extended Containment Leakage Testing Intervals Utilizing ORAMTM, EPRI TR-105189, Final Report, May 1995.
[9]  PSEG Nuclear, LLC letter to NRC forwarding the Salem Units 1 & 2 License Renewal Application, August 18, 2009.
[10] Oak Ridge National Laboratory, Impact of Containment Building Leakage on LWR Accident Risk, NUREG/CR-3539, ORNL/TM-8964, April 1984.
[11] Pacific Northwest Laboratory, Reliability Analysis of Containment Isolation Systems, NUREG/CR-4220, PNL-5432, June 1985.
[12] U.S. Nuclear Regulatory Commission, Technical Findings and Regulatory Analysis for Generic Safety Issue II.E.4.3 Containment Integrity Check, NUREG-1273, April 1988.
[13] Pacific Northwest Laboratory, Review of Light Water Reactor Regulatory Requirements, NUREG/CR-4330, PNL-5809, Vol. 2, June 1986.
[14] U.S. Nuclear Regulatory Commission, Severe Accident Risks: An Assessment for Five U.S. Nuclear Power Plants, NUREG -1150, December 1990.
[15] U.S. Nuclear Regulatory Commission, Reactor Safety Study, WASH-1400, October 1975.
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[16] Salem Generating Station PRA Notebook - Quantification Notebook, SA-PRA-014, Revision 3, October 2022.
[17] Salem Generating Station Probabilistic Risk Analysis - Level 2 Analysis, SA-PRA-015, Revision 4, September 2022.
[18] Salem Generating Station Individual Plant Examination of External Events, Public Service Electric and Gas Company, January 1996.
[19] Response to Request for Additional Information Concerning the License Amendment Request for a One-Time Integrated Leakage Rate Test Extension, Letter from Mr. C. H. Cruse (Calvert Cliffs Nuclear Power Plant) to NRC Document Control Desk, Docket No. 50-317, March 27, 2002.
[20] Letter from D.E. Young (Florida Power) to U.S. Nuclear Regulatory Commission, 3F0401-11, dated April 25, 2001.
[21] Letter from A. Pietrangelo (NEI) to NEI Administrative Points of Contact, One-Time Extension of Containment Integrated Leak Rate Test Interval - Additional Information, November 30, 2001.
[22] Electric Power Research Institute, Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals: Revision 2-A of 1009325. Report #
1018243, October 2008.
[23] Salem Generating Station U1 License Amendment Request Type A One-Time Extension, September 21, 2009, ML092730362.
[24] Salem Generating Station Fire Probabilistic Risk Assessment, Summary, Quantification, and Uncertainty Notebook, SA-PRA-104, Rev. 0, October 2022.
[25] U.S. Nuclear Regulatory Commission, Acceptability of Probabilistic Risk Assessment Results for Risk-Informed Activities, Regulatory Guide 1.200, Revision 3, December 2020.
[26] U.S. Nuclear Regulatory Commission, Generic Environmental Impact Statement for License Renewal of Nuclear Plants Regarding Hope Creek Generating Station and Salem Nuclear Generating Station, Units 1 and 2 NUREG-1437 Supplement 45, March 2011.
[27] PSEG Nuclear letter to NRC, Response to Request for Additional Information Regarding License Amendment Request for One-Time Extension of the Type A Test Interval, February 24, 2010, ML100630695.
[28] Salem Generating Station Unit 1 July 2016 ILRT Test Report, ILRT Inc.,
SAL1ILRT.16-R160728A.
[29] Salem Generating Station Unit 2 November 2015 ILRT Test Report, ILRT Inc.,
SAL2ILRT.15-R151214A.
[30] Salem Generating Station Unit 2 ILRT Extension, S-C-ZZ-MEE-1613, Revision 1, March 2002, ML021000416.
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[31] U.S. Nuclear Regulatory Commission, Generic Issue 199 (GI-199), Implications of Updated Probabilistic Seismic Hazard Estimates in Central and Eastern United States on Existing Plants Safety/Risk Assessment, August 2010.
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Risk Impact Assessment of Extending Salem Unit 1 ILRT Interval Appendix A - PRA Technical Acceptability Appendix A PRA Technical Acceptability SA-LAR-021

