ML24099A157
| ML24099A157 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 05/29/2024 |
| From: | James Kim Plant Licensing Branch 1 |
| To: | Mcfeaters C Public Service Enterprise Group |
| Kim J | |
| References | |
| EPID L 2023 LLA 0094 | |
| Download: ML24099A157 (1) | |
Text
May 29, 2024 Charles V. McFeaters President and Chief Nuclear Officer PSEG Nuclear LLC - N09 P.O. Box 236 Hancocks Bridge, NJ 08038
SUBJECT:
SALEM NUCLEAR GENERATING STATION, UNIT NOS. 1 AND 2 ISSUANCE OF AMENDMENT NOS. 348 AND 330 RE: PERMANENT EXTENSION OF TYPE A AND TYPE C CONTAINMENT LEAK RATE TEST FREQUENCIES (EPID L-2023-LLA-0094)
Dear Charles McFeaters:
The U.S. Nuclear Regulatory Commission (the Commission) has issued the enclosed Amendment Nos. 348 and 330 to Renewed Facility Operating License Nos. DPR-70 and DPR-75 for the Salem Nuclear Generating Station, Unit Nos. 1 and 2, respectively. These amendments consist of changes to the technical specification (TS) in response to your application dated June 23, 2023.
The amendments revise the Salem Nuclear Generating Station, Units 1 and 2, Technical Specification 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 and the conditions and limitations specified in NEI 94-01, Revision 2-A.
C. McFeaters A copy of the related safety evaluation is also enclosed. A Notice of Issuance will be included in the Commissions monthly Federal Register notice.
Sincerely,
/RA/
James S. Kim, Project Manager Plant Licensing Branch I Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket Nos. 50-272 and 50-311
Enclosures:
- 1. Amendment No. 348 to DPR-70
- 2. Amendment No. 330 to DPR-75
- 3. Safety Evaluation cc: Listserv PSEG NUCLEAR LLC CONSTELLATION ENERGY GENERATION, LLC DOCKET NO. 50-272 SALEM NUCLEAR GENERATING STATION, UNIT NO. 1 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 348 Renewed License No. DPR-70 1.
The U.S. Nuclear Regulatory Commission (the Commission) has found that:
A.
The application for amendment filed by PSEG Nuclear LLC, acting on behalf of itself and Exelon Generation Company, LLC (the licensees), dated June 23, 2023, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commissions rules and regulations set forth in 10 CFR Chapter I; B.
The facility will operate in conformity with the application, the provisions of the Act, and the rules and regulations of the Commission; C.
There is reasonable assurance: (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commissions regulations; D.
The issuance of this amendment will not be inimical to the common defense and security or to the health and safety of the public; and E.
The issuance of this amendment is in accordance with 10 CFR Part 51 of the Commissions regulations and all applicable requirements have been satisfied.
2.
Accordingly, the license is amended by changes to the Technical Specifications as indicated in the attachment to this license amendment, and paragraph 2.C.(2) of Renewed Facility Operating License No. DPR-70 is hereby amended to read as follows:
(2)
Technical Specifications and Environmental Protection Plan The Technical Specifications contained in Appendix A, as revised through Amendment No. 348, and the Environmental Protection Plan contained in Appendix B, are hereby incorporated in the renewed license. PSEG Nuclear LLC shall operate the facility in accordance with the Technical Specifications, and the Environmental Protection Plan.
3.
This license amendment is effective as of its date of issuance and shall be implemented within 60 days of the date of issuance.
FOR THE NUCLEAR REGULATORY COMMISSION Hipólito González, Chief Plant Licensing Branch I Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation
Attachment:
Changes to Renewed Facility Operating License and Technical Specifications Date of Issuance: May 29, 2024 HIPOLITO GONZALEZ Digitally signed by HIPOLITO GONZALEZ Date: 2024.05.29 15:02:16 -04'00'
ATTACHMENT TO LICENSE AMENDMENT NO. 348 SALEM NUCLEAR GENERATING STATION, UNIT NO. 1 RENEWED FACILITY OPERATING LICENSE NO. DPR-70 DOCKET NO. 50-272 Replace the following page of Renewed Facility Operating License No. DPR-70 with the attached revised page as indicated. The revised page is identified by amendment number and contains a marginal line indicating the area of change.
Remove Insert Replace the following page of the Appendix A, Technical Specifications, with the attached revised page as indicated. The revised page is identified by amendment number and contain marginal lines indicating the areas of change.
Remove Insert 6-19 6-19 Renewed License No. DPR-70 Amendment No. 348 (4)
PSEG Nuclear LLC, pursuant to the Act and 10 CFR Parts 30, 40 and 70 to receive, possess and use at any time any byproduct, source and special nuclear material as sealed neutron sources for reactor startup, sealed sources for reactor instrumentation and radiation monitoring equipment calibration, and as fission detectors in amounts as required; (5)
PSEG Nuclear LLC, pursuant to the Act and 10 CFR Parts 30, 40 and 70, to receive, possess and use in amounts as required any byproduct, source or special nuclear material without restriction to chemical or physical form, for sample analysis or instrument calibration or associated with radioactive apparatus or components; and (6)
PSEG Nuclear LLC, pursuant to the Act and 10 CFR Parts 30 and 70, to possess but not separate, such byproduct and special nuclear materials as may be produced by the operation of the facility.
C. This renewed license shall be deemed to contain and is subject to the conditions specified in the following Commission regulations in 10 CFR Chapter I: Part 20, Section 30.34 of Part 30, Section 40.41 of Part 40, Sections 50.54 and 50.59 of Part 50, and Section 70.32 of Part 70; and is subject to all applicable provisions of the Act and to the rules, regulations, and orders of the Commission now or hereafter in effect; and is subject to the additional conditions specified or incorporated below:
(1)
Maximum Power Level PSEG Nuclear LLC is authorized to operate the facility at a steady state reactor core power level not in excess of 3459 megawatts (one hundred percent of rated core power).
(2)
Technical Specifications and Environmental Protection Plan The Technical Specifications contained in Appendix A, as revised through Amendment No. 348, and the Environmental Protection Plan contained in Appendix B, are hereby incorporated in the renewed license. PSEG Nuclear LLC shall operate the facility in accordance with the Technical Specifications, and the Environmental Protection Plan.
(3)
Deleted Per Amendment 22, 11-20-79 (4)
Less than Four Loop Operation PSEG Nuclear LLC shall not operate the reactor at power levels above P-7 (as defined in Table 3.3-1 of Specification 3.3.1.1 of Appendix A to this renewed license) with less than four (4) reactor coolant loops in operation until safety analyses for less than four loop operation have been submitted by the licensees and approval for less than four loop operation at power levels above P-7 has been granted by the Commission by Amendment of this renewed license.
(5)
PSEG Nuclear LLC shall implement and maintain in effect all provisions of the approved fire protection program as described in the Updated Final Safety
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 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 peak calculated containment internal pressure for the design basis loss of coolant accident, Pa, is 47.0 psig.
The maximum allowable containment leakage rate, La, at Pa, shall be 0.1% of primary containment air weight per day.
Leakage Rate Acceptance Criteria are:
- a.
Primary containment leakage rate acceptance criterion is less than or equal to 1.0 La. During the first unit startup SALEM - UNIT 1 6-19 Amendment No. 348 PSEG NUCLEAR LLC CONSTELLATION ENERGY GENERATION, LLC DOCKET NO. 50-311 SALEM NUCLEAR GENERATING STATION, UNIT NO. 2 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 330 Renewed License No. DPR-75
- 1.
The U.S. Nuclear Regulatory Commission (the Commission) has found that:
A.
The application for amendment filed by PSEG Nuclear LLC, acting on behalf of itself and Exelon Generation Company, LLC (the licensees), dated June 23, 2023, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commissions rules and regulations set forth in 10 CFR Chapter I; B.
The facility will operate in conformity with the application, the provisions of the Act, and the rules and regulations of the Commission; C.
There is reasonable assurance: (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commissions regulations; D.
The issuance of this amendment will not be inimical to the common defense and security or to the health and safety of the public; and E.
The issuance of this amendment is in accordance with 10 CFR Part 51 of the Commissions regulations and all applicable requirements have been satisfied.
2.
Accordingly, the license is amended by changes to the Technical Specifications as indicated in the attachment to this license amendment, and paragraph 2.C.(2) of Renewed Facility Operating License No. DPR-75 is hereby amended to read as follows:
(2)
Technical Specifications and Environmental Protection Plan The Technical Specifications contained in Appendix A, as revised through Amendment No. 330, and the Environmental Protection Plan contained in Appendix B, are hereby incorporated in the renewed license. PSEG Nuclear LLC shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.
3.
This license amendment is effective as of its date of issuance and shall be implemented within 60 days of the date of issuance.
FOR THE NUCLEAR REGULATORY COMMISSION Hipólito González, Chief Plant Licensing Branch I Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation
Attachment:
Changes to Renewed Facility Operating License and Technical Specifications Date of Issuance: May 29, 2024 HIPOLITO GONZALEZ Digitally signed by HIPOLITO GONZALEZ Date: 2024.05.29 15:02:38 -04'00'
ATTACHMENT TO LICENSE AMENDMENT NO. 330 SALEM NUCLEAR GENERATING STATION, UNIT NO. 2 RENEWED FACILITY OPERATING LICENSE NO. DPR-75 DOCKET NO. 50-311 Replace the following page of Renewed Facility Operating License No. DPR-75 with the attached revised page as indicated. The revised page is identified by amendment number and contains a marginal line indicating the area of change.
Remove Insert Replace the following page of the Appendix A, Technical Specifications, with the attached revised page as indicated. The revised page is identified by amendment number and contains marginal lines indicating the areas of change.
