ML17121A449

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

ML17121A449
Person / Time
Site:	Quad Cities
Issue date:	04/27/2017
From:	Simpson P R Exelon Generation Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
RS-17-051
Download: ML17121A449 (192)

Text

4300 Winfield Road Warrenville, IL 60555 630 657 2000 Office

RS-17-051 10 CFR 50.90 April 27, 2017

U.S. Nuclear Regulatory Commission

ATTN: Document Control Desk Washington, DC 20555-0001

Quad Cities Nuclear Power Station, Units 1 and 2 Renewed Facility Operating License Nos. DPR-29 and DPR-30 NRC Docket Nos. 50-254 and 50-265

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

References:

1. Letter from P. R. Simpson (Exelon Generation Company, LLC) to U.S. NRC, "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," dated September 19, 2016

2. Letter from P. R. Simpson (Exelon Generation Company, LLC) to U.S. NRC, "Withdrawal of 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," dated December 22, 2016

3. Letter from K. J. Green (U.S. NRC) to B. C. Hanson (Exelon Generation Company, LLC), "Quad Cities Nuclear Power Station, Units 1 and 2 -

Withdrawal of Requested Licensing Action to Revise Technical Specification 5.5.12 for Permanent Extension of Type A and Type C Leak Rate Test Frequencies Submitted to NRC for Acceptance Review (CAC Nos. MF8387 and MF8388)," dated December 23, 2016

In Reference 1, Exelon Generation Company, LLC (EGC) submitted a license amendment request for Quad Cities Nuclear Power Station (QCNPS), Units 1 and 2, respectively, to allow for the permanent extension of the Type A Integrated Leak Rate Testing (ILRT) and Type C Leak Rate Testing frequencies. However, EGC withdrew the proposed license amendment request in Reference 2 based on concerns that were identified during the NRC's acceptance review of the license amendment request. The NRC concerns were summarized and provided to EGC in Reference 3. Specifically, Reference 3 states that the Reference 1 application did not April 27, 2017 U.S. Nuclear Regulatory Commission

Page 2 provide the following technical information in sufficient detail to enable the NRC to complete its detailed review, and this information should be included if EGC decides to resubmit the request:

• The results of a peer review of the internal events probabilistic risk assessment (PRA) that was conducted against all the supporting requirements of the PRA Standard ASME/ANS RA-Sa-2009, and Regulatory Guide 1.200, Revision 2, "An approach for Determining the Technical Adequacy of Probabili stic Risk Assessment Results for Risk-Informed Activities" (ADAMS Accession No. ML090410014), that were affected by any PRA upgrades;

• A list of the facts and observations (F&Os) from this peer review, with details of their disposition; and

• For any open or unresolved F&Os, justification for why not meeting the corresponding Capability Category I requirements has no impact on the requested licensing action. As discussed in Attachment 3, EGC recently completed an independent peer review of the QCNPS internal events PRA model, and has dispositioned the findings related to F&Os, to address the concerns listed above. Therefore, in accordance with 10 CFR 50.90, "Application for amendment of license, construction permit, or early site permit," EGC requests an amendment to Renewed Facility Operating License Nos. DPR-29 and DPR-30 for QCNPS, Units 1 and 2, respectively. The proposed change revises Technical Specifications (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 QCNPS TS 5.5.12 by replacing the reference to Regulatory Guide (RG) 1.163, "Performance-Based Containment Leak-Test Program," with a reference to 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 QCNPS 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 QCNPS-specific evaluation to assess the risk impact of the proposed change. A copy of the risk assessment is provided in . This request is subdivided as follows.

• Attachment 1 provides a description and evaluation of the proposed change.

• Attachment 2 provides a markup of the affected TS pages.

• Attachment 3 provides QC-LAR-03, "Risk Assessment for QCNPS Regarding the ILRT (Type A) Permanent Extension Request," Revision 2.