Risk Impact Assessment of Extending Salem Unit 1 ILRT Interval Appendix A - PRA Technical Acceptability A.1     Overview Regulatory Guide 1.200 [A-1] provides guidance for determining the technical acceptability of Probabilistic Risk Assessment (PRA) results for risk-informed activities.
The majority of the items identified in RG 1.200 (i.e., Section C.3) pertain to the alignment and use of the PRA to support the application and are addressed in the main portion of this risk assessment and through the implementation of industry methodologies (e.g., [A-2]). RG 1.200 Section C.3.3 identifies two aspects to demonstrating the acceptability of the portions of the PRA used to support an application. The first aspect is the assurance that the portions of the PRA used in the application have been developed and performed in a technically correct manner. The second aspect is the assurance that the assumptions and approximations used in developing the PRA are appropriate. These two aspects are primarily addressed through the application of industry standards for PRA development, a PRA model configuration control program, and peer review of the PRA models and configuration control program. Portions of the second aspect are also addressed via the sensitivity cases performed for the ILRT risk assessment using the EPRI methodology as documented in the main report.
Note that for this application, the accepted methodology involves a bounding approach to estimate the change in LERF from extending the ILRT interval. Rather than exercising the PRA model itself, it involves the establishment of separate calculations that are linearly related to the plant CDF contribution that is not already LERF. Consequently, a reasonable representation of the plant CDF that is not LERF is all that is required for the application. The analysis included several sensitivity studies and factored in the potential impacts from external events in a bounding fashion. Since the accepted process utilizes a bounding analysis approach which is mostly driven by that CDF contribution which does not already lead to LERF, there are no identified key assumptions or sources of uncertainty for this application other than those already incorporated using the industry methodology.
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Risk Impact Assessment of Extending Salem Unit 1 ILRT Interval Appendix A - PRA Technical Acceptability This ILRT risk assessment uses recently completed Internal Event (including Internal Flooding) and Fire PRA models. There are no other approved PRA models (e.g., seismic) for Salem. Other external events were evaluated as discussed in the main report.
A.2               Internal Events and Internal Flood PRA The latest Salem Internal Events and Internal Flood model (SA121A) was used for this risk assessment as documented in the Level 1 and Level 2 PRA quantification notebooks
[A-3, A-4]. This model update was completed in October 2022. The SGS PRA modeling is highly detailed, including a wide variety of initiating events, modeled systems, operator actions, and common cause events. The PRA model quantification process used for the SGS PRA is based on the event tree / fault tree methodology, which is a well-known methodology in the industry.
This latest model is a successor model of a previously peer reviewed PRA model. In November 2008, a Pressurized Water Reactors Group (PWROG) team completed a peer review [A-5] of the Salem Revision 4.1 PRA Model using the Nuclear Energy Institute (NEI) process for performing follow-on PRA peer reviews to determine compliance with Part 2 and Part 3 of the ASME PRA Standard [A-6] and RG 1.200 [A-7]. The peer review identified Finding-level Facts and Observations (F&O) and by January 2019, all open F&Os were resolved and considered closed by the F&O Closure Team, which was documented in the F&O Closure Teams independent assessment and focused-scope peer review report [A-8].
Changes after the Revision 4.1 internal events (and internal flooding) model through the previous periodic update (SA112A) included the following:
* Revision 4.2 (March 2009) - Refined failure modes for service water valves to support local operation credit when permissible.
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Risk Impact Assessment of Extending Salem Unit 1 ILRT Interval Appendix A - PRA Technical Acceptability
* Revision 4.3 (December 2009) - Refined AC power modeling, HVAC procedure improvements, and resolved some peer review findings such as scrubbing to reduce LERF and more detailed modeling of offsite power recovery.
* Revision SA112A (September 2014) - Periodic update. Modeling changes included offsite power recovery logic refinements to ensure non-recovery probabilities applied, verification of annualized basis for support system fault tree initiator logic, additional credit for Control Area Ventilation based on operator interviews and pruning of unused gates.
* Revision SA115A (December 2016) - Periodic update. Modeling changes included credit for 4th AFW pump to support MSPI and SBO event tree enhancements to model use of FLEX equipment.
All of the changes made between the Revision 4.2 model and the SA115A model are considered PRA maintenance activities, including changes made to support closure of the 2008 Peer Review F&Os.
The changes made to the internal events (including internal flooding) PRA model (SA121A) as part of the 2022 periodic update included the following:
* Modeling refinements to reflect recent plant modifications (e.g., SW valves)
* Updating of internal flood modeling (e.g., including aging factors, refinement of spray scenarios)
* Inclusion of additional suction sources for AFW
* Unit cross-tie credit refinements (e.g., CVCS)
* Refinements to support the Fire PRA model development (which is built upon the internal events model)
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Risk Impact Assessment of Extending Salem Unit 1 ILRT Interval Appendix A - PRA Technical Acceptability
* Refinements to human actions credit based on revised plant procedures and operator interviews
* Refinements to support FLEX modeling
* Revised modeling of SGTR based on PWROG-21024-P [A-13] which is based on the updated NRC induced SGTR research in NUREG-2195.
All of the above model changes except that associated with the SGTR modeling are considered PRA maintenance activities (i.e., not an upgrade to the PRA which would require a follow-on focused scope peer review).            The revised SGTR modeling was considered a method change that warranted a Focused Scope Peer Review (FSPR). The FSPR was conducted in October 2022 and the results indicated that 100% of the LE SRs were met at Capability Category II or higher [A-14]. There was one suggestion and one note of an Unreviewed Analysis Method pertaining to the TI-SGTR methodology from the PWROG. It was noted that the method was implemented appropriately and that this issue has low significance provided the method passes the newly developed method peer review. As such, there is no immediate impact on the ILRT application.
The Salem PRA model is controlled in accordance with station procedures which defines the process for implementing regularly scheduled and interim PRA model updates, for tracking issues identified as potentially affecting the PRA models (e.g., due to changes in the plant, errors or limitations identified in the model, industry operating experience), and for controlling the model and associated computer files. To ensure that the current PRA model remains an accurate reflection of the as-built, as-operated plants, the following activities are routinely performed:
* Design changes and procedure changes are reviewed for their impact on the PRA model.
* New engineering calculations and revisions to existing calculations are reviewed for their impact on the PRA model.
* Plant specific initiating event frequencies, failure rates, and maintenance unavailabilities are updated via periodic model updates.
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Risk Impact Assessment of Extending Salem Unit 1 ILRT Interval Appendix A - PRA Technical Acceptability A PRA updating requirements evaluation (URE, a PRA model update tracking database item) is created for all issues that are identified that could impact the PRA model. The URE database includes the identification of those plant changes that could impact the PRA model. A review of the current open items in the URE database identified no items with significant potential impact upon the ILRT risk assessment as the latest PRA model was just recently completed. The majority of the open UREs related to tracking model rollout activities, the online risk models, suggestions for minor refinements, documentation related items, and tracking of expected future plant modifications (i.e., not yet installed). A few UREs reflected model changes that would be expected to lower the quantified CDF/LERF thereby making the current model used for the ILRT assessment potentially conservative.
Based on the above, the internal events (including internal flooding) PRA model is deemed acceptable to perform this ILRT risk evaluation A.3    Fire PRA Model A Unit 1 Fire PRA model (SA121A-F) was just recently completed for Salem as documented in the Fire Quantification Notebook [A-10]. (A Unit 2 model has not yet been completed.) This Fire PRA model contains highly detailed modeling commensurate with the internal events model, but including the phenomenology associated with internal fire events.
Similar to the Internal Events PRA, the Fire PRA is controlled in accordance with station procedures which defines the process for implementing regularly scheduled and interim PRA model updates, for tracking issues identified as potentially affecting the PRA models, and for controlling the model and associated computer files. A URE item is created for all issues that are identified that could impact the Fire PRA model. A review of the current open items in the URE database identified no items with significant potential impact upon the ILRT risk assessment as the latest Fire PRA model was just recently completed. The majority of the open Fire PRA UREs related to tracking of expected future plant A-6                                     SA-LAR-021