Remove Insert 6-19 6-19 Renewed License No. DPR-75 Amendment No. 330 (3)
PSEG Nuclear LLC, pursuant to the Act and 10 CFR Part 70, to receive, possess and use at any time special nuclear material as reactor fuel, in accordance with the limitations for storage and amounts required for reactor operation, as described in the Final Safety Analysis Report, as supplemented and amended; (4)
PSEG Nuclear LLC, pursuant to the Act and 10 CFR Parts 30, 40 and 70, to receive, possess and use at any time any byproduct, source or special nuclear material as sealed neutron sources for reactor startup, sealed sources for reactor instrumentation and radiation monitoring equipment calibration and as fission detectors in amounts as required; (5)
PSEG Nuclear LLC, pursuant to the Act and 10 CFR Parts 30, 40 and 70, to receive, possess and use in amounts as required any byproduct, source or special nuclear material without restriction to chemical or physical form, for sample analysis or instrument calibration or associated with radioactive apparatus or components; and (6)
PSEG Nuclear LLC, pursuant to the Act and 10 CFR Parts 30, 40 and 70, to possess but not separate, such byproduct and special nuclear materials as may be produced by the operation of the facility.
C. This renewed license shall be deemed to contain and is subject to the conditions specified in the Commissions regulations set forth in 10 CFR Chapter I and is subject to all applicable provisions of the Act and to the rules, regulations and orders of the Commission now or hereafter in effect; and is subject to the additional conditions specified or incorporated below:
(1)
Maximum Power Level PSEG Nuclear LLC is authorized to operate the facility at steady state reactor core power levels not in excess of 3459 megawatts (thermal).
(2)
Technical Specifications and Environmental Protection Plan The Technical Specifications contained in Appendix A, as revised through Amendment No. 330, and the Environmental Protection Plan contained in Appendix B, are hereby incorporated in the renewed license. PSEG Nuclear LLC shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.
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 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 peak calculated containment internal pressure for the design basis loss of coolant accident, Pa, is 47.0 psig.
The maximum allowable containment leakage rate, La, at Pa, shall be 0.1% of primary containment air weight per day.
Leakage Rate Acceptance Criteria are:
- a.
Primary containment leakage rate acceptance criterion is less than or equal to 1.0 La. During the first unit startup following testing in accordance with this program, the leakage rate SALEM - UNIT 2 6-19 Amendment No. 330 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NOS. 348 AND 330 TO RENEWED FACILITY OPERATING LICENSE NOS. DPR-70 AND DPR-75 PSEG NUCLEAR LLC CONSTELLATION ENERGY GENERATION, LLC SALEM NUCLEAR GENERATING STATION, UNIT NOS. 1 AND 2 DOCKET NOS. 50-272 AND 50-311
1.0 INTRODUCTION
By application dated June 23, 2023 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML23174A186), PSEG Nuclear LLC (PSEG or the licensee) submitted a license amendment request (LAR) for the Salem Nuclear Generating Station (Salem or SNGS), Units 1 and 2.
The amendments propose changes to TS 6.8.4.f, Primary Containment Leakage Rate Testing Program, to allow for the permanent extension of the Type A Integrated Leak Rate Testing (ILRT) and Type C Leak Rate Testing frequencies based on the guidance in NEI [Nuclear Energy Institute] 94-01, Revision 3-A, Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J, dated July 2012 (ML12221A202).
Specifically, the proposed change will revise Salem Units 1 and 2 Technical Specification (TS) 6.8.4.f by replacing the references to Regulatory Guide (RG) 1.163, Performance-Based Containment Leak-Test Program, (ML003740058) with a reference to NEI 94-01, Revision 3-A, and the limitations and conditions specified in NEI 94-01, Revision 2-A, of the same name, dated October 2008 (ML100620847), as the documents used to implement the performance-based containment leakage testing program in accordance with Option B of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix J, Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors.
2.0 REGULATORY EVALUATION
2.1 Background
Pages 4-7 of the LAR described the Salem Containment System.
Description of Salem Containment System:
The Salem 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 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 10 CFR 50, 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 RG 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-feet elevation of the containment structure for retaining coating debris to mitigate recirculating water flow blockage following a design basis accident.
Liner Insulation The liner insulation extends from just above the bottom floor at elevation 78 feet to approximately elevation 110 feet except locally around some liner penetrations and around other interferences. The insulation consists of 2-inch-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 American Society of Mechanical Engineers (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.
Pressure and monitoring taps are provided to pressure test the double gaskets on each door to a "between the seals test pressure" of 10 pounds per square inch gauge (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 10 CFR Part 50, 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 Units 1 and 2 are not required to be Type B tested for 10 CFR Part 50, 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 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 10 CFR Part 50, 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 150 degrees Fahrenheit (°F). 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 271 °F 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.
There are 56 electrical penetrations per unit.
2.2 Licensees Proposed Changes The LARs proposed change will revise Salem, Units 1 and 2, TS 6.8.4.f, Primary Containment Leakage Rate Testing Program, by replacing the reference to RG 1.163 with a reference to NEI 94-01, Revision 3-A, and the conditions and limitations specified in NEI 94-01, Revision 2-A.
Additionally, the licensee proposed deletion of Salem, Units 1 and 2, TS 6.8.4.f paragraph a.
Paragraph a is an exception that addresses the performance of a specific Salem Type A test.
The exception was for activities that have already taken place and are no longer applicable.
2.3 Regulatory Requirements Under 10 CFR 50.90, whenever a holder of a license wishes to amend the license, including technical specifications in the license, an application for amendment must be filed, fully describing the changes desired. Under 10 CFR 50.92(a), determinations on whether to grant an applied-for license amendment are to be guided by the considerations that govern the issuance of initial licenses or construction permits to the extent applicable and appropriate. Both the common standards in 10 CFR 50.40(a), and those specifically for issuance of operating licenses in 10 CFR 50.57(a)(3), provide that there must be reasonable assurance that the activities at issue will not endanger the health and safety of the public.
As stated in the introduction section in Option BPerformance-Based Requirements" of Appendix J to 10 CFR Part 50 one of the conditions required of all operating licenses for light-water-cooled power reactors as specified in 10 CFR 50.54(o) is that primary reactor containments meet the leakage-rate test requirements in either Option A or B of Appendix J to 10 CFR Part 50. These test requirements ensure that (a) leakage through these containments or systems and components penetrating these containments does not exceed allowable leakage rates specified in the technical specifications; and (b) integrity of the containment structure is maintained during its service life. Option B of Appendix J identifies the performance-based requirements and criteria for preoperational and subsequent periodic leakage-rate testing.
The U.S. Nuclear Regulatory Commission (NRC) regulatory requirements related to the content of the TSs are contained in 10 CFR 50.36, Technical specifications. The regulations in 10 CFR 50.36(c)(5), Administrative controls, state, in part:
Administrative controls are the provisions relating to organization and management, procedures, recordkeeping, review and audit, and reporting necessary to assure operation of the facility in a safe manner.
The regulations in 10 CFR 50.55a, Codes and standards, contain the containment inservice inspection (ISI) requirements, which, in conjunction with the requirements of 10 CFR Part 50, Appendix J, ensure the continued leak-tight and structural integrity of the containment during its service life.
Section V.B.3 of 10 CFR Part 50, Appendix J, Option B, states that the RG or other implementation document used by a licensee to develop a performance-based leakage-testing program must be included, by general reference, in the plant TSs. The submittal for TS revisions must contain justification, including supporting analyses, if the licensee deviates from methods approved by the NRC and endorsed in an RG.
Option B of Appendix J to 10 CFR Part 50, specifies performance-based requirements and criteria for preoperational and subsequent leakage rate testing. These requirements are met by performing (1) Type A tests to measure the containment system overall integrated leakage rate, (2) Type B pneumatic tests to detect and measure local leakage rates across pressure leakage-limiting boundaries such as penetrations, and (3) Type C pneumatic tests to measure containment isolation valve leakage rates.
After the containment system has been completed and is ready for operation, Type A tests are conducted at periodic intervals based on the historical performance of the overall containment system to measure the overall integrated leakage rate. The leakage rate test results must not exceed the maximum allowable leakage (La) at design-basis LOCA pressure (Pa) with margin, as specified in the TSs. Option B also requires that a general visual inspection for structural deterioration of the accessible interior and exterior surfaces of the containment system be conducted prior to each Type A test and at a periodic interval between tests based on the performance of the containment system. A general visual inspection is necessary as structural deterioration of the surfaces of the containment system may affect the containments leak-tight integrity.
Type B and Type C tests are performed based on the safety significance and historical performance of each boundary and isolation valve to ensure integrity of the overall containment system as a barrier to fission product release.
The adoption of the Option B performance-based containment leakage rate testing for Types A, B, and C testing does not alter the basic method by which Appendix J to 10 CFR Part 50 leakage rate testing is performed; however, it does alter the frequency at which Types A, B, and C containment leakage tests must be performed. Under the performance-based option of 10 CFR Part 50, Appendix J, the test frequency is based upon an evaluation that reviews as-found leakage history to determine the frequency for leakage testing, which provides assurance that leakage limits will be maintained.
2.4 Regulatory Guidance NEI 94-01, Revision 0 (ML11327A025), provides methods for complying with the provisions of 10 CFR Part 50, Appendix J, Option B, and includes provisions that address the extension of the performance-based Type A test interval for up to 10 years, based upon two consecutive successful tests. Salem adopted Option B of 10 CFR Part 50, Appendix J, for integrated (Type A) and local (Types B and C) leakage rate testing with Amendments Nos. 207 and 188 (Salem, Unit 1 and 2, respectively) (ML011720334) and is part of the current Salem licensing bases for Units 1 and 2.