ATTACHMENT 1 Evaluation of Proposed Change Page 1 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 Specifications 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 SE Limitations and Conditions

4.0 REGULATORY EVALUATION

4.1 Applicable

Regulatory Requirements/Criteria

4.2 Precedent

4.3 No Significant Hazards Consideration

6.0 REFERENCES

ATTACHMENT 1 Evaluation of Proposed Change Page 2 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-29 and DPR-30, for Quad Cities Nuclear Power

Station (QCNPS), Units 1 and 2. The proposed change revises Technical Specifications (TS) 5.5.12, "Primary Containment Leakage Rate Testing Program," to allow the following:

• Increase the existing Type A integrated leakage rate test (ILRT) program test interval from 10 years to 15 years in accordance with Nuclear Energy Institute (NEI) Topical Report (TR) NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J," Revision 3-A (Reference 2), and the conditions and limitations specified in NEI 94-01, Revision 2-A (Reference 8). Note: This change would make permanent, a test interval extension of the Type A, Appendix J ILRT testing of QCNPS Units 1 and 2, previously approved on March 8, 2004, in License Amendments No. 220 (Unit 1) and No. 214 (Unit 2) (Reference 17).

These amendments provided a one-time TS change extending the Type A, Appendix J test interval from 10 to 15 years as applied to QCNPS, Units 1 and 2.

• Adopt an extension of the containment isolation valve (CIV) leakage rate testing (Type C) frequency from the 60 months currently permitted by 10 CFR 50, Appendix J, "Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors,"

Option B, to a 75-month frequency for Type C leakage rate testing of selected components, in accordance with NEI 94-01, Revision 3-A (Reference 2).

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

• Adopt a more conservative allowable test in terval extension of nine months, for Type A, Type B and Type C leakage rate tests in accordance with NEI 94-01, Revision 3-A (Reference 2). Specifically, the proposed change contained herein, would revise QCNPS TS 5.5.12 by replacing the reference to Regulatory Guide (RG) 1.163, "Performance-Based Containment Leak-Test Program," (Reference 1) with a reference to NEI 94-01, Revision 3-A (Reference 2),

and the limitation and conditions specified in NEI 94-01, Revision 2-A, dated October 2008 (Reference 8). These new documents will be used by QCNPS 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 QCNPS Type A tests to be performed no later than July 22, 2009, for Unit 1 and May 16, 2008, for Unit 2, as these Type A

tests have already occurred.

ATTACHMENT 1 Evaluation of Proposed Change Page 3 2.0 DETAILED DESCRIPTION QCNPS TS 5.5.12, "Primary Containment Leakage Rate Testing Program," 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 1 Type A test performed after the July 23, 1994, Type A test shall be performed no later than July 22, 2009. 2. NEI 94 1995, Section 9.2.3: The first Unit 2 Type A test performed after the May 17, 1993, Type A test shall be performed no later than May 16, 2008. The proposed changes to QCNPS 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 QCNPS Type A tests to be performed no later than July 22, 2009, for Unit 1 and May 16, 2008, for Unit 2. 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 No. 220 and No. 214 for QCNPS, Units 1 and 2, 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 conditions and limitations specified

in NEI 94-01, Revision 2-A, dated October 2008. A markup of the proposed change is provided in Attachment 2. A plant specific risk assessment conducted to support this proposed change, summarized in Section 3.4 of this enclosure, is presented in full in Attachment 3 of this LAR. This risk assessment follows the guidelines of NRC RG 1.174, Revision 2 (Reference 3) and NRC RG 1.200, Revision 2 (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 QCNPS risk profiles.

ATTACHMENT 1 Evaluation of Proposed Change Page 4

3.0 TECHNICAL EVALUATION

3.1 Description

of Primary Containment System QCNPS 1 and 2 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). Primary containment consists of a drywell, which encloses the reactor vessel, reactor coolant recirculation system, and branch lines of the reactor coolant system; a toroidal-shaped pressure suppression chamber containing a large volume of water (i.e., torus or wetwell); and a vent system connecting the drywell to the water space of the suppression chamber. 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 56 psig and for a maximum allowable internal operating pressure of 62 psig, both coincident with a maximum temperature of 281°F. The maximum allowable leakage rate for primary containment is

< 1.0 L a , where L a is defined as 3 percent of primary containment air weight per day at the design basis LOCA maximum peak containment pressure (P a) of 43.9 psig. The drywell is a steel pressure vessel with a spherical lower section, approximately 66 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 a 26 ft thick concrete fill from the spring line down. 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 115,000 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 interconnect ed 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, arranged in 48 pairs around the vent header circumference, terminating below the surface of the suppression chamber water volume.