Risk Impact Assessment of Extending Salem Unit 1 ILRT Interval Appendix A - PRA Technical Acceptability modifications (i.e., not yet installed). A few UREs reflected model changes that would be expected to have minimal impact on CDF/LERF.
As noted previously, a reasonable representation of the plant CDF that is not LERF is all that is required for the application. The analysis included several sensitivity studies and factored in the potential impacts from external events in a bounding fashion. Since the accepted process utilizes a bounding analysis approach which is mostly driven by that CDF contribution which does not already lead to LERF, a peer review of the Fire PRA is not necessarily required for the ILRT application.
In any event, this Fire PRA model received a Peer Review in October 2022 against the ASME PRA Standard [A-11]. The peer review indicated that ~90% of the applicable supporting requirements are met at Category II or higher. This provides a high level of confidence that the results used for the bounding ILRT assessment provide a reasonable approximation of the fire risk at the site. The peer review identified Finding-level Facts and Observations (F&Os) as documented in the Peer Review Report [A-12].                   For completeness, Table A-1 summarizes the Unit 1 Fire PRA findings and their potential impact upon this ILRT risk assessment.
For the ILRT extension assessment, a bounding analysis approach is utilized which is driven by that CDF contribution which does not already lead to LERF. With that in mind, a single bounding assessment is performed to estimate the maximum contribution from the Fire PRA that would still lead to acceptable results for the ILRT assessment. Based on the assessment provided in Section 5.7, a Fire CDF of 8.4E-5/yr and a Fire LERF of 8.4E-6/yr would still lead to results that would meet the acceptance criteria for the ILRT extension. This would represent more than 15% increase in Fire CDF and more than a 50% increase in Fire LERF from the results used in this assessment. Although addressing the findings from the peer review could lead to increases in Fire CDF and Fire LERF in some instances, addressing other items and additional refinements will also lead to reductions in the final Fire CDF and Fire LERF numbers. Therefore, it is judged that it is reasonable to assume that the maximum aggregate net impact by addressing the findings A-7                                    SA-LAR-021

Risk Impact Assessment of Extending Salem Unit 1 ILRT Interval Appendix A - PRA Technical Acceptability will lead to a Fire CDF of less than 8.4E-5/yr and a Fire LERF of less than 8.4E-6/yr, such that the conclusions from the ILRT extension assessment will not change. Additionally, as noted previously if the results from the IPEEE for Salem Fire Risk were used rather than the updated Fire PRA, the results would still be acceptable.
Based on the above, the Salem Fire PRA is deemed acceptable to perform this ILRT risk evaluation TABLE A-1

==SUMMARY==
OF FINDINGS APPLICABLE TO THE UNIT 1 SALEM FIRE PRA MODEL SR Finding Description                         Impact on ILRT Application (F&O #)
PP-B2,      There are non-rated barriers (walkway              None - documentation only. Need to Met         openings, open shaft, operations openings),        provide documented justification for the (01-002)    that are not justified in the plant partitioning   non-rated barriers credited for these PAU notebook.                                          to PAU interactions.
PP-B6,      There are buildings identified within the GAB      None - documentation only. Need to Met         that are qualitatively screened that do not        update Table A-1 to include the location (01-001)    appear to be identified as PAUs. This can          key/building and if the location generate traceability problems on how the          qualitatively screens.
different PAUs are treated in the Fire PRA.
PP-B6,      The PAU "YARD" is inconsistently defined           Minimal impact - addressing this issue Met         between the PP notebook and the IGN                will lead to slight shifts in the ignition (01-008)    notebook.                                          frequencies for some scenarios, but will not significantly impact the results.
PP-C3,      Certain PAUs developed for the fire PRA are        None - documentation only. Need to add Met         not able to be located (e.g., captured in          drawing references or better describe the (01-003)    drawings and/or described).                        PAUs not documented in the Salem FHA.
ES-A5,      The consideration for the treatment of 92-18,      Minimal impact - addressing this issue Met         over torque of MOVs due to hot shorts that         will not have a significant impact on the (03-004)    bypass the torque switches does not appear to      results (if any).
be evaluated for valves included in the FPRA.
ES-B4,      A difference was observed on the disposition       Minimal impact - addressing this issue Met         the CCF basic event RPS-LOG-FC-TRNAB               will not have a significant impact on the (03-005)    between appendices in the ES notebook and          results.
the FRANX tables.
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Risk Impact Assessment of Extending Salem Unit 1 ILRT Interval Appendix A - PRA Technical Acceptability TABLE A-1