NEI 94-01, Revision 2-A, incorporates the regulatory positions stated in RG 1.163 and delineates a performance-based approach for determining Types A, B, and C containment leakage rate testing frequencies. It also includes provisions for extending Type A ILRT intervals to up to 15 years. This approach uses industry performance, plant-specific data, and risk insights in determining the appropriate testing frequency, and discusses the performance factors that licensees must consider in determining test intervals. In a letter dated June 25, 2008 (ML081140105), the NRC published a safety evaluation (SE) with limitations and conditions for NEI 94-01, Revision 2, and Electric Power Research Institute (EPRI) Report No. 1009325 (ML072970204).
NEI 94-01, Revision 3-A, provides guidance for extending Type C local leakage rate test (LLRT) intervals beyond 60 months. The NRC published an SE with limitations and conditions for NEI 94-01, Revision 3, by letter dated June 8, 2012 (ML121030286). In the SE, the NRC concluded that NEI 94-01, Revision 3, describes an acceptable approach for implementing the optional performance-based requirements of 10 CFR Part 50, Appendix J, and is acceptable for referencing by licensees proposing to amend their containment leakage rate testing TSs, subject to two conditions. The SE was incorporated into Revision 3 and subsequently issued as NEI 94-01, Revision 3-A, in July 2012.
EPRI Report No. 1009325, Revision 2-A1, provides a generic assessment of the risks associated with a permanent extension of the ILRT surveillance interval to 15 years, and a risk-informed methodology to be used to confirm the risk impact of the ILRT extension on a plant-specific basis. Probabilistic risk assessment (PRA) methods are used, in combination with ILRT performance data and other considerations, to justify the extension of the ILRT surveillance interval. This is consistent with guidance provided in RG 1.174, Revision 3, An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis (ML17317A256), and RG 1.177, Revision 1, An Approach for Plant-Specific, Risk-Informed Decision-making: Technical Specifications (ML1100910008), to support changes to surveillance test intervals.
3.0 TECHNICAL EVALUATION
3.1 Integrated Leak Rate Testing History (Type A Testing)
At Salem, a Type A ILRT is currently required to be performed once every 10 years. The LAR proposes extending the maximum Type A test interval to 15 years. The NRC staff notes that in 1 EPRI Report 1018243 is also identified as EPRI Report 1009325, Revision 2-A. This report is publicly available and can be found at www.epri.com by typing 1018243 in the search box.
Amendment No. 296 (ML102000445) and Amendment No. 232 (ML020720154), the NRC has previously approved one-time (Type A test) interval increases from a maximum of a 10-year interval to a maximum 15-year interval, for Salem, Units 1 and 2, respectively.
Per TS 6.8.4.f, Salem specified a maximum allowable containment leakage rate La of 0.10 percent of the primary containment air weight per day at the calculated peak pressure, Pa.
TS 6.8.4.f indicates that the peak calculated containment internal pressure for the DBLOCA, Pa, is 47.0 psig.
For Salem, the licensee has performed six ILRTs on the Salem Unit 1 containment building and five ILRTs on the Salem Unit 2 containment building.
The LAR provided the ILRT results which show substantial margin has been maintained relative to the performance criterion for the most recent Type A tests, so the extended interval would be allowed by the NEI 94-01, Revision 3-A, guidance for Salem. The test results of these ILRTs were documented in LAR Sections 3.3.4 and 3.3.5. The most recent test results for Salem, Units 1 and 2, are summarized in table 3.1.1 below.
TABLE 3.1.1 Salem Type A ILRT History Test Date Pa (psig)
(1)
Pt Test Pressure (psig)
(2)
Upper 95%
Confidence Limit (UCL)
(wt%/day)
As-Found Acceptance Criteria (wt%/day)
As-Left Acceptance Criteria (wt%/day)
Unit 1
May 2001 47.0 47.63 0.0038 0.10 (1.0 La) 0.075 (0.75 La)
July 2016 47.0 45.97 0.0693 0.10 (1.0 La) 0.075 (0.75 La)
Unit 2
Oct 2006 47.0 46.1 0.0276 0.10 (1.0 La) 0.075 (0.75 La)
Nov 2015 47.0 46.05 0.0141 0.10 (1.0 La) 0.075 (0.75 La)
Table 3.1.1 Notes:
(1) Pa - As defined in Salem TS 6.8.4.f (2) Pt - Final test Pressure (psig) - minimum allowable Pt is 0.96 Pa psig = 45.12 psig
(
Reference:
ANSI/ANS-56.8-1994, Section 3.2.11)
Section 9.1.2, Test Interval, of NEI 94-01 Revision 3-A states, in part, The elapsed time between the first and the last tests in a series of consecutive passing tests used to determine performance shall be at least 24 months. As shown in table 3.1.1 of this SE, the data in this table is consistent with the methodology required by NEI 94-01, Revision 3-A, Section 9.1.2, and therefore has been satisfied.
Salem TS 6.8.4.f currently references RG 1.163. Section C, Regulatory Position, of RG 1.163 states, in part, that NEI 94-01, Revision 0, provides methods acceptable to the NRC staff for complying with the provisions of Option B in Appendix J to 10 CFR Part 50.
Section 9.2.3, Extended Test Intervals, of NEI 94-01, Revision 0, states, in part, that:
In reviewing past performance history, Type A test results may have been calculated and reported using computational techniques other than the Mass Point method from ANSI/ANS [American National Standards Institute/American Nuclear Society]-56.8-1994 (e.g., Total Time or Point-to-Point). Reported test results from these previously acceptable Type A tests can be used to establish the performance history. Additionally, a licensee may recalculate past Type A Upper Confidence Limit (UCL) (using the same test intervals as reported) in accordance with ANSI/ANS-56.8-1994 Mass Point methodology and its adjoining Termination criteria in order to determine acceptable performance history.
NEI 94-01, Revision 3-A, includes substantively identical language except for referring to ANSI/ANS-56.8-2002, Containment System Leakage Testing Requirements, instead of ANSI/ANS 56.8-1994.
The NRC staff notes that this language does not include recalculation of past Type A test results to demonstrate conformance with the definition of performance leakage rate contained in NEI 94-01, Revision 3-A. The NRC staff also notes that the Salem ILRT results since the Units 1 and 2 startups, has demonstrated ample margin (i.e., >30 percent for Unit 1 and >72 percent for Unit 2) between each UCL leakage value and La.
Salem TS 6.8.4.f (i.e., Primary Containment Leakage Rate Testing Program) establishes the maximum limit for the as-left leakage rate for startup following completion of Type A testing at 0.75 La, which currently equals 0.075 percent of containment air weight per day.
Salem TS 6.8.4.f specifies a leakage rate La not to exceed 0.10 percent of containment air weight per day at the calculated peak pressure, Pa. As displayed in Table 3.3.4-1, Periodic Type A ILRT Results of the LAR, there has been adequate margin to the performance limit as described in TS 6.8.4.f of La for the historical ILRTs since startup for Salem.
The past ILRT results for Salem since startup have confirmed that the primary containment leakage rates are acceptable with respect to the design criterion leakage of containment air weight (La) per day. Since the last two Type A tests for Salem had as found test results well within the current maximum allowable containment leakage rate specified in TS 6.8.4.f of 0.10 weight-percent/day (1.0 La), the Type A test frequency could be extended to 15 years in accordance with NEI 94-01, Revision 3-A and the conditions and limitations of NEI 94-01, Revision 2-A.
Based on the above, the NRC staff concludes that the Salem ILRT test results provide reasonable assurance that containment overall leakage will be maintained below the design-basis leak rate, consistent with the requirements in TS 6.8.4.f, and will fulfill the requirements of 10 CFR 50, Appendix J, Option B, with the test frequency of 15 years.
3.2 Type B and C Testing The LAR proposes extending the containment isolation valve (CIV) leakage rate testing (Type C) frequency from the 60 months currently permitted by 10 CFR Part 50, Appendix J, Option B, to a 75-month frequency for Type C leakage rate testing of selected components, in consistent with NEI 94-01, Revision 3-A.
The Salem 10 CFR Part 50 Appendix J, Type B and Type C leakage rate test program requires testing of electrical penetrations, airlocks, hatches, flanges, and containment isolation valves within the scope of the program, as required by 10 CFR 50, Appendix J, Option B and TS 6.8.4.f. There are 60 Type B penetrations for Salem, which include two personnel hatches, an equipment hatch, fuel transfer tube, and 56 electrical penetrations. 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 ILRT. 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. Therefore, containment piping penetrations designed for Salem are not required to be Type B tested for 10 CFR 50, Appendix J.
The NRC staff reviewed the local leak rate summaries contained in LAR Section 3.5.6 Containment Leakage Rate Testing Program - Type B and Type C Testing Program. For Salem, the combined Type B and Type C leakage acceptance criterion is 0.60 La (129,770 standard cubic centimeters per minute (sccm)). Therefore, La equals 216,284 sccm. NEI 94-01, Revision 3-A Section 10.2 indicates that the combined as-found minimum pathway leakage rate of all Type B and C tests shall be less than 0.60 La when containment operability is required. In addition, if Type B or C testing occurred during an outage, the combined as-left maximum pathway leakage rate for all penetrations subject to Type B or C tests shall be less than 0.60 La before entering a mode where containment operability is required.
The NRC staff notes that the Type B and Type C test results show a large amount of margin between the actual as-found and the as-left outage summations and the respective TS 6.8.4.f leakage rate acceptance criteria.
With the use of these La values and the data contained in LAR Section 3.5.6, the NRC staff confirmed the accuracy of the Percentage of La values contained in the LAR and concluded that:
Unit 1 The as-found minimum pathway leakage rates for the last eight refueling outages since 2011 (i.e., 1R21) have an average of 4 percent of La with a high of 7 percent La.
The as-left maximum pathway leakage rates for the last eight refueling outages since 2012 (1R21) have an average of 13 percent of La with a high of 17 percent La.
Unit 2 The as-found minimum pathway leakage rates for the last nine refueling outages since 2011 (i.e., 2R18) have an average of 5 percent of La with a high of 9 percent La.