ATTACHMENT 1 Evaluation of Proposed Change Page 5 The original design of the Mark I containment system considered postulated accident loads associated with the containment design. 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 sy stem and in-plant testing for the Mark I primary containment system, new suppression chamber hydrodynamic loads were identified. 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 QCNPS containment. The Mark I Program culminated in the issuance of the plant unique analysis report (PUAR) (Reference 21) for QCNPS followed by NRC review and acceptance (Reference 22). Primary containment, including the suppression chamber for QCNPS, Units 1 and 2, were originally designed, erected, pressure-tested, and N-stamped in accordance with the ASME Code,Section III, 1965 Edition with Addenda up to and including Winter 1965. For the Mark I Program re-evaluation, the acceptance criteria generally follow the rules contained in 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 QCNPS 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 QCNPS 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 piping lines that allow for relatively little movement are pipe sleeves that attach to the drywell. These penetrations are designed for 56 psig, but because of structural thicknesses, can withstand a substantially higher pressure. No bellows are required, since

drywell thermal expansion is minimal. 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. Each penetration seal has the same basic elements as shown in the QCNPS UFSAR Figure 3.8-39 (Reference 37).

ATTACHMENT 1 Evaluation of Proposed Change Page 6 An assembly is sized to be inserted in and welded to a 12-inch schedule 80 penetration nozzle, which were 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 Boiler and Pressure Code,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, described in Section 7.6 of the UFSAR, has five guide tubes which pass from the reactor building through the primary containment. Guide tube

penetrations of the primary containment are sealed by brazing which meets the requirements of ASME Boiler and Pressure Vessel Code,Section VIII. 3.1.4 Personnel and Equipment Access Locks Access to the drywell is provided by the drywell head, one personnel airlock, one control rod drive removal hatch, and one bolted equipment hatch. The personnel airlock has a locking mechanism on each door that is designed so that a tight seal will be maintained under either internal or external pressure. The doors are mechanically interlocked so that a door may be operated only if its companion door is closed and locked. The hatch covers are bolted in place and sealed with a double tongue-and-groove seal. The seals on the hatches 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 in tegrity 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. 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.

ATTACHMENT 1 Evaluation of Proposed Change Page 7 3.1.7 Modifications to Primary Containment Although not a modification to the primary containment, a modification to the primary containment vent piping is underway at QCNPS, Units 1 and 2. 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 event. Specifically, EA-13-109 requires that boiling water reactors (BWRs) with Mark I or Mark II containments ensure that in addition to pre-core damage venting capability, the HCVS also provides a reliable hardened venting capability from the wetwell and drywell under severe accident conditions, including those involving a breach of the reactor vessel by molten core debris. Upon installation, this modification will be tested and maintained in accordance with the Appendix J and Containment ISI Programs as applicable. 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 QCNPS UFSAR Section 6.2.1.2.4.5.2. 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 Appendix J Type C Local Leak Rate Test (LLRT) Program. 3.2 Emergency Core Cooling System Net Positive Suction Head Analysis (Post-Extended Power Uprate (EPU)) The ECCS, Residual Heat Removal (RHR), and Core Spray pump net positive suction head (NPSH) requirements are addressed in Section 6.3.3.2.9.3 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 minimum containment pressure present in the suppression chamber air space for these bounding cases and support the use of the following

credited containment pressure values (Table 3.2-1 below) used in the RHR and Core Spray NPSH analyses.