==SUMMARY==
OF FINDINGS APPLICABLE TO THE UNIT 1 SALEM FIRE PRA MODEL SR Finding Description                       Impact on ILRT Application (F&O #)
ES-D1,   In multiple instances of the ES notebook, it      None - documentation only. Need to Met      references Section 3.1.3 of the PRM notebook,     update the ES notebook to correct the (03-001) SA-PRA-102 for the implementation of the Fire     section and appendix references to the Initiating Events Decision Trees (FIEDT). This is PRM notebook.
the wrong section in the PRM notebook.
ES-D1,   Section 3.1.2 of the ES notebook identifies that  None - documentation only. Need to Met      any additional dependencies identified during     update Section 3.1.2 of the ES notebook (03-002) the cable selection were applied as additional    to be similar to Section 3.2.4.
failures of that equipment by mapping the interlocked component to the basic event for the primary component. This does not match the process identified in Section 3.2.4 of the ES notebook that identifies the process of adding the dependencies to the FPRA logic model.
CS-A1,   Samples of incomplete cable selection were        Although addressing this issue might lead Not Met  identified.                                       to increases in the Fire CDF and LERF (02-004)                                                   values, the aggregate impact is not expected to significantly alter the final Fire CDF or LERF values such that the conclusions from the ILRT assessment would be impacted.
CS-A10,  Two raceway segments (a conduit and a cable       Minimal impact - addressing this issue Met      terminal end) in the route of cable 1A11X-A       will not have a significant impact on the (02-014) were determined to be lacking a fire area         results.
location(s) in FRANX.
CS-B1,   Overcurrent current protection and coordination   Although addressing this issue might lead Met      has not been assessed for electrical distribution to increases in the Fire CDF and LERF (02-008) bus "13KV AC South Bus" or for branch circuits    values, the aggregate impact is not (typically fuses in low voltage AC and DC         expected to significantly alter the final distribution networks) fed from power supplies    Fire CDF or LERF values such that the that are credited in the Fire PRA plant response  conclusions from the ILRT assessment model.                                            would be impacted.
A-9                                            SA-LAR-021

Risk Impact Assessment of Extending Salem Unit 1 ILRT Interval Appendix A - PRA Technical Acceptability TABLE A-1

==SUMMARY==
OF FINDINGS APPLICABLE TO THE UNIT 1 SALEM FIRE PRA MODEL SR Finding Description                       Impact on ILRT Application (F&O #)
CS-B1,   Circuits were identified whose failure could       Although addressing this issue might lead Met      challenge power supply availability due to         to increases in the Fire CDF and LERF (02-009) inadequate electrical overcurrent protective       values, the aggregate impact is not device coordination have not been incorporated     expected to significantly alter the final into the plant response model for the              Fire CDF or LERF values such that the associated power supply, or whose failure could    conclusions from the ILRT assessment challenge switchgear availability due to loss of   would be impacted.
overcurrent trip protection for electrically operated circuit breakers with their power cable in the initiating fire.
CS-C1,   Use of term "Fire Zone" in Sections 2.2, 3.7.2,    None - documentation only. Need to Met      and 4.2.2 of SA-PRA-109 is incorrect as the        update Sections 2.2, 3.7.2, and 4.2.2 of (02-019) Salem Fire PRA PAUs are not defined by fire        SA-PRA-109 to remove reference to the zone.                                              term Fire Zone and replace with the term Fire Area.
CS-C3,   Fire PRA documentation (SA-PRA-109 and             Although addressing this issue might lead Not Met  FDM) does not include documentation of             to increases in the Fire CDF and LERF (02-007) specific cables, their raceways and cable          values, the aggregate impact is not terminal end locations, for which a PAU            expected to significantly alter the final location(s) (fire area[s]) has been assumed.       Fire CDF or LERF values such that the This information needs to be explicitly identified conclusions from the ILRT assessment such that the fire modeling activity can           would be impacted.
appropriately consider and map these targets to fire scenarios.
CS-C3,   The wording for SA-PRA-109, Section 2.2,           Although addressing this issue might lead Not Met  assumptions no. 3 and 4 should either be           to increases in the Fire CDF and LERF (02-020) removed from SA-PRA-109, or reworded in SA-        values, the aggregate impact is not PRA-109 to address how fire area location(s)       expected to significantly alter the final are assumed for situations where the cable         Fire CDF or LERF values such that the terminal ends and/or connecting raceways are       conclusions from the ILRT assessment located in different fire areas which may be       would be impacted.
adjacent, or which may not be adjacent.
QLS-A3,  Areas listed in Table 4-2 of the fire PRA          Minimal impact - addressing this issue Met      Notebook SA-PRA-101 Rev 0, which list the          will not have a significant impact on the (07-001) qualitatively screened PAUs are later quantified   results.
in the Fire PRA. Examples of this condition is the fire pump house S58 and 1-FA-CONPOL-100. The latter was qualitatively screened but has a frequency calculated for it.
A-10                                            SA-LAR-021