The as-left maximum pathway leakage rates for the last nine refueling outages since 2013 (2R18) have an average of 14 percent of La with a high of 24 percent La.
As stated in the LAR, for Salem, Unit 1, 80.7 percent of all penetrations eligible for extended intervals are on extended intervals and for Salem, Unit 2, 77.3 percent of all penetrations eligible for extended intervals are on extended intervals. The number of penetrations on extended frequency is adjusted periodically based on valve performance and other plant testing requirements as previously discussed.
Based on the NRC staffs review of the historical information provided in LAR Section 3.5.6 Containment Leakage Rate Testing Program - Type B and Type C Testing Program, and LAR Section 3.5.7 Type B and Type C Local Leak Rate Testing Program Implementation Review, the NRC staff observed noted that the licensee is adequately implementing the testing program in accordance with the requirements of Appendix J option B performance-based testing program. there was no indication of the licensees failure to adequately implement the requirements of its Appendix J Option B performance-based testing program.
Based on the review of LAR Sections 3.5.6 and 3.5.7, the NRC staff concluded that the aggregate leakage rate results of the As-Found Minimum Pathway for all Salem Type B and C tests from the last two outages were all well below (i.e., > 88 percent margin) the Types B and Type C test TS leakage rate acceptance criteria of less than (<) 0.60 La.
Furthermore, based on its review of the information contained in LAR Sections 3.5.6 and 3.5.7, the NRC staff concludes that the licensee has implemented the Type B and Type C testing programs for both units at Salem and the corrective actions taken regarding the hatch opening at Salem Unit 1 and the electrical penetrations at Salem Unit 2 in a manner that is consistent with both Section 10.2.1 Type B Test Interval, and Section 10.2.3 Type C Test Interval, of NEI 94-01, Revision 0.
Types B and Type C Test Program Assessment - Salem In summary, the NRC staff determined that:
The licensee has been compliant with the guidance of RG 1.163 and NEI 94-01, Revision 0; The recent historical combined total Types B and C test results are substantially below the acceptance limit of TS 6.8.4.f; and The licensee has a corrective action program that appropriately addresses poor performing valves and penetrations.
The NRC staff finds that the licensee is effectively implementing the Salem Type B and C leakage rate test program, as required by Option B of 10 CFR Part 50, Appendix J. Therefore, extending the CIV leakage rate testing (Type C) frequency from the 60 months currently permitted by 10 CFR Part 50, Appendix J, Option B, to a 75-month frequency for Type C leakage rate testing of selected components, in accordance with the guidance in NEI 94-01, Revision 3-A, and is acceptable.
3.3 Containment Inspection 3.3.1 Containment Inservice Inspection (CISI) Program The CISI programs are summarized below for subsections IWE and IWL to the requirements of ASME Boiler and Pressure Vessel Code (ASME Code),Section XI, Inservice Inspection of Nuclear Power Plant Components, the 2013 Edition and with the applicable conditions in 10 CFR 50.55a(b)(2)(ix), and for Service Level I (SLI) Containment Coating and Assessment Program in accordance with CC-SA-6006, Monitoring the Performance of Service Level I Coating Systems. The CC-SA-6006 program is based on the guidance presented in ASTM D 5163, Standard Guide for Establishing a Program for Condition Assessment of Coating Service Level I Coating Systems in Nuclear Power Plants.
Service Level I Containment Coating and Assessment Program Section 3.5.1 of the LAR describes the Protective Coating Monitoring and Maintenance Program as an existing program that provides for aging management of Service Level I coatings inside the containment structure. The program provides for inspections, assessments, and repairs for any condition that adversely affects the ability of Service Level I coatings to function as intended. Documentation of the coatings condition is provided per the requirements of the license renewal protective coatings monitoring and maintenance aging management program.
The applicant provided summaries of past Service I coatings inspection notifications, follow-up actions, and their respective status for the last two refueling outages in Section 3.5.2. The applicant notes in the LAR that qualified inspectors review the past notifications prior to performing the walkdowns and initiates new notifications to correct coating degradation.
Section 3.5.2 further notes that overall, the Service Level I coatings were found to be in good condition.
Based on the above, the NRC staff finds that the licensee has demonstrated that it has an adequate containment coatings assessment program in accordance with CC-SA-6006and is performing general visual inspections and monitoring the condition of the Service Level I coatings with notification reports as demonstrated in Tables 3.5.2, Notifications from Previous Outage.
Summary of ASME Section XI, Subsections IWE and IWL Containment ISI Programs The containment leak-tight integrity is verified through periodic ISI conducted in accordance with the requirements of the ASME Code,Section XI, Subsection IWE and IWL that provides the rules and requirements for the ISI of Class Metal Containment (MC) and Concrete Containment (CC) pressure-retaining components and their integral attachments. ASME Section XI requires visual examinations 3 times within a 10-year interval for ASME Class MC components and their integral attachments (Subsection IWE) and 2 times within a 10-year interval for ASME Class CC components and their integral attachments (Subsection IWL). Furthermore, the methodology in 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, and these requirements are not changed because of the extended ILRT interval. In addition, Appendix J to 10 CFR Part 50, 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 and Type C test frequency.
In LAR Section 3.5.3, SNGS Units 1 and 2, 3rd Interval Containment Inservice Inspection Program Plan, the licensee outlined the requirements for the non-destructive examinations (NDEs) of Salems containment pressure boundary and related components as specified by 10 CFR 50.55a. The licensee developed the Containment Inservice Inspection (CISI) program in accordance with the requirements of ASME Section XI, Subsection IWE and IWL, 2013 Edition and the applicable conditions in 10 CFR 50.55a(b)(2)(iii),Section XI condition: Concrete containment examinations, and 10 CFR 50.55a(b)(2)(ix),Section XI condition: Metal containment examinations. The licensee provided the dates of inspection periods for the containment pressure boundary inspection intervals, as follows:
The CISI periods during the third ten-year containment inspection interval:
First Period (36 months):
January 1, 2021, to December 31, 2024 Second Period (36 months): January 1, 2025, to December 31, 2027 Third Period (36 months):
January 1, 2028, to December 31, 2030 And with IWL examinations scheduled on the following dates:
Unit 1 first exam (5 years): Fall of 2023 Unit 1 second exam (5 years): Spring of 2028 Unit 2 first period (5 years): April 1, 2023, to April 28, 2023 Unit 2 second period (5 years): Fall of 2027 The proposed CISI periods during the fourth ten-year containment inspection interval (The fourth interval plan has not been finalized yet):
First Period (36 months):
January 1, 2031, to December 31, 2033 Second Period (36 months): January 1, 2034, to December 31, 2037 Third Period (36 months):
January 1, 2038, to December 31, 2040 And with IWL examinations scheduled on the following dates:
Unit 1 first exam (5 years): Fall of 2032 Unit 1 second exam (5 years): Spring of 2037 Unit 2 first period (5 years): Spring of 2032 Unit 2 second period (5 years): Fall of 2036 Additionally, the licensee referenced ASME Section XI, IWA-2430 which allows the inspection interval to be increased or decreased by 12 months to coincide with Salem refueling outages.
Summary of the Containment Inservice Inspection Examination Results:
Subsection Containment ISI Plan to Section 3.5.3 of the LAR provides detail requirements for the inspections of Class MC and CC components and integral attachments at Salem, Units 1 and 2, in accordance with ASME Section XI, 2013 Edition. LAR tables 3.5.3-6 to 3.5.3-11 provides a summary for the Unit 1 and Unit 2, interval 3 containment in-service inspections pertaining to ASME IWL and IWE and license renewal enhancement commitments. The summary tables list the number of components required to examined along with the number of components to be examined at each inspection period.
The results of recent IWE/IWL containment examinations are identified in the LAR Tables 3.5.5-1 through Table 3.5.5-4 for Salem, Units 1 and 2. The tables identified conditions what were not acceptable, required evaluation, or explanation were provided for acceptance.
Where the conditions were marked as No for acceptance, a notification number is provided.
The NRC staff reviewed Table 3.5.5 and found that the accepted abnormal conditions were minor and do not substantially impact the function of the containment pressure boundary system. The abnormal conditions that were not accepted were limited to holes in insulation packages, missing caulking, holes in leak channels, coatings damage, corrosion of leak test channels, rusting of several containment liner panels, and missing insulation at various locations. Notification numbers were assigned to unaccepted abnormal conditions in the corrective actions program, to facilitate resolution of the non-acceptable condition.
Based on the NRC staffs review of these tables, the NRC staff finds that the licensee conducted examinations for the containments in accordance with the ASME Boiler and Pressure Vessel (BPV) Code,Section XI, Subsection IWE and IWL, requirements, and that all examinations were performed satisfactorily. Therefore, the NRC staff concludes that the Salem containments meet the ASME BPV Code,Section XI, Subsection IWL, requirements, and the inspection results are acceptable.
3.3.2 Operating Experience In LAR Section 3.6, Operating Experience (OE), the licensee described the impacts of the following selected site-specific and industry operating experiences:
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 Regulatory Issue Summary (RIS) 2016-07, Containment Shell or Liner Moisture Barrier Inspection The NRC issued IN 1992-20 to alert licensees to problems with the local leak rate testing of two-ply stainless-steel bellows used on piping penetrations at some plants. In LAR Section 3.6.1, the licensee stated that there are no pressure retaining bellows used on containment penetrations at Salem Units 1 and 2 as Salem pipe penetrations rely on partial/full penetration seal welds as the leakage limit boundary.