ATTACHMENT 1 Evaluation of Proposed Change Page 8 Table 3.2-1 Credited Containment Pressure From (Seconds)

To (Seconds)

Credited Containment Pressure (psig) 0 290 8.0 290 5,000 4.8 5,000 44,500 6.7 44,500 52,500 6.0 52,500 60,500 5.5 60,500 75,000 4.7 75,000 95,000 3.8 95,000 115,000 3.0 115,000 155,000 2.3 155,000 Accident End 1.8 The analysis showed sufficient containment pressure is available during the first 290 seconds to provide adequate NPSH for the RHR and Core Spray pumps; however, pump cavitation may occur for a short time after 290 seconds until operators throttle the RHR and Core Spray 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 RHR pump, which is the same model as the Core Spray 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 6.3.3.2.9.3, for credited containment pressure in the RHR and Core Spray NPSH analyses, were evaluated by the NRC and approved in the safety evaluation (SE) for Amendments 202 and 198 for Units 1 and 2, respectively (Reference 15). 3.3 Justification for the Technical Specifications 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 TS. 10 CFR 50, Appendix J also ensures that periodic surveillances of reactor containment penetrations and isolation valves are performed so that proper maintenance and repairs are made during the service life of the containment and of the systems and components penetrating primary containment. The limitation on containment leakage provides assurance that the containment would perform its design function following an accident up to and including the plant DBA. Appendix J identifies three types of required tests: (1) Type A tests, intended to measure the primary containment overall integrated leakage rate; (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 CIV leakage ATTACHMENT 1 Evaluation of Proposed Change Page 9 rates. Types B and C tests identify the vast majority of potential containment leakage paths. Type A tests identify the overall (i.e., integrated) containment leakage rate and serve to ensure continued leakage integrity of the containment structure by evaluating those structural parts of the containment not covered by Types B and C testing. In 1995, 10 CFR 50, Appendix J, was amended to provide a performance-based Option B for the containment leakage testing requirements. Option B requires that test intervals for Type A, Type B, and Type C testing be determined by using a performance-based approach.

Performance-based test intervals are based on consideration of the operating history of the component and resulting risk from its failure. The use of the term "performance-based" in 10 CFR 50, Appendix J, refers to both the performance history necessary to extend test intervals as well as to the criteria necessary to meet the requirements of Option B. Also in 1995, RG 1.163 (Reference 1) was issued. The RG endorsed NEI 94-01, Revision 0, (Reference 5) with certain modifications and additions. Option B, in concert with RG 1.163 and NEI 94-01, Revision 0, allows licensees with a satisfactory ILRT performance history (i.e., two consecutive, successful Type A tests) to reduce the test frequency for the containment Type A ILRT test from three tests in 10 years to one test in 10 years. This relaxation was based on an NRC risk assessment contained in NUREG-1493, (Reference 6) and Electric Power Research Institute (EPRI) TR-104285 (Reference 7), both of which showed that the risk increase associated with extending the ILRT surveillance interval was very small. In addition to the 10-year ILRT interval, provisions for extending the test interval an additional 15 months were considered in the establishment of the intervals allowed by RG 1.163 and NEI 94-01, but that this extension of interval "should be used only in cases where refueling schedules have been changed to accommodate other factors." In 2008, NEI 94-01, Revision 2-A (Reference 8), was issued. This document describes an acceptable approach for implementing the optional performance-based requirements of Option B to 10 CFR 50, Appendix J, subject to the limitations and conditions noted in Section 4.0 of the NRC SE on NEI 94-01. NEI 94-01, Revision 2-A, includes provisions for extending Type A ILRT intervals to up to 15 years and incorporates the regulatory positions stated in RG 1.163 (Reference 1). 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. In 2012, NEI 94-01, Revision 3-A (Reference 2), was issued. This document describes an acceptable approach for implementing the optional performance-based requirements of Option B to 10 CFR 50, Appendix J and includes provisions for extending Type A ILRT intervals to up to 15 years. NEI 94-01 has been endorsed by RG 1.163 and NRC SEs of June 25, 2008 (Reference 9), and June 8, 2012 (Reference 10), as an acceptable methodology for complying with the provisions of Option B in 10 CFR 50, Appendix J. The regulatory positions stated in RG 1.163 as modified by References 9 and 10 are incorporated in 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 licensee's allowable adm inistrative limits. Intervals may be increased from 30 months up to a maximum of 120 months for Type B tests, except for containment ATTACHMENT 1 Evaluation of Proposed Change Page 10 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 SE 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 prov isions 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 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 SE 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.