Risk Impact Assessment of Extending Salem Unit 1 ILRT Interval Appendix A - PRA Technical Acceptability TABLE A-1

==SUMMARY==
OF FINDINGS APPLICABLE TO THE UNIT 1 SALEM FIRE PRA MODEL SR Finding Description                         Impact on ILRT Application (F&O #)
PRM-A4,  Several components (approximately 55 valves          Although addressing this issue might lead Not Met  and instruments) are identified as requiring         to increases in the Fire CDF and LERF (03-006) circuit analysis in the ES notebook and mapped       values, the aggregate impact is not to an equipment functional state, these              expected to significantly alter the final functional states have circuit analysis identified   Fire CDF or LERF values such that the in the CS notebook, however they are missing         conclusions from the ILRT assessment cable mapping in the FRANX component to              would be impacted.
cable table.
PRM-A4,  An undeveloped event in the Unit 1 model is          Minimal impact - addressing this issue Not Met  missing the consideration of the Unit 2 service      will not have a significant impact on the (03-008) water components to be potentially damage by         results.
fire scenarios considered in the Unit 1 model.
PRM-B1,  The main body of the PRM notebook identifies         None - documentation only. Need to Met      that the FPIE model is SA121, however the            update the PRM notebook to reference (03-009) references section and road map section              the SA121 model and FPIE identify that it is SA115. It was confirmed that     documentation.
the model of record utilized was the SA121.
PRM-B6,  The MCR abandonment model for loss of                Minimal impact - addressing this issue Met      habitability is not appropriately modeled to         will not have a significant impact on the (03-023) quantify the scenarios that can lead to              results.
abandonment from loss of habitability. The event SCENARIOS-ABANDON transfer gate is not populated with the scenario fire initiators in the one-top model.
PRM-B10, Some components from the FPIE that are not           Although addressing this issue might lead Not Met  credited in the FPRA model have not been             to increases in the Fire CDF and LERF (03-011) modeled for the worst possible failure mode.         values, the aggregate impact is not expected to significantly alter the final Fire CDF or LERF values such that the conclusions from the ILRT assessment would be impacted.
PRM-C1,  The Plant Response Model Notebook SA-PRA-            None - documentation only. Need to Met      102 Revision 0 contains some section pointers        update the PRM notebook to section and (03-012) in the roadmaps contained in the PRM                 reference links.
Notebook that are referencing the wrong section.
FSS-A4,  Some severe scenarios are missing from the           Minimal impact - addressing this issue Met      FRANX files and potentially from quantification. will not have a significant impact on the (01-016)                                                      results.
A-11                                              SA-LAR-021

Risk Impact Assessment of Extending Salem Unit 1 ILRT Interval Appendix A - PRA Technical Acceptability TABLE A-1

==SUMMARY==
OF FINDINGS APPLICABLE TO THE UNIT 1 SALEM FIRE PRA MODEL SR Finding Description                       Impact on ILRT Application (F&O #)
FSS-A5,  The fire modeling does not assess the impact of Minimal impact - addressing this issue Met      non-cable secondary combustibles (i.e., HVAC will not have a significant impact on the (06-013) insulation or other) when modeling fire growth    results.
and propagation. For example, the chillers in 1FA-EP-100G have foam insulation on the chiller and associated piping.
FSS-A5,  The Fire Scenario Development Notebook            Minimal impact - addressing this issue Met      identifies that transient scenarios are only      will not have a significant impact on the (06-014) modeled at vertical cable risers and at cable     results.
tray intersections with multiple cable trays.
There are no transient scenarios postulated near equipment to assess the risk impact of potentially impacting multiple components.
The Fire Scenario Development Notebook identifies that transient scenarios were assigned a generic 100 ft2 floor area as opposed to a specific floor area that could impact the targets.
FSS-B2,  Transient fire scenarios in the Main Control      Minimal impact - addressing this issue Met      Room are not included in the scenarios            will not have a significant impact on the (06-012) quantified for the MCR.                           results.
FSS-C5,  Detailed fire modeling scenarios developed in     Minimal impact - addressing this issue Met      the Fire Modeling Workbook do not consider        will not have a significant impact on the (06-018) the lower damage thresholds associated with       results.
sensitive electronic targets.
FSS-C7,  There is no discussion in the Fire Modeling       Minimal impact - addressing this issue Not Met  Treatments Notebook that the Salem Fire PRA       will not have a significant impact on the (06-017) evaluates and properly models dependencies        results.
among the credited paths including dependencies associated with recovery of a failed fire suppression system, if such recovery is credited as required by the standard.
FSS-E4,  The assumed routing is not characterized in the   None - documentation only. Need to run Not Met  Salem Fire PRA documentation.                     and document a sensitivity study for (01-010)                                                   cables in the Fire PRA that had assumed routing.
A-12                                            SA-LAR-021

Risk Impact Assessment of Extending Salem Unit 1 ILRT Interval Appendix A - PRA Technical Acceptability TABLE A-1