The NRC issued IN 2004-09 to alert licensees on how corrosion of the liner plate could reduce safety factors and could change the failure threshold of the containment during extreme conditions. In LAR Section 3.6.2, the licensee stated that at Salem the original design basis did not take credit for liner plate monitor channels and assumed the liner welds as the boundary. It was determined previously by NRC staff in the SER dated December 12, 1990, that the channels welds are qualitatively equivalent to or better than those for primary containment liner welds. Salem committed to performing 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 emphasized that since the plugged liner plate monitor channels serve as a pressure retaining boundary, they are considered as part of the interior surfaces of containment for the purposes of the pre-test inspection. The licensee noted initial NDE (ultrasonic testing) inspections of the liner at Salem, at locations with signs of degradation have yielded results within acceptable criteria. Furthermore, as part of the license renewal commitment, Salem will inspect 82 randomly selected liner panels at Unit 1 and 72 randomly selected liner panels at Unit 2. During Salem Unit 1 spring 2016 refueling outage (1R24), panel
- 100-3 was replaced due to corrosion build up discovered during liner panel inspections.
The NRC issued IN 2010-12 to inform licensees of recent issues involving corrosion of the steel reactor containment building liner. 10 CFR 50.55a require the use of ASME Section XI, Subsection IWE to perform inservice inspections of containment components, such as the steel containment liner and attachments, using visual examinations and ultrasonic thickness measurements. In Section 3.6.3 of the LAR, in October 2009, at Salem, Unit 2, the licensee noted that heavy corrosion was discovered on the containment liner near the concrete floor, deemed inaccessible due to insulation covering it. In response, the licensee enhanced inspections of the liner within 6 inches of the concrete floor and stated that it will randomly inspect areas that were covered by insulation. The enhanced inspection revealed corrosion in several areas, though subsequent ultrasonic measurements indicated no significant wall loss.
Ultrasonic testing of 440 locations was conducted to evaluate safety implications, and it was determined the liner remained operable because the lowest measured thickness remained above design minimum wall thickness. The licensee determined the source of the moisture causing corrosion was attributed to service water leakage from containment fan coil units and associated piping. Corrective actions included frequent walk-downs, repair of any identified service water leaks, and verification that water did not reach the containment liner. In addition, the licensee stated in its license renewal submittals that it would perform supplemental inspections of liner plates in its license renewal commitment.
The NRC issued IN 2011-15 to inform licensees 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. In Section 3.6.4 of the LAR, the licensee stated that it has addressed IN 2011-15 during the license renewal process and has committed to enhance the CISI plan by inspecting the containment liner covered by insulation and lagging prior to extended operation and every ten years thereafter; visually inspecting 100 percent of the moisture barrier in accordance with IWE; to examine accessible liner knuckle plate, perform repairs, and extend examinations to inaccessible areas as required; and inspect the steel liner covered by insulation under the fuel transfer canal at each period. Furthermore, the licensee stated that a plant-specific aging management plan of the inaccessible areas of the Salem containment liner plates in addition to the visual inspection recommended in NUREG-1801 has been developed in the IWE Augmented Inspection Plan CISI plan.
The NRC issued IN 2014-07 to inform licensees of issues concerning degradation of floor weld leak-chase channel systems that could affect leak-tightness and aging management of the containment structure. The leak chase system provides a pathway for potential intrusion of moisture that could cause corrosion degradation of inaccessible areas of the pressure-retaining containment shell. In Section 3.6.5 of the LAR, the licensee noted that the Salem containment liner features liner plate monitor channels originally installed to assess leak tightness of liner plate butt-welds during construction. Additionally, there are monitor channels for liner plates beneath the concrete floor, and some of the monitor channels were found to contain through-wall holes during license renewal inspections, allowing moisture to enter the monitor channel sections below the concrete. The licensee stated that the CISI Program was enhanced to encompass additional inspections of areas below the concrete floor by removing concrete and accessing floor liner plate monitor channels. Inspection plans now include periodic assessments of all noted test headers, vertical liner plate monitor channels at the outermost circumference, and locations beneath the concrete where moisture was identified. Degraded areas have been corrected to ensure a moisture seal is maintained to prevent further moisture ingress below the concrete floor. These periodic inspections will continue for the remainder of the plant's operational life in accordance with ASME Section XI Subsection IWE. A plant-specific aging management plan has also been developed to supplement visual inspections as recommended in NUREG-1801, with initial inspections and necessary repairs completed for both Salem, Unit 1 and 2.
The NRC issued RIS 2016-07 to all licensees to reiterate the NRCs position regarding inservice inspection requirements for moisture barrier materials. The NRC staff requires licensees to inspect 100 percent of accessible moisture barriers during each inspection period, in accordance with ASME Section XI, Table IWE-2500-1, Item E1.30. In Section 3.6.6 of the LAR, the licensee state that Salem had identified similar conditions to those described in RIS 2016-07 and have modified the containment liner insulation system and trimmed the insulation lagging that was previously obstructing access to the moisture barrier and performed the required examinations. The licensee further stated that a plant-specific aging management plan of the inaccessible areas of the Salem Containment liner plates in addition to the visual inspection recommended in NUREG-1801 has been developed in the IWE augmented CISI plan. Initial inspections, examinations and required repairs have been completed on both Salem, Units 1 and 2.
3.4 Net Positive Suction Head (NPSH) and Spray Water Entrapment In LAR Section 3.2, Net Positive Suction Head (NPSH) and Spray Water Entrapment, the licensee reviewed the available NPSH for the containment spray (CS) and residual heat removal (RHR) pumps that draw water from the containment sump during the recirculation phase of a design-basis accident (DBA) considering loss of water through entrapment outside the containment sump. The licensee stated that the total quantity of water released to the containment at the beginning of the recirculation phase of the CS system operation, assuming a DBA with reactor coolant loop piping half full of water, is approximately 275,000 gallons. The licensee also stated that 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. With the required NPSH for the RHR pump at a water level relative to the bottom of the containment sump, the NRC staff notes that the indicated available water volume is several feet above the containment sump top, which will allow sufficient water volume in the containment sump to permit recirculation flow between the core and the containment and meet the NPSH requirements of the CS and RHR pumps.
The licensee provided the values of the available and required NPSH for the CS and the RHR pumps, which are consistent with Salems updated final safety analysis report (ML22298A056)Table 6.2-6, NPSH for Containment Spray. The available NPSH calculation conservatively assumes an empty refueling water storage tank and there is no credit taken for increased containment pressures following the LOCA. There is at least 14 percent NPSH margin in the available NPSH from the required NPSH.
Based on the above, the NRC staff finds that the licensee will maintain the current licensing basis NPSH analysis with consideration of the potential of trapped water during the recirculation phase.
3.5 NEI 94-01, Revision 2-A, Limitations and Conditions In the SE of NEI 94-01, Revision 2, dated June 25, 2008, NRC concluded that the methodology is acceptable for referencing by licensees proposing to amend their TS to permanently extend the Type A surveillance test interval to 15 years, subject to the limitations and conditions noted within the SE. In LAR Table 3.8.1-1, NEI 94-01 Revision 2-A Limitations and Conditions, the licensee provided a response to each of these limitations and conditions.
3.5.1 NEI 94-01, Revision 2-A, Condition 1 Condition 1 of NEI 94-01, Revision 2-A, states:
For calculating the Type A leakage rate, the licensee should use the definition in NEI 94-01, Revision 2, in lieu of that in ANSI/ANS-56.8-2002. (Refer to SE Section 3.1.1.1).
The licensees response to Condition 1 states:
Salem will utilize the definition in NEI 94-01, Revision 3-A, Section 5.0. This definition has remained unchanged from Revision 2-A to Revision 3-A of NEI 94-01.
NRC Staff Assessment of Licensees Response to Condition 1 Section 3.2.9 Type A test performance criterion of ANSI/ANS-56.8-2002 defines the performance leakage rate and reads in part:
The performance criterion for a Type A test is met if the performance leakage rate is less than La. The performance leakage rate is equal to the sum of the measured Type A test UCL and the total as-left [minimum pathway leakage rate]
of all Type B or Type C pathways isolated during performance of the Type A test.
NRC SE section 3.1.1.1 Enclosure Page 6, for NEI 94-01 Revision 2, reads in part:
Section 5.0 of NEI TR 94-01, Revision 2, uses a definition of performance leakage rate for Type A tests that is different from that of ANSI/ANS-56.8-2002.
The definition contained in NEI TR [topical report] 94-01, Revision 2, is more inclusive because it considers excessive leakage in the performance determination. In defining the minimum pathway leakage rate, NEI TR 94-01, Revision 2, includes the leakage rate for all Type B and Type C pathways that were in service, isolated, or not lined up in their test position prior to the performance of the Type A test. Additionally, the NEI TR 94-01, Revision 2, definition of performance leakage rate requires consideration of the leakage pathways that were isolated during performance of the test because of excessive leakage in the performance determination. The NRC staff finds this modification of the definition of performance leakage rate used for Type A tests to be acceptable.
Section 5.0 Definitions of NEI 94-01, Revision 3-A reads in part:
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 1.0 La.
The NRC staff reviewed the definitions of performance leakage rate contained in NEI 94-01, Revision 2 and Revision 3-A and notes that the definitions contained in both documents are identical.
Therefore, the NRC staff concludes that the licensee may use the definition found in Section 5.0 of NEI 94-01, Revision 3-A for calculating the Type A leakage rate in the Salem Primary Containment Leakage Rate Testing Program and that this adequately addresses Condition 1.
3.5.2 NEI 94-01, Revision 2-A, Condition 2 Condition 2 of NEI 94-01, Revision 2-A, states:
The licensee submits a schedule of containment inspections to be performed prior to and between Type A tests. (Refer to SE Section 3.1.1.3).
The licensees response to Condition 2 states:
Reference Section 3.5.3 (Tables 3.5.3-3 and 3.5.3-4, of this LAR submittal).
