RS-17-060, Request for License Amendment to Revise Technical Specifications Section 5.5.12 for Permanent Extension of Type a and Type C Leak Rate Test Frequencies

Request for License Amendment to Revise Technical Specifications Section 5.5.12 for Permanent Extension of Type a and Type C Leak Rate Test Frequencies

ML17123A104
Person / Time
Site:	Dresden
Issue date:	05/03/2017
From:	Simpson P Exelon Generation Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
RS-17-060
Download: ML17123A104 (230)

Text

4300 Winfield Road Warrenville, IL 60555 630 657 2000 Office RS-17-060 10 CFR 50.90 May 3, 2017 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001 Dresden Nuclear Power Station, Units 2 and 3 Renewed Facility Operating License Nos. DPR-19 and DPR-25 NRC Docket Nos. 50-237 and 50-249

Subject:

Request for License Amendment to Revise Technical Specifications Section 5.5.12 for Permanent Extension of Type A and Type C Leak Rate Test Frequencies In accordance with 10 CFR 50.90, "Application for amendment of license, construction permit, or early site permit," Exelon Generation Company, LLC (EGC) requests an amendment to Renewed Facility Operating License Nos. DPR-19 and DPR-25 for Dresden Nuclear Power Station (DNPS), Units 2 and 3, respectively. The proposed change revises Technical Specification (TS) 5.5.12, "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.

Specifically, the proposed change revises DNPS TS 5.5.12 by replacing the reference to Regulatory Guide (RG) 1.163, "Performance-Based Containment Leak-Test Program," with a reference to Nuclear Energy Institute (NEI) 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J," Revision 3-A, and the conditions and limitations specified in NEI 94-01, Revision 2-A, as the documents used by DNPS to implement the performance-based leakage testing program in accordance with Option B of 10 CFR 50, Appendix J. This license amendment request also proposes an administrative change to TS 5.5.12 to delete references to Type A tests that have already occurred.

The proposed change is risk-informed and follows the guidance in Regulatory Guide 1.174, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis," Revision 2. EGC has performed a DNPS-specific evaluation to assess the risk impact of the proposed change. A copy of the risk assessment is provided in .

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE

SUBJECT:

License Amendment Request - Revise Technical Specification 5.5.12 for Permanent Extension of Type A and Type C Leak Rate Test Frequencies 1.0

SUMMARY

DESCRIPTION 2.0 DETAILED DESCRIPTION

3.0 TECHNICAL EVALUATION

3.1 Description of Primary Containment System 3.2 Emergency Core Cooling System Net Positive Suction Head Analysis (Post-Extended Power Uprate (EPU))

3.3 Justification for the Technical Specification Change 3.4 Plant Specific Confirmatory Analysis 3.5 Non-Risk Based Assessment 3.6 Operating Experience 3.7 License Renewal Aging Management 3.8 NRC SER Limitations and Conditions 3.9 Conclusions

4.0 REGULATORY EVALUATION

4.1 Applicable Regulatory Requirements/Criteria 4.2 Precedents 4.3 No Significant Hazards Consideration Evaluation 4.4 Conclusions 5.0 ENVIRONMENTAL EVALUATION

6.0 REFERENCES

Page 1 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE 1.0

SUMMARY

DESCRIPTION In accordance with 10 CFR 50.90, "Application for amendment of license, construction permit, or early site permit," Exelon Generation Company, LLC (EGC) requests an amendment to Renewed Facility Operating License Nos. DPR-19 and DPR-25, for Dresden Nuclear Power Station (DNPS), Units 2 and 3.

The proposed change revises Technical Specification (TS) 5.5.12, "Primary Containment Leakage Rate Testing Program," to allow the following:

x Increase the existing Type A integrated leakage rate test (ILRT) program test interval from 10 years to 15 years in accordance with Nuclear Energy Institute (NEI) Topical Report (TR)

NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J," Revision 3-A (i.e., Reference 2), and the conditions and limitations specified in NEI 94-01, Revision 2-A (i.e., Reference 8).

x Adopt an extension of the containment isolation valve (CIV) leakage rate testing (i.e., Type C) frequency from the 60 months currently permitted by 10 CFR 50, Appendix J, "Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors," Option B, to a 75-month frequency for Type C leakage rate testing of selected components, in accordance with NEI 94-01, Revision 3-A (i.e., Reference 2).

x Adopt the use of ANSI/ANS 56.8-2002, "Containment System Leakage Testing Requirements," (i.e., Reference 43).

Specifically, the proposed change contained herein, would revise DNPS TS 5.5.12 by replacing the references to Regulatory Guide (RG) 1.163, "Performance-Based Containment Leak-Test Program," (i.e., Reference 1) with a reference to NEI 94-01, Revision 3-A (i.e., Reference 2),

and the limitation and conditions specified in NEI 94-01, Revision 2-A, dated October 2008 (i.e.,

Reference 8). These new documents will be used by DNPS to continue with the implementation of the performance-based leakage testing program in accordance with Option B of 10 CFR 50, Appendix J.

This License Amendment Request (LAR) also proposes an administrative change to TS 5.5.12 to delete the information regarding the performance of the next DNPS Type A tests to be performed no later than February 27, 2011, for Unit 2 and July 13, 2009, for Unit 3, as these Type A tests have already occurred.

This LAR is applicable only to DNPS Units 2 and 3. DNPS, Unit 1 was retired from operational service on August 31 1984.

Page 2 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE 2.0 DETAILED DESCRIPTION DNPS TS 5.5.12 currently states, in part:

This program shall establish the leakage testing of the primary containment as required by 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option B, as modified by approved exemption. This program shall be in accordance with the guidelines contained in Regulatory Guide 1.163, "Performance-Based Containment Leak-Testing Program,"

dated September 1995, as modified by the following exceptions:

1. NEI 94 1995, Section 9.2.3: The first Unit 2 Type A test performed after the February 28, 1996, Type A test shall be performed no later than February 27, 2011.

2. NEI 94 1995, Section 9.2.3: The first Unit 3 Type A test performed after the July 14, 1994, Type A test shall be performed no later than July 13, 2009.

The proposed changes to DNPS TS 5.5.12 will replace the reference to RG 1.163 with a reference to NEI TR NEI 94-01, Revisions 2-A and 3-A.

Additionally, this LAR incorporates an administrative change to TS 5.5.12 to delete the information regarding the performance of the next DNPS Type A tests to be performed no later than February 27, 2011, for Unit 2 and July 13, 2009, for Unit 3. This change will have no impact as these dates have already occurred and these Type A tests have already been performed. This Type A test information had been previously approved in Amendments Nos. 210 and 202 for DNPS, Units 2 and 3, respectively, and is no longer applicable since the test dates occur in the past.

The proposed change will revise TS 5.5.12 to state, in part:

This program shall establish the leakage testing of the primary containment as required by 10 CFR 50.54(o) and 10 CFR 50, 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 limitations and conditions specified in NEI 94-01, Revision 2-A, dated October 2008.

Markups of TS 5.5.12 are provided in Attachment 2.

A plant specific risk assessment conducted to support this proposed change is summarized in Section 3.4 of this enclosure and included as Attachment 3 of this LAR. The risk assessment follows the guidelines of NRC RG 1.174, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis," Revision 2 (i.e., Reference 3) and NRC RG 1.200, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities," Revision 2 (i.e., Reference 4). The risk assessment concluded that increasing the ILRT test frequency on a permanent basis to a one-in-fifteen year frequency is not considered to be significant since it represents only a small change in the DNPS risk profiles.

Page 3 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE

3.0 TECHNICAL EVALUATION

3.1 Description of Primary Containment System DNPS, Units 2 and 3 were built with the General Electric Mark I primary containment system that is designed to condense the steam released during a postulated loss-of-coolant accident (LOCA), to limit the release of fission products associated with such an accident, and to serve as a source of water for the emergency core cooling system (ECCS).

The primary containment system consists of a drywell; a pressure suppression chamber which is partially filled with water; a vent system connecting the drywell and the suppression chamber water pool; isolation valves; heating, ventilating, and cooling systems; and other service equipment. The drywell is a steel pressure vessel which houses the reactor vessel, the reactor coolant recirculation system, and other branch connections of the reactor primary system. The pressure suppression chamber is an approximately toroidal steel pressure vessel encircling the base of drywell. Due to its shape the suppression chamber is commonly called the torus. The vent system from the drywell terminates below the suppression chamber water level.

The safety design basis for the Primary Containment is to withstand the pressures and temperatures of the limiting Design Bases Accident (DBA) without exceeding the design leakage rate. Primary Containment is designed for a maximum internal pressure of 62 pounds per square inch gage (psig), with a maximum temperature of 281 degrees Fahreheit (°F). The PD[LPXPDOORZDEOHOHDNDJHUDWHIRUSULPDU\FRQWDLQPHQWLV/a, where La is defined as three (3) percent (%) of primary containment air weight per day at the design basis LOCA maximum peak containment pressure (Pa) of 43.9 psig.

The drywell is a steel pressure vessel with a spherical lower section, approximately 66 feet (ft.)

in diameter, a cylindrical upper section, approximately 37 ft. in diameter and a hemispherical tophead. The drywell shell is enclosed in reinforced concrete to provide radiological shielding and additional resistance to deformation. A portion of the lower spherical drywell section is embedded in concrete. Beneath the drywell is concrete fill from the spring line down. At the foundation level, a sand pocket was formed to soften the transition between the foundation and the containment vessel. Above the foundation transition zone, the drywell is separated from the reinforced concrete by a gap of approximately 2 inches to accommodate thermal expansion.

The embedment, in combination with the upper lateral restraints attached to the cylindrical section, forms the drywell support system.

The suppression chamber is a steel pressure vessel, approximately 109 ft. in diameter, constructed from 16 mitered cylindrical shell segments 30 ft. in diameter, joined together to shape a torus, encircling and located below the drywell. It contains approximately 116,300 cubic feet of water and has a free air volume above the water line. The vertical support system provides a load transfer mechanism which acts to reduce local suppression chamber shell stresses and to more evenly distribute reaction loads to the reactor building basemat.

The drywell and suppression chamber are interconnected by a vent system. Eight main vents connect the drywell to a vent ring header, which is located within the suppression chamber air space. A bellows assembly is located at the junction where each main vent penetrates the suppression chamber shell to permit differential movement of the suppression chamber and drywell/vent system. Projecting downward from the vent ring header are downcomer pipes, Page 4 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE arranged in 48 pairs around the vent header circumference, terminating below the surface of the suppression chamber water volume.

The original design of the Mark I containment system considered postulated accident loads associated with the containment design as input into the analysis. These included pressure and temperature loads resulting from a LOCA, seismic loads, dead loads, jet-impingement loads, hydrostatic loads due to water in the suppression chamber, and pressure test loads.

Subsequently, while performing large-scale testing for the Mark III containment system and in-plant testing for the Mark I primary containment system, new suppression chamber hydrodynamic loads were identified. These hydrodynamic loads are related to the postulated LOCA and safety relief valve (SRV) actuation. Because these hydrodynamic loads had not been considered in the original design of the containment, a detailed re-evaluation was undertaken. This re-evaluation, referred to as the Mark I Program, involved tasks performed to restore the originally intended design safety margins for the DNPS plant. The Mark I Program culminated in the issuance of the Plant Unique Analysis Report (PUAR) (i.e., Reference 21) for DNPS followed by NRC review and acceptance (i.e., Reference 22).

Primary containment, including the suppression chamber for DNPS, Units 2 and 3 was originally designed, erected, pressure-tested, and N-stamped in accordance with the American Society of Mechanical Engineering (ASME) Boiler and Pressure Vessel Code (Code), Section III, "Rules for Construction of Nuclear Facility Components," 1965 Edition with Addenda up to and including Summer 1965.

For the Mark I Program re-evaluation, the acceptance criteria generally follow the ASME Code, Section III, 1977 Edition with Addenda up to and including Summer 1977 for Class MC (Metal Containment) components and component supports. Further detail regarding structural acceptance criteria may be found in the DNPS Updated Final Safety Analysis Report (UFSAR)

Section 3.8.2.3.5.

3.1.1 Pipe Penetrations Two general types of pipe penetrations are provided in the DNPS Mark I containment, they are:

(1) those which must accommodate thermal movement, and; (2) those which experience relatively little thermal stress. The piping penetrations, which accommodate thermal movement, are the high temperature lines such as the steam lines, feedwater lines, and other reactor auxiliary system lines. The drywell nozzle passes through the concrete shield and is attached to a bellows expansion joint, which in turn, is attached to a penetration adapter to form a containment pressure boundary. The process line, which passes through the penetration, is attached to the penetration adapter and is free to move axially. A guard pipe immediately surrounds the process line and is designed to protect the bellows and containment boundary should the process pipe fail within the penetration.

Penetration details of cold piping lines that allow for relatively little movement are pipe sleeves that attach to the drywell. These penetrations are designed for 62 psig but can withstand a substantially higher pressure due to the use of heavy wall pipe. No bellows are required, since thermal expansion is minimal.

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ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE 3.1.2 Electrical Penetrations Electrical penetrations were designed to accommodate the electrical requirements of the plant.

Penetrations are functionally grouped into low voltage power and control cable penetration assemblies, high voltage power cable penetration assemblies, and shielded cable penetration assemblies.

An assembly is sized to be inserted in the 12-inch Schedule 80 penetration nozzles, which are furnished as part of the containment structure. Installation of the penetration assembly was accomplished by inserting it from either side of the containment into the penetration nozzle.

Three field welds were required to complete the installation of the assembly in the penetration nozzle.

The design and fabrication of each type of penetration assembly is in accordance with the requirements of the ASME, Section III, Class B Vessel, and materials of construction are self-extinguishing in accordance with ASTM-D635.

3.1.3 Traversing In-Core Probe Penetrations The traversing in-core probe (TIP) system, as described in Section 7.6 of the DNPS, Units 2 and 3 UFSAR, has several guide tubes which pass from the reactor building through the primary containment wall. Penetrations of the insertion guide tubes in the primary containment are sealed by means of brazing which meets the requirements of ASME Section VIII. Each TIP system guide tube is provided with an isolation valve which closes automatically upon receipt of an isolation signal and after the TIP cable and fission chamber have been retracted. In series with this isolation valve, an additional or backup isolation shear valve is included. Both valves are located outside the drywell.

3.1.4 Personnel and Equipment Access Locks Access to the drywell is provided by a manway located on the drywell head, one bolted equipment hatch, and one personnel airlock.

The manway in the drywell head has a double seal arrangement. The equipment hatch cover is bolted in place and sealed with a double-tongue-and-groove seal. The stabilizer support shear lug access hatches have double-gasketed, bolted, flanged connections. The personnel airlock has two doors which open inward toward the drywell and are designed to withstand a large outward force due to a high drywell internal pressure. The doors are mechanically interlocked so that a door may be operated only if the other door is closed and locked. The seals on the doors and the manways can be tested for leakage.

3.1.5 Pressure Suppression Chamber Access to the pressure suppression chamber from the reactor building is provided by two access ports consisting of manholes with double-gasketed bolted covers. These access ports are bolted closed when primary containment integrity is required. They are opened only when the primary coolant temperature is below 212°F and the pressure suppression system is not required to be operational. A test connection between the double gaskets on each cover permits checking gasket leak tightness without pressurizing the containment. A drainpipe with double isolation valves provides for suppression chamber cleaning and decontamination.

Page 6 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE 3.1.6 Access for Refueling Operations The drywell head is removed during refueling operations. The head is held in place by bolts and is sealed with a double tongue-and-groove seal arrangement, which permits periodic checks for leak tightness without pressurizing the entire containment. The head is bolted closed when primary containment integrity is required.

3.1.7 Modifications to Primary Containment NRC Order EA-13-109, "Issuance Of Order To Modify Licenses With Regard To Reliable Hardened Containment Vents Capable Of Operation Under Severe Accident Conditions" Although not a modification to the Primary Containment, a modification to the primary containment vent piping is underway at DNPS, Units 2 and 3. This modification installs a hardened containment vent system (HCVS) to comply with NRC Order EA-13-109. This NRC Order is the result of lessons learned from the Fukushima Dai-ichi Tsunami event.

When used in conjunction with the emergency operating procedures (EOPs) and severe accident management guidelines (SAMGs), the HCVS is capable of removing decay heat, venting the containment atmosphere (i.e., including steam, hydrogen, carbon monoxide, non-condensable gases, aerosols, and fission products), and controlling containment pressure within acceptable limits. The capability of the HCVS is not limited to a specific event, but the purpose of the HCVS is to provide broad functional capability to prevent containment over-pressurization prior to core damage and to mitigate over-pressure conditions that may exist after core damage.

In a letter dated June 30, 2014, EGC issued RS-14-058 as an overall integrated plan in response to the June 6, 2013, Commission Order modifying Licenses with regard to reliable hardened containment vents capable of operation under severe accident conditions.

The portion of the new HCVS does not interface with the existing Augmented Primary Containment Vent System required by NRC Generic Letter (GL) 89-16 as described in the DNPS UFSAR Section 6.2.7.

Primary containment is also not impacted since the tie-in for the HCVS will be to the vent line outboard of an existing primary containment isolation valve. The modification installs a new valve second in-line valve as an outboard CIV in the existing vent line. The new valve, once installed, will be tested and become a part of the 10 CFR 50, Appendix J, Type C Local Leak Rate Test (LLRT) Program.

Engineering Change (EC) No. 351639 / 351640, "Drywell Pneumatic Air Isolation Valve Single Point Vulnerability" Installation of new air-operated valve (AOV) 2(3)-4724, "Drywell Pneumatic Inlet Air Operated Primary Containment Isolation Valve," and in series with check valve 2(3)-4799-531, "Drywell Pneumatic Inlet Check Valve," on a redundant flow path will form the primary containment isolation boundary. The valves were added into the LLRT Program for integrated local leak rate testing. The existing AOV 2(3)-4722, "Drywell Pneumatic Inlet Air Operated Primary Containment Isolation Valve," is a fail closed valve on loss of power to the solenoid, solenoid failure, certain type AOV actuator failure isolating the pneumatic air to the drywell. The same Page 7 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE feature was added to the new AOV 2(3)-4724. Additional isolation valves were added to facilitate LLRT and provide means of isolation.

This design change consisted of a parallel flow path to AOV 2(3)-4722, with both valves located outside the drywell, and in series with check valve 2(3)-4799-530, "Drywell Pneumatic Inlet Check Valve," which is located inside the drywell. These valves are powered from different breakers off of the Unit 2(3) Instrument bus for the new AOV. Manual isolation valves used for isolation purpose were installed for both the original flow path and the new flow path.

Primary containment was not impacted since the tie-in for the new AOV 2(3)-4724 was outboard of the drywell and downstream of the existing outboard primary containment isolation valve AOV 2(3)-4722. All post modification testing was addressed by the performance of LLRTs.

3.2 Emergency Core Cooling System Net Positive Suction Head Analysis (Post-Extended Power Uprate (EPU))

The ECCS, Low Pressure Coolant Injection (LPCI), and Core Spray (CS) Pump net positive suction head (NPSH) requirements are addressed in Section 6.3.3.4.3 of the UFSAR. An evaluation was conducted to support NPSH pumping requirement for post-extended power uprate (EPU) (i.e., 2957 MWth) operation. The analysis evaluated both short term (i.e., first 600 seconds) and long term (i.e., after 600 seconds) post accident pressure and temperature response of containment. The containment analyses determined the minimum containment pressure present in the suppression chamber air space for these bounding cases and supports the use of the following credited containment pressure values as shown in Table 3.2-1 below, and used in the LPCI and CS NPSH analyses.

Table 3.2-1 Credited Containment Pressure From To Credited Containment (Seconds) (Seconds) Pressure (psig) 0 290 9.5 290 5,000 4.8 5,000 30,000 6.6 30,001 40,000 6.0 40,001 45,500 5.4 45,501 52,500 4.9 52,501 60,500 4.4 60,501 70,000 3.8 70,001 84,000 3.2 84,001 104,000 2.5 104,001 136,000 1.8 Accident 136,001 1.1 Termination Page 8 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE The analysis showed sufficient containment pressure is available during the first 290 seconds to provide adequate NPSH for the LPCI and CS pumps; however, pump cavitation may occur for a short time after 290 seconds until operators throttle the LPCI and CS systems to restore NPSH.

While the pumps may cavitate during this time period, they will continue to provide sufficient flow to the vessel to ensure core flood up. Cavitation tests have been performed on the LPCI pump, which is the same model as the CS pump, and these tests demonstrated that the pumps can cavitate in the short-term without any damage to pump internals or any degradation in pump performance.

The values shown in Table 3.2-1 above, and in UFSAR Section 6.3.3.4.3.4, for credited containment pressure in the LPCI and CS NPSH analyses, were evaluated by the NRC and approved in the safety evaluation (SE) for Amendment Nos. 191 and 185 for Units 2 and 3, respectively (i.e., Reference 15).

3.3 Justification for the Technical Specification Change 3.3.1 Chronology of Testing Requirements of 10 CFR 50, Appendix J The testing requirements of 10 CFR 50, Appendix J, provide assurance that leakage from the containment, including systems and components that penetrate the containment, does not exceed the allowable leakage values specified in the TSs. 10 CFR 50, Appendix J also ensures that periodic surveillances of reactor containment penetrations and isolation valves are performed so that proper maintenance and repairs are made during the service life of the containment and of the systems and components penetrating primary containment. The limitation on containment leakage provides assurance that the containment would perform its design function following an accident up to and including the plant DBA. Appendix J identifies three types of required tests: 1) Type A tests, intended to measure the primary containment overall integrated leakage rate; 2) Type B tests, intended to detect local leaks and to measure leakage across pressure-containing or leakage limiting boundaries (other than valves) for primary containment penetrations, and; 3) Type C tests, intended to measure containment isolation valve leakage rates. Types B and C tests identify the vast majority of potential containment leakage paths. Type A tests identify the overall (integrated) containment leakage rate and serve to ensure continued leakage integrity of the containment structure by evaluating those structural parts of the containment not covered by Types B and C testing.

In 1995, 10 CFR 50, Appendix J, was amended to provide a performance-based option (i.e., Option B) for the containment leakage testing requirements. Option B requires that test intervals for Type A, Type B, and Type C testing be determined by using a performance-based approach. Performance-based test intervals are based on consideration of the operating history of the component and resulting risk from its failure. The use of the term performance-based in 10 CFR 50, Appendix J refers to both the performance history necessary to extend test intervals as well as to the criteria necessary to meet the requirements of Option B.