==SUMMARY==
OF FINDINGS APPLICABLE TO THE UNIT 1 SALEM FIRE PRA MODEL SR Finding Description                       Impact on ILRT Application (F&O #)
FSS-F2,  Appendix A of the structural steel notebook       None - documentation only. Need to Met      does not discuss the fire size considered for the update the report to include that Appendix (01-014) main feedwater pumps.                             A concludes that for the large oil fire no collapse is postulated.
FSS-F3,  The quantification for the fire scenarios         Minimal impact - addressing this issue Not Met  resulting in building collapse do not have all    will not have a significant impact on the (01-009) targets failed in the FRANX model.                results.
FSS-G3,  The MCA Notebook currently screens the            Minimal impact - addressing this issue Met      boundary between the Unit 1 and Unit 2            will not have a significant impact on the (06-002) Turbine Buildings based on the area being         results.
open to the outside, however, this only applies to the 140' elevation and the lower elevations are separated by physical barriers.
FSS-G4,  There are PAUs with open boundaries to            Minimal impact - addressing this issue Met      adjacent PAUs in the MCA that utilize a barrier   will not have a significant impact on the (06-007) failure probability other than 1.0.               results.
FSS-G6,  The unscreened MCA scenarios (PAU                 Although addressing this issue might lead Not Met  combinations) are not included in the             to increases in the Fire CDF and LERF (06-008) Quantification.                                   values, the aggregate impact is not expected to significantly alter the final Fire CDF or LERF values such that the conclusions from the ILRT assessment would be impacted.
FSS-H1,  During the Peer Review Walkdown of select         None - documentation only. Need to Met      PAU scenarios, a few documentation issues         correct the elevation of the U1 Turbine (06-003) related to the fire scenario sheets were          Building transient fire scenario, and revise identified.                                       the Fire Scenario Development Notebook scenario sheets to Include the documentation of cables excluded from specific fire scenarios. Also need to temove targets/components from the scenario sheets that are no longer in the model.
A-13                                            SA-LAR-021

Risk Impact Assessment of Extending Salem Unit 1 ILRT Interval Appendix A - PRA Technical Acceptability TABLE A-1

==SUMMARY==
OF FINDINGS APPLICABLE TO THE UNIT 1 SALEM FIRE PRA MODEL SR Finding Description                         Impact on ILRT Application (F&O #)
FSS-H1,  The fire modeling results (frequency, non-         None - documentation only. Need to Met      suppression probability, severity factor, target   provide a clear roadmap to follow the fire (06-015) set) are located in different tables in multiple   modeling results in order for ease of notebooks with no clear roadmap to follow the      review and provide additional detail in the calculations in the development of the results. Fire Scenario Development Notebook to correlate scenario IDs to specific sources and transient locations.
FSS-H8,  The MCA Notebook does not identify the             None - documentation only. Need to Not Met  assigned fire ignition frequency, non-             document the ignition sources and/or fire (06-009) suppression probability, or severity factor to     scenarios and applicable associated establish which individual fire sources or groups  characteristics that are used to develop of sources result in the development of HGL in     the frequency of occurrence of the MCA the PAU combinations.                              scenarios to be quantified.
FSS-H9,  There is no documentation of the key sources       None - documentation only. Need to Not Met  of uncertainty in FSS.                             identify and document the key sources of (01-015)                                                    uncertainty in the FSS technical element.
FSS-H10, The Fire Scenario Walkdown Notebook does           None - documentation only. Need to Met      not include the actual fire modeling walkdown      include the walkdown notes in Appendix (06-019) notes in Appendix A.                               A of the Notebook.
IGN-A7,  There is no ignition frequency apportioned for     Minimal impact - addressing this issue Met      Bin 29. Bin 35 has a count of 1, whereas it        will not have a significant impact on the (01-006) should have a total count of 2.                    results.
IGN-A7,  The Unit 1 and Unit 2 Diesel Generator Building Minimal impact - addressing this issue Met      PAUs, the Unit 1 and Unit 2 Fuel Handling Area will not have a significant impact on the (06-006) Building PAUs, and the Radioactive Waste           results.
Storage Area PAU are grouped with the CAR not plant wide areas.
IGN-A7,  Iso-phase bus duct counting is counted in an       Minimal impact - addressing this issue Met      area with no iso-phase bus duct connection         will not have a significant impact on the (01-004) points. This may distort the iso- phase bus duct   results.
frequency apportioned to other areas.
A-14                                            SA-LAR-021

Risk Impact Assessment of Extending Salem Unit 1 ILRT Interval Appendix A - PRA Technical Acceptability TABLE A-1