NRC Staff Assessment of Licensees Response to Condition 2 NRC SE section 3.1.1.3, Adequacy of Pre-Test Inspections (Visual Examinations) (enclosure page 7), for NEI 94-01 Revision 2, reads, in part:
NEI TR 94-01, Revision 2, Section 9.2.3.2, states that: To provide continuing supplemental means of identifying potential containment degradation, a general visual examination of accessible interior and exterior surfaces of the containment for structural deterioration that may affect the containment leak-tight integrity must be conducted prior to each Type A test and during at least three other outages before the next Type A test if the interval for the Type A test has been extended to 15 years. NEI TR 94-01, Revision 2, recommends that these inspections be performed in conjunction or coordinated with the examinations required by ASME Code,Section XI, Subsections IWE and IWL. The NRC staff finds that these visual examination provisions, which are consistent with the provisions of regulatory position C.3 of RG 1.163, are acceptable considering the longer 15 year interval. Regulatory Position C.3 of RG 1.163 recommends that such examination be performed at least two more times in the period of 10 years.
The NRC staff agrees that as the Type A test interval is changed to 15 years, the schedule of visual inspections should also be revised. Section 9.2.3.2 in NEI TR 94-01, Revision 2, addresses the supplemental inspection requirements that are acceptable to the NRC staff.
Section 9.2.1 Pretest Inspection and Test Methodology, of NEI 94-01, Revision 3-A (page 10),
reads in part:
Prior to initiating a Type-A test, a visual examination shall be conducted of accessible interior and exterior surfaces of the containment system for structural problems that may affect either the containment structure leakage integrity or the performance of the Type A test. This inspection should be a general visual inspection of accessible interior and exterior surfaces of the primary containment and components. It is recommended that these inspections be performed in conjunction or coordinated with the ASME Boiler and Pressure Vessel Code,Section XI, Subsection IWE/IWL required examinations.
Section 9.2.3.2 Supplemental Inspection Requirements of NEI 94-01, Revision 3-A (page 12),
reads:
To provide continuing supplemental means of identifying potential containment degradation, a general visual examination of accessible interior and exterior surfaces of the containment for structural deterioration that may affect the containment leak-tight integrity must be conducted prior to each Type A test and during at least three other outages before the next Type A test if the interval for the Type A test has been extended to 15 years. It is recommended that these inspections be performed in conjunction or coordinated with the ASME Boiler and Pressure Vessel Code,Section XI, Subsection IWE/IWL required examinations.
The NRC staff reviewed Section 3.5.3, SNGS Units 1 and 2, 3rd Interval Containment Inservice Inspection Program Plan, Tables 3.5.3-3 and 3.5.3-4, SNGS Third Ten-Year CISI Interval schedule, and Section 3.5.5, Results of Recent Containment examinations. Per Section 3.5.3, the Third Ten-Year CISI program commenced on January 1, 2021, and Tables 3.5.3-3 and 3.5.3-4 provide a schedule of containment inspections divided into three periods with two outages within each period. The three periods support the CISI examinations to be performed in each period as outlined in Tables 3.5.3-6 through 3.5.3-11. Review of the LAR sections and tables, support the conclusion that Salem performed, and continues to perform, general visual inspection of the accessible interior and exterior surfaces of the primary containment and components prior to Type A tests. Based on this review, the NRC staff confirms that the scheduled IWE and the IWL inspection condition of section 3.1.1.3 of the NRC SE to NEI 94-01 Revision 2-A is adequately addressed for Salem, Units 1 and 2.
Based on the foregoing discussion, the NRC staff concludes that Salem submitted plans which demonstrate the guidance contained in NEI 94-01, Revision 3-A, Sections 9.2.1 and 9.2.3.2, will be met for Salem Units 1 and 2, and Condition 2 on NEI 94-01, Revision 2-A, has been adequately addressed.
3.5.3 NEI 94-01, Revision 2-A, Condition 3 Condition 3 of NEI 94-01, Revision 2-A, states:
The licensee addresses the areas of the containment structure potentially subjected to degradation. (Refer to SE Section 3.1.3).
The licensees response to Condition 3 states:
Reference Section 3.5.3 (Tables 3.5.3-8 and 3.5.3-11, of this LAR submittal).
NRC Staff Assessment of Licensees Response to Condition 3 As described in the Safety Evaluation for NEI 94-01, Revision 2-A, Section 3.1.3, Type A Test (ILRT), Type B and Type C Tests (LLRTs), and Containment In-Service Inspections (ISIs), the NRC staff identified areas that need to be specifically addressed during the IWE and IWL inspections. The areas include containment pressure-retaining boundary components (e.g.,
seals, and gaskets of mechanical and electrical penetrations, bolting, penetration bellows), and accessible and inaccessible areas of the containment structures (e.g., moisture barriers, steel shells, liners backed by concrete, inaccessible areas of ice-condenser containments) that are subject to potential corrosions. Furthermore, the licensee should also explore inaccessible degradation-susceptible areas in plant inspections using viable NDE methods.
The IWE and IWL programs periodically examine, monitor, and manage structural deterioration and aging degradation of the Salem containment pressure boundary per ASME Section XI Tables IWE-2500-1 and IWL-2500-1 such that the primary containment can perform its intended function as a leak-tight barrier consistent with the guidance contained in NEI 94-01, Revision 2-A. In the LAR, the licensee provided Tables 3.5.3-6 through 3.5.3-11, which summarize the containment areas and components inspected during the 3rd CISI interval.
Tables 3.5.3-8 and 3.5.3-11 summarize the enhancement inspections, which is a general visual inspection of a sample inaccessible liner covered by insulation and lagging every 10 years and a general visual inspection of the containment liner under the fuel transfer canal and behind the liner insulation every 10 years.
Based on the information above, the NRC staff finds that the prior IWE and IWL inspections were performed by the licensee in accordance with the ASME Code,Section XI as required by 10 CFR 50.55a(b)(2)(ix) for all the areas of the containment structure potentially subject to degradation as identified in the SE for NEI-94-01, Rev 2-A at Section 3.1.3. Therefore, the NRC staff concludes that Salem has adequately addressed Condition 3.
3.5.4 NEI 94-01, Revision 2-A, Condition 4 Condition 4 of NEI 94-01, Revision 2-A, states:
The licensee addresses any tests and inspections performed following major modifications to the containment structure, as applicable. (Refer to SE Section 3.1.4).
The licensees response to Condition 4 states:
Steam Generator replacements were performed using the installed equipment hatches. There are no major modifications planned that would require the performance of a Type A test.
NRC Staff Assessment of Licensees Response to Condition 4 In Section 3.1.3, the licensee stated that steam generator replacements were performed using the installed equipment hatches and no modifications to containment were required. The licensee also states in Table 3.8.1-1 that no major modifications are planned that would require the performance of a Type A test.
The NRC staffs SE, Section 3.1.4, Major and Minor Containment Repairs and Modifications, for NEI 94-01, Revision 2, states, in part:
Repairs and modifications that affect the containment leakage integrity require LLRT or short duration structural tests as appropriate to provide assurance of containment integrity following the modification or repair. This testing shall be performed prior to returning the containment to operation. Article IWE-5000 of the ASME Code,Section XI, Subsection IWE (up to the 2001 Edition and the 2003 Addenda), would require a Type A test after major repair or modifications to the containment. In general, the NRC staff considers the cutting of a large hole in the containment for replacement of steam generators or reactor vessel heads, replacement of large penetrations, as major repair or modifications to the containment structure.
This condition is intended to verify that any major modification or maintenance repair of the containment since the last ILRT has been appropriately accompanied by either a structural integrity test or ILRT, and that any plans for such major modification also include appropriate pressure testing. As stated in the licensees response to Condition 4 in the LAR, no major modifications are planned for the Salem containment structures. The NRC staff finds that the licensee has addressed major modifications to the containment structure and concludes that the licensee has adequately addressed Condition 4.
The NRC staff also finds that, since the licensee is performing supplemental inspections to periodically examine and monitor aging degradation, there is reasonable assurance that the containment structural and leak-tight integrity will continue to be maintained.
3.5.5 NEI 94-01, Revision 2-A, Condition 5 Condition 5 of NEI 94-01, Revision 2-A, states:
The normal Type A test interval should be less than 15 years. If a licensee has to utilize the provision of Section 9.1 of NEI 94-01, Revision 2, related to extending the ILRT interval beyond 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).
The licensees response to Condition 5 states:
Salem will follow the requirements of NEI 94-01Revision 3-A, Section 9.1. This requirement has remained unchanged from Revision 2-A to Revision 3-A of NEI 94-01.
In accordance with the requirements of NEI 94-01, Revision 2-A, SER Section 3.1.1.2, Salem 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.
NRC Staff Assessment of Licensees Response to Condition 5 The licensees response stated that it will follow the requirements of NEI 94-01, Revision 2-A, SER Section 3.1.1.2 and will also demonstrate that an unforeseen emergent condition exists in the event an extension beyond the 15-year interval is required; therefore, the licensee has adequately addressed Condition 5.
3.5.6 NEI 94-01, Revision 2-A, Condition 6 Condition 6 of NEI 94-01, Revision 2-A, states:
For plants licensed under 10 CFR Part 52, applications requesting a permanent extension of 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.
The licensees response to Condition 6 states:
Not applicable. Salem was not licensed under 10 CFR Part 52.
NRC Staff Assessment of Licensees Response to Condition 6 Condition 6 applies only to plants licensed under 10 CFR Part 52. The Salem license was issued under Part 50 and, therefore, this condition is not applicable.
3.5.7 Conclusion Related to the Six Conditions Listed in NEI 94-01, Revision 2-A, Section 4.1, of the NRC SE The NRC staff evaluated each of the six conditions on NEI 94-01, Revision 2-A, listed in Section 4.1, of the NRC SE and determined that the licensee adequately addressed each of them. Therefore, the NRC staff finds it acceptable for the licensee to adopt the conditions and limitations specified in NEI 94-01, Revision 2-A, dated October 2008, as part of the implementation documents listed in TS 6.8.4.f.