Also in 1995, RG 1.163 (i.e., Reference 1) was issued. The RG endorsed NEI 94-01, Revision 0, (i.e., Reference 5) with certain modifications and additions. Option B, in concert with RG 1.163 and NEI 94-01, Revision 0, allows licensees with a satisfactory ILRT performance history (i.e., two consecutive, successful Type A tests) to reduce the test frequency for the containment Type A (ILRT) test from three tests in 10 years to one test in 10 years. This relaxation was based on an NRC risk assessment contained in NUREG-1493, "Performance-Page 9 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE Based Containment Leak-Test Program," (i.e., Reference 6) and Electric Power Research Institute (EPRI) TR-104285, Risk Impact Assessment of Revised Containment Leak Rate Testing Intervals," (i.e., Reference 7), both of which showed that the risk increase associated with extending the ILRT surveillance interval was very small. In addition to the 10-year ILRT interval, provisions for extending the test interval an additional 15 months were considered in the establishment of the intervals allowed by RG 1.163 and NEI 94-01, but that this extension of interval should be used only in cases where refueling schedules have been changed to accommodate other factors.

In 2008, NEI 94-01, Revision 2-A (i.e., Reference 8), was issued. This document describes an acceptable approach for implementing the optional performance-based requirements of Option B to 10 CFR 50, Appendix J, subject to the limitations and conditions noted in Section 4.0 of the NRC SER on NEI 94-01. NEI 94-01, Revision 2-A, includes provisions for extending Type A ILRT intervals to up to 15 years and incorporates the regulatory positions stated in RG 1.163 (i.e., Reference 1). The document also delineates a performance-based approach for determining Type A, Type B, and Type C containment leakage rate surveillance testing frequencies. Justification for extending test intervals is based on the performance history and risk insights.

In 2012, NEI 94-01, Revision 3-A (i.e., Reference 2), was issued. This document describes an acceptable approach for implementing the optional performance-based requirements of Option B to 10 CFR 50, Appendix J and includes provisions for extending Type A ILRT intervals to up to 15 years. NEI 94-01 has been endorsed by RG 1.163 and NRC SERs dated June 25, 2008 (i.e., Reference 9), and June 8, 2012 (i.e., Reference 10), as an acceptable methodology for complying with the provisions of Option B in 10 CFR 50, Appendix J. The regulatory positions stated in RG 1.163 as modified by References 9 and 10 are incorporated in this document. It delineates a performance-based approach for determining Type A, Type B, and Type C containment leakage rate surveillance testing frequencies. Justification for extending test intervals is based on the performance history and risk insights. Extensions of Type B and Type C test intervals are allowed based upon completion of two consecutive periodic as-found tests where the results of each test are within a licensees allowable administrative limits.

Intervals may be increased from 30 months up to a maximum of 120 months for Type B tests (i.e., except for containment airlocks) and up to a maximum of 75 months for Type C tests. If a licensee considers extended test intervals of greater than 60 months for Type B or Type C tested components, the review should include the additional considerations of as-found tests, schedule and review as described in NEI 94-01, Revision 3-A, Section 11.3.2.

The NRC has provided guidance concerning the use of test interval extensions in the deferral of ILRTs beyond the 15-year interval in NEI 94-01, Revision 2-A, NRC SER Section 3.1.1.2 which states, in part:

Section 9.2.3, NEI TR 94-01, Revision 2, states, Type A testing shall be performed during a period of reactor shutdown at a frequency of at least once per 15 years based on acceptable performance history. However, Section 9.1 states that the required surveillance intervals for recommended Type A testing given in this section may be extended by up to 9 months to accommodate unforeseen emergent conditions but should not be used for routine scheduling and planning purposes. The NRC staff believes that extensions of the performance-based Type A test interval beyond the required 15 years should be infrequent and used only for compelling reasons. Therefore, if a licensee wants to use the provisions Page 10 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE of Section 9.1 in TR NEI 94-01, Revision 2, the licensee will have to demonstrate to the NRC staff that an unforeseen emergent condition exists.

NEI 94-01, Revision 3-A, Section 10.1, "Introduction," concerning the use of test interval extensions in the deferral of Type B and Type C LLRTs, based on performance, states, in part, that:

Consistent with standard scheduling practices for Technical Specifications Required Surveillances, intervals of up to 120 months for the recommended surveillance frequency for Type B testing and up to 75 months for Type C testing given in this section may be extended by up to 25% of the test interval, not to exceed nine months.

Notes: For routine scheduling of tests at intervals over 60 months, refer to the additional requirements of Section 11.3.2.

Extensions of up to nine months (total maximum interval of 84 months for Type C tests) are permissible only for non-routine emergent conditions. This provision (nine-month extension) does not apply to valves that are restricted and/or limited to 30-month intervals in Section 10.2 (such as [boiling water reactor] BWR MSIVs) or to valves held to the base interval (30 months) due to unsatisfactory LLRT performance.

The NRC has also provided the following concerning the extension of ILRT intervals to 15 years in NEI 94-01, Revision 3-A, NRC SER Section 4.0, Condition 2, which states, in part:

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.

3.3.2 Current DNPS, Units 2 and 3 ILRT Requirements Title 10 CFR 50, Appendix J was revised, effective October 26, 1995, to allow licensees to choose containment leakage testing under either Option A, "Prescriptive Requirements," or Option B, "Performance-Based Requirements." On January 11, 1996, the NRC approved Amendment Nos. 148 and 142 for DNPS, Units 2 and 3, respectively. These amendments authorized the implementation of 10 CFR 50, Appendix J, Option B for Types A, B, and C tests (i.e., Reference 13).

In the implementation of Option B, the safety evaluation noted that DNPS differed with the model TS developed by the NRC in cooperation with NEI, on one item. Specifically, DNPS chose to retain its existing surveillance to monitor secondary containment integrity. The NRC noted that: The current specifications provide adequate assurance of secondary containment, were previously approved by the staff, and are acceptable. Based on the above, the licensees proposed changes implementing Option B of Appendix J are acceptable (i.e., Reference 13).

Option B states that specific existing exemptions to Option A are still applicable unless specifically revoked by the NRC. DNPS currently has approved exemptions to 10 CFR Part 50, Appendix J that were issued by the NRC on June 25, 1982 (i.e., Reference 40). These exemptions, which focus on testing methodology aspects of Appendix J, are unaffected by the Page 11 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE change to the Option B testing frequency requirements. These exemptions are also unaffected by this ILRT testing amendment.

Currently, TS 5.5.12 requires that a program be established to comply with the containment leakage rate testing requirements of 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option B, as modified by approved exemption. The program is required to be in accordance with the guidelines contained in RG 1.163. RG 1.163 endorses, with certain exceptions, NEI 94-01, Revision 0, as an acceptable method for complying with the provisions of Appendix J, Option B.

RG 1.163, Section C.1 states that licensees intending to comply with 10 CFR 50, Appendix J, Option B, should establish test intervals based upon the criteria in Section 11.0 of NEI 94-01 (i.e., Reference 5) rather than using test intervals specified in ANSI/ANS 56.8-1994. NEI 94-01, Section 11.0 refers to Section 9, which states that Type A testing shall be performed during a period of reactor shutdown at a frequency of at least once-per-ten years based on acceptable performance history. Acceptable performance history is defined as completion of two consecutive periodic Type A tests where the calculated performance leakage was less than 1.0La (where La is the maximum allowable leakage rate at design pressure). Elapsed time between the first and last tests in a series of consecutive satisfactory tests used to determine performance shall be at least 24 months.

Adoption of the Option B performance-based containment leakage rate testing program altered the frequency of measuring primary containment leakage in Types A, B, and C tests but did not alter the basic method by which Appendix J leakage testing is performed. The test frequency is based on an evaluation of the as found leakage history to determine a frequency for leakage testing which provides assurance that leakage limits will not be exceeded. The allowed frequency for Type A testing as documented in NEI 94-01 is based, in part, upon a generic evaluation documented in NUREG-1493. The evaluation documented in NUREG-1493 included a study of the dependence or reactor accident risks on containment leak tightness for differing containment types. NUREG-1493 concluded in Section 10.1.2 that reducing the frequency of Type A tests (ILRT) from the original three (3) tests per 10 years to one (1) test per 20 years was found to lead to an imperceptible increase in risk. The estimated increase in risk is very small because ILRTs identify only a few potential containment leakage paths that cannot be identified by Types B and C testing, and the leaks that have been found by Type A tests have been only marginally above existing requirements. Given the insensitivity of risk to containment leakage rate and the small fraction of leakage paths detected solely by Type A testing, NUREG-1493 concluded that increasing the interval between ILRTs is possible with minimal impact on public risk.

3.3.3 DNPS 10 CFR 50, Appendix J, Option B Licensing History SE dated January 11, 1996 (NRC Accession No. ML021160123)

The NRC approved Amendment Nos. 148 and 142 for DNPS, Units 2 and 3, respectively, on January 11, 1996 (i.e., Reference 13). The amendments authorized the implementation of 10 CFR 50, Appendix J, Option B for Types A, B, and C tests.

SE dated December 21, 1999 (NRC Accession No. ML993630259)

The NRC issued Amendment Nos. 175 and 171 for DNPS, Units 2 and 3, respectively on October 1, 1999 (i.e., Reference 14). The amendments changed TS 4.7.0.6 by replacing the Page 12 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE leakage limit of 11.5 standard cubic feet per hour (scfh) for each main steam isolation valve (MSIV) with a limit of 46 scfh on the total combined leakage for the MSIVs of all four main steam lines. The value chosen for the new total limit is equivalent to the sum of the current individual limits.

SE dated December 21, 2001 (NRC Accession No. ML013540187)

The NRC issued Amendment Nos. 191 and 185 for DNPS, Unit 2 and 3, respectively, on December 21, 2001 (i.e., Reference 15). The amendments allowed an increase in the maximum authorized operating power level from original rated thermal power (ORTP) of 2511 Megawatts thermal power (MWth) to 2957 MWth. The changes increased the rated thermal power (RTP) by approximately 17.8 percent and were considered an EPU. The amendments changed the TS appended to the operating licenses to allow plant operation at 2957 MWth. These amendments also modified license conditions and requested additional license conditions to support the power uprate. Two noteworthy license changes of the EPU amendment with consideration to containment are: (1) decreasing Pa, from the pre-EPU peak calculated primary containment internal pressure from a DBA resulting in a Pa of 48.0 psig to post-EPU DBA Pa of 43.9 psig (SE, Section 4.1.1.3); and, (2) containment overpressure is credited for pressure effects on NPSH for the LPCI and CS pumps (i.e., SE, Section 4.2.5) (See also Section 3.2 of this LAR).

SE dated October 10, 2003 (NRC Accession No. ML032740364)

The NRC issued Amendment Nos. 203 and 195 for DNPS, Units 2 and 3, respectively on October 10, 2003 (i.e., Reference 16). The Amendments allowed a revision to TS 3.6.1.3, "Primary Containment Isolation Valves (PCIVs)," Surveillance Requirement (SR) 3.6.1.3.8 to require that a representative sample of reactor instrumentation line excess flow check valves (EFCVs) be tested every 24 months, such that each EFCV will be tested nominally at least once every 10 years. Currently, TS SR 3.6.1.3.8 is performed for testing of each reactor instrumentation line EFCV at a 24-month frequency in accordance with the DNPS, Units 2 and 3 Surveillance Frequency Control Program (SFCP).

SE dated October 13, 2004 (ML042520432)

The NRC issued Amendment Nos. 210 and 202 for DNPS, Units 2 and 3, respectively, on March 8, 2004 (i.e., Reference 17). These amendments provided a one-time TS change to extend the test interval from 10 to 15 years for the containment leakage rate, Appendix J, Type A tests. Additionally, these amendments included the following exceptions:

1. NEI 94-01-1995, Section 9.2.3: The first Unit 2 Type A test performed after the February 18, 1996, Type A test shall be performed no later than February 27, 2011; and

2. NEI 94-01-1995, Section 9.2.3: The first Unit 3 Type A test performed after the July 14, 1993, Type A test shall be performed no later than July 13, 2009.

Note: The LLRTs (i.e., Type B and Type C tests), including their schedules, were not affected by these amendments. In addition, the vacuum breaker TS SRs 3.6.1.7 and 3.6.1.8, including their schedules, were not affected by these amendments.

Page 13 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE Notice of Issuance of Renewed Facility Operating License, October 28, 2004 (NRC Accession No. ML042960560)

Notice was given that the NRC issued Renewed Facility Operating License Nos. DPR-19 and DPR-25 to Exelon Generation Company, LLC, the operator of DNPS, Unit Nos. 2 and 3, on October 28, 2004 (i.e., Reference 33). NUREG-1796, the SER related to the Renewed Facility Operating License for DNPS, Unit Nos. 2 and 3, was issued in October of 2004 (i.e., Reference 18).

This renewed license approves extended operation for DNPS, Unit 2 until December 22, 2029, and for DNPS, Unit 3 until January 12, 2031. According to the SER, Section 2.4, "Scoping and Screening Results: Structures," and found in Section 2.4.1.3, "Conclusions," the NRC concluded that; the applicant has adequately identified the structural components of the primary containment that are within the scope of license renewal, as required by 10 CFR 54(a), and that the applicant adequately identified the structural components of the primary containment that are subject to Aging Management Review (AMR), as required by 10 CFR 54.21(a)(1).

Additionally from the DNPS UFSAR, Appendix A, "UFSAR Supplement," Section A.3.4, "Containment Fatigue," it is noted that fatigue management activities will ensure that fatigue effects are adequately managed and are maintained within code design limits for extended operation, in accordance with the requirements of 10 CFR 54.21(c)(1)(iii). The UFSAR Supplement Section A.1.28 also credits the existing 10 CFR 50, Appendix J Program for monitoring leakage rates through the containment pressure boundary during the period of extended operation.

SE dated September 11, 2006 (NRC Accession No. ML062070290)

The NRC issued Amendment Nos. 221 and 212 for DNPS, Units 2 and 3, respectively, on September 11, 2006 (i.e., Reference 47). These amendments approved adoption of an alternative source term methodology by replacing the current accident source term described in Technical Information Document (TID) 14844 (source term) with an accident source term as prescribed in Title 10 to the Code of Federal Regulations Section 50.67, "Accident source term."

Applicable parts of these amendments pertaining to containment and this LAR are: (1) change was made to the maximum allowable containment leak rate from 1 percent primary containment air weight per day to 3 percent primary containment air weight per day (Section 3.3.6 of the SER), and (2) change was made to the allowable leak rate limits for the MSIVs from 11.5 scfh for individual MSIVs and 46 scfh combined to a new limit of 34 scfh individual and 86 scfh combined (i.e., Section 3.3.7 of the SE).

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ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE 3.3.4 Integrated Leakage Rate Testing History (ILRT)

As noted previously, DNPS TS 5.5.12 currently requires Type A, B, and C leak rate testing in accordance with RG 1.163, which endorses the methodology for complying with 10 CFR 50, Appendix J, Option B. Since the adoption of Option B, the performance leakage rates are calculated in accordance with NEI 94-01, Section 9.1.1 for Type A testing. Tables 3.3.4-1 and 3.3.4-2 lists the past Periodic Type A ILRT results for DNPS, Units 2 and 3.

Table 3.3.4-1, DNPS Units 2 and 3 ILRT Test History Test Date Leakage1 (weight-percent/day)

Unit 2 November 1969 0.1634 April 1972 0.3015 May 1976 0.2535 April 1979 0.3935 April 1983 0.278 March 1985 0.4732 December 1986 0.6366 December 1990 0.7428 May 1993 0.8184 Unit 3 August 1970 0.232 May 1974 0.2839 April 1978 0.4505 1982 0.5399 July 1986 0.6567 March 1988 0.4800 February 1990 1.0075 March 1992 0.5546 Note 1: The maximum allowable primary containment leakage rate, La, 1.6 percent (%) of primary containment air weight per day. TS leakage rate acceptance criteria for a Type A test for unit startup is 0.75La (i.e., 1.2% containment air weight per day).

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ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE The current ILRT test interval for DNPS Units 2 and 3 is ten years. Verification of this interval is presented in Table 3.3.4-2. The acceptance criteria used for this verification is contained in NEI 94-01 Rev. 2-A and Rev. 3-A, Section 5.0, "Definitions." and is as follows:

The performance leakage rate is calculated as the sum of the Type A upper confidence limit (UCL) and as-left minimum pathway leakage rate (MNPLR) leakage rate for all Type B and Type C pathways that were in service, isolated, or not lined up in their test position (i.e., drained and vented to containment atmosphere) prior to performing the Type A test.

In addition, leakage pathways that were isolated during performance of the test because of excessive leakage must be factored into the performance determination. The performance criterion for Type A tests is a performance leak rate of less than 1.0La.

Table 3.3.4-2, DNPS ILRT Test Results Verification of Current Extended ILRT Interval Upper 95% As Left Min Test Confidence Pathway Adjusted Level Method /

Test Level Penalty for As Left Acceptance Corrections Data Date (wt.%/day) Isolated Leak Rate Criteria (wt.%/day) Analysis (Test Pathways (wt.%/day) 1 Techniques Pressure ) (wt.%/day)

Unit 2 Absolute

<0.75La, February 0.33798 Method /

0.00860 0.09540 0.44198 1.2 1996 (50.59 psig) BN-TOP-1, wt.%/day Rev 1 0.595874 Conservat- <0.75La, November (45.8237 ively 0.1379 0.7338 2.25 Mass Point 2009 psig) Ignored wt.%/day Unit 3

<0.75La, Absolute July 0.5740 0.0087 0.0722 0.6549 1.2 Method /

1994 (49.793 psig) wt.%/day BN-TOP-1, Rev 1

<0.75La, November 0.81627 0.0061 0.202 1.041 2.25 2008 (45.64 psig) Mass Point wt.%/day Note 1: TS Amendments 191 and 185 for DNPS, Units 2 and 3, respectively, on December 21, 2001, decreased Pa, from the pre-EPU peak calculated primary containment internal pressure from a DBA resulting in a Pa of 48.0 psig to post-EPU DBA Pa of 43.9 psig (Reference 15).

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ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE 3.4 Plant Specific Confirmatory Analysis 3.4.1 Methodology An evaluation has been performed to provide an assessment of the risk associated with implementing a permanent extension of the DNPS, Units 2 and 3 containment Type A ILRT interval from ten years to fifteen years. The risk assessment follows the guidelines from a number of documents, which include: (1) NEI 94-01 (i.e., Reference 2), (2) the methodology outlined in EPRI TR-104285 (i.e., Reference 7) as updated by EPRI TR-1018243, "Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals: Revision 2-A of 1009325,"

(i.e., Reference 11), (3) the NRC regulatory guidance on the use of Probabilistic Risk Assessment (PRA) findings and risk insights in support of a request for a plants licensing basis as outlined in RG 1.174 (i.e., Reference 3), and (4) the methodology used for Calvert Cliffs to estimate the likelihood and risk implications of corrosion-induced leakage of steel liners going undetected during the extended test interval (i.e., Reference 32). The format of this document is consistent with the intent of the Risk Impact Assessment Template for evaluating extended integrated leak rate testing intervals provided in the EPRI TR-1018243 (i.e., Reference 11).

Details of the DNPS, Units 2 and 3 risk assessment, providing an assessment of the risk associated with implementing a permanent extension of the DNPS containment Type A ILRT interval from ten years to fifteen years, is contained in Attachment 3 of this LAR submittal.

The NRC report on performance-based leak testing, NUREG-1493 (i.e., Reference 6), analyzed the effects of containment leakage on the health and safety of the public and the benefits realized from the containment leak rate testing. In that analysis, it was determined for a comparable boiling water reactor (BWR) plant, that increasing the containment leak rate from the nominal 0.5 percent per day to 5 percent per day leads to a barely perceptible increase in total population exposure, and increasing the leak rate to 50 percent per day increases the total population exposure by less than one percent. Because ILRTs represent substantial resource expenditures, it is desirable to show that extending the ILRT interval will not lead to a substantial increase in risk from containment isolation failures to support a reduction in the test frequency for DNPS. The current analysis is being performed to confirm these conclusions based on DNPS-specific PRA models and available data.

Earlier ILRT frequency extension submittals have used the EPRI TR-104285 (i.e., Reference 7) methodology to perform the risk assessment. In October 2008, EPRI TR 1018243 (i.e., Reference 11) was issued to develop a generic methodology for the risk impact assessment for ILRT interval extensions to 15 years using current performance data and risk informed guidance, primarily NRC RG 1.174 (i.e., Reference 3). This more recent EPRI document considers the change in population dose, large early release frequency (LERF), and containment conditional failure probability (CCFP), whereas EPRI TR-104285 considered only the change in risk based on the change in population dose. This ILRT interval extension risk assessment for DNPS, Units 2 and 3 employs the EPRI 1018243 methodology, with the affected System, Structure, or Component (SSC) being the primary containment boundary.

In the safety evaluation (SE) issued by NRC letter dated June 25, 2008 (i.e., Reference 9), the NRC concluded that the methodology in EPRI TR-1009325, Revision 2 (i.e., Reference 20), 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 Page 17 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE Section 4.0 of the SE. Table 3.4.1-1 below addresses each of the four limitations and conditions from Section 4.2 of the SE for the use of EPRI 1009325, Revision 2.

Table 3.4.1-1, EPRI Report No. 1009325 Revision 2 Limitations and Conditions Limitation and Condition DNPS Response (From Section 4.2 of SE)

1. The licensee submits documentation DNPS PRA technical adequacy is addressed indicating that the technical adequacy of in Section 3.4.2 of this LAR and Attachment their PRA is consistent with the 3, Risk Assessment for DNPS Regarding the requirements of RG 1.200 relevant to the ILRT (Type A) Permanent Extension ILRT extension application. Request, located in Appendix A, PRA Technical Adequacy.

2.a The licensee submits documentation Since the ILRT extension has negligible indicating that the estimated risk increase impact on core damage frequency (CDF),

associated with permanently extending the relevant criterion is LERF. The increase the ILRT surveillance interval to 15 years in internal events LERF resulting from a is small, and consistent with the change in the Type A ILRT interval for the clarification provided in Section 3.2.4.5 of base case with corrosion included is this SE. 3.31E-08/year (yr).

In using the EPRI Expert Elicitation methodology, the change is estimated as 7.23E-09/yr.

Both of these values fall within the very small change region of the acceptance guidelines in RG 1.174.

2.b Specifically, a small increase in The change in dose risk for changing the population dose should be defined as an Type A test frequency from three-per-ten increase in population dose of less than years to once-per-fifteen-years, measured as or equal to either 1.0 person-roentgen an increase to the total integrated dose risk equivalent man (rem) per year or 1% of for all internal events accident sequences for the total population dose, whichever is DNPS, is 4.26E-02 person-rem/yr (0.27%)

less restrictive. using the EPRI guidance with the base case corrosion included.