==SUMMARY==
OF FINDINGS APPLICABLE TO THE UNIT 1 SALEM FIRE PRA MODEL SR Finding Description                         Impact on ILRT Application (F&O #)
IGN-A7,   Self-Ignited Cable fire frequency is apportioned    Minimal impact - addressing this issue Met       among PAUs, but is not required due to              will not have a significant impact on the (01-012)  thermoset insulation. Self- ignited cable fires     results.
are not postulated in detailed fire modeling.
For PAUs that are not in the HA (for example 1FA-CWSWGR,Duct Bank 1), there are no cable weights assigned for the CFWC frequencies (Bins 5, 11, and 31).
IGN-A7,   The hydrogen piping on the roof of the Unit 1       Minimal impact - addressing this issue Met       and Unit 2 Auxiliary Building are counted in the    will not have a significant impact on the (01-013)  PAU "Yard" or the switchyard (at ground level). results.
Due to the change in elevation and physical location of the auxiliary building roof to the switchyard, this apportionment is non-appropriate.
IGN-A9,   PAUs 1FA-AB-100C, 1FA-AB-64B, 1FA-AB-               Minimal impact - addressing this issue Met       84B, 2FA-AB-100C, 2FA-AB-64B, and 2FA-AB- will not have a significant impact on the (01-011)  84B Reactor Plant Auxiliary Building Equipment results.
areas are identified as having a HIGH occupancy factor which does not appear to align with the use of the areas as HIGH would apply to continually occupied areas.
Additionally, PAU 12FA-ADM-100 does not have transient factors assigned in Appendix B.
IGN-B3,   Several issues related to documentation of          Minimal impact - addressing this issue Met       Salem specific counting that can be improved        will not have a significant impact on the (01-005)  for usability and updating were identified.         results.
CF-A1,    To achieve SR Capability Category II, SA-PRA-       None - results are currently conservative Met Cat I 113 needs to include additional criteria (or refer  and further refinements would reduce the (02-002)  to another Fire PRA Notebook where the              risk associated with the ILRT criteria is considered for application of hot short assessment.
duration probability).
CF-A1,    SA-PRA-113 does not describe the                    None - results are currently conservative Met Cat I methodology and does not require collection of      and further refinements would reduce the (02-001)  all data necessary to assign circuit failure        risk associated with the ILRT probability values based on assessment of           assessment.
specific circuit configuration under consideration for risk-significant contributors.
A-15                                             SA-LAR-021

Risk Impact Assessment of Extending Salem Unit 1 ILRT Interval Appendix A - PRA Technical Acceptability TABLE A-1

==SUMMARY==
OF FINDINGS APPLICABLE TO THE UNIT 1 SALEM FIRE PRA MODEL SR Finding Description                        Impact on ILRT Application (F&O #)
HRA-A3,   One instance [S1.OP-AR.ZZ-0011(Q), 57,             None - documentation only. Need to Met       CONTROL AIR PRESSURE LO,                           correct documentation.
(08-008)  COMPRESSED AIR SYSTEM (Bezel 2-3)] was identified where the disposition in Appendix F was incorrect and an ARP identified as Not Relevant was in fact cited as a procedure in the HRA Calculator.
HRA-A4,   Operator interviews to establish clear conditions Minimal impact - addressing this issue Met       for the Loss of Control MCR Abandonment            will not have a significant impact on the (08-003)  scenario were not performed.                       results.
HRA-C1,   Of the ~23 risk significant individual HFEs for    None - results are currently conservative Met Cat I CDF based on FV >0.005, there are 8 HFEs           and further refinements would reduce the (08-005)  quantified with screening values, 4 of which are   risk associated with the ILRT not related to MCRA. Other findings already        assessment.
discuss MCRA quantification and documentation issues.
HRA-E1,   Although there are tables in the PRM Notebook      None - documentation only. Need to Met       that correlate the HFEs to the fire areas for      enhance documentation related to MCR (08-004)  which MCRA is relevant, and supplementary          abandonemtn scenarios.
spreadsheets that identify procedure steps for the HFEs, this information does not provide the depth and breadth of information required to explain the approach.
FQ-A1,    The use of the "Fire Impacts" table in FRANX is Minimal impact - addressing this issue Not Met   not well described so that the quantification      will not have a significant impact on the (07-002)  results can be understood. Examples on the         results.
treatment of targets in the Fire Impacts table for the structural steel scenarios and the main control board scenarios was not clear and could not be reviewed.
FQ-A1,    A number of fire areas in the cable routing        Minimal impact - addressing this issue Not Met   database do not have corresponding PAUs            will not have a significant impact on the (07-003)  defined in plant partitioning. Therefore, Fire     results.
PRA cables in these areas are not captured in the quantification process.
A-16                                             SA-LAR-021

Risk Impact Assessment of Extending Salem Unit 1 ILRT Interval Appendix A - PRA Technical Acceptability TABLE A-1

==SUMMARY==
OF FINDINGS APPLICABLE TO THE UNIT 1 SALEM FIRE PRA MODEL SR Finding Description                         Impact on ILRT Application (F&O #)
FQ-A3,   Selected scenarios appear to be missing the          Minimal impact - addressing this issue Met      control room abandonment flag. An example of         will not have a significant impact on the (07-005) one of these scenarios is 1FA- AB-100A-03.           results.
This particular scenario is resulting in a CCDP of 1.0.
FQ-E1,   Although the model meets the standard                Although addressing this issue might lead Not Met  definition of ability to identify significant        to increases in the Fire CDF and LERF (05-004) sequences and basic events, the current results      values, the aggregate impact is not are dominated by a few areas which have been         expected to significantly alter the final identified during the course of the peer reivew      Fire CDF or LERF values such that the to have issues which may have skewed the             conclusions from the ILRT assessment relative importance of modeled elements. When        would be impacted.
these are corrected and the results/truncation levels are recalculated it is assumed that there will be a significant shift in the results and insights.
FQ-E1,   The quantification results shall be reviewed,        Although addressing this issue might lead Not Met  and significant contributors to CDF (and LERF),      to increases in the Fire CDF and LERF (05-003) such as initiating events, accident sequences,       values, the aggregate impact is not and basic events shall be identified. Part of        expected to significantly alter the final HLR-QU-D requires that the importance, both          Fire CDF or LERF values such that the large and small, be reviewed to determine that       conclusions from the ILRT assessment they make logical sense. Although this effort        would be impacted.
was performed, it is not believed to have been sufficient to identify some major issues present in the current results.
FQ-F1,   The FQ notebook does not include the material        None - documentation only. Need to Not Met  required in the back references HLR-QU-F and         expand the material in the FQ notebooks (07-004) HLR-LE-G and their SRs in Part 2.                    with insights and discussions as required in QU-F2, F2, F4 and LE-G2, G3 and G4 as required by the standard.
FQ-F2,   FQ Notebook SA-PRA-104 Rev 0 Section 3.5             None - documentation only. Need to Not Met  describes the bases for non-applicability of         correct the statement in Section 3.5 of FQ (07-023) requirements. The section states that no new         Notebook SA-PRA-104 Rev 0 associated circular logic was introduced. However, PRM          with circular logic.
log indicates resolution of circular logic issues.
A-17                                           SA-LAR-021