3.6 NEI 94-01, Revision 3-A, Conditions The NRC published an SE with limitations and conditions for NEI 94-01, Revision 3, by letter dated June 8, 2012. In that SE, the NRC concluded that NEI 94-01, Revision 3, describes an acceptable approach for implementing the optional performance-based requirements of Appendix J, and is acceptable for reference by licensees proposing to amend their containment leakage rate testing TSs, subject to two conditions. The SE was incorporated into Revision 3 and subsequently issued as NEI 94-01, Revision 3-A, on July 31, 2012.
The LAR proposes to use NEI 94-01, Revision 3-A, as the implementation document for the leak rate testing program. Accordingly, Salem will be adopting, in part, the testing criteria of ANSI/ANS 56.8-2002 as part of its licensing basis. As stated in NEI 94-01, Revision 3-A, Section 2.0, Purpose and Scope, where technical guidance overlaps between NEI 94-01, Revision 3-A, and ANSI/ANS 56.8-2002, the guidance in NEI 94-01, Revision 3-A, takes precedence.
3.6.1 NEI 94-01, Revision 3-A, Condition 1 NEI 94-01, Revision 3-A, Condition 1 states:
NEI TR 94-01, Revision 3-A, 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 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.
Condition 1 identifies three issues that are required to be addressed:
(1)
The allowance of an extended interval for Type C LLRTs of 75 months requires that a licensees post-outage report include the margin between the Type B and Type C leakage rate summation and its regulatory limit; (2)
A corrective action plan is to be developed to restore the margin to an acceptable level; and (3)
Use of the allowed 9-month extension for eligible Type C valves is only allowed for non-routine emergent conditions, but not for valves categorically restricted and other excepted valves.
The licensees response to Condition 1, Issue 1 states:
The post-outage report shall include the margin between the Type B and Type C MNPLR summation value, as adjusted to include the estimate of applicable Type C leakage understatement, and its regulatory limit of 0.6 La.
The licensees response to Condition 1, Issue 2 states:
When the potential leakage understatement adjusted Types B and C MNPLR total is greater than the Salem 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 Salem 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.
The licensees response to Condition 1, Issue 3 states:
Salem 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.
NRC Staff Assessment of Licensees Response to Condition 1 The NRC staff has reviewed the licensees responses for Issues (1), (2), and (3) to Condition 1 of NEI TR 94-01, Revision 3-A. The licensees responses indicate that, following approval of the subject amendment, the licensees actions will be consistent with the guidance of NEI TR 94-01, Revision 3-A. The NRC staff notes that revised guidance contained in Revision 3-A:
Section 10.1 Introduction, Section 10.2.3.4 Corrective Action, Section 11.3.2 Programmatic Controls, and Section 12.1 Report Requirements, reflects the NRC staffs SE input pertaining to Issues (1), (2), and (3). The NRC staff concludes that the licensee has accepted all the issues of Condition 1, and that the licensee has established programs for Salem to comply with these requirements; therefore, the licensee has adequately addressed Condition 1.
3.6.2 NEI 94-01, Revision 3-A, Condition 2 NEI 94-01, Revision 3-A, Condition 2 states:
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 that more leakage rate test results from farther back in time are summed with fewer just tested penetrations and that total 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 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 Type B & 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.
There are two issues in Condition 2 to be addressed:
(1)
Extending the Type C 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 94-01, Revision 3, Section 12.1; and (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 Type B and Type C total and must be included in a licensees 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.
The licensees response to Condition 2, Issue 1 states:
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, Salem 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).
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 Salem 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 Salem 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.
The licensees response to Condition 2, Issue 2 states:
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 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 Salem, 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 Salem, 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.
NRC Staff Assessment of Licensees Response to Condition 2 The NRC staff has reviewed the licensees responses for Issues (1) and (2) to Condition 2 of NEI TR 94-01, Revision 3-A.
The licensees responses indicates that following approval of the subject amendment, the licensees actions will be consistent with the guidance of NEI TR 94-01, Revision 3-A. The NRC staff notes that revised guidance contained in NEI 94-01, Revision 3-A, Section 11.3.2 Programmatic Controls, and Section 12.1 Report Requirements, reflects the NRC staffs SE input pertaining to both Issues (1) and (2). The NRC staff concludes that the licensee has accepted all the issues of Condition 2, and that the licensee has established programs for Salem to comply with these requirements; therefore, the licensee has adequately addressed Condition 2.
3.6.3 NEI 94-01, Revision 3-A, Limitations and Conditions Conclusion Based on the above evaluation of each condition, the NRC staff determined that the licensee has adequately addressed the conditions in Section 4.0 of the NRC SE of NEI 94-01, Revision 3. Therefore, the NRC staff finds it acceptable for the licensee to adopt NEI 94-01, Revision 3-A, as the implementation document listed in Salem TS 6.8.4.f.
3.7 Probabilistic Risk Assessment of the Proposed Extension of the ILRT Test Intervals 3.7.1 Background Section 9.2.3.1, General Requirements for ILRT Interval Extensions beyond Ten Years, of Nuclear Energy Institute (NEI) 94-01, Revision 3-A, Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J, discusses how plant-specific confirmatory analyses are needed when extending the Type A ILRT interval beyond ten years.
Section 9.2.3.4, Plant-Specific Confirmatory Analyses, of NEI 94-01 states that the assessment should be performed using the approach and methodology described in EPRI TR-1018243. The analysis is to be performed by the licensee and retained in the plant documentation and records as part of the basis for extending the ILRT interval.
The limitations and conditions specified in NEI 94-01, Revision 2-A are found in the SER, dated June 25, 2008, contained in NEI 94-01, Revision 2-A. These conditions, set forth in Section 4.2 of the SER for EPRI TR-1009325, Revision 2, stipulate that:
- 1. The licensee submit documentation indicating that the technical adequacy of their Probabilistic Risk Assessment (PRA) is consistent with the requirements of Regulatory Guide (RG) 1.200, An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities, relevant to the ILRT extension application. [Additional application specific guidance on the technical adequacy of a PRA used to extend ILRT intervals is provided in the SER for EPRI TR-1009325, Revision 2.]
- 2. The licensee submits documentation indicating that the estimated risk increase associated with permanently extending the ILRT surveillance interval to 15 years is small and consistent with the clarification provided in Section 3.2.4.62 of the SER for EPRI TR-1009325, Revision 2.
- 3. The methodology in EPRI TR-1009325, Revision 2, is acceptable provided the average leak rate for the pre-existing containment large leak accident case (i.e.,
accident case 3b) used by licensees is assigned a value of 100 times the maximum allowable leakage rate (La) instead of 35 La.
- 4. A [license amendment request] LAR is required in instances where containment over-pressure is relied upon for [emergency core cooling system] ECCS performance. According to the clarification provided in Section 3.2.4.6 of the NRC SER for NEI 94-01, Revision 2, and EPRI TR-1009325, Revision 2, plants that rely on containment over-pressure (or containment accident pressure) net positive suction head (NPSH) for ECCS injection must also consider core damage frequency (CDF) in the ILRT evaluation.
3.7.2 Plant-Specific Risk Evaluation The licensee provided a plant-specific risk assessment for permanently extending the currently allowed containment Type A ILRT interval to 15 years in Section 3.4 Plant Specific 2 Section 4.2 of the SER for EPRI TR-1009325, Revision 2, indicates that the clarification regarding small increases in risk is provided in Section 3.2.4.5; however, the clarification is actually provided in Section 3.2.4.6.
Confirmatory Analysis of the LAR submitted June 23, 2023. The staffs evaluation of the risk assessment is provided in Section 3.7.2.1.1 through 3.7.2.4 where the Staff found that all 4 conditions were met as described below.
In the SE issued by the NRC letter dated June 25, 2008, the NRC concluded that the methodology in EPRI TR-1009325, Revision 2, 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. The following addresses each of the four (4) limitations and conditions from Section 4.2 of the SE for the use of EPRI 1009325, Revision 2.
3.7.2.1.1 PRA Technical Adequacy - Condition 1 The first condition stipulates that the licensee submit documentation indicating that the technical adequacy of its PRA is consistent with the requirements of Regulatory Guide 1.200 relevant to the ILRT extension application. RG 1.200 describes one acceptable approach for determining whether the technical adequacy of the PRA, in total or the parts that are used to support an application, is sufficient to provide confidence in the results, such that the PRA can be used in regulatory decision-making for light-water reactors.
Consistent with the information provided in Regulatory Issue Summary (RIS) 2007-06, Regulatory Guide 1.200 Implementation, the NRC staff will use Revision 2 of RG 1.200 to assess technical adequacy of the PRA used to support risk-informed applications received after March 2010. In Section 3.2.4.1 of the SER for - EPRI TR1009325, Revision 2, the NRC staff states that Capability Category I of the American Society of Mechanical Engineers (ASME) PRA standard shall be applied as the standard for assessing PRA quality for ILRT extension applications, since approximate values of core damage frequency (CDF) and large early release frequency (LERF) and their distribution among release categories are sufficient to support the evaluation of changes to ILRT frequencies. The NRC Safety Evaluation also states the assessment of external events can be taken from existing, previously submitted and approved analyses or other alternate method of assessing an order of magnitude estimate for contribution of the external event to the impact of the changed interval.
The Salem PRA technical adequacy is addressed in Section 3.4.2, "Risk Impact Assessment of Extending Salem ILRT Interval, and Appendix A, "PRA Technical Acceptability" of the LAR.
The NRC staff notes that for the Salem LAR, the methodology involved 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, the analysis included several sensitivity studies and factored in the potential impacts from external events in a bounding fashion.