The change in dose risk drops to 1.14E-02 person-rem/yr (0.07%) when using the EPRI Expert Elicitation methodology.

The values calculated per the EPRI guidance are all lower than the acceptance criteria of less than or equal to 1.0 person-rem/yr or less than 1.0% person-rem/yr defined in Section 1.3 (of Attachment 3).

Page 18 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE Table 3.4.1-1, EPRI Report No. 1009325 Revision 2 Limitations and Conditions Limitation and Condition DNPS Response (From Section 4.2 of SE) 2.c In addition, a small increase in CCFP The increase in the conditional containment should be defined as a value marginally failure frequency from the three in ten year greater than that accepted in a previous interval to one in fifteen years including one-time 15-year ILRT extension corrosion effects using the EPRI guidance is requests. This would require that the 1.03%. This value drops to 0.22% using the increase in CCFP be less than or equal to EPRI Expert Elicitation methodology.

1.5 percentage point.

Both of these values are below the acceptance criteria of less than 1.5%.

3. The methodology in EPRI Report No. The representative containment leakage for 1009325, Revision 2, is acceptable except Class 3b sequences used by DNPS is for the calculation of the increase in 100 La, based on the recommendations in expected population dose (per year of the latest EPRI report (i.e., Reference 20) reactor operation). In order to make the and as recommended in the NRC SE on this methodology acceptable, the average leak topic (i.e., Reference 9). It should be noted rate accident case (accident case 3b) that this is more conservative than the earlier used by the licensees shall be 100 La previous industry ILRT extension requests, instead of 35 La. which utilized 35 La for the Class 3b sequences.

4. A licensee amendment request (LAR) is DNPS relies upon containment over-required in instances where containment pressure for ECCS performance. See over-pressure is relied upon for ECCS Section 3.2 of this LAR Attachment for performance. details. The LPCI and Core Spray NPSH analyses were evaluated by the NRC and approved in the SER for Amendment 191 for Unit 2, and Amendment 185 for Unit 3.

3.4.2 Technical Adequacy of the PRA The PRA Technical Adequacy evaluation is presented in Attachment 3, Appendix A, PRA Technical Adequacy, of this LAR. The following is a summary of that evaluation.

3.4.2.1 Demonstrate the Technical Adequacy of the PRA The guidance provided in RG 1.200 (i.e., Reference 4), Section 4.2, "License Submittal Documentation," indicates that the following items be addressed in documentation submitted to the NRC to demonstrate the technical adequacy of the PRA:

x Identify plant changes (design or operational practices) that have been incorporated at the site, but are not yet in the PRA model and justify why the change does not impact the PRA results used to support the application.

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ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE x Document peer review findings and observations that are applicable to the parts of the PRA required for the application, and for those that have not yet been addressed justify why the significant contributors would not be impacted.

x Document that the parts of the PRA used in the decision are consistent with applicable standards endorsed by the Regulatory Guide. Provide justification to show that where specific requirements in the standard are not met, it will not unduly impact the results.

x Identify key assumptions and approximations relevant to the results used in the decision-making process.

The risk assessment performed for the ILRT extension request is based on the current Level 1 and Level 2 PRA model. Note that for this application, the accepted methodology involves a bounding approach to estimate the change in the PRA risk metric of LERF from extending the ILRT interval. Rather than exercising the PRA model itself, it involves the establishment of separate evaluations that are linearly related to the plant CDF contribution. Consequently, a reasonable representation of the plant CDF that does not result in a LERF does not require that Capability Category II be met in every aspect of the modeling if the Category I treatment is conservative or otherwise does not significantly impact the results.

3.4.2.2 PRA Model Evolution and Peer Review Summary The 2013A versions of the DNPS PRA models are the most recent evaluations of the Unit 2 and Unit 3 risk profile at DNPS for internal event challenges. The DNPS PRA modeling is highly detailed, including a wide variety of initiating events, modeled systems, operator actions, and common cause events. The PRA model quantification process used for the DNPS PRA is based on the event tree / fault tree methodology, which is a well-known methodology in the industry.

EGC employs a multi-faceted approach to establishing and maintaining the technical adequacy and plant fidelity of the PRA models for all operating EGC nuclear generation sites. This approach includes both a proceduralized PRA maintenance and update process, and the use of self-assessments and independent peer reviews. The following information describes this approach as it applies to the DNPS PRA.

3.4.2.3 PRA Maintenance and Update The EGC Risk Management process ensures that the applicable PRA model is an accurate reflection of the as-built and as-operated plants. This process is defined in the Exelon Risk Management Program, which consists of a governing procedure and subordinate implementation procedures. The PRA model update procedure delineates the responsibilities and guidelines for updating the full power internal events PRA models at all operating Exelon nuclear generation sites. The overall Exelon Risk Management program defines the process for implementing regularly scheduled and interim PRA model updates, for tracking issues identified as potentially affecting the PRA models (e.g., due to changes in the plant, industry operating experience, etc.), and for controlling the model and associated computer files.

3.4.2.4 Plant Changes Not Yet Incorporated into the PRA Model A PRA updating requirements evaluation (URE- Exelon PRA model update tracking database) is created for all issues that are identified that could impact the PRA model. The URE database Page 20 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE includes the identification of those plant changes that could impact the PRA model. A review of the open UREs indicates that there are no plant changes that have not yet been incorporated into the PRA model that would affect this application.

3.4.2.5 Consistency with Applicable PRA Standards Several assessments of technical capability have been made for the DNPS internal events PRA models. These assessments are as follows and are further discussed in the paragraphs below.

x An independent PRA peer review was conducted under the auspices of the BWR Owners Group in 1998, following the Industry PRA Peer Review process (i.e., References 33 and 23). This peer review included an assessment of the PRA model maintenance and update process. The DNPS PRA was significantly upgraded following the peer review resulting in the need for a second independent PRA peer review.

x A second independent PRA peer review was conducted under the auspices of the BWR Owners Group in 2000, again following an Industry PRA Peer Review process (i.e., Reference 29). This peer review (i.e., Reference 31) was a full scope review and included an assessment of the PRA model maintenance and update process.

x In March 2009, a self-assessment (i.e., Reference 34) was performed against the available version of the ASME/ANS PRA Standard (Reference 30) x In March 2009, an independent Focused PRA Peer Review (i.e., Reference 23) of the DNPS Internal Flooding (IF) PRA model was performed using the NEI 05-04, Rev. 2 (i.e., Reference 52) process, the ASME PRA Standard (i.e., Reference 46), and RG 1.200, Rev. 1 (i.e., Reference 48). The results of that assessment are used as the basis for the capability assessment provided in Attachment 3, Table A-1 of this LAR.

x In June 2009, a minor revision of the DNPS PRA self-assessment (i.e., Reference 35) was issued to ensure certain critical technical changes from the ASME/ANS PRA Standard were addressed in the self-assessment.

x In October 2009, the DNPS PRA self-assessment (i.e., Reference 38) was updated to reflect the 2009A PRA model and resolution of open items.

x In May 2010, an independent Focused PRA Peer Review (i.e., Reference 41) of the DNPS IF PRA model was performed using the NEI 05-04 Rev. 2 (i.e., Reference 52) process, the ASME PRA Standard (i.e., Reference 46), and RG 1.200, Rev. 1 (i.e., Reference 48).

x Following the most recent 2013 PRA update, another self-assessment (i.e., Reference 36) was performed to reflect the status after the 2013A model. This self-assessment was performed against the ASME/ANS PRA Standard (i.e., Reference 30), and RG 1.200, Rev. 2 (i.e., Reference 4).

x In November of 2016, an independent PRA Peer Review (i.e., Reference 51) of the DNPS Internal Events PRA model was performed using the NEI 05-04 Rev. 2 (i.e., Reference 46) process, the ASME PRA Standard (i.e., Reference 52), and RG 1.200, Rev. 2 (i.e., Reference 4). The Peer review included all supporting requirements (SRs) except those related to internal flooding, which were previously peer reviewed in 2009. In addition, Page 21 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE five (5) SRs were assessed as not applicable to the Dresden PRA. The results of that assessment are used as the basis for the capability assessment provided in Attachment 3, Table A-2 of this LAR.

The DNPS PRA has previously undergone four PRA peer reviews. The results of the second PRA peer review performed in 2000 found that the PRA was capable of being used for risk-informed applications. The grades and Facts and Observation results derived from the DNPS PRA Peer Review(1) were as follows:

x Grading(1) o 94% of the SRs were graded at 3 or above (i.e., Capability Category II or III) o 6% of the SRs were graded at 2 o 0% of the SRs were graded at 1 x Facts and Observations o A: There were no A level Facts and Observations o B: There were 9 B level Facts and Observations. These were all resolved in the 2005B model update.

o C & D: There were 30 C and D level Facts and Observations. These were all resolved in the 2005B model update.

(1)

The grading scheme used in the 2000 peer review differs from that found in the ASME/ANS PRA Standard (i.e., Reference 30).

The ASME/ANS PRA Standard added a significant number of explicit Supporting Requirements for the IF hazard after the DNPS PRA Peer Review. As a result, the DNPS PRA was subjected to an intensive focused PRA Peer Review for the internal flooding (IF) PRA element in 2009.

This focused PRA Peer Review of internal flooding used the ASME PRA Standard SRs (i.e., Reference 46) along with the NRC clarifications provided in Regulatory Guide 1.200, Rev.

1 and the review process guidelines in NEI 05-04 (i.e., Reference 52).

The results of that focused PRA Peer Review were:

x Number of Supporting Requirements at Capability Category I or higher 60 of 67 x Number of Gaps Identified for 2013A PRA (Capability Category Not Met) 7 An independent peer review of the 2013A PRA model was performed in November 2016. The result of this review found the following:

x Number of Supporting Requirements at Capability Category I or higher or Deemed Not Applicable 244 of 258 x Number of Gaps Identified for 2013A PRA (Capability Category Not Met) 14 There were 67 SRs previously assessed in the 2009 focused IF peer review and excluded from the 2016 peer review. Of the 67 SRs, 7 SRs were assessed as not met. Of these seven SRs, six SRs were addressed in the 2010A PRA update, leaving one SR not met (i.e., see , Table A-1 for a disposition of IF SRs). This leaves a total of 15 SRs of the 325 SRs applicable to the 2013A Dresden PRA that are not at Capability Category I or above.

These 15 SRs remain open for the 2013A PRA model. However, it is judged that these Page 22 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE deviations do not significantly impact the base PRA model or its ability to support the DNPS ILRT LAR risk assessment. As indicated above, a PRA model update was completed in 2013, resulting in the DR213A and DR313A updated models. The PRA model assessments show that approximately 95% of all the supporting requirements are characterized as meeting Capability Category I or better.

3.4.2.6 Applicability of Peer Review Findings and Observations According to the NRC SE for NEI 94-01, Revision 2 (i.e., Reference 9), the appropriate PRA quality to support an ILRT risk assessment is that the PRA Standard SRs should meet Capability Category I or greater.

Table A-1, Appendix A of Attachment 3 to this LAR, identifies the findings from the IF focused peer review. The IF peer review resulted in nine findings resulting in seven SRs that did not meet Capability Category I or higher requirements. The findings and associated SRs are described in Attachment 3,Table A-1. , Appendix A Table A-2 identifies the findings from the 2016 peer review. The peer review resulted in 31 findings resulting in 14 SRs that did not meet Capability Category I or higher requirements. The findings and associated SRs are described in Table A-2.

As detailed in Tables A-1 and A-2, there are no remaining gaps that fundamentally impact the conclusions of this ILRT extension application.

3.4.2.7 External Events Although EPRI Report 1018243 (i.e., Reference 11) recommends a quantitative assessment of the contribution of external events, such as fire and seismic, where a model of sufficient quality exists, it also recognizes that the external events assessment can be taken from existing, previously submitted and approved, analyses or another alternate method of assessing an order of magnitude estimate for contribution of the external event to the impact of the changed interval. Based on this, currently available information for external events models was referenced, and a multiplier was applied to the internal events results based on the available external events information. This is further discussed in Attachment 3, Section 5.7, "External Events Contribution."

3.4.2.8 PRA Quality Summary Based on the above, the DNPS PRA is of sufficient quality and scope for this application. The modeling is detailed; including a comprehensive set of initiating events (i.e., transients, LOCAs, and support system failures) including IF, system modeling, human reliability analysis and common cause evaluations. The DNPS PRA technical capability evaluations and the maintenance and update processes described above provide a robust basis for concluding that these PRA models are suitable for use in the risk-informed process used for this application.

3.4.2.9 Identification of Key Assumptions The methodology employed in this risk assessment followed the EPRI guidance as previously approved by the NRC. The analysis included the incorporation of several sensitivity studies and factored in the potential impacts from external events in a bounding fashion. None of the sensitivity studies or bounding analyses indicated any source of uncertainty or modeling Page 23 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE assumption that would have resulted in exceeding the acceptance guidelines. Since the accepted process utilizes a bounding analysis approach which is mostly driven by CDF contribution which does not already lead to LERF, there are no identified key assumptions or sources of uncertainty for this application (i.e., those which would change the conclusions from the risk assessment results presented here).

3.4.2.10 Summary A PRA technical adequacy evaluation was performed consistent with the requirements of RG 1.200, Revision 2. This evaluation, combined with the details of the results of this analysis, demonstrates with reasonable assurance that the proposed extension to the ILRT interval for DNPS, Units 2 and 3 to 15 years satisfies the risk acceptance guidelines in RG 1.174.

3.4.3 Summary of Plant-Specific Risk Assessment Results The findings of the DNPS, Units 2 and 3 Risk Assessment contained in Attachment 3 confirm the general findings of previous studies that the risk impact associated with extending the ILRT interval from three in 10 years to one in 15 years is small.

Based on the results from Attachment 3, Section 5.0, "Results," and the sensitivity calculations presented in Attachment 3, Section 6.0, "Sensitivities," the following conclusions regarding the assessment of the plant risk are associated with permanently extending the Type A ILRT test frequency to fifteen years:

x 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 below 1.0E-06/yr. and increases in LERF below 1.0E-07/yr. Small changes in risk are defined as increases in CDF below 1.0E-05/yr. and increases in LERF below 1.0E-06/yr.

Since the ILRT extension was demonstrated to have negligible impact on CDF for DNPS, the relevant criterion is LERF. The increase in internal events LERF resulting from a change in the Type A ILRT test interval for the base case with corrosion included is 3.31E-08/yr.

(Attachment 3 of this LAR, Table 5.6-1), which falls within the very small change region of the acceptance guidelines in RG 1.174.

o When using the EPRI Expert Elicitation Methodology, the change is estimated as 7.23E-09/yr. (Attachment 3 of this LAR, Table 6.2-2), which falls further within the very small change region of the acceptance guidelines in RG 1.174.

x The change in dose risk for changing the Type A test frequency from three-per-10 years to once-per-15-years, measured as an increase to the total integrated dose risk for all internal events accident sequences for DNPS, is 4.26E-02 person-rem/yr. (0.27%) using the EPRI guidance with the base case corrosion included (Attachment 3, Table 5.6-1). This change meets both of the related acceptance criteria for change in population dose of less than or equal to 1.0 person-rem/yr. or less than 1% person-rem/yr. identified in Attachment 3 of this LAR, Section 1.3.

o When using the EPRI Expert Elicitation methodology, the change in dose risk drops to 1.14E-02 person-rem/yr. (0.07%) (Attachment 3, Table 6.2-2). The change in dose risk meets both of the related acceptance criteria for change in population dose of less than Page 24 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE or equal to 1.0 person-rem/yr. or less than 1% person-rem/yr. identified in Attachment 3, Section 1.3 of this LAR.

x The increase in the conditional containment failure frequency from the three in ten-year interval to one in fifteen years including corrosion effects using the EPRI guidance is 1.03%

(Attachment 3, Section 5.5), which is below the acceptance criteria of 1.5% identified in Attachment 3, Section 1.3 of this LAR.

o When using the EPRI Expert Elicitation methodology, this value drops to 0.22%

(i.e., Attachment 3, Table 6.2-2). This value is below the acceptance criteria of less than 1.5% identified in Attachment 3 of this LAR, Section 1.3.

x To determine the potential impact from external events, a bounding assessment from the risk associated with external events was performed utilizing available information. As shown in Attachment 3, Table 5.7-8, the total increase in LERF due to internal events and the bounding external events assessment is 4.14E-07/yr. This value is in Region II of the RG 1.174 acceptance guidelines (i.e., small change in risk). The changes in dose risk and conditional containment failure frequency also remained below the acceptance criteria.

x The same bounding analysis as shown in Attachment 3, Table 5.7-7 indicates that the total LERF from both internal and external risks is 9.82E-06/yr., which is less than the RG 1.174 limit of 1.0E-05/yr. given that the delta () LERF is in Region II (i.e., small change in risk).

x Including age-adjusted steel liner corrosion effects in the ILRT assessment was demonstrated to be a small contributor to the impact of extending the ILRT interval for DNPS, Units 2 and 3.

Therefore, increasing the ILRT interval on a permanent basis to a one-in-15-year frequency is not considered to be significant since it represents only a small change in the DNPS risk profiles.

3.4.4 Previous Assessments In NUREG-1493 (i.e., Reference 6), the NRC has previously concluded that:

x Reducing the frequency of Type A tests (i.e., ILRTs) from three per 10 years to one per 20 years was found to lead to an imperceptible increase in risk. The estimated increase in risk is very small because ILRTs identify only a few potential containment leakage paths that cannot be identified by Types B and C testing, and the leaks that have been found by Type A tests have been only marginally above existing requirements.

x Given the insensitivity of risk to containment leakage rate and the small fraction of leakage paths detected solely by Type A testing, increasing the interval between integrated leakage rate tests is possible with minimal impact on public risk. The impact of relaxing the ILRT frequency beyond one in 20 years has not been evaluated. Beyond testing the performance of containment penetrations, ILRTs also test the integrity of the containment structure.

The findings for DNPS confirm these general findings on a plant specific basis considering the severe accidents evaluated for DNPS, the DNPS containment failure modes, and the local population surrounding DNPS.

Page 25 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE Details of the DNPS, Units 2 and 3 risk assessment are contained in Attachment 3 of this LAR submittal.

3.5 Non-Risk Based Assessment Consistent with the defense-in-depth philosophy discussed in RG 1.174, DNPS has assessed other non-risk-based considerations relevant to the proposed amendment. DNPS has multiple inspections and testing programs that ensure the containment structure continues to remain capable of meeting its design functions and that are designed to identify any degrading conditions that might affect that capability. These programs are discussed below.

3.5.1 Safety-Related Coatings Inspection Program DNPS has committed to follow RG 1.54, "Quality Assurance Requirements for Protective Coatings Applied to Water-Cooled Nuclear Power Plants," Revision 0. RG 1.54 describes a method to comply with requirements of 10 CFR 50, Appendix B and invokes several ANSI Standards. Standards pertinent to coatings are: ANSI N101.2, "Protective Coatings (Paints) for Light Water Nuclear Reactor Containment Facilities," ANSI N101.4, "Quality Assurance for Protective Coatings Applied to Nuclear Facilities," and ANSI N5.12, "Protective Coatings for the Nuclear Industry."

DNPS implements a Safety-Related Coatings Program that ensures DBA qualified coating systems are used inside Primary Containment. The program assures that safety-related DBA qualified coatings (i.e., Service Level 1) are selected, procured, applied and inspected in a manner that conforms to the applicable 10 CFR 50, Appendix B criteria. Unqualified coatings are controlled and tracked to ensure that emergency core cooling systems will not be adversely affected by coating debris following an accident. The program objective is to conform to licensee commitments made in response to GL 98-04. The Safety-Related Coatings Program also receives the support of the formal Maintenance Rule (10 CFR 50.65) condition-monitoring program. Engineering reviews and evaluates the results of coating condition examinations performed by qualified examiners.

A program to maintain containment coatings was developed to meet the requirements of RG 1.54, Revision 0, and is implemented by approved plant procedures.

Preventive maintenance activities have taken place and will continue to inspect and repair the protective coatings in the suppression chamber (i.e., submerged areas and vapor phase areas) and the drywell.

Primary Containment interior surface coating inspections are performed in the following areas:

all elevations of the drywell liner interior surfaces, biological shield visible surfaces, subpile room surfaces, drywell head interior surface, and the suppression chamber interior surface including the centipede, vent lines, water line region and the areas above.

The submerged regions of the suppression chamber are inspected underwater every refueling outage in accordance with site and approved vendor procedures. Table 3.5.1-1 below, provides the results from coating inspections that have been performed on DNPS, Units 2 and 3, during the second Containment Inservice Inspection Program (CISI) Interval for the past three refueling Page 26 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE outages. Table 3.5.1-1 lists for each units refueling outage, the coating inspection results for both the Torus underwater and the Primary Containment interior surface coating inspections.

Table 3.5.1-1 DNPS, Units 2 and 3 Coating Inspection Results Refueling Type of Outage & Coating Inspection Results Inspection Date Unit 2 All bays of submerged shell inspected, desludged, 66 coating deficiencies found, all repaired, no metal loss greater than 65 mil threshold (i.e., Reference 45). The overall coating Keeler and Long 6548/7107 condition is good with minimal pitting corrosion and coating Torus deficiencies on less than 1% of the coating.

Unit 2 Underwater D2R22 Ref Documents:

EC 383651 Rev 0,

Conclusion:

The underwater section of the torus is in October generally good shape with minimal pinpoint corrosion.

2011 Work Order (WO)

These results are consistent with findings from outages 1306973-01 going back to 2001. This stable trend supports the recommended action to continue to perform desludging, coating inspection and spot repair activities every outage. No additional actions are recommended from the underwater coatings report or this EC Evaluation.

Conclusion:

The conclusions of the vapor environment section of the reports identify that the coatings are in moderate condition compared to the age of the coatings.

The torus vapor side is in fair condition while the Coating centipede and drywell head have been consistently in Evaluation good or excellent condition. The conclusions from this Unit 2 report identify that some coating systems are exhibiting a declining trend or are in poor condition, and coating Ref. Documents: repairs are necessary. IRs 996128, 996133 and 996134 D2R22 EC 383651 and were created to document actions that should be October Issue Report (IR) completed by D2R25. IR 1279336 was created after 2011 1279336 D2R22 to document the preliminary results of the WO 01289774-01, walkdowns performed per DNPS Procedure DTS 1600-

-02 & -03. 11, Revision 10. IR 1286974 was created for actions for D2R23. Based on the results of each walkdown, there are no areas of significant degradation that are an immediate concern to the safety of plant operation or safe shutdown.