Risk Impact Assessment of Extending Salem Unit 1 ILRT Interval Appendix A - PRA Technical Acceptability TABLE A-1

==SUMMARY==
OF FINDINGS APPLICABLE TO THE UNIT 1 SALEM FIRE PRA MODEL SR Finding Description                         Impact on ILRT Application (F&O #)
UNC-A1,  A comprehensive uncertainty and sensitivity         None - ILRT methodology only utilizes Not Met  analysis has not been completed. UNCERT             the total CDF and that portion which is (07-006) runs are completed and documented, but a            not LERF in the assessment.
systematic assessment of uncertainties and assumptions as related to the Salem Fire PRA has not been developed or documented.
UNC-A2,  The treatment of uncertainties, including explicit None - ILRT methodology only utilizes Not Met  modeling through parametric uncertainties,          the total CDF and that portion which is (07-007) sensitivity analyses or qualitative dispositions,   not LERF in the assessment.
from different Fire PRA tasks was not completed. Some individual Fire PRA In addition, Notebooks (e.g., SA-PRA-16 Rev 0 for detailed fire modeling) do not have the treatment of uncertainties necessary to support the requirements in UNC-A2.
A-18                                           SA-LAR-021

Risk Impact Assessment of Extending Salem Unit 1 ILRT Interval Appendix A - PRA Technical Acceptability A.4    Summary A PRA technical acceptability evaluation was performed consistent with the requirements of RG-1.200 [A-1]. This evaluation combined with the details of the results of this analysis demonstrate with reasonable assurance that the proposed permanent extension to the ILRT interval for Salem to fifteen years satisfies the risk acceptance guidelines in RG 1.174 [A-9].
A-19                                       SA-LAR-021

Risk Impact Assessment of Extending Salem Unit 1 ILRT Interval Appendix A - PRA Technical Acceptability A.5                References
[A-1] U.S. Nuclear Regulatory Commission, Acceptability of Probabilistic Risk Assessment Results for Risk-Informed Activities, Regulatory Guide 1.200, Revision 3, December 2020.
[A-2] Electric Power Research Institute, Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals: Revision 2-A of 1009325. Report #
1018243, October 2008.
[A-3] Salem Generating Station PRA Notebook - Quantification Notebook, SA-PRA-014, Revision 3, October 2022.
[A-4] Salem Generating Station Probabilistic Risk Analysis - Level 2 Analysis, SA-PRA-015, Revision 4, September 2022.
[A-5] Westinghouse, RG 1.200 PRA Peer Review Against the ASME PRA Standard Requirements for the Salem Generating Station, Units 1 and 2 Probabilistic Risk Assessment, LTR-RAM-II-09-001, June 2009.
[A-6] American Society of Mechanical Engineers, Standard for Probabilistic Risk Assessment for Nuclear Power Plant Applications, ASME RA-S-2002, Addenda RA-Sb-2005, December 2005.
[A-7] U.S. Nuclear Regulatory Commission, An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities, Regulatory Guide 1.200, Revision 1.
[A-8] Jensen Hughes, PRA Finding-Level Fact and Observation Independent Assessment & Focused Scope Peer Review, 003059-RPT-02, Revision 0.
[A-9] U.S. Nuclear Regulatory Commission, An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis, Regulatory Guide 1.174, Revision 3, January 2018.
[A-10] Salem Generating Station Fire Probabilistic Risk Assessment, Summary, Quantification, and Uncertainty Notebook, SA-PRA-104, Rev. 0, October 2022.
[A-11] American Society of Mechanical Engineers, Standard for Level 1 / Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications, ASME/ANS RA-Sa-2009, 2009.
[A-12] PWROG, Peer Review of the Salem Units 1 and 2 Fire Probabilistic Risk Assessment, PWROG-22025-P, Revision 0, January 2023.
[A-13] PWR Owners Group, PWROG LERF/ Simplified Level 2 PRA Methodology, PWROG-21024-P Revision 0-A, December 2021.
[A-14] Jensen Hughes, Salem Generating Station, Focused Scope Peer Review of Level 2 ISGTR Analysis (PRA Standard Element LE), SA-MISC-030, October 2022.
A-20                                    SA-LAR-021}}