The Salem ILRT risk assessment used recently completed Internal Event (including Internal Flooding) and Fire PRA models. PSEG indicated that there are no other approved PRA models (e.g., seismic) for Salem. Other external events were evaluated as discussed in the main report of the LAR and summarized below.
Internal Events and Internal Flooding The licensee stated that the focused scope peer review was conducted in October 2022 and the results indicated that 100 percent of the LERF supporting requirements were met at Capability Category II or higher which is more than sufficient for this evaluation which needs only to meet the less comprehensive Capability Category I. There was one suggestion and one note of an Unreviewed Analysis Method pertaining to the Temperature Induced-Steam Generator Tube Rupture methodology from the Pressure Water Reactor Owners Group. It was noted in the LAR that the method was implemented appropriately and that this issue has low significance. The Staff agrees that the Steam Generator tube rupture methodology has no impact on the ILRT application because the subject of this LAR is not this particular accident analysis methodology.
PSEG indicated that a review of the current PRA open items did not identify any items with significant potential impact upon the ILRT risk assessment. The Fire PRA model received a peer review in October 2022 against the ASME PRA Standard. The peer review indicated that
~90% of the applicable supporting requirements are met at Category II or higher which again is higher than the less restrictive Capability Category I. Applicable supporting requirements met at Category II or higher 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.
Other External Hazards The licensee indicated that 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 was presented in Section 5.7 of the LAR. The primary purpose for the licensees investigation was to determine the total LERF following an increase in the ILRT testing interval from 3-in-10 years to 1-in-15 years.
The NRC staff finds the methods used are consistent with the screening and assessment processes identified in the supporting requirements of the ASME/ANS PRA Standard, as endorsed by RG 1.200, Rev. 2.
The NRC staff concludes that the PRA technical adequacy is sufficient to support the evaluation of changes to the Salem ILRT frequencies and that condition 1 from Section 4.2 of the SE for the use of EPRI 1009325, Revision 2 is met.
3.7.2.2 Estimated Risk Increase - Condition 2 The second condition stipulates that the licensee submit documentation indicating that the estimated risk increase associated with permanently extending the ILRT interval to 15 years is small, consistent with the guidance in RG 1.174 and the clarification provided in Section 4.2 of the NRC SER for NEI 94-01, Revision 2, and EPRI TR-1009325, Revision 2. Specifically, a "small" increase in population dose should be defined as an increase in population dose of less than or equal to either 1.0 person-rem per year or 1 percent of the total population dose, whichever is less restrictive. In addition, a "small" increase in conditional containment failure probability (CCFP) should be defined as a value marginally greater than that accepted in previous one-time 15-year ILRT extension requests. This would require that the increase in CCFP be less than or equal to 1.5 percentage points. Lastly, for plants that rely on containment over-pressure for net positive suction head (NPSH) for ECCS injection, both CDF and LERF will be considered in the ILRT evaluation and compared with the risk acceptance guidelines in RG 1.174. RG 1.174 defines very small changes in risk as resulting in increases of CDF and LERF of less than 1.0E-6/year and 1.0E-07/year respectively. Thus, the associated risk metrics include population dose, CCFP, delta CDF and LERF.
The licensee reported the results to the plant-specific risk assessment in Section 5.0 of the LAR.
External events are considered in Section 5.7. The reported risk impacts are based on a change in the Type A containment ILRT frequency from three tests in 10 years (the test frequency under 10 CFR 50 Appendix J, Option A) to one test in 15 years. The following conclusions can be drawn from the licensees analysis associated with extending the Type A ILRT frequency:
RG 1.174 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-06 per reactor year and increases in LERF less than 1E-07 per reactor year. There is no quantifiable change in CDF as a result of the proposed ILRT Type A test interval extension. Therefore, the RG 1.174 acceptance guideline for a very small change in CDF is considered to be met as the impact on CDF for the Type A test interval extension is negligible.
Thus, the relevant acceptance criterion is LERF.
Since the ILRT does not impact core damage frequency (CDF) for Salem, the relevant criterion is large early release frequency (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) including the risk impact of corrosion induced leakage.
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. including the risk impact of corrosion induced leakage. Therefore, the risk increase is small using the acceptance guidelines of RG 1.174.
The calculated increase in the total 50-mile population dose risk for the proposed ILRT Type A interval change from three per ten years to once per 15 years is measured as an increase to the total integrated dose risk for all accident sequences influenced by Type A testing. The EPRI Guidance states that a very small population dose is defined as an increase of
<1.0 person-rem/yr or <1 percent 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. Since the very small change of 7.0E-2 person-rem/yr is less than<1.0 person-rem/yr, this criterion is met.
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 percent using the EPRI Guidance, and decreases to about 0.09 percent using the EPRI Expert Elicitation methodology. Per the EPRI Guidance, increases of CCFP <1.5 percent are considered to be small.
Based on the risk assessment results, the NRC staff concludes that the increase in LERF is small and within the acceptance guidelines of RG 1.174, and the increase in the total population dose and the magnitude of the change in the CCFP for the proposed change are also small. The defense-in-depth philosophy is maintained as the independence of barriers will not be degraded because of the requested change, and the use of the quantitative risk metrics collectively ensures that the balance between prevention of core damage, prevention of containment failure, and consequence mitigation is preserved. Accordingly, the second condition is met.
3.7.2.3 Leak Rate for the Large Pre-Existing Containment Leak Rate Case - Condition 3 The third condition stipulates that the average leak rate for the pre-existing containment large leak rate accident case (i.e., accident case 3b) used by the licensees should be 100 La instead of 35 La. As noted by the licensee in Table 3.4.1-1 of the LAR, the methodology incorporated the use of 100 La as the average leak rate for the pre-existing containment large leakage rate accident case (accident case 3b), and this value has been used in the Salem plant-specific risk assessment. Accordingly, the third condition is met.
3.7.2.4 Containment Overpressure is Relied Upon for ECCS Performance - Condition 4 The fourth condition stipulates that in instances where containment over-pressure is relied upon for ECCS performance, a LAR is required to be submitted. In Table 3.4.1-1 of the LAR, the licensee states that Salem does not rely on containment overpressure for ECCS performance.
Accordingly, the fourth condition is not applicable.
3.8 Technical Conclusion Based on the preceding regulatory and technical evaluations, the NRC staff finds that the results of the recent ILRTs and of the LLRTs combined totals demonstrate acceptable performance and support a conclusion that the structural and leak-tight integrity of the primary containment will continue to be periodically monitored and managed effectively with the proposed changes. The NRC staff finds that the licensee has addressed the NRC limitations and conditions to demonstrate acceptability of adopting NEI 94-01, Revision 3-A, and the limitations and conditions identified in the staff SE incorporated in NEI 94-01, Revision 2-A. The NRC staff also finds that the PRA used by the licensee is of sufficient technical adequacy to support the evaluation of changes to ILRT frequency. The licensee proposed to change Salem, Units 1 and 2, TS 6.8.4.f as described in section 2.2 of this SE. Based on the preceding regulatory and technical evaluations, the NRC staff concludes that the proposed change to Salem, Units 1 and 2, TS 6.8.4.f to replace the reference to RG 1.163 with a reference to the guidelines contained in 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, is acceptable because the proposed change continues to assure operation of the facility in a safe manner. Therefore, the NRC staff finds that the Salem, Units 1 and 2, TS 6.8.4.f proposed change will continue to meet 10 CFR 50.36(c)(5).
In addition, the current Salem, Units 1 and 2, TS 6.8.4.f contains an exception (paragraph a).
The LAR proposes to delete the exception. Specifically, the exception pertains to the performance of the next Type A test no later than a specified date. This exception is associated with activities that have already taken place. Therefore, the NRC staff finds that the deletion of Salem, Units 1 and 2, TS 6.8.4.f paragraph a is acceptable because the deleted information is not required under 10 CFR 50.36(c)(5).
4.0 STATE CONSULTATION
In accordance with the Commissions regulations, the New Jersey State official was notified of the proposed issuance of the amendment on May 7, 2024. The State official had no comments.
5.0 ENVIRONMENTAL CONSIDERATION
The amendments change requirements with respect to the installation or use of facility components located within the restricted area as defined in 10 CFR Part 20 and change SRs.
The NRC staff has determined that the amendments involve no significant increase in the amounts, and no significant change in the types, of any effluents that may be released offsite, and that there is no significant increase in individual or cumulative occupational radiation exposure. The Commission has previously issued a proposed finding that the amendments involve NSHC, published in the Federal Register on September 5, 2023 (88 FR 60719), and there were no public comments on such finding. Accordingly, the amendments meet the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9). Pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the issuance of the amendments.
6.0 CONCLUSION
The Commission has concluded, based on the considerations discussed above, that: (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) there is reasonable assurance that such activities will be conducted in compliance with the Commissions regulations, and (3) the issuance of the amendments will not be inimical to the common defense and security or to the health and safety of the public.
Principal Contributors: B. Lee, NRR J. Dozier, NRR N. Hansing, NRR S. Lai, NRR Date: May 29, 2024
ML24099A157 OFFICE NRR/DORL/LPL1/PM NRR/DORL/LPL1/LA NRR/DRA/ARCB/BC NAME JKim KEntz KHsueh DATE 4/17/2024 4/16/2024 1/19/2024 OFFICE NRR/DSS/SPCB/BC (A)
NRR/DEX/ESEB/BC NRR/DEX/EMIB/BC (A)
NAME NKaripineni ITseng TScarbrough for DATE 2/9/2024 4/8/2024 5/3/2024 OFFICE NRR/DSS/SNSB/BC NRR/DSS/STSB/BC (A)
OGC -NLO NAME PShad SMehta DRoth DATE 5/3/2024 5/1/2024 5/22/2024 OFFICE NRR/DORL/LPL1/BC NRR/DORL/LPL1/PM NAME HGonzález JKim DATE 5/29/2024 5/29/2024