Page 27 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE Table 3.5.1-1 DNPS, Units 2 and 3 Coating Inspection Results Refueling Type of Outage & Coating Inspection Results Inspection Date All bays of submerged shell inspected, desludged, 89 coating deficiencies found, all repaired, no metal loss greater than 65 mil threshold. The overall coating Keeler and Long 6548/7107 condition is good with coating and Torus substrate deficiencies found on less than 1% of the torus Unit 2 shell surface Underwater D2R23

Conclusion:

The underwater section of the torus is in Ref. Documents:

November EC 396049 Rev 0, generally good shape with minimal pinpoint corrosion.

2013 These results are relatively consistent with findings from WO 01488716-01 previous outages. This trend supports the recommended action to continue to perform desludging, coating inspection and spot repair activities every outage. No additional actions are recommended from the underwater coatings report or this EC Evaluation.

Conclusion:

The conclusions of the vapor section evaluation indicate that the coatings are in moderate condition compared to the age of the coatings. The vapor portion of the torus is in good condition, the Coating centipede is in fair condition, and the drywell head is in Evaluation very good condition. Repairs during D2R23 of the two Unit 2 remaining electromatic relief valve (ERV) supports in the Ref. Documents: vent lines from the drywell to the vent header have eliminated the degraded condition identified during D2R23 D2R21. Additionally, a portion (i.e., approximately 1/8)

EC 396049 Rev 0 November of the drywell liner in the basement was recoated in an IR 1584967 2013 effort to repair the degraded coatings before failure. IR WO 01483459-01, 1584967 was generated during D2R23 to document the

-02 & -03. preliminary results of the walkdowns performed per DTS 1600-11, Revision 11. Based on the results of each walkdown, there are no areas of significant degradation that are an immediate concern to the safety of plant operation or safe shutdown.

Page 28 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE Table 3.5.1-1 DNPS, Units 2 and 3 Coating Inspection Results Refueling Type of Outage & Coating Inspection Results Inspection Date All bays of submerged shell inspected, desludged, 112 coating deficiencies found, all repaired, no metal loss greater than 65 mil threshold.

Torus Unit 2 Underwater

Conclusion:

The underwater section of the torus is in generally good shape with minimal pinpoint corrosion.

These results are relatively consistent with findings from D2R24 Ref. Documents:

outages going back to 2003 as documented in the latest EC 403925 Rev 0, November Underwater Construction Company (UCC) inspection 2015 report for D2R24. This trend supports the recommended WO 1693780-01 action to continue to perform desludging, coating inspection and spot repair activities every outage, as directed by the License Renewal Commitment. No additional actions are recommended from the underwater coatings report or this EC Evaluation.

Coating Evaluation The conclusions of the vapor section evaluation indicate Ref. Documents: that the coatings are in fair condition with respect to the EC 403925 Rev 0 coatings age. The vapor portion of the torus is in good Unit 2 IR 2583358 condition, the centipede is in good condition, and the drywell head is in very good condition. During D2R24 a WO 1693613-01, - concerted effort to stabilize areas was completed for the D2R24 02 & -03. drywell basement, first and second elevations.

November IR 2583358 documents the as-found condition per DTS 2015 WO 1600-11, Revision 11. Based on the results of each 0169361302A, B, walkdown, there are no areas of significant degradation

&C that are an immediate concern to the safety of plant operation or safe shutdown.

WO 1692773-01,

-02 & -03.

Unit 3 Page 29 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE Table 3.5.1-1 DNPS, Units 2 and 3 Coating Inspection Results Refueling Type of Outage & Coating Inspection Results Inspection Date All bays of submerged shell inspected, desludged, 93 coating deficiencies found, all repaired, no metal loss greater than 65 mil threshold.

Conclusion:

The underwater torus is in generally good Torus shape with minimal pinpoint corrosion and is consistent Unit 3 Underwater with findings from outages going back to 2000, as documented in the latest preliminary UCC inspection D3R21 report for D3R21. There were 93 repairs, which was Ref. Document:

November EC 382066 Rev 0 higher than all past outages and could indicate a slight 2010 degrading trend if continues in D3R22. The WO 1204167-01 recommended action remains to continue to perform desludging, coating inspection and spot repair every outage, as directed by the License Renewal Commitment. No additional actions are recommended from the underwater coatings report or in this EC Evaluation.

Conclusion:

The conclusions of the vapor environment section of the reports identify that the coatings are in moderate condition compared to the age of the coatings, are exhibiting a declining trend and that coating repairs Coating will be necessary. The torus vapor side is in fair Evaluation condition and the centipede and reactor vessel head have been consistently in good condition. Repairs to the Unit 3 shell began in D3R21 and the efforts to repair will need Ref. Document: to continue for the next three outages with aggressive EC 382066 Rev 0, efforts recommended to scrape, spot repair and recoat.

D3R21 IR 1143975 November and IR 1137571 2010 Additional actions for D3R22 and the conclusion of this WO 1185975 -01, report are documented in IR 1143975 for addressing the

-02 , & - 03 priority items addressed in this evaluation. Also IR 1137571 was written for the Torus vapor side, there are some areas of pinpoint rusting. There were no areas of significant degradation from all inspections that would be an immediate concern to safety of plant operation or safe shutdown.

Page 30 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE Table 3.5.1-1 DNPS, Units 2 and 3 Coating Inspection Results Refueling Type of Outage & Coating Inspection Results Inspection Date All bays of submerged shell inspected, desludged, 206 coating deficiencies found, 204 had no metal loss greater than 65 mil threshold, all deficiencies repaired.

Two small pits were identified (IR 1443730) with less than 240 mils in depth and were subsequently repaired by applying additional coating. The overall coating Keeler and Long 6548/7107 condition is good with Torus coating and substrate deficiencies found on less than Unit 3 1% of the torus shell surface.

Underwater D3R22

Conclusion:

The underwater section of the torus is in Ref. Document:

November EC 391374 Rev 0, generally good shape with minimal pinpoint corrosion.

2012 These results are relatively consistent with findings from WO 1390161-01 outages going back to 2002, although with a slight increase, as documented in the latest UCC inspection report for D3R22. This trend supports the recommended action to continue to perform desludging, coating inspection and spot repair activities every outage, as directed by the License Renewal Commitment. No additional actions are recommended from the underwater coatings report or this EC Evaluation.

The conclusions of the vapor section evaluation indicate that the coatings are in moderate condition compared to the age of the coatings. The vapor portion of the torus is in good condition, and the centipede and drywell head are also in fairly good condition. Aggressive repairs Coating during D3R22 of the ERV supports in the vent lines from Evaluation the drywell to the vent header have eliminated the Unit 3 degraded condition identified during D3R21. Also, the Ref. Document: drywell head as been an area identified as needing D3R22 repair during D3R23.

EC 391374 Rev 0, November IR 1440267 2012 IR 1440267 was generated during D3R22 to document WO 1385878-01,

-02 & -03 the preliminary results of the walkdowns performed per DTS 1600-11.

Based on the results of each walkdown, there are no areas of significant degradation that are an immediate concern to the safety of plant operation or safe shutdown Page 31 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE Table 3.5.1-1 DNPS, Units 2 and 3 Coating Inspection Results Refueling Type of Outage & Coating Inspection Results Inspection Date All bays of submerged shell inspected, desludged, 129 coating deficiencies found, all repaired, no metal loss greater than 65 mil threshold.

Conclusion:

The underwater section of the torus is in Torus generally good shape with minimal pinpoint corrosion.

Unit 3 Underwater These results are relatively consistent with findings from previous inspections since 2003, although with a slight D3R23 increase, as documented in the latest UCC inspection Ref. Document:

November EC 400046 Rev 0, report for D3R23. This trend supports the recommended 2014 action to continue to perform desludging, coating WO 1597807-01 inspection and spot repair activities every outage, as directed by the License Renewal Commitment. Not able to post-repair inspect 20 deficiencies distributed in Bays 1, 15, and 16. IR 2412330 written as follow-up to inspect repair locations in D3R24.

The conclusions of the vapor section evaluation indicate the coatings are in fair condition relative to the coating Coating age. The torus vapor portion, centipede and the drywell Evaluation head are in good condition.

Unit 3 Based on the results of each walkdown, there are no Ref. Document: areas of significant degradation that are an immediate D3R23 EC 400046 Rev 0, concern to the safety of plant operation or safe November IR 2407080 shutdown.

2014 IR 2408182 WO 1592439-01, IR 02407080, was generated on drywell results and the

-02 & -03 bare metal areas were VT-1 inspected and coated with KL65487107 epoxy coating. IR 2408182 written on Torus coating inspection results.

Page 32 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE Table 3.5.1-1 DNPS, Units 2 and 3 Coating Inspection Results Refueling Type of Outage & Coating Inspection Results Inspection Date All bays of submerged shell inspected, desludged.

Divers preliminarily identified and repaired 30 coating deficiencies inside the torus during D3R24. Additional D3R24 detailed data was not available at the time of this evaluation and shall be included in the D3R25 coatings evaluation.

Per the D3R23 inspection report, the coating condition in the immersion area is generally in good condition.

Coating deficiencies in immersion include random spot corrosion and random areas of light-to-heavy surface staining from corrosion products in contact with the topcoat; surface staining is generally not considered a deficiency as it typically does not affect coating integrity.

Previously applied coatings are performing well.

Torus In D3R23, at the direction of the Outage Control Center, Underwater post-repair inspections were not performed on the 20 spot repairs distributed through Bays 1, 15, and 16.

Unit 3 These 20 repair locations accounted for an approximate Ref. Document: cumulative surface area of 70.3 square inches at an D3R24 EC 407124 Rev 0, average wet film thickness of 24 mils (0.024) inches.

November WO 1784321-03 These areas were inspected in D3R24 per WO 2016 WO 01794148 01794148, D3 RFL COM Desludge Torus & Inspect Coating and found acceptable. IR 2412330, IR 2412330 "Incomplete Visual Inspection of Torus Coating Repairs,"

PMID 11970-01 was previously generated to document this issue.

Conclusion:

The underwater section of the torus is in generally good shape with minimal pinpoint corrosion.

These results are relatively consistent with findings from previous inspections since 2003, although with a slight increase, as documented in the latest UCC inspection report for D3R23. UCC divers preliminarily identified and repaired 30 coating deficiencies inside the torus during D3R24. Additional D3R24 detailed data was not available at the time of this evaluation and shall be included in the D3R25 coatings evaluation.

This trend supports the recommended action to continue to perform desludging, coating inspection and spot repair activities every outage, as directed by the License Renewal Commitment.

Page 33 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE Table 3.5.1-1 DNPS, Units 2 and 3 Coating Inspection Results Refueling Type of Outage & Coating Inspection Results Inspection Date The conclusions of the vapor section evaluation indicate the drywell liner coatings are generally in fair condition relative to the coating age. The torus vapor portion, centipede and the drywell head are generally in good condition.

Due to the age of the application, various coating systems throughout primary containment are exhibiting a declining trend or are in poor condition. For these areas, Coating coating repairs are necessary and must be prioritized Unit 3 Evaluation based on the as-found inspection. During each refueling outage, aggressive efforts are recommended to scrape loose coating from all drywell levels of the drywell. This D3R24 Ref. Document:

is done to stabilize areas, preventing further coating November EC 407124 Rev 0, loss, and to remove potential debris which could be 2016 WO 1784321-03 transported to the suction strainers during a Loss-Of-Coolant Accident (LOCA). Spot repairs on the liner will be performed each outage on areas of bare metal.

No current coating conditions were identified that appear to impact structural integrity, plant operations, or the safe shutdown of the plant. Dresden is committed to keeping unqualified coatings to less than 250 square feet.

During the Drywell, Torus Vapor Phase and Centipede Vent Header inspections, it was noted that less than 50 square feet of unqualified coating was reported.

Torus Vapor No new coating deficiencies were identified during Unit 3 Space D3R24 walk down that were not previously identified.

Coating is defect free with the exception of the coating D3R24 Ref. Document: deficiencies mentioned above. Coating degradation is November EC 407124 Rev 0, consistent with results of previous inspections. There 2016 WO 1784321-03 are no coating deficiencies within the torus vapor region that require immediate remediation.

Page 34 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE Table 3.5.1-1 DNPS, Units 2 and 3 Coating Inspection Results Refueling Type of Outage & Coating Inspection Results Inspection Date The torus centipede vent header is in good condition with no significant issues. Small patches of rust are Torus Centipede indicative of uncoated areas where metal had previously Vent Lines and been welded. However, these areas do not appear Unit 3 Vent Header corroded and do not currently warrant repair. There is rust discoloration throughout from foot traffic and from water draining from the Drywell, but this has no impact D3R24 Ref. Document: on the underlying coating. The coating is in good November EC 407124 Rev 0, condition throughout all downcomers, vent header 2016 piping, and spherical junctions. No coating failures were WO 1784321-02 found in any areas. One small area of mechanical damage was found on the floor of the centipede in Bay 14. This area showed no active corrosion and can be repaired in a future outage.

Unit 3 Drywell Head The Unit 3 drywell head interior coating is in good D3R24 condition. Several spot repairs have been performed Ref. Document:

November within the last ten years, and the repairs remain intact EC 407124 Rev 0, with no noticeable degradation.

2016 WO 1784321-01 As a whole, the drywell coating is in fair condition with consideration of the coating age. Although areas of Drywell Liner failed coating were identified, the majority of these regions still had primer protecting the subsurface. In Unit 3 D3R24, coating mitigation has been completed per the Ref. Document: Coating Inspectors direction per WO 01784321-04.

D3R24 EC 407124 Rev 0, November WO 1784321-02 The primary cause of the degraded drywell coating is 2016 attributed to age-related degradation. Paint flakes have WO 01784321-04 been found during the inspections for the last several outages leading to the conclusion that failure is occurring during normal operating cycles rather than being caused by abnormal conditions Page 35 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE Table 3.5.1-1 DNPS, Units 2 and 3 Coating Inspection Results Refueling Type of Outage & Coating Inspection Results Inspection Date The Drywell liner in the basement is in fair/poor condition due to repairs made in previous outages. There is some topcoat delamination in various areas, but the primer coat is still adhered to the substrate and providing protection. A few areas of concern were identified near Azimuth 0° where bare substrate with light rust was observed. The basement floor coating has extensive mechanical damage and is entirely missing in some areas, where bare concrete substrate is unprotected.

Drywell Basement Reference In D3R21, the drywell liner between Azimuths 180° and Unit 3 250° was recoated with Keeler & Long 6548/7101. This Elevation 502 coating is in good condition after three operating cycles.

D3R24 Full scale Drywell basement re-coating was scope Ref. Document: deleted from D3R23 and D3R24. No additional coating November 2016 EC 407124 Rev 0, is planned for future outages due to scheduling issues WO 1784321-02 associated with the short outage duration.

The coating system is aged and has been repaired in numerous areas. Minor mechanical damaged areas are present throughout the basement area. Areas of delaminated and flaking coating are few, the result of a periodic inspection/stabilization program to remove loose coating back to tightly adhered coating. Neither incipient coating failure nor pitting corrosion was identified on the containment wall. Drywell basement coating spot stabilization repairs were performed in D3R24.

The first floor of the Drywell is in fair condition, with a few areas of mechanical damage resulting in loose or Drywell First delaminated coating. The top coat and primer coat are Floor Reference adhered tightly to the substrate. A few areas of Unit 3 Elevation 515 delaminating or loose coatings were found on the Bio Shield which was addressed by scraping and collection D3R24 Ref. Document: of the coatings. Age related degradation is not November accelerated, however the topcoat is removed in some EC 407124 Rev 0, locations while the primer continues to protect the 2016 WO 1784321-02 substrate. Spot repairs were performed during D3R24 as appropriate. In relation to the drywell higher elevations, the coatings on the first floor appear to be more resistant to flaking and dis-bonding.

Page 36 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE Table 3.5.1-1 DNPS, Units 2 and 3 Coating Inspection Results Refueling Type of Outage & Coating Inspection Results Inspection Date The condition of the second floor liner coating is in good/fair condition with a few areas of loose coating observed. Some mechanical damage is present with Drywell Second loose coating, but primer still intact. The bio shield has Floor Reference mechanical damage and coating failure due to heat.

Unit 3 Elevation 537 Loose delaminating top coat was observed in various areas. Age related degradation is not accelerated, but is causing some topcoat to be removed from the primer D3R24 Ref. Document: below. This primer continues to protect the substrate. In November EC 407124 Rev 0, relation to the drywell higher elevations, the coatings on 2016 the second floor appear to be more resistant to flaking WO 1784321-02 and dis-bonding. The as-found inspection identified a lesser amount of loose and flaking coating material and in locations where the topcoat is loose or missing the underlying primer appears to be protecting the substrate to a greater degree in comparison to other elevations.

Page 37 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE Table 3.5.1-1 DNPS, Units 2 and 3 Coating Inspection Results Refueling Type of Outage & Coating Inspection Results Inspection Date The majority of the liner plate coating is in good/fair condition with the topcoat tightly adhered to the primer coat. A few areas of topcoat delamination and flaking were observed. These areas were addressed by scraping and collection of paint chips. A few areas of bare substrate and light rust were observed at Azimuth 135°. The bio shield was also in good condition but has areas of loose topcoat which was scraped and collected. Bare substrate was observed at Azimuth 90° and Azimuth 135°.

The drywell third floor containment coatings degradation Drywell Third is primarily attributed to age-related degradation and Floor Reference heat-induced coating damage. The original drywell Elevation 562 coatings consisted of two vinyl coats which are typically Unit 3 rated for approximately 150°F. The measured drywell temperatures in this elevation can range from 130°F to D3R24 Ref. Document: 225°F. The hotter environment on the third and fourth November EC 407124 Rev 0, floors is evident in the quantity of failed topcoat.

2016 WO 1784321-02 EC 377898, "Containment Coating LR B.1.32 D2R21 Trend and Eval," and ATI 751100-34 investigated EC 377898 reducing drywell third and fourth floor elevation ATI 751100-34 temperatures but this was deemed unnecessary because the coating systems being used for repairs are rated for the operational temperatures.

The substrate remains protected by the primer in areas where the coating has delaminated. The potential exists for this primer to degrade due to heat, so increased focus will be put on identifying areas of bare metal during outage inspections. Repairs to the third floor are a priority; however, they are not as pressing as the basement and fourth floors because there is no evidence to suggest severe coating failure. Spot repairs were completed during D3R24.

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ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE Table 3.5.1-1 DNPS, Units 2 and 3 Coating Inspection Results Refueling Type of Outage & Coating Inspection Results Inspection Date The drywell fourth floor containment coatings have age-related and heat-induced coating damage. The coating on the walls and the bulkhead on the fourth floor of the drywell are exposed to temperatures greater than the rated temperature of the coating. As a result, the coating is experiencing significant delamination. For the most part, the primer is able to protect the substrate.

Extensive delamination of the coatings topcoat is prevalent on the ceiling bulkhead, but the primer coat is still intact. The liner plate is in good condition with the majority of the liner topcoat intact. Areas with loose topcoat were scraped and collected. The bio shield was in poor condition with most of the top coat missing and or flaking, but still had sound primer underneath.

Drywell Fourth Floor Reference Loose coating top coat material is systematically Unit 3 Elevation 576 removed during each outage. Due to the industrial safety requirements needed to perform coatings work in D3R24 Ref. Document: the drywell, performing a large scale repair of either the November third or fourth floor is unfeasible. There is no evidence EC 407124 Rev 0, to suggest that coating failure on a large scale will occur 2016 WO 1784321-02 without prior evidence or precursors identified in the as-found inspections performed during each refueling outage. Currently, this type of failure does not appear imminent. Inspections will continue to identify any areas in which substantial coating degradation has led to exposed liner. Future repairs will be pursued as spot repairs rather than a large scale recoat project.

The condition of the coatings on the ceiling and bulkhead as seen from the drywell fourth floor has not changed significantly since the previous assessments. It is typical of the age related and heat induced deterioration of the original coating material. In areas in the ceiling have topcoat missing, primer is present and appears to be intact and providing protection to the substrate. There does not appear to be any active substrate degradation or pitting.

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ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE 3.5.2 Containment Inservice Inspection (CISI) Program The Inservice Inspection (ISI) Program Plan details the requirements for the examination and testing of ISI Class 1, 2, 3, and MC pressure retaining components, supports, and containment structures at DNPS, Units 2, 3, and Common (2/3). Unit Common components are included in the Unit 3 sections, reports, and tables. The ISI Program Plan also includes CISI, Risk-Informed Inservice Inspections (RISI), Augmented Inservice Inspections (AUG), and System Pressure Testing (SPT) requirements imposed on or committed to by DNPS.

The ISI Program Plan is controlled and revised in accordance with the requirements of EGC Procedure ER-AA-330, "Conduct of Inservice Inspection Activities," which implements the ASME Code, Section XI, ISI Program.

The DNPS, Units 2 and 3 are currently in the Fifth ISI Interval, which commenced on January 20, 2013, and ends on January 19, 2023. Additionally, DNPS, Units 2 and 3 are in the Second CISI Interval, which started September 9, 2008, and is effective through September 8, 2018.

These effective interval dates are based on DNPS is now operating under an approved extended license renewal. The ASME Section XI Code of Record for the Fifth ISI Interval is the 2007 Edition through the 2008 Addenda, and the ASME Section XI Code of Record for the Second CISI Interval is the 2001 Edition through the 2003 Addenda.

The DNPS Containment ISI Plan includes ASME Section XI ISI Class MC pressure retaining components and their integral attachments that meet the criteria of Subarticle IWA-1300. This Containment ISI Plan also includes information related to augmented examination areas, component accessibility, and examination review.

DNPS has no ISI Class Concrete Containment (CC) components that meet the criteria of Subarticle IWL-1100; therefore, no requirements to perform examinations in accordance with Subsection IWL are incorporated into this Containment ISI Plan. The basis for exclusion of Class CC components from examination in accordance with ASME Section XI, Subsection IWL, is provided in DG97-001424 (i.e., Reference 37).

The CISI Second Interval CISI Program Plan was developed in accordance with the requirements of 10CFR50.55a and the 2001 Edition through the 2003 Addenda of ASME Section XI, subject to the limitations and modifications contained within Paragraph (b) of the regulation. These limitations and modifications are detailed in Table 3.5.2-1 of this section.

Overall, this Second Interval CISI Program Plan addresses Subsections IWE, Mandatory Appendices of ASME Section XI, approved IWE Code Cases, approved alternatives through relief requests and SE's, and utilizes Inspection Program B as described in ASME Section XI, IWE-2412.