ATTACHMENT 1 Evaluation of Proposed Change Page 11 3.3.2 Current QCNPS ILRT Requirements 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 amendments 169 and 165 for QCNPS Units 1 and 2, respectively, authorizing the implementation of 10 CFR 50, Appendix J, Option B for Types A, B and C tests (Reference 13). In the implementation of Option B, the SE noted that QCNPS differed with the model TS developed by the NRC in cooperation with NEI, on one item. QCNPS 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 licensee's proposed changes implementing Option B of Appendix J are acceptable." (Reference 13) Option B states that specific existing exemptions to Option A are still applicable unless specifically revoked by the NRC. QCNPS currently has approved exemptions to 10 CFR 50, Appendix J that were issued by the NRC on June 12, 1984 (Reference 41). These exemptions, which focus on testing methodology aspects of Appendix J, are unaffected by the change to the Option B testing frequency requirements. These exemptions are also unaffected by the proposed change to the ILRT testing frequency. 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 (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 1.0 L a. 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 from the original three tests per 10 years to one test per 20 years was found to ATTACHMENT 1 Evaluation of Proposed Change Page 12 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 QCNPS 10 CFR 50, Appendix J, Option B Licensing History SE dated January 11, 1996 (ML021160123) The NRC approved amendments 169 and 165 for QC NPS Units 1 and 2, respectively, on January 11, 1996 (Reference 13). The amendm ent authorized the implementation of 10 CFR 50, Appendix J, Option B for Types A, B and C tests.

SE dated December 21, 1999 (ML993630259) The NRC issued amendments 192 and 188 for QCNPS Units 1 and 2, respectively, on December 21, 1999 (Reference 14). The amendments changed TS 3/4.7.D and the associated Bases to eliminate the individual leakage limits for each main steam isolation valve (MSIV). The removed limits were replaced with a total limit for all four main steam lines combined. The current leakage limit is 11.5 standard cubic feet per hour (scfh) per valve. The amendments changed the limit to 46 scfh for all four main steam lines combined. The value chosen for the new total limit is equivalent to the sum of the current individual limits.

SE dated December 21, 2001 (ML013540222) The NRC issued amendments 202 and 198 for QCNPS Units 1 and 2, respectively, on December 21, 2001 (Reference 15). The amendments allowed an increase in the maximum authorized operating power level from original rated thermal power (ORTP) of 2511 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 amendments with consideration to containment are:

(1) decreasing P a, from the pre-EPU peak calculated primary containment internal pressure from a DBA resulting in a P a of 48.0 psig to post-EPU DBA P a of 43.9 psig (SE, Section 4.1.1.3); and (2) containment overpressure is credited for pressure effects on NPSH for the RHR and Core Spray pumps (SE, Section 4.2.5) (See also Section 3.2 of this LAR). SE dated October 10, 2003 (ML032740364) The NRC issued amendments 218 and 212 for QCNPS Units 1 and 2, respectively, on October 10, 2003 (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 ATTACHMENT 1 Evaluation of Proposed Change Page 13 10 years. The Frequency of SR 3.6.1.3.8 is in accordance with the Surveillance Frequency Control Program, which currently requires performance of SR 3.6.1.3.8 on a 24-month

frequency. SE dated March 8, 2004 (ML040280368) The NRC issued amendments 220 and 214 for QCNPS Units 1 and 2, respectively, on March 8, 2004 (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 1 Type A test performed after the July 23, 1994, Type A test shall be performed no later than July 22, 2009; and 2. NEI 