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ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE Table 3.5.2-1 Code of Federal Regulations 10CFR50.55A Requirements (Applicable to Containment Inspection Program) 10 CFR 50.55a Limitations, Modifications, and Clarifications Paragraphs (CISI) Examination of metal containments and the liners of concrete containments: For Class MC applications, the licensee shall evaluate the acceptability of inaccessible areas when conditions exist in accessible areas that could indicate the presence of or result in degradation to such inaccessible areas.

For each inaccessible area identified, the licensee shall provide 10CFR50.55a(b)(2)(ix)(A) the following in the ISI Summary Report as required by IWA-6000:

(1) A description of the type and estimated extent of degradation, and the conditions that led to the degradation; (2) An evaluation of each area, and the result of the evaluation, and; (3) A description of necessary corrective actions.

(CISI) Examination of metal containments and the liners of concrete containments: When performing remotely the visual examinations required by Subsection IWE, the maximum direct examination distance specified in Table IWA-2210-1 may be 10CFR50.55a(b)(2)(ix)(B) extended and the minimum illumination requirements specified in Table IWA-2210-1 may be decreased, provided that the conditions or indications for which the visual examination is performed can be detected at the chosen distance and illumination.

(CISI) Examination of metal containments and the liners of concrete containments: VT-1 and VT-3 examinations must be conducted in accordance with IWA-2200. Personnel conducting examinations in accordance with the VT-1 or VT-3 examination 10CFR50.55a(b)(2)(ix)(F) method shall be qualified in accordance with IWA-2300. The owner-defined personnel qualification provisions in IWE-2330(a) for personnel that conduct VT-1 and VT-3 examinations are not approved for use.

(CISI) Examination of metal containments and the liners of concrete containments: The VT-3 examination method must be used to conduct the examinations in Items E1.12 and E1.20 of Table IWE-2500-1, and the VT-1 examination method must be used to conduct the examination in Item E4.11 of Table IWE-10CFR50.55a(b)(2)(ix)(G) 2500-1. An examination of the pressure-retaining bolted connections in Item E1.11 of Table IWE-2500-1 using the VT-3 examination method must be conducted once each interval. The owner-defined visual examination provisions in IWE-2310(a) are not approved for use for VT-1 and VT-3 examinations.

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ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE Table 3.5.2-1 Code of Federal Regulations 10CFR50.55A Requirements (Applicable to Containment Inspection Program) 10 CFR 50.55a Limitations, Modifications, and Clarifications Paragraphs (CISI) Examination of metal containments and the liners of concrete containments: Containment bolted connections that are disassembled during the scheduled performance of the examinations in Item E1.11 of Table IWE-2500-1 must be examined using the VT-3 examination method. Flaws or degradation identified during the performance of a VT-3 examination must be examined in accordance with the VT-1 10CFR50.55a(b)(2)(ix)(H) examination method. The criteria in the material specification or IWB-3517.1 must be used to evaluate containment bolting flaws or degradation. As an alternative to performing VT-3 examinations of containment bolted connections that are disassembled during the scheduled performance of Item E1.11, VT-3 examinations of containment bolted connections may be conducted whenever containment bolted connections are disassembled for any reason.

(CISI) Examination of metal containments and the liners of concrete containments: The ultrasonic examination acceptance 10CFR50.55a(b)(2)(ix)(I) standard specified in IWE-3511.3 for Class MC pressure-retaining components must also be applied to metallic liners of Class CC pressure-retaining components.

The inspections of containment structures and components are performed in accordance with EGC Procedures ER-AA-330-007, "Visual Examination of Section XI Class MC Surfaces and Class CC Liners," ER-AA-335-004, "Manual Ultrasonic Measurement of Material Thickness and Interfering Conditions," and ER-AA-335-018, "Visual Examination of ASME IWE Class MC and Metallic Liners of IWL Class CC Components."

Since both of the DNPS units are in the second CISI interval, CISI inspections have been completed for the first and second periods, with the third period inspections currently ongoing.

The results of recent inspections performed during refueling outages, show that various indications were observed, documented, evaluated, and determined to be acceptable. The results of inspections performed during the past three refueling outages examining primary containment are summarized in Table 3.5.2-2 shown below.

There will be no change to the schedule for these inspections as a result of the extended ILRT interval.

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ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE Table 3.5.2-2 Summary of IWE Examinations on Primary Containment Unit 2 D2R22 IWE Inspections documented on WO 01309392-01; April 4, 2011 - Per Exam schedule only inspections required were those for preservice and of repair/replacement activities. Bolting inspections of opened CRD Hatch, Torus Hatches, Drywell Equipment Hatch and Drywell head found no reportable indications.

Database Component Item Results of Inspection Resolution No.

None All no reportable indications D2R23 IWE Inspections documented on WO 01488694-01; November 13, 2013 - Bolting inspections of opened CRD Hatch, Torus Hatches, Drywell Equipment Hatch and Drywell head found no reportable indications.

General visual of IWE Program inspections:

Item No. E1.11 - performed 294 inspections, described (in-part) on drywell containment liner interior & exterior, vent header interior, torus all bays exterior and interior (above normally wetted area) and hatches, and penetrations of drywell and torus. No reportable indications.

Item No. E1.30 - performed 4 inspections on moisture barriers in drywell basement, equipment hatch, personnel hatch penetration and personnel hatch floor. No reportable indications.

Database Component Item Results of Inspection Resolution No.

None All no reportable indications D2R24 IWE Inspections on WO 01712780-01; May 8, 2015 - Per Exam schedule only inspections required were those for preservice and of repair/replacement activities. Bolting inspections of opened CRD Hatch, Torus Hatches, Drywell Equipment Hatch and Drywell head found no reportable indications.:

Database Component Item Results of Inspection Resolution No.

None All no reportable indications Page 43 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE Table 3.5.2-2 Summary of IWE Examinations on Primary Containment Unit 3 D3R21 IWE Inspections on WO 01200752 01; November 10, 2010 - Per Exam schedule inspections required were those for preservice and of repair/replacement activities. Bolting inspections of opened CRD Hatch, Torus Hatches, Drywell Equipment Hatch, Drywell support ring and Drywell head found no reportable indications.

Additional VT-3 inspections performed for License Renewal Commitment baseline inspections. (See Action Tracking Item (ATI) 101522.35.01 and 101522-49-08 & 101522 60)

- WO 01200752 02, ATI 101522-49-08, from Table 1 of ATI 101522-37, items 7, 8, 9, and 10; 7). torus vent system support columns (in torus), NDE Report 09-181 (2008) one indication, 8). biological shield to containment stabilizer assemblies, NDE Report 10-385 (2010) no indications, 9). drywell shear lug male stabilizer, NDE Report 10-384 (2010) no indications, 10). drywell shear lug female stabilizers, NDE Report 10-384(2010) no indications.

- WO 01200752 03, ATI 101522-49-60: Penetration X-123, RBCCW support, NDE Report 10-413 (2010) no indications.

- WO 01200752 04, ATI 101522-49-60: Pressure Suppression system supports 1). M-3411-04 spring hanger, NDE Report 10-415 (2010) no indications, 2). M-1194D-57 guide, NDE Report 10-416 (2010) no indications, 3). M-3410-09 rigid support, NDE Report 10-412 (2010) no indications.

Database Component Item Results of Inspection Resolution No.

IR 0949941, clean &

NDE 09-181 6 Corrosion on base plate anchor paint D3R22 IWE Containment Inspections on WO 01389865 01, November 16, 2012 -

General visual of IWE Program inspections:

Item No. E1.11 - performed 241 inspections, described (in-part) on drywell containment liner interior & exterior surfaces, vent header interior, torus all bays exterior and interior (above normally wetted area) and torus hatches, and penetrations of drywell and torus. Three reportable indications addressed below.

Item No. E1.30 - performed 4 inspections on moisture barriers in drywell basement, equipment hatch, personnel hatch floor and personnel hatch penetration. No reportable indications.

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ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE Table 3.5.2-2 Summary of IWE Examinations on Primary Containment Database Component Item Results of Inspection Resolution No.

Bolting X-306A One stud damaged and one nut IR 01443642; Damaged Torus missing. on disassembly. New Access stud, nuts and washers Hatch installed (East) WO 01390161-02 Bolting Liner Interior DW 502 Recordable Indications - Coating Use as is.

Surface thru 576 missing and damaged in various Liner locations and various elevations.

No loss of liner material.

Liner Interior DW Head Recordable Indication - Coating Use as is.

Surface Interior missing at one spot. No loss of liner material.

D3R23 IWE Containment Inspections on WO 01612817 01, August 1, 2014 - Per Exam schedule only inspections required were those for preservice and of repair/replacement activities.

Bolting inspections of opened CRD Hatch, Torus Hatches, Drywell Equipment Hatch, Drywell support ring and Drywell head found no reportable indications. No reportable indications.

Database Component Item Results of Inspection Resolution No.

None All no reportable indications Programmatically, the 10-year CISI Interval is divided into three successive inspection periods as determined by calendar year of plant service within the inspection interval. Table 3.5.2-3 identifies the period start and end dates for the Second CISI Interval as defined by the DNPS ISI Program Plan. Table 3.5.2-4 identifies the successive period start and end dates for the Third CISI Interval, whose dates are approximate since the Third CISI Interval inspection program has not been developed at this time.

In accordance with ASME Section XI, Paragraph IWA-2430(c)(1), the inspection periods specified in these Tables may be decreased or extended by as much as one year to coincide with refueling outages, and Paragraph IWA-2420(d) allows an inspection interval to be extended when a unit is out of service continuously for six months or more. The extension may be taken for a period of time not to exceed the duration of the outage.

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ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE Table 3.5.2-3 DNPS, Units 2 and 3 Second CISI Interval/Period/Outage Matrix (For ISI Class MC Component Examinations)

Unit 2 Period Interval Period Unit 3 Start Outage or Start Date Start Date Outage or Outage Date Outage Projected Start to to Projected Number to Number Date End Date End Date Start Date End Date 1ST Scheduled Scheduled D2R21 10/09 9/9/08 to 1ST 10/08 D3R20 9/8/2011 2nd 9/9/08 to Scheduled (Unit 2) 9/8/11 Scheduled D2R22 2nd 9/9/08 to D3R21 10/11 10/10 9/9/11 to 9/8/18 Scheduled 9/8/2015 Scheduled D2R23 2nd D3R22 10/13 nd 10/12 2 9/9/11 to Scheduled Scheduled D2R24 rd (Unit 3) 9/8/15 D3R23 10/15 3 10/14 9/9/08 to 9/9/15 to 3rd Scheduled 9/8/18 Scheduled D2R25 9/8/2018 9/9/15 to D3R24 10/17 10/16 9/8/18 Table 3.5.2-4 DNPS Units 2 and 3 Third CISI Interval/Period/Outage Matrix (For ISI Class MC Component Examinations)

(Approximate)1 Unit 2 Period Interval Period Unit 3 Start Outage or Start Date Start Date Outage or Outage Date Outage Projected Start to End to Projected Number to Number Date Date End Date Start Date End Date 1ST 1ST Scheduled Scheduled D2R26 9/9/18 to 9/9/18 to D3R25 10/19 nd 10/18 9/8/2021 2 9/8/21 Scheduled (Unit 1) Scheduled D2R27 D3R26 10/21 2nd 9/9/18 to 10/20 9/9/21 to 9/8/28 Scheduled Scheduled D2R28 9/8/2025 2nd D3R27 10/23 10/22 2nd 9/9/21 to Scheduled (Unit 2) 9/8/25 Scheduled D2R29 9/9/18 to D3R28 10/25 3 rd 10/24 9/9/25 to 9/8/28 3rd Scheduled 9/8/2028 9/9/25 to Scheduled D2R30 D3R29 10/27 9/8/28 10/26 Note 1: Table 3.5-5 identifies the successive periods start and end dates for the Third CISI Interval, which is approximate since the Third CISI Interval inspection program has not been developed at this time Page 46 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE The DNPS CISI Plan includes ASME Section XI ISI Class MC pressure retaining components and their integral attachments that meet the criteria of Subarticle IWA-1300. This CISI Plan also includes information related to examined areas, augmented examination areas, component accessibility, and examination review. A summary of inspected containment components, Category E-A, and augmented containment components, Category E-C, are provided for DNPS, Units 2 and 3 in Table 3.5.2-5.

Table 3.5.2-5 DNPS, Units 2 and 3 (U-2 and U-3) IWE Inservice Inspection Summary Examination Total Category Number of Relief (with Item Exam Components Request/

Description Notes Examination Number Requirements (Unit 3 TAP Category includes Number Description) common)

E-A E1.11 Containment Vessel General Visual U-2: 309 Containment Pressure Retaining U-3: 241 Surfaces Boundary -

Accessible Surface Areas E1.11 Containment Vessel Visual, VT-3 U-2: 41 1 Pressure Retaining U-3: 36 1 Boundary -

Bolted Connections, Surfaces E1.12 Containment Vessel Visual, VT-3 U-2: 16 2 Pressure Retaining U-3: 16 2 Boundary -

Wetted Surfaces of Submerged Areas E1.20 Containment Vessel Visual, VT-3 U-2: 45 2 Pressure Retaining U-3: 45 2 Boundary -

BWR Vent System Accessible Surface Areas E1.30 Containment Vessel General Visual U-2: 4 Pressure Retaining U-3: 4 Boundary -

Moisture Barriers E-C E4.11 Containment Surface Visual, VT-1 U-2: 0 Containment Areas - Visible Surfaces U-3: 0 Page 47 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE Table 3.5.2-5 DNPS, Units 2 and 3 (U-2 and U-3) IWE Inservice Inspection Summary Examination Total Category Number of Relief (with Item Exam Components Request/

Description Notes Examination Number Requirements (Unit 3 TAP Category includes Number Description) common)

Surfaces E4.12 Containment Surface Ultrasonic U-2: 0 Requiring Areas - Surface Area U-3: 22 Augmented Grid, Minimum Wall Examination Thickness Location -

Core Bore Hole Liner Surface, (Sectors 1, 2, 3, 4, 5, and 6 Note 1: Bolted connections examined in accordance with Item Number E1.11 require a General Visual examination each period and a VT-3 visual examination once per interval and each time the connection is disassembled during a scheduled Item Number E1.11 examination. Additionally, a VT-1 visual examination shall be performed if degradation or flaws are identified during the VT-3 visual examination.

These modifications are required by 10 CFR 50.55a(b)(2)(ix)(G) and 10 CFR 50.55a(b)(2)(ix)(H).

Note 2: Item Numbers E1.12 and E1.20 require VT-3 visual examination in lieu of General Visual examination, as modified by 10 CFR 50.55a(b)(2)(ix)(G).

3.5.2.1 Code Cases The only Code Case implemented in the DNPS CISI Program is N-649, which is an EGC fleet relief request identified at DNPS as I5R-12. This relief request is briefly shown in Table 3.5.2-6 below, and is further described in detail below Table 3.5.2-6.

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ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE 3.5.2.2 Relief Requests Table 3.5.2-6 contains an index of Relief Requests applicable to the CISI Program. Note that only Relief Requests applicable to the requirements for Class MC components are addressed in this Table.

Table 3.5.2-6 Second Ten-Year CISI Interval Relief Request Relief Revision/

Status (Program) Description/Approval Summary Request Date I5R-12 0 Authorized (CISI) Expanded Applicability of ASME Code Exelon June 30, Case N-649, Alternative Requirements for IWE-5240 Fleet 2014 Visual Examination, Revision 0.

Relief Request Authorized April 30, 2014 Explanation of use of Code Case N-649 in accordance with 10 CFR 50.55a(a)(3)(i):

Applicable Code Edition and Addenda

The Inservice Inspection program is based on the American Society of ASME B&PV Code, Section XI, 2001 Edition through the 2003 Addenda.

Applicable Code Requirement

IWE-5240, "Visual Examination," requires that a detailed visual examination be performed during any IWE-5220 leakage test on areas affected by repair/replacement activities.

ASME Code Case N-649, "Alternative Requirements for IWE-5240 Visual Examination,"

allows for a VT-3, VT-1, or detailed visual examination depending on the timing of the leakage test.

Reason for Request

Pursuant to 10CFR50.55a(a)(3)(i), relief is requested on the basis that the proposed alternative will provide an acceptable level of quality and safety.

The Applicability Index for Section XI Code Cases states that ASME Code Case N-649 is applicable up to and including the 2000 Addenda of ASME Section XI. The Edition/Addenda references in the Code Case text itself also stop at the 2000 Addenda.

However, the requirements of Paragraph IWE-5240 are identical in both the 2000 Addenda and the 2001 Edition through the 2003 Addenda. Paragraph IWE-5240 requires that a detailed visual examination of repaired areas be completed during a post repair pressure test. DNPS, Units 2 and 3 has a metal containment that is inaccessible during a post repair pressure test. ASME Code Case N-649 was issued to allow this visual examination to be performed during or after the pressure test in recognition of the impracticality of performing the visual examinations of metal containment during the post Page 49 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE repair pressure test. ASME did not address this impracticality in the Code until the 2006 Addenda of ASME Section XI was issued, so ASME Code Case N-649 is actually needed for the 2001 Edition through the 2003 Addenda of ASME Section XI.

Proposed Alternative and Basis for Use:

DNPS, Units 2 and 3 requests the applicability of ASME Code Case N-649 be extended to the 2001 Edition through the 2003 Addenda for use in the plants Second Containment Inspection Interval (Fifth Ten-Year Inservice Inspection Interval). NRC Regulatory Guide 1.147, Revision 16, lists ASME Code Case N-649 as acceptable for use with no conditions or limitations. The only issue being addressed by this relief request is the applicability listed in the Applicability Index for Section XI Cases. (This relief request was subsequently authorized with an SE issued by the NRC on April 30, 2014.)

Duration of Proposed Alternative:

Relief is requested for the Second Containment Inspection Interval (Fifth Ten-Year Inservice Inspection Interval) for DNPS, Units 2 and 3.

3.5.2.3 Identification of Class MC and/or CC Exempt Components The containment sections of the ISI Classification Basis Document discusses the containment design and components. Metal containment surface areas subject to accelerated degradation and aging require augmented examination per Examination Category E-C and Paragraph IWE-1240.

A significant condition is a condition that is identified as requiring application of additional augmented examination requirements under Paragraph IWE-1240.

The CISI components overall were evaluated for potential candidates to be included programmatically in the Augmented Inspection Program. The details of this evaluation are contained in the ISI Classification Basis Document, Section 4.1.12. The evaluation resulted in one component (i.e., area) being recommended on a programmatic basis, as candidates for the Augmented Program within Examination Category E-C, and therefore appear on Table IWE-2500-1. This augmented inspection area is the Drywell Shell at the Sand Pocket Location.

This sand pocket area at DNPS Unit 3, is inaccessible and is located outside of the drywell shell at the bottom of the 2 inch thermal gap between the drywell shell and the reactor building concrete shield wall. This area was identified as an industry concern in NRC IN 86-99 and GL 87-05, and discussed further in Section 3.6.5 of this LAR. Specifically, regarding potential corrosion of the drywell steel shell in the sand pocket region. The concern relates primarily to plants which have their sand pocket regions open to the gap between the drywell and surrounding concrete. Due to their small size, the drains in this region have a greater potential of clogging, and the likelihood of adequately drying the sand is low should copious amounts of water enter the sand cushion region. DNPS has conducted an extensive review of this concern, the results of which are summarized in DNPS UFSAR, Section 6.2.1.2.1.2. To date, the concerns raised by the notices are evident but have not resulted in any degradation of the drywell shell. However, since water continues to enter this region, DNPS will consider it as an augmented containment inspection area and it will be inspected as such.

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ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE In the First and Second CISI Intervals, portions of the DNPS, Unit 3 Drywell Shell located at the sand pocket were identified as augmented surface areas requiring examination in accordance with Paragraph IWE-1240. These surface areas were categorized in accordance with Table IWE-2500-1, Examination Category E-C, Item Number E4.12, requiring volumetric examination of 100% of the minimum wall thickness locations identified.

3.5.2.4 Augmented Inspection Program Requirements Augmented Inspection Program requirements are those inspections that are performed above and beyond the requirements of ASME Section XI.

Below is a summary of those examinations performed by DNPS that are not specifically addressed by ASME Section XI, or the inspections that will be performed in addition to the requirements of ASME Section XI on a routine basis during the Second CISI Interval.

Note that in accordance with NUREG-1796 (i.e., Reference 18), DNPS will perform a VT-3 visual examination on nonexempt Class MC piping supports, which were added to the augmented inspection program in accordance with the DNPS commitment for license renewal.

These inspections are addressed in the 5th Interval ISI Program Plan, and in the ISI Program Selection documents. The inspections are identified as NUREG-1796 inspections found in the ISI Database that are addressed by the IWF Program and by the Structural Monitoring Program.

The Augmented Inspection Plans at DNPS associated with IWE and the integrity of the primary containment, are listed in Table 3.5.2-7 below.

Table 3.5.2-7 DNPS, Units 2 and 3 Augmented Containment Inspection Program Matrix Examination Category Relief Total Number (with Aug Exam Request Description of Notes Examination Number Requirements / TAP Components Category Number Description)

E-C Containment E4.12 Containment - Surface Volumetric U-2: 0 N/A Surfaces Area Grid, Minimum (UT Thickness) U-3: 22 N/A Requiring Wall Thickness Augmented Location - Core Bore Examination Hole Liner Surface, (Sectors 1, 2, 3, 4, 5, and 6 Additional monitoring of the containment liner applicable to DNPS, Unit 2 is the inspections instituted at DNPS, Unit 3 of the inaccessible annulus area to ensure that potential corrosion does not occur. As part of Plant Licensing Renewal, NUREG-1796 (i.e., Reference 18), Section 3.0, "Aging Management Review," Pages 3-403, a description is provided of the monitoring at DNPS consisting of the inspection of a sample of locations of the drywell, using ultrasonic measurements of the drywell shell thickness made from accessible areas of the drywell interior.

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ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE DNPS, Unit 2 credits the inspections performed on Unit 3 to establish the most conservative bounding case for continued inspection. This inspection is a part of the ASME Section XI, Subsection IWE Program, Commitment B.1.26 at DNPS.

3.5.2.5 Component Accessibility ISI Class MC components subject to examination shall remain accessible for either direct or remote visual examination from at least one side per the requirements of ASME Section XI, Paragraph IWE-1230.

Paragraph IWE-1231(a)(3) requires 80% of the pressure-retaining boundary that was accessible after construction to remain accessible for either direct or remote visual examination, from at least one side of the vessel, for the life of the plant. DNPS addressed, in Calculation DRE03-0032 (i.e., Reference 12), compliance with this requirement by calculating the containment pressure boundary surface area that was accessible for examination at the beginning of the CISI Program resulting in a determination for the limit of surface area which may be made inaccessible for the balance of plant life.

Portions of components embedded in concrete or otherwise made inaccessible during construction are exempted from examination, provided that the requirements of ASME Section XI, Paragraph IWE-1232 have been fully satisfied.

In addition, inaccessible surface areas exempted from examination include those surface areas where visual access by line of sight with adequate lighting from permanent vantage points is obstructed by permanent plant structures, equipment, or components; provided these surface areas do not require examination in accordance with the inspection plan, or augmented examination in accordance with Paragraph IWE-1240.

3.5.2.6 Inaccessible Areas For Class MC applications, DNPS shall evaluate the acceptability of inaccessible areas when conditions exist in accessible areas that could indicate the presence of or result in degradation to such inaccessible areas. For each inaccessible area identified, DNPS shall provide the following in the Owners Activity Report-1, as required by 10 CFR 50.55a(b)(2)(ix)(A):

x A description of the type and estimated extent of degradation, and the conditions that led to the degradation; x An evaluation of each area, and the result of the evaluation; and x A description of necessary corrective actions.

An evaluation has been performed to determine if DNPS has inaccessible areas that could indicate the presence of or result in, degradation to such inaccessible areas requiring identification per 10 CFR 50.55a(b)(2)(ix)(A). The evaluation resulted in no areas identified and is contained in the ISI Classification Basis Document, Section 4.1.12. DNPS has not needed to implement any new technologies to perform inspections of any inaccessible areas at this time.

However, EGC actively participates in various nuclear utility owners groups and ASME Code committees to maintain cognizance of ongoing developments within the nuclear industry.

Industry operating experience is also reviewed to determine its applicably to DNPS.

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ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE Adjustments to inspection plans and availability of new, commercially available technologies for the examination of the inaccessible areas of the containment would be explored and considered as part of these activities.

3.5.2.7 Responsible Individual ASME Section XI, Subsection IWE requires the Responsible Individual to be involved in the development, performance, and review of the CISI examinations. At DNPS, the Responsible Individual is committed to meet the requirements of ASME Section XI, Paragraph IWE-2320.

3.5.2.8 Examination Methods & Personnel Qualifications The examination methods used to perform Code examinations for the nonexempt Class MC components are in accordance with 10 CFR 50.55a requirements and the applicable ASME Codes.

Personnel performing IWE examinations shall be qualified in accordance with EGCs written practice, or approved vendor written practice for certification and qualification of nondestructive examination personnel.

3.5.3 Supplemental Inspection Requirements With the implementation of the proposed change, TS 5.5.12 will be revised by replacing the reference to RG 1.163 (i.e., Reference 1) with reference to NEI 94-01, Revision 3-A (i.e., Reference 2). This will require that a general visual examination of accessible interior and exterior surfaces of the containment for structural deterioration that may affect the containment leak-tight integrity be conducted. This inspection must be conducted prior to each Type A test and during at least three (3) other outages before the next Type A test, if the interval for the Type A test has been extended to 15 years in accordance with the following sections of NEI 94-01, Revision 3-A:

x Section 9.2.1, "Pretest Inspection and Test Methodology" x Section 9.2.3.2, "Supplemental Inspection Requirements" In addition to the inspections performed by the IWE/IWL Containment Inspection Program, EGC Procedure ER-AA-380, "Primary Containment Leakrate Testing Program," and DNPS Procedure DTS 1600-07, "Unit 2 (3) Primary Containment Integrated Leak Rate Test," require that the structural integrity of the exposed accessible interior and exterior surfaces of the drywell and the containment, including the liner plate, be determined by a visual inspection of those surfaces prior to the Type A Containment Leak Rate Test.

This inspection also fulfills the surveillance requirement of TS SR 3.6.1.1.1 and NEI 94-01.

3.5.4 Primary Containment Leakage Rate Testing Program - Type B and Type C Testing Program DNPS Types B and C testing program requires testing of electrical penetrations, airlocks, hatches, flanges, and containment isolation valves in accordance with 10 CFR 50, Appendix J, Option B, and RG 1.163. The results of the test program are used to demonstrate that proper Page 53 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE maintenance and repairs are made on these components throughout their service life. The Types B and C testing program provides a means to protect the health and safety of plant personnel and the public by maintaining leakage from these components below appropriate limits. In accordance with the DNPS TS 5.5.12, the allowable maximum pathway total Types B and C leakage is 0.6La (Note: For DNPS, 0.6La is defined as 810.507 scfh and La is defined as 1350.84 scfh).

As discussed in NUREG-1493 (i.e., Reference 6), Type B and Type C tests can identify the vast majority of all potential containment leakage paths. Type B and Type C testing will continue to provide a high degree of assurance that containment integrity is maintained.

A review of the DNPS Type B and Type C test results from 2007 through 2015 for Unit 2 and from 2006 through 2014 for Unit 3 has shown an exceptional amount of margin between the actual As-Found (AF) and As-Left (AL) outage summations and the regulatory requirements.

Tables 3.5.4-1 and 3.5.4-2 provide LLRT data trend summaries for DNPS Unit 2 since 2007 (i.e., the last ILRT was performed in 2009) and for Unit 3 since 2006 (i.e., the last ILRT was performed in 2008).

Table 3.5.4-1 DNPS, Unit 2 Types B and C LLRT Combined As-Found/As-Left Trend Summary Refueling Outage R20 R21 R22 R23 R24

& 2 2007 2009 2011 2013 2015 Year Undeter AF Min Path (scfh) 394.909 251.651 1253.92 946.685 mined3 Fraction of La 1 0.292 0.186 0.928 - 0.701 AL Max Path (scfh) 344.048 341.338 245.724 299.878 291.229 Fraction of La 0.255 0.253 0.182 0.222 0.216 AL Min Path (scfh) 177.218 134.345 117.139 109.442 118.691 Fraction of La 0.131 0.099 0.087 0.081 0.088 Note 1: 0.6La = 810.507 scfh and La = 1350.84 scfh Note 2: D2R21 in 2009 was also an ILRT outage.

Note 3: AF was undetermined due to excessive leakage, Feedwater valves -

LER 13-005-00.

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ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE Table 3.5.4-2 DNPS, Unit 3 Type B and C LLRT Combined As-Found/As-Left Trend Summary Refueling Outage R19 R20 R21 R22 R23 R24

& Year 2006 20082 2010 2012 2014 2016 AF Min Path (scfh) 95.78 191.709 293.903 283.894 299.356 157.421 Fraction of La1 0.071 0.142 0.218 0.210 0.222 0.117 AL Max Path (scfh) 230.5 410.876 337.358 318.434 361.035 304.5 Fraction of La 0.171 0.304 0.250 0.236 0.267 0.225 AL Min Path (scfh) 79.61 187.546 179.735 97.236 109.515 131.4 Fraction of La 0.059 0.139 0.133 0.072 0.081 0.097 Note 1: 0.6La = 810.507 scfh and La = 1350.84 scfh Note 2: D3R20 in 2008 was also an ILRT outage The As-Found minimum pathway summations represent the high quality of maintenance of Type B and Type C tested components while the As-Left maximum pathway summations represent the effective management of the Containment Leakage Rate Testing Program by the program owner.

3.5.5 Type B and Type C Local Leak Rate Testing Program Implementation Review Tables 3.5.5-1 and 3.5.5-2 below, identify DNPS Units 2 and 3 components, respectively, which were on Appendix J, Option B performance-based extended test intervals, but have not demonstrated acceptable performance during the previous two outages. The component test intervals for the components shown have been reduced to 30 months.

Table 3.5.5-1 DNPS, Unit 2 Type B and C LLRT Program Implementation Review 2013-D2R23 Admin As- As-Limit Alert/ Cause of Corrective Scheduled Component found left Action Failure Action Interval (scfh) (scfh)

(scfh)

None 2015-D2R24 As- Admin Limit As-Cause of Corrective Scheduled Component found Alert/Action left Failure Action Interval (scfh) (scfh) (scfh)

None Page 55 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE Table 3.5.5-2 DNPS, Unit 3 Type B and C LLRT Program Implementation Review 2014-D3R23 As- Admin Limit As- Cause of found Alert/ left Failure Corrective Scheduled Component (scfh) Action (scfh) Action Interval (scfh) 3-1201-2 UND IR 2407944 Reactor (min. Normal

 1.3 disassemble 30 month Water Clean path wear d, repaired up 0.13)

IR 2409889 DTP 47 3-4799-531 Form 47A Instrument 40.4  40.4 N/A 30 month deferral Air paperwork (1) 2016-D3R24 As- Admin Limit As-Cause of Corrective Scheduled Component found Alert/Action left Failure Action Interval (scfh) (scfh) (scfh)

None Note (1): In D3R24 as-left leakage was 3.3 scfh following valve replacement due to excessive wear identified on valve.

The percentage of the total number of DNPS, Appendix J, Type B tested components that are on extended performance-based test intervals is approximately 67% each for Unit 2 and Unit 3.

The percentage of the total number of DNPS Appendix J Type C tested components that are on extended performance-based test intervals is approximately 55% each for Unit 2 and Unit 3.

3.5.6 On-Line Monitoring of Primary Containment The drywell and suppression chamber comprise the primary containment volume at DNPS (i.e., Mark I containment design). During power operation, the primary containment atmosphere is inerted with nitrogen to mitigate concerns with hydrogen production following certain design basis accidents. DNPS, Units 2 and 3 TS 3.6.2.5, "Drywell-to-Suppression Chamber Differential Pressure," requires that containment drywell pressure be maintained at a positive pressure relative to containment suppression chamber pressure (i.e., SVLGGLIIHUHQWLDOSUHVVXUH . TS Section 3.6.1.4 also requires WKDWGU\ZHOOSUHVVXUHEHPDLQWDLQHGSVLJ. The Containment Atmospheric Control System provides a supply of makeup nitrogen to automatically maintain primary containment pressure within the TS limits. Drywell and suppression chamber pressure are continuously recorded in the Main Control Room (MCR). The MCR operators monitor drywell pressure and drywell to suppression chamber differential pressure via surveillances.

Additionally, drywell high or low pressure annunciators in the MCR alert the operators to off Page 56 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE normal conditions. The containment pressure monitoring described above provides indications of changes to containment leakage.

3.6 Operating Experience During the conduct of the various examinations and tests conducted in support of the containment related programs previously mentioned, issues that do not meet established criteria or that provide indication of degradation, are identified, placed into the site's corrective action program, and corrective actions are planned and performed.

For the DNPS Primary Containment, the following site specific and industry events have been evaluated for impact:

x Information Notice (IN) 1992-20, "Inadequate Local Leak Rate Testing" x IN 2010-12, "Containment Liner Corrosion" x IN 2014-07, "Degradation of Leak-Chase Channel Systems for Floor Welds of Metal Containment Shell and Concrete Containment Metallic Liner" x Regulatory Issue Summary (RIS) 2016-07, "Containment Shell or Liner Moisture Barrier Inspection" x Through-wall Torus Shell Crack at James A. Fitzpatrick Nuclear Power Plant x GL 87-05, "Request for Additional Information - Assessment of Licensee Measures to Mitigate and/or Identify Potential Degradation of Mark I Drywells "

Each of these areas are discussed in detail in Sections 3.6.1 through 3.6.6, respectively.

3.6.1 IN 1992-20, Inadequate Local Leak Rate Testing The issues discussed in IN 1992-20, "Inadequate Local Leak Rate Testing," were based on events at four different plants: Quad Cities Nuclear Power Station (QCNPS), Dresden Nuclear Power Station, Perry Nuclear Plant, and the Clinton Power Station. The common issue in the four events was the failure to adequately perform local leak rate testing on different penetration configurations leading to problems that were discovered during ILRT tests in the first three cases.

The IN event for DNPS was that a leakage rate was found significantly greater than the maximum allowed during the pressurization phase of its ILRT. Dresden identified the source of the leak as the inboard flange of the torus purge exhaust inner isolation valve with an estimated leakage rate of approximately 25 weight percent per day at 15 psig. DNPS had last performed maintenance on this valve during the previous outage. Although a LLRT had been performed on the valve following the maintenance, the test did not challenge the inboard flange.

A second IN event was described for QCNPS that also applied to DNPS. Specifically, testing of two-ply bellows design was not properly subjected to LLRT pressure with the conclusion that the two-ply bellows design could not be Type B LLRT tested as configured. In the events at DNPS, QCNPS, and Perry Nuclear Plant, flanges were not considered a leakage path when the Type C Page 57 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE LLRT test was designed. This omission led to a leakage path that was not discovered until the plant performed an ILRT test. Both flanges are now tested.

DNPS Discussion:

At DNPS, LLRT testing of the two-ply stainless steel bellows is performed by a proceduralized series of test techniques, which are; (1) air is first used as the test media to determine leak tightness, (2) followed by helium as a test media if leakage exceeds a predetermined test value, (3) then welding in temporary test fixtures and testing as a Type B component to determine leakage, and (4) then finally, by the replacement of a failed bellow. This test technique was reviewed and supported by the NRC with an exemption granted from testing requirements of Appendix J (i.e., Reference 42).

3.6.2 IN 2010-12, "Containment Liner Corrosion" This IN was issued to alert plant operators to three events that occurred where the steel liner of the containment building was corroded and degraded. At Beaver Valley and Brunswick plants, material was found in the concrete, which trapped moisture against the liner plant and corroded the steel. In one case, it was material intentionally placed in the building and in the other case, it was foreign material which had inadvertently been left in the concrete form when the wall was poured. But the result in both cases was that the material trapped moisture against the steel liner plate leading to corrosion. In the third case, an insulating material placed between the concrete floor and the steel liner plate at Salem absorbed moisture and led to corrosion of the liner plate.

Subsequent to IN 2010-12, the NRC issued Technical Letter Report - Revision 1, "Containment Liner Corrosion Operating Experience Summary," (Reference 19), on August 2, 2011, that summarized this topic across the nuclear industry. The technical letter addresses operating plants that have containment buildings constructed with carbon steel liners in contact with concrete. In the United States, there are 55 pressurized water reactors (PWRs) and 11 BWRs with carbon steel liners in contact with concrete. The focus of the Technical Letter was to evaluate steel containment liner corrosion initiated at the liner/concrete interface.

DNPS Discussion:

DNPS was designed and constructed with a Mark 1 containment that is a freestanding steel primary containment that is not in contact with the concrete (i.e., either reinforced steel or prestressed/post-tensioned) containment structure. Because the objective of the Technical Letter is focused on corrosion of steel in contact with concrete, plants with freestanding steel primary containments, (i.e., specifically DNPS, Units 2 and 3) are not included in their review.

EGC has implemented periodic examinations for the DNPS units during each period on metallic containment structures or liners in accordance with ASME Section XI, Subsection IWE. The applicable EGC visual examination procedure requires the conditions described in the IN examples to be recorded. Conditions that may affect containment surface integrity are then required to be evaluated by engineering evaluation or repair/replacement prior to startup from refueling outages.

Page 58 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE 3.6.3 IN 2014-07, "Degradation of Leak-Chase Channel Systems for Floor Welds of Metal Containment Shell and Concrete Containment Metallic Liner" The containment basemat metallic shell and liner plate seam welds of pressurized water reactors are embedded in three-to four feet thick concrete floor during construction and are typically covered by a leak-chase channel system that incorporates pressurizing test connections. This system allows for pressure testing of the seam welds for leak-tightness during construction and also in service, as required. A typical basemat shell or liner weld leak-chase channel system consists of steel channel sections that are fillet welded continuously over the entire bottom shell or liner seam welds and subdivided into zones, each zone with a test connection.

Each test connection consists of a small carbon or stainless steel tube (i.e., less than one-inch diameter) that penetrates through the back of the channel and is seal-welded to the channel steel. The tube extends up through the concrete floor slab to a small steel access junction box embedded in the floor slab. The steel tube, which may be encased in a pipe, projects up through the bottom of the access box with a threaded coupling connection welded to the top of the tube, allowing for pressurization of the leak-chase channel. After the initial tests, steel threaded plugs or caps are installed in the test tap to seal the leak-chase volume. Gasketed cover plates or countersunk plugs are attached to the top of the access box flush with the containment floor. In some cases, the leak-chase channels with plugged test connections may extend vertically along the circumference of the cylindrical containment shell or liner to a certain height above the floor.

DNPS Discussion:

No similar deficiencies are present at DNPS, which is a BWR with a Mark I Containment, and does not have a leak-chase channel system inside containment. The containment is periodically inspected as part of the Coatings Program and CISI Program. Water accumulation and corrosion degradation would be observed as part of that program. Nothing significant has been noted and minor corrosion has been promptly repaired.

3.6.4 RIS 2016-07, "Containment Sell or Liner Moisture Barrier Inspection" Section XI of the ASME Code, in Table IWE-2500-1 (E-A), Item E1.30 requires general visual examination of 100% of accessible moisture barriers during each inspection period. Note 3 for Item E1.30 under the "Parts Examined" column states, Examination shall include moisture barrier materials intended to prevent intrusion of moisture against inaccessible areas of the pressure retaining metal containment shell or liner at concrete-to-metal interfaces and at metal-to-metal interfaces which are not seal-welded. Containment moisture barrier materials include caulking, flashing, and other sealants used for this application.

For metal-to-metal, concrete-to metal interface and other configurations in which a material has been applied to prevent moisture from making contact with inaccessible areas of the metal containment shell or liner, these materials should be inspected as a moisture barrier under Item E1.30.

Page 59 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE DNPS Discussion:

Moisture barrier inspections for DNPS, Units 2 and 3, are performed each inspection period.

The requirement for inspection is reflected on Table 3.5-6, Item E1.30 located in Section 3.5.2 of this LAR. This moisture barrier inspection is performed as a part of the CISI program. There are four inspections locations performed, they are: (1) Drywell Basement Moisture Barrier, (2) X-100 Equipment Hatch Moisture Barrier, (3) X-101 Personnel Hatch Floor Moisture Barrier, and (4) X-101 Personnel Hatch Penetration Moisture Barrier. The inspection results for these four inspection locations, for the last two inspection periods, have resulted in no reportable indications.

3.6.5 Through-Wall Torus Shell Crack at James A. Fitzpatrick Nuclear Power Plant A through-wall torus shell crack was discovered at the James A. Fitzpatrick Nuclear Power Plant (JAF) on June 27, 2005, and was reported via licensee event report (LER)05-003 (ML052510120). The JAF High Pressure Coolant Injection (HPCI) turbine exhaust line that discharged into the suppression pool is open-ended and does not have an end cap or a sparger.

DNPS Discussion:

On July 1st, 2005 an inspection was performed on the DNPS, Unit 2 and Unit 3 torus shells in response to leakage identified in the torus at Fitzpatrick. The inspection was performed in the region where torus support legs attach to the torus shell. The attachments on both sides of the HPCI turbine exhaust penetration (i.e., Bay 13 to 14 and Bay 14 to 15 support legs) were inspected from the torus basement floor for signs of leakage or distress. No indication of leakage or distress was identified.

Extent of Condition:

EGC has modified the DNPS torus (column) supports to accommodate the Mark I loads. The HPCI exhaust line to the torus shell configuration (i.e., reinforced nozzle and internal support),

at DNPS is such that it will transmit the HPCI discharge loads more evenly to the torus shell and column supports.

EGC has reviewed the DNPS configuration including the HPCI exhaust line configuration, torus support, HPCI nozzle penetration details, and concluded that the root cause of the torus leak at JAF does not apply for DNPS. The DNPS HPCI exhaust line configuration is different from and better than the JAF HPCI exhaust line configuration for mitigating the HPCI discharge loads.

3.6.6 GL 87-05, Request for Additional Information - Assessment of Licensee Measures to Mitigate and/or Identify Potential Degradation of Mark I Drywells GL 87-05 described drywell shell degradation, which occurred at Oyster Creek Nuclear Generating Station as a result of water intrusion into the air gap between the outer drywell surface and the surrounding concrete and subsequent wetting of the sand cushion at the bottom of the air gap.

The cause of this degradation was determined to be from water entering the drywell air gap region, and becoming trapped in the sand cushion region at the base of the air gap. The air gap Page 60 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE region surrounds the outside surface of the drywell and extends from the sand cushion region at the bottom, to just below the drywell bellows region at the top. During refueling activities, a potential leakage path could exist through the drywell bellows region, as experienced on the reported Mark I containment. The drywell bellows provides a flexible seal between the drywell and the reactor cavity. The drywell to concrete seal drains are also located in this bellows area.

Leakage of these components could allow water to enter the air gap region.

Discussion:

In response to NRC Inspection and Enforcement Notice (IEN) 86-99 and GL 87-05, an extensive review was conducted by DNPS for the potential for drywell steel corrosion in the area of the sand pocket. The response to this GL is contained in UFSAR, Section 6.2.1.2.1.2, "Drywell Corrosion Potential."

The UFSAR response reads, in part:

The DNPS review included an inspection of the drain lines, initiation of a surveillance program to detect leakage into the annulus, and an evaluation of the actual plate thickness at Dresden Unit 3.

The review found that initially, all lines in both units were clogged. After the lines were cleared, leakage from all lines was observed. The source of the leakage is believed to be past the refueling bellows drain line expansion joints. The method utilized to plug the drain lines during refueling is the installation of an expanding stop plug, which if incorrectly placed in the expansion joint, could produce leakage. In an effort to eliminate leakage, the plug design was altered to preclude incorrect placement. Water samples taken were tested and determined to be noncorrosive in nature, so there was no immediate safety concern. This, however, did not prevent future leakage.

Ultrasonic test (UT) results indicated that over 18 years of operation of DNPS, Unit 3, no detrimental corrosion has occurred in the drywell steel plate at the sand pocket level. This conclusion is further supported by the fact that all of the thickness measurements were on the high side (i.e., greater than the nominal 1.0625-inch thickness). These results have been obtained in spite of the fact that substantial moisture has previously been found in the sand pocket.

Finally, a surveillance procedure has been established to monitor sand pocket drain lines during refuel activities. If leakage is detected during refuel flood-up, an inspection to determine the source will take place and further corrective measures will be initiated.

Preventive Maintenance Identification Numbers (PMIDs) have been generated at DNPS for monitoring leakage from the Dryer Separator Pit, the Spent Fuel Pool, and the Drywell Liner Area Drains (i.e., drywell liner) . In addition, a separate procedure has been written and PMIDs generated for testing the drain lines for water and to ensure clear, unplugged lines from the sand pocket. The inspection results of the sand pocket and of the drywell liner area for the past two refueling outages for each unit is shown in Table 3.6.6-1 below.

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ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE Table 3.6.6-1 Leakage Monitoring Refueling Outage Date Results Number Leak found during DOS 1600-31 Drywell Annulus Leakage Inspection. Torus bellows seal 67 and 112 degrees, 250 ml November / 3 min leak.

D2R23 2013 Rod out drywell liner sand pocket drains. Some sand found in 2 drains. Sand pocket drains were cleared of sand.

Leak found during DOS 1600-31, Unit 2 Drywell Annulus Leakage Inspection, a small leak was found. The Drywell Liner Sand Pocket Drain Line at Bay 12 has an approximate November D2R24 1 drop per minute leak.

2015 Rod out drywell liner sand pocket drains. Sand pocket drains are clear of sand.

No leakage identified during DOS 1600-31 Drywell Leakage Inspection.

November D3R23 2014 Rod out drywell liner sand pocket drains. Sand pocket drains are clear of sand.

No leakage identified during DOS 1600-31 Drywell Leakage November Inspection.

D3R24 2016 Rod out drywell liner sand pocket drains. Sand pocket drains are clear of sand.

3.7 License Renewal Aging Management DNPS UFSAR, Appendix A, "Updated Final Safety Analysis Report (UFSAR) Supplement,"

contains the UFSAR Supplement as required by 10 CFR 54.21(d) for the DNPS License Renewal Application (LRA). The NRC issued NUREG-1796, "Safety Evaluation Report Related to the License Renewal of Dresden Nuclear Power Station, Units 2 and 3 and Quad Cities Nuclear Power Station, Units 2 and 3 (i.e., Reference 18)," that provided their SER of the DNPS LRA.

The aging management activity descriptions presented in the UFSAR, Appendix A represent commitments for managing aging of the in-scope systems, structures, and components during the period of extended operation.

As part of the license renewal effort, it had to be demonstrated that the aging effects applicable to the components and structures within the scope of license renewal would be adequately managed during the period of extended operation.

In many cases, existing activities were found adequate for managing aging effects during the period of extended operation. In some cases, aging management reviews revealed that existing Page 62 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE activities required enhancement to adequately manage applicable aging effects. In a few cases, new activities were developed to provide added assurance that aging effects are adequately managed.

The following programs/activities are credited with the aging management of the Primary Containment (Drywell and Torus).

x 10 CFR Part 50, Appendix J (Supplement Appendix A.1.28)

The 10 CFR Part 50, Appendix J aging management program monitors leakage rates through the containment pressure boundary, including the drywell and torus, penetrations, fittings, and other access openings; in order to detect degradation of containment pressure boundary. Corrective actions are taken if leakage rates exceed acceptance criteria. The Appendix J program also manages changes in material properties of gaskets, O-rings, and packing materials for the containment pressure boundary access points. The containment leak rate tests are performed in accordance with the regulations and guidance provided in 10 CFR 50, Appendix J, Option B, RG 1.163, "Performance-Based Containment Leak-Testing Program," NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50 Appendix J," and ANSI/ANS 56.8, "Containment System Leakage Testing Requirements."

x ASME Section XI, Subsection IWE (Supplement Appendix A.1.26)

The ASME Section XI, Subsection IWE aging management program consists of periodic visual examination for signs of degradation, and limited surface or volumetric examination when augmented examination is required. The program covers steel containment shells and their integral attachments; containment hatches and airlocks; seals, gaskets and moisture barriers; and pressure-retaining bolting. The program includes assessment of damage and corrective actions. The requirements of ASME Section XI will be implemented in accordance with 10 CFR 50.55(a).

x Protective Coating Monitoring and Maintenance Program (Supplement Appendix A.1.32)

The protective coating monitoring and maintenance aging management program consists of guidance for selection, application, inspection, and maintenance of Service Level I protective coatings. This program is implemented in accordance with RG 1.54, "Quality Assurance Requirements for Protective Coatings Applied to Water-Cooled Nuclear Power Plants," Revision 0, ANSI N101 4-1972, "Quality Assurance for Protective Coatings Applied to Nuclear Facilities," and the guidance of EPRI TR-109937, "Guidelines on Nuclear Safety-Related Coating." Prior to the period of extended operation the program was revised to include thorough visual inspection of Service Level 1 coatings near sumps or screens for the emergency core cooling system, pre-inspection review of previous reports so that trends can be identified, and analysis of suspected causes of any coating failures.

Page 63 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE 3.8 NRC SER Limitations And Conditions 3.8.1 Limitations and Conditions Applicable to NEI 94-01, Revision 2-A The NRC found that the use of NEI TR 94-01, Revision 2, was acceptable for referencing by licensees proposing to amend their TS to permanently extend the ILRT surveillance interval to 15 years, provided the following conditions as listed in Table 3.8.1-1 were satisfied:

Table 3.8.1-1 NEI 94-01, Revision 2-A, Limitations and Conditions Limitation/Condition DNPS Response (From Section 4.0 of SE)

For calculating the Type A leakage rate, the DNPS will utilize the definition in NEI 94-01 licensee should use the definition in the NEI Revision 3-A, Section 5.0. This definition TR 94-01, Revision 2, in lieu of that in has remained unchanged from Revision 2-A ANSI/ANS-56.8-2002. (Refer to SE Section to Revision 3-A of NEI 94-01.

3.1.1.1.)

The licensee submits a schedule of containment inspections to be performed Reference Section 3.5.2 (Tables 3.5.2-3 and prior to and between Type A tests. (Refer to 3.5.2-4) of this LAR submittal.

SE Section 3.1.1.3.)

The licensee addresses the areas of the Reference Section 3.5.2 (Tables 3.5.2-3, containment structure potentially subjected 3.5.2-4, and 3.5.2-7) of this LAR submittal.

to degradation. (Refer to SE Section 3.1.3.)

There are no major modifications planned to the containment structure.

Modification is underway to comply with NRC Order EA-13-109, to install a hardened containment vent system. Does not directly modify containment.

The licensee addresses any tests and Modification has been completed that inspections performed following major installed new AOV 2(3)-4724 in series with modifications to the containment structure, check valve 2(3)-4799-531. These valves as applicable. (Refer to SE Section 3.1.4.)

are in a parallel flow path to AOV 2(3)-4722 (Both located outside the drywell) and in series with check valve 2(3)-4799-530 (located inside the drywell). Does not directly modify containment.

Refer to Section 3.1.7 of this LAR submittal for additional details.

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ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE Table 3.8.1-1 NEI 94-01, Revision 2-A, Limitations and Conditions Limitation/Condition DNPS Response (From Section 4.0 of SE)

DNPS will follow the requirements of NEI 94-01 Revision 3-A, Section 9.1. This The normal Type A test interval should be requirement has remained unchanged from less than 15 years. If a licensee has to Revision 2-A to Revision 3-A of NEI 94-01.

utilize the provision of Section 9.1 of NEI TR 94-01, Revision 2, related to extending the ILRT interval beyond 15 years, the In accordance with the requirements of 94-licensee must demonstrate to the NRC staff 01 Revision 2-A, SER Section 3.1.1.2, that it is an unforeseen emergent condition. DNPS will also demonstrate to the NRC that (Refer to SE Section 3.1.1.2.) an unforeseen emergent condition exists in the event an extension beyond the 15-year interval is required.

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 Not applicable. DNPS was not licensed construction and testing of containments for under 10 CFR Part 52.

that design have been completed and applicants have confirmed the applicability of NEI 94-01, Revision 2, and EPRI Report No. 1009325, Revision 2, including the use of past containment ILRT data.

3.8.2 Limitations and Conditions Applicable to NEI 94-01, Revision 3-A The NRC found that the guidance in NEI TR 94-01, Revision 3, was acceptable for referencing by licensees in the implementation of the optional performance-based requirements of Option B to 10 CFR 50, Appendix J. However, the NRC identified two conditions on the use of NEI TR 94-01, Revision 3 (i.e., Reference NEI 94-01 Revision 3-A, NRC SER 4.0, Limitations and Conditions):

Topical Report Condition 1 NEI TR 94-01, Revision 3, is requesting that the allowable extended interval for Type C LLRTs be increased to 75 months, with a permissible extension (for non-routine emergent conditions) of nine months (84 months total). The staff is allowing the extended interval for Type C LLRTs be increased to 75 months with the requirement that a licensee's post-outage report include the margin between the Type B and Type C leakage rate summation and its regulatory limit. In addition, a corrective action plan shall be developed to restore the margin to an acceptable level. The staff is also allowing the non-routine emergent extension out to 84-months as applied to Type C valves at a site, with some exceptions that must be detailed in NEI TR 94-01, Revision 3. At no time shall an extension be allowed for Type C valves that are restricted categorically (e.g., BWR MSIVs), and those valves with a history of leakage, or any valves held to either a less than maximum interval or to the base refueling cycle interval. Only non-routine emergent conditions allow an extension to 84 months.

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ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE Response to Condition 1 Condition 1 presents the following three (3) separate issues that are required to be addressed:

x ISSUE 1 - The allowance of an extended interval for Type C LLRTs of 75 months carries the requirement that a licensee's post-outage report include the margin between the Type B and Type C leakage rate summation and its regulatory limit.

x ISSUE 2 - In addition, a corrective action plan shall be developed to restore the margin to an acceptable level.

x ISSUE 3 - Use of the allowed nine-month extension for eligible Type C valves is only authorized for non-routine emergent conditions with exceptions as detailed in NEI 94-01, Revision 3-A, Section 10.1.

Response to Condition 1, ISSUE 1 The post-outage report shall include the margin between the Type B and Type C Minimum Pathway Leak Rate (MNPLR) summation value, as adjusted to include the estimate of applicable Type C leakage understatement, and its regulatory limit of 0.60 La.

Response to Condition 1, ISSUE 2 When the potential leakage understatement adjusted Types B and C MNPLR total is greater than the DNPS, Units 2 and 3, 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 DNPS leakage limit. The corrective action plan shall focus on those components which have contributed the most to the increase in the leakage summation value and what manner of timely corrective action, as deemed appropriate, best focuses on the prevention of future component leakage performance issues so as to maintain an acceptable level of margin.

Response to Condition 1, ISSUE 3 DNPS, Units 2 and 3 will apply the nine-month allowable interval extension period only to eligible Type C components and only for non-routine emergent conditions. Such occurrences will be documented in the record of tests.

Topical Report Condition 2 The basis for acceptability of extending the ILRT interval out to once per 15 years was the enhanced and robust primary containment inspection program and the local leakage rate testing of penetrations. Most of the primary containment leakage experienced has been attributed to penetration leakage and penetrations are thought to be the most likely location of most containment leakage at any time. The containment leakage condition monitoring regime involves a portion of the penetrations being tested each refueling outage, nearly all LLRTs being performed during plant outages. For the purposes of assessing and monitoring or trending overall containment leakage potential, the as-found minimum pathway leakage rates for the just tested penetrations are summed with the as-left minimum pathway leakage rates for penetrations tested during the previous 1 or 2 or even 3 refueling outages. Type C tests involve Page 66 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE 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 is used to assess the current containment leakage potential. This leads to the possibility that the LLRT totals calculated understate the actual leakage potential of the penetrations. Given the required margin included with the performance criterion and the considerable extra margin most plants consistently show with their testing, any understatement of the LLRT total using a five-year test frequency is thought to be conservatively accounted for.

Extending the LLRT intervals beyond five years to a 75-month interval should be similarly conservative provided an estimate is made of the potential understatement and its acceptability determined as part of the trending specified in NEI TR 94-01, Revision 3, Section 12.1.

When routinely scheduling any LLRT valve interval beyond 60-months and up to 75-months, the primary containment leakage rate testing program trending or monitoring must include an estimate of the amount of understatement in the Types B and C total leakage, and must be included in a licensee's post-outage report. The report must include the reasoning and determination of the acceptability of the extension, demonstrating that the LLRT totals calculated represent the actual leakage potential of the penetrations.

Response to Condition 2 Condition 2 presents the following two (2) separate issues that are required to be addressed:

x ISSUE 1 - Extending the LLRT intervals beyond five years to a 75-month interval should be similarly conservative provided an estimate is made of the potential understatement and its acceptability determined as part of the trending specified in NEI TR 94-01, Revision 3, Section 12.1.

x ISSUE 2 - When routinely scheduling any LLRT valve interval beyond 60 months and up to 75 months, the primary containment leakage rate testing program trending or monitoring must include an estimate of the amount of understatement in the Types B and C total, and must be included in a licensee's post-outage report. The report must include the reasoning and determination of the acceptability of the extension, demonstrating that the LLRT totals calculated represent the actual leakage potential of the penetrations.

Response to Condition 2, ISSUE 1 The change in going from a 60-month extended test interval for Type C tested components to a 75-month interval, as authorized under NEI 94-01, Revision 3-A, represents an increase of 25%

in the LLRT periodicity. As such, DNPS, Units 2 and 3 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 Page 67 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE 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 DNPS 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 DNPS 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 (i.e., Reference 44).

Response to Condition 2, ISSUE 2 If the potential leakage understatement adjusted leak rate MNPLR is less than the DNPS leakage summation limit of 0.50 La, then the acceptability of the greater than a 60-month test interval up to the 75-month LLRT extension for all affected Type C components has been adequately demonstrated and the calculated local leak rate total represents the actual leakage potential of the penetrations.

In addition to Condition 1, ISSUES 1 and 2, which deal with the MNPLR Types B and C summation margin, NEI 94-01, Revision 3-A, also has a margin-related requirement as contained in Section 12.1, "Report Requirements."

A post-outage report shall be prepared presenting results of the previous cycles Type B and Type C tests, and Type A, Type B and Type C tests, if performed during that outage. The technical contents of the report are generally described in ANSI/ANS-56.8-2002 and shall be available on-site for NRC review. The report shall show that the applicable performance criteria are met, and serve as a record that continuing performance is acceptable. The report shall also include the combined Type B and Type C leakage summation, and the margin between the Type B and Type C leakage rate summation and its regulatory limit. Adverse trends in the Type B and Type C leakage rate summation shall be identified in the report and a corrective action plan developed to restore the margin to an acceptable level.

At DNPS, 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 DNPS, 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.

Page 68 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE 3.9 Conclusions NEI 94-01, Revision 3-A, dated July 2012, and the limitations and conditions specified in NEI 94-01, Revision 2-A, dated October 2008, describe an NRC-accepted approach for implementing the performance-based requirements of 10 CFR 50, Appendix J, Option B. It incorporated the regulatory positions stated in RG 1.163 and includes provisions for extending Type A intervals to 15 years and Type C test intervals to 75 months. NEI 94-01, Revision 3-A delineates a performance-based approach for determining Type A, Type B, and Type C containment leakage rate surveillance test frequencies. DNPS is adopting the guidance of NEI 94-01, Revision 3-A, and the limitations and conditions specified in NEI 94-01, Revision 2-A, for the DNPS, Units 2 and 3, 10 CFR 50, Appendix J testing program plan.

Based on the previous ILRTs conducted at DNPS, Units 2 and 3, it may be concluded that the permanent extension of the containment ILRT interval from 10 to 15 years represents minimal risk to increased leakage. The risk is minimized by continued Type B and Type C testing performed in accordance with Option B of 10 CFR 50, Appendix J, drywell Inspections and the overlapping inspection activities performed as part of the following DNPS inspection programs:

• Containment Inservice Inspection Program (IWE)

• Containment Inspections per TS SR 3.6.1.1.1

• Containment Coatings Inspection and Assessment Program This experience is supplemented by risk analysis studies, including the DNPS risk analysis provided in Attachment 3. The risk assessment concludes that increasing the ILRT interval on a permanent basis to a one-in-fifteen year frequency is not considered to be significant since it represents only a small change in the DNPS risk profile.

4.0 REGULATORY EVALUATION

4.1 Applicable Regulatory Requirements/Criteria The proposed change has been evaluated to determine whether applicable regulations and requirements continue to be met. 10 CFR 50.54(o) requires primary reactor containments for water-cooled power reactors to be subject to the requirements of 10 CFR 50, Appendix J, "Leakage Rate Testing of Containment of Water Cooled Nuclear Power Plants." Appendix J specifies containment leakage testing requirements, including the types required to ensure the leak-tight integrity of the primary reactor containment and systems and components which penetrate the containment. In addition, Appendix J discusses leakage rate acceptance criteria, test methodology, frequency of testing and reporting requirements for each type of test.

The adoption of the Option B performance-based containment leakage rate testing for Type A, Type B, and Type C testing did not alter the basic method by which Appendix J leakage rate testing is performed; however, it did alter the frequency at which Type A, Type B, and Type C containment leakage tests must be performed. Under the performance-based option of 10 CFR 50, Appendix J, the test frequency is based upon an evaluation that reviewed as-found leakage history to determine the frequency for leakage testing which provides assurance that leakage limits will be maintained. The change to the Type A test frequency did not directly result in an increase in containment leakage. Similarly, the proposed change to the Type C test frequencies will not directly result in an increase in containment leakage.

Page 69 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE EPRI TR-1009325, Revision 2-A (i.e., Reference 20), provided a risk impact assessment for optimized ILRT intervals up to 15 years, utilizing current industry performance data and risk informed guidance. NEI 94-01, Revision 3-A, Section 9.2.3.1 (i.e., Reference 2), states that Type A ILRT intervals of up to 15 years are allowed by this guideline. The Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals, EPRI Report 1018243 (formerly TR-1009325, Revision 2-A), indicates that, in general, the risk impact associated with ILRT interval extensions for intervals up to 15 years is small. However, plant-specific confirmatory analyses are required.

The NRC reviewed NEI TR 94-01, Revision 2, and EPRI Report No. 1009325, Revision 2. For NEI TR 94-01, Revision 2, the NRC determined that it described an acceptable approach for implementing the optional performance-based requirements of 10 CFR 50, Appendix J, Option B. This guidance includes provisions for extending Type A ILRT intervals up to 15 years and incorporates the regulatory positions stated in RG 1.163. The NRC found that the Type A testing methodology, as described in ANSI/ANS-56.8-2002, and the modified testing frequencies recommended by NEI TR 94-01, Revision 2, serve to ensure continued leakage integrity of the containment structure. Type B and Type C testing ensures that individual penetrations are essentially leak tight. In addition, aggregate Type B and Type C leakage rates support the leakage tightness of primary containment by minimizing potential leakage paths.

For EPRI Report No. 1009325, Revision 2, a risk-informed methodology using plant-specific risk insights and industry ILRT performance data to revise ILRT surveillance frequencies, the NRC found that the proposed methodology satisfies the key principles of risk-informed decision making applied to changes to TS as delineated in RG 1.177 and RG 1.174. The NRC, therefore, found that this guidance was acceptable for referencing by licensees proposing to amend their TS in regards to containment leakage rate testing, subject to the limitations and conditions noted in Section 4.2 of the SER.

The NRC reviewed NEI TR 94-01, Revision 3, and determined that it described an acceptable approach for implementing the optional performance-based requirements of 10 CFR 50, Appendix J, Option B, as modified by the limitations and conditions summarized in Section 4.0 of the associated SE. This guidance included provisions for extending Type C LLRT intervals up to 75 months. Type C testing ensures that individual containment isolation valves are essentially leak tight. In addition, aggregate Type C leakage rates support the leakage tightness of primary containment by minimizing potential leakage paths. The NRC, therefore, found that this guidance, as modified to include two limitations and conditions, was acceptable for referencing by licensees proposing to amend their TS in regards to containment leakage rate testing. Any applicant may reference NEI TR 94-01, Revision 3, as modified by the associated SER and approved by the NRC, and the limitations and conditions specified in NEI 94-01, Revision 2-A, dated October 2008, in a licensing action to satisfy the requirements of 10 CFR 50, Appendix J, Option B.

Page 70 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE 4.2 Precedents This LAR is similar in nature to the following license amendments to extend the Type A Test Frequency to 15 years and the Type C test frequency to 75 months as previously authorized by the NRC:

x Surry Power Station, Units 1 and 2 (Reference 24) x Donald C. Cook Nuclear Plant, Units 1 and 2 (Reference 25) x Beaver Valley Power Station, Unit Nos. 1 and 2 (Reference 26) x Calvert Cliffs Nuclear Power Plant, Unit Nos. 1 and 2 (Reference 27) x Peach Bottom Atomic Power Station, Units 2 and 3 (Reference 28) x Comanche Peak Nuclear Power Plant, Units 2 and 3 (Reference 39) x Catawba Nuclear Station, Units 1 and 2 (Reference 49) x H. B. Robinson Steam Electric Plant, Unit No. 2 (Reference 50) 4.3 No Significant Hazards Consideration Evaluation Exelon Generation Company, LLC (EGC) has evaluated whether or not a significant hazards consideration is involved with the proposed amendment by focusing on the three standards set forth in 10 CFR 50.92, "Issuance of amendment," as discussed below:

1. Does the proposed amendment involve a significant increase in the probability or consequences of an accident previously evaluated?

Response: No.

The proposed activity involves revision of the Dresden Nuclear Power Station (DNPS)

Technical Specification (TS) 5.5.12, "Primary Containment Leakage Rate Testing Program," to allow the extension of the DNPS, Units 2 and 3, Type A containment integrated leakage rate test (ILRT) interval to 15 years, and the extension of the Type C local leakage rate test interval to 75 months. The current Type A test interval of 120 months (i.e., 10 years) would be extended on a permanent basis to no longer than 15 years from the last Type A test. The existing Type C test interval of 60 months for selected components would be extended on a performance basis to no longer than 75 months. Extensions of up to nine months (i.e., total maximum interval of 84 months for Type C tests) are permissible only for non-routine emergent conditions.

The proposed extension does not involve either a physical change to the plant or a change in the manner in which the plant is operated or controlled. The containment is designed to provide an essentially leak tight barrier against the uncontrolled release of radioactivity to the environment for postulated accidents. As such, the containment and the testing requirements invoked to periodically demonstrate the integrity of the containment exist to ensure the plant's ability to mitigate the consequences of an accident, and do not involve the prevention or identification of any precursors of an accident.

The change in dose risk for changing the Type A, ILRT interval from three-per-ten years to once-per-fifteen-years, measured as an increase to the total integrated dose risk for all internal events accident sequences for DNPS, is 4.26E-02 person-roentgen equivalent man (rem)/year (0.27 percent(%)) using the Electric Power Research Institute (EPRI) guidance with the base case corrosion included. The change in dose risk drops to 1.14E-Page 71 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE 02 person-rem/year (i.e., 0.07%) when using the EPRI Expert Elicitation methodology.

The values calculated per the EPRI guidance are all lower than the acceptance criteria of less than or equal to 1.0 person-rem/year or less than 1.0% person-rem/year defined in Section 1.3 of Attachment 3 to this LAR. Therefore, this proposed extension does not involve a significant increase in the probability of an accident previously evaluated.

As documented in NUREG-1493, "Performance-Based Containment Leak-Test Program,"

dated January 1995, Types B and C tests have identified a very large percentage of containment leakage paths, and the percentage of containment leakage paths that are detected only by Type A testing is very small. The DNPS, Units 2 and 3 Type A test history supports this conclusion.

The integrity of the containment is subject to two types of failure mechanisms that can be categorized as: (1) activity based, and, (2) time based. Activity based failure mechanisms are defined as degradation due to system and/or component modifications or maintenance. Local leak rate test requirements and administrative controls such as configuration management and procedural requirements for system restoration ensure that containment integrity is not degraded by plant modifications or maintenance activities.

The design and construction requirements of the containment combined with the containment inspections performed in accordance with American Society of Mechanical Engineers (ASME) Section XI, and TS requirements serve to provide a high degree of assurance that the containment would not degrade in a manner that is detectable only by a Type A test. Based on the above, the proposed test interval extensions do not significantly increase the consequences of an accident previously evaluated.

The proposed amendment also deletes an exception previously granted in License Amendments Nos. 210 and No. 202 for DNPS, Units 2 and 3, respectively, to allow one-time extensions of the ILRT test frequency. This exception was for an activity that has already taken place; therefore, this deletion is solely a non-technical, editorial change that does not result in any alteration in how DNPS, Units 2 and 3 are operated.

Therefore, the proposed change does not result in a significant increase in the probability or consequences of an accident previously evaluated.

2. Does the proposed change create the possibility of a new or different kind of accident from any accident previously evaluated?

Response: No.

The proposed amendment to TS 5.5.12 involves the extension of the DNPS, Units 2 and 3 Type A containment test interval to 15 years and the extension of the Type C test interval to 75 months. The containment and the testing requirements to periodically demonstrate the integrity of the containment exist to ensure the plants ability to mitigate the consequences of an accident.

The proposed change does not involve a physical modification to the plant (i.e., no new or different type of equipment will be installed), nor does it alter the design, configuration, or change the manner in which the plant is operated or controlled beyond the standard functional capabilities of the equipment.

Page 72 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE The proposed amendment also deletes an exception previously granted under TS License Amendment Nos. 210 and No. 202 for Units 2 and 3, respectively to allow one-time extensions of the ILRT test frequency. This exception was for an activity that has already taken place; therefore, this deletion is solely a non-technical, editorial change that does not result in any alteration in how DNPS, Units 2 and 3 are operated.

Therefore, the proposed change does not create the possibility of a new or different kind of accident from any previously evaluated for DNPS, Units 2 and 3.

3. Does the proposed change involve a significant reduction in a margin of safety?

Response: No.

The proposed amendment to TS 5.5.12 involves the extension of the DNPS, Units 2 and 3 Type A containment test interval to 15 years and the extension of the Type C test interval to 75 months for selected components. This amendment does not alter the manner in which safety limits, limiting safety system set points, or limiting conditions for operation are determined. The specific requirements and conditions of the TS Containment Leak Rate Testing Program exist to ensure that the degree of containment structural integrity and leak-tightness that is considered in the plant safety analysis is maintained. The overall containment leak rate limit specified by TS is maintained.

The proposed change involves the extension of the interval between Type A containment leak rate tests and Type C tests for DNPS, Units 2 and 3. The proposed surveillance interval extension is bounded by the 15-year ILRT interval and the 75-month Type C test interval currently authorized within NEI 94-01, Revision 3-A. Industry experience supports the conclusion that Types B and C testing detects a large percentage of containment leakage paths and that the percentage of containment leakage paths that are detected only by Type A testing is small. The containment inspections performed in accordance with ASME Code, Section Xl and TS serve to provide a high degree of assurance that the containment would not degrade in a manner that is detectable only by Type A testing. The combination of these factors ensures that the margin of safety in the plant safety analysis is maintained. The design, operation, testing methods and acceptance criteria for Types A, B, and C containment leakage tests specified in applicable codes and standards would continue to be met, with the acceptance of this proposed change, since these are not affected by changes to the Type A and Type C test intervals.

The proposed amendment also deletes an exception previously granted under TS License Amendments Nos. 210 and No. 202 for Units 2 and 3, respectively to allow one-time extensions of the ILRT test frequency for DNPS, Units 2 and 3. This exception was for an activity that has taken place; therefore, the deletion is solely a non-technical, editorial change that does not result in any alteration in how DNPS, Units 2 and 3 are operated and maintained. Thus, there is no reduction in any margin of safety.

Therefore, the proposed changes do not involve a significant reduction in a margin of safety.

Based on the above, EGC concludes that the proposed amendment does not involve a significant hazards consideration under the standards set forth in 10 CFR 50.92(c), and, accordingly, a finding of no significant hazards consideration is justified.

Page 73 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE 4.4 Conclusions In conclusion, based on the considerations discussed above, (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) such activities will be conducted in compliance with the Commissions regulations, and (3) the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public.

5.0 ENVIRONMENTAL EVALUATION A review has determined that the proposed amendment would change a requirement with respect to installation or use of a facility component located within the restricted area, as defined in 10 CFR 20, or would change an inspection or surveillance requirement. However, the proposed amendment does not involve (i) a significant hazards consideration, (ii) a significant change in the types or significant increase in the amounts of any effluent that may be released offsite, or (iii) a significant increase in individual or cumulative occupational radiation exposure.

Accordingly, the proposed amendment meets the eligibility criterion for categorical exclusion set forth in 10 CFR 51.22(c)(9). Therefore, pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the proposed amendment.

6.0 REFERENCES

1. Regulatory Guide 1.163, "Performance-Based Containment Leak-Test Program," dated September 1995

2. NEI 94-01, Revision 3-A, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J," dated July 2012

3. RG 1.174, Revision 2, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis," dated May 2011

4. RG 1.200, Revision 2, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities," dated March 2009

5. NEI 94-01, Revision 0, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J," dated July 1995

6. NUREG-1493, "Performance-Based Containment Leak-Test Program," dated January 1995

7. EPRI TR-104285, "Risk Impact Assessment of Revised Containment Leak Rate Testing Intervals," dated August 1994

8. NEI 94-01, Revision 2-A, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J," dated October 2008 Page 74 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE

9. Letter from M. J. Maxin (NRC) to J. C. Butler (NEI), "Final Safety Evaluation for Nuclear Energy Institute (NEI) Topical Report (TR) 94-01, Revision 2, 'Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J,' and Electric Power Research Institute (EPRI) Report No. 1009325, Revision 2, August 2007, 'Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals,' (TAC No. MC9663),"

dated June 25, 2008 (ML081140105)

10. Letter from S. Bahadur (NRC) to B. Bradley (NEI), "Final Safety Evaluation of Nuclear Energy Institute (NEI) Report 94-01, Revision 3, 'Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J' (TAC No. ME2164)," dated June 8, 2012 (ML121030286)

11. EPRI TR-1018243, "Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals: Revision 2-A of 1009325," dated October 2008

12. DNPS Calculation DRE03-0032 (EC343681), "Calculation to Determine 80% of Primary Containment Remains Accessible for Examination for Dresden Units 2 and 3," dated July 29, 2003

13. Letter from John F. Stang (NRC) to D. L. Farrar (Commonwealth Edison Company (CECo)), "Issuance of Amendments [No. 148 and 142] Related to 10 CFR Part 50, Appendix J, Option B (TAC Nos. M94061, M94062, M94065 and M94066)," dated January 11, 1996 (ML021160123)

14. Letter from L. W. Rossbach (NRC) to O. D. Kingsley (CECo), "Dresden Nuclear Power Station, Units 2 and 3 - Issuance of Amendments (TAC NOS. MA5754 and MA5755),"

dated October 1, 1999

15. Letter from L. W. Rossbach (NRC) to O. D. Kingsley (EGC), "Dresden Nuclear Power Station, Units 2 and 3 - Issuance of Amendments for Extended Power Uprate (TAC Nos. MB0844 and MB0845), Enclosure 3 - Safety Evaluation Related to Amendments No 191 and No 185," dated December 21, 2001 (ML012510595 with additional supporting documents in ML013540187 and ML013600415)

16. Letter from L. W. Rossbach (NRC) to J. L. Skolds (EGC), "Issuance of Amendment -

Dresden Nuclear Power Station, Units 2 and 3, and Quad Cities Nuclear Power Station, Units 1 and 2, Excess Flow Check Valves (TAC Nos. MB7732, MB7733, MB7734, AND MB7735)," dated October 10, 2003 (ML032740364)

17. Letter from M. Banerjee (NRC) to C. M. Crane (EGC), "Issuance of Amendments -

[Nos. 210 and 202] Dresden Nuclear Power Station, Units 2 and 3, One-Time Extension of Containment Type A Leakage Rate Test Interval (TAC Nos. MC1796 and MC1797),"

dated October 13, 2004 (ML042520432)

18. Safety Evaluation Report, Related to the License Renewal of the Dresden Nuclear Power Station, Units 2 and 3 and Quad Cities Nuclear Power Station, Units 1 and 2, (NUREG-1796), dated October 28, 2004 (ML043060582)

Page 75 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE

19. Technical Letter Report, Revision 1, "Containment Liner Corrosion Operating Experience Summary," by D. S. Dunn, A. L. Pulvirenti, and M. A. Hiser, issued by the NRC on August 2, 2011 (ML112070867)

20. Electric Power Research Institute, Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals: Revision 2-A of 1009325, EPRI TR-1018243, dated October 2008

21. Letter from B. Rybak (CECo) to H. R. Denton (NRC), dated June 27, 1983, "Dresden Nuclear Power Station, Units 2 and 3 Plant Unique Analysis Report," Revision 0, dated May 1983, UFSAR, Section 3.8.2, Reference 1, (Reference described on Page 3.8-30)

22. Letter from J. A. Zwolinski (NRC) to D. L. Farrar (CECo), September 18, 1985, "Mark I Containment Long Term Program," UFSAR, Section 3.8.2, Reference 2 (Reference described on Page 3.8-30)

23. Dresden Nuclear Power Station PRA Peer Review Report (Internal Flooding) Using ASME PRA Standards, dated August 2009

24. Letter to D. Heacock from S. Williams (NRC), Surry Power Station, Units 1 and 2 -

Issuance of Amendment Regarding the Containment Type A and Type C Leak Rate Tests," dated July 3, 2014 (ML14148A235)

25. Letter to L. Weber from A. Dietrich (NRC), "Donald C. Cook Nuclear Plant, Units 1 and 2 -

Issuance of Amendments Re: Containment Leakage Rate Testing Program," dated March 30, 2015 (ML15072A264)

26. Letter to E. Larson from T. Lamb (NRC), "Beaver Valley Power Station, Unit Nos. 1 and 2 -

Issuance of Amendment Re: License Amendment Request to Extend Containment Leakage Rate Test Frequency," dated April 8, 2015 (ML15078A058)

27. Letter to G. Gellrich from A. Chereskin (NRC), "Calvert Cliffs Nuclear Power Plant, Unit Nos. 1 and 2 - Issuance of Amendments Re: Extension of Containment Leakage Rate Testing Frequency," dated July 16, 2015 (ML15154A661)

28. Letter to B. Hanson from R. Ennis (NRC), "Peach Bottom Atomic Power Station, Units 2 and 3 - Issuance of Amendments Re: Extension of Type A and Type C Leak Rate Test Frequencies (TAC Nos. MF5172 and MF5173)," dated September 8, 2015 (ML15196A559)

29. NEI 00-02, "Probabilistic Risk Assessment Peer Review Process Guidance," Rev. A3, dated March 2000

30. ASME/ANS RA-Sa-2009, "Addenda to ASME/ANS RA-S-2008, Standard for Level 1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications," dated March 2009

31. Dresden Nuclear Power Station PRA Peer Review Report, BWROG Final Report, dated January, 2000 Page 76 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE

32. Letter from C. H. Cruse (Constellation Nuclear, Calvert Cliffs Nuclear Power Plant) to (NRC), "Response to Request for Additional Information Concerning the License Amendment Request for a One-Time Integrated Leakage Rate Test Extension," dated March 27, 2002 (ML020920100)

33. Letter from R. Auluck (NRC) to C. Crane (EGC), "Issuance of Renewed Facility Operating License Nos. DPR-19, DPR-25, DPR-29, and DPR-30, Dresden Nuclear Power Station, Units 2 and 3, and Quad Cities Nuclear Power Station, Units 1 and 2, dated October 28, 2004 (ML042960560)

34. DR-PSA-016 Self-Assessment of the Dresden PRA Against the Combined ASME/ANS PRA Standard Requirements, Revision 0, dated March 2009

35. DR-PSA-016 Self-Assessment of the Dresden PRA Against the Combined ASME/ANS PRA Standard Requirements, Revision 1, dated June, 2009

36. DR-PSA-016, Self-Assessment of the Dresden PRA Against the Combined ASME/ANS PRA Standard Requirements, Revision 3, dated December, 2013

37. DG97-001424, Applicability of IWL Concrete Examination Requirements for Dresden and Quad Cities (Basis for exclusion of concrete (Class CC components) from examination per ASME Section XI, Subsection IWL), Commonwealth Edison Document, October 23, 1997

38. DR-PSA-016, Self-Assessment of the Dresden PRA Against the Combined ASME/ANS PRA Standard Requirements, Revision 2, dated October, 2009

39. Letter from B. Singal (NRC) to R. Flores (Luminant Generation Co.), "Comanche Peak Nuclear Power Plant, Units 1 and 2 - Issuance of Amendments Re: Technical Specification Change for Extension of the Integrated Leak Rate Test Frequency from 10 to 15 Years (CAC Nos. MF5621 and MF5622)," dated December 30, 2015 (ML15309A073)

40. Letter from D. G. Eisenhut (NRC) to L. DelGeorge, (CECo), "Re: Dresden Nuclear Power Station, Units 2 and 3," [Exemption from 10 CFR 50.54(o) and Appendix J pertaining to test sequence for Type A and C tests, the exclusion of instrument line and MSIVs for the Type C test requirement and extends the interval between Type B test for the containment airlock], dated June 25, 1982 (ML021150112)

41. Dresden Nuclear Power Station PRA Peer Review Report (Internal Flooding) Using ASME PRA Standards, November, 2010

42. Letter from B. A. Boger (NRC) to T. J. Kovach (Commonwealth Edison Company),

"Exemption from the Testing Requirements of Appendix J to 10 CFR Part 50 for Dresden and Quad Cities Nuclear Power Stations (TAC Nos. M81299, M81300, M81301, and M81302)," dated February 6, 1992. (ML021150419) [Subsequent letter dated February 9, 1995, from the NRC further revised imposed test measures (TAC Nos. M90628, M90629, M90630, and M90631)]

43. ANSI/ANS 56.8-2002, "Containment System Leakage Testing Requirements," dated November 27, 2002 Page 77 of 78

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGE

44. Letter from K. Mulligan (Entergy Operations, Inc.) to NRC, "Grand Gulf Nuclear Station Response to Request for Additional Information Regarding License Amendment Request to Revise Technical Specification for Containment Leak Rate Testing, Grand Gulf Nuclear Station, Unit 1, Docket No. 50-416, License No. NPF-29," Entergy document GNRO-2015/00063 (ML15302A042)

45. Design Analysis No. 64.305.1027, Rev. 3, "Evaluation of Dresden Unit 2 Torus Pitting,"

dated April 1, 2002

46. American Society of Mechanical Engineers, Standard for Probabilistic Risk Assessment for Nuclear Power Plant Applications, RA-Sc-2007, August 2007

47. Letter from M. Banerjee (NRC) to C. M. Crane (EGC) "Dresden Nuclear Power Station, Units 2 and 3, and Quad Cities Nuclear Power Station, Units 1 and 2 - Issuance of Amendments Re: Adoption of Alternative Source Term Methodology (TAC Nos. MB6530, MB6531, MB6532, MB6533, MC8275, MC8276, and MC8278)," dated September 11, 2006 (ML062070290) and Subsequent letter from D. S. Collins (NRC) to C. M. Crane (EGC) "Dresden Nuclear Power Station, Units 2 and 3, and Quad Cities Nuclear Power Station, Units 1 and 2 - Correction of Safety Evaluation for Amendment Dated September 11, 2006 (TAC Nos. MB6530, MB6531, MB6532, MB6533, MC8275, MC8276, and MC8278)," (ML062680404)

48. Regulatory Guide 1.200, Revision 1, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk Informed Activities," dated January 2007

49. Letter from M. D. Orenak (NRC) to K. Henderson (Duke Energy), "Catawba Nuclear Station, Units 1 and 2 - Issuance Of Amendments Regarding Extension of the Containment Integrated Leak Rate Test Intervals (CAC Nos. MF7265 and MF7266),"

dated September 12, 2016 (ML16229A113)

50. Letter from D. J. Galvin (NRC) to R. M. Glover (Duke Energy Progress, LLC),

"H. B. Robinson Steam Electric Plant, Unit No. 2 - Issuance of Amendment to Extend Containment Leakage Rate Test Frequencies (CAC No. MF7102)," dated October 11, 2016 (ML16201A195)

51. Dresden Nuclear Power Station PRA Peer Review Report (All applicable SRs except Internal Flooding), dated January 2017

52. NEI 05-04, Revision 2, "Process for Performing Internal Events PRA Peer Reviews Using the ASME/ANS PRA Standard," dated November 2008 Page 78 of 78

ATTACHMENT 2 Markup of Proposed Technical Specifications Pages Dresden Nuclear Power Station, Units 2 and 3 Renewed Facility Operating License Nos. DPR-19 and DPR-25 REVISED TECHNICAL SPECIFICATIONS PAGES 5.5-11 5.5-12

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.11 Safety Function Determination Program (SFDP) (continued)

b. A loss of safety function exists when, assuming no concurrent single failure, and assuming no concurrent loss of offsite power or loss of onsite diesel generator(s), a safety function assumed in the accident analysis cannot be performed. For the purpose of this program, a loss of safety function may exist when a support system is inoperable, and:

1. A required system redundant to system(s) supported by the inoperable support system is also inoperable; or

2. A required system redundant to system(s) in turn supported by the inoperable supported system is also inoperable; or

3. A required system redundant to support system(s) for the supported systems described in b.1 and b.2 above is also inoperable.

c. The SFDP identifies where a loss of safety function exists.

If a loss of safety function is determined to exist by this program, the appropriate Conditions and Required Actions of the LCO in which the loss of safety function exists are required to be entered. When a loss of safety function is caused by the inoperability of a single Technical Specification support system, the appropriate Conditions and Required Actions to enter are those of the support system.

5.5.12 Primary Containment Leakage Rate Testing Program

a. This program shall establish the leakage testing of the primary containment as required by 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions exemption. This program shall be in accordance with the guidelines contained in Regulatory Guide 1.163, "Performance-Based Containment Leak-Testing Program," dated September 1995, as modified by the following exceptions:

1. NEI 94 1995, Section 9.2.3: The first Unit 2 Type A test performed after the February 28, 1996, Type A test shall be performed no later than February 27, 2011.

NEI 94-01, "Industry Guideline for Implementing Performance-Based Option (continued) 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.

Dresden 2 and 3 5.5-11 Amendment No. 210/202

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.12 Primary Containment Leakage Rate Testing Program (continued)

2. NEI 94 1995, Section 9.2.3: The first Unit 3 Type A test performed after the July 14, 1994, Type A test shall be performed no later than July 13, 2009.

b. The peak calculated primary containment internal pressure for the design basis loss of coolant accident, Pa, is 43.9 psig.

c. The maximum allowable primary containment leakage rate, La, at Pa, is 3% of primary containment air weight per day.

d. Leakage rate acceptance criteria are:

1. Primary containment overall leakage rate acceptance criterion is ! 1.0 La. During the first unit startup following testing in accordance with this program, the leakage rate acceptance criteria are ! 0.60 La for the combined Type B and Type C tests, and ! 0.75 La for Type A tests.

2. Air lock testing acceptance criteria is the overall air lock leakage rate is ! 0.05 La when tested at # Pa.

e. The provisions of SR 3.0.3 are applicable to the Primary Containment Leakage Rate Testing Program.

5.5.13 Battery Monitoring and Maintenance Program This Program provides for restoration and maintenance, based on the recommendations of IEEE Standard 450-1995, "IEEE Recommended Practice for Maintenance, Testing, and Replacement of Vented Lead-Acid Batteries for Stationary Applications," including the following:

a. Actions to restore battery cells with float voltage

< 2.13 V, and

b. Actions to equalize and test battery cells that had been discovered with electrolyte level below the minimum established design limit.

(continued)

Dresden 2 and 3 5.5-12 Amendment No. 226/218

ATTACHMENT 3 DR-LAR-02, "Risk Assessment for DNPS Regarding the ILRT (Type A)

Permanent Extension Request," Revision 1, dated February 7, 2017

Exelon Risk Management Team RM DOCUMENTATION NO. DR*LAR-02 REV: 1 PAGE NO. 1 STATION: Dresden Nuclear Power Station (DNPS)

UNIT(s) AFFECTED: 2 & 3 TITLE: Risk Assessment for DNPS Regarding the ILRT (Type A) Permanent Extension Request

SUMMARY

DNPS is pursuing a License Amendment Request (LAR) to permanently extend the Integrated Leak Rate Test (ILRT) to 15 years.

The purpose of this document is to provide an assessment of the risk associated with implementing a permanent extension of the DNPS Unit 2 and Unit 3 containment ILRT interval to 15 years. Revision 1 updates Appendix A, PRA Technical Adequacy, to incorporate the 2016 Peer Review results and modifies Section 5.7, External Events Contribution.

This is a Category I Risk Management Document in accordance with ER-AA-600-1012 Risk Management Documentation [24], which requires independent review and approval, ER-AA-600-1046 Risk Metrics -

NOED and LAR [25] and ER-AA-600-1051 , "Risk Asses-sment of Surveillance Test Frequency Changes*

26.

[ X] Internal RM Documentation ( ] External RM Documentation Electronic Calculation Data Files:

Microsoft Excel DR_ILRT-Final.xlsx, 09/06/2016, 10:49 AM , 422 KB Method of Review: [ X ) Detailed [ ] Alternate [ ] Review of External Document This RM documentation supersedes:

Prepared by: John E. Steinmetz I I 2/6/2017 Print Date Prepared by: Dustin Wong I I 2/6/2017 Print Date Reviewed by: Grant Teagarden Print

.L=: I 2/6/2017 Date Reviewed by: Don Vanover t:MA11..-) I 2/=r fit:_

~

Print Approved by: Eugene M. Kelly I Print e Revision 1 1GWH32252.000-13085-2/8/2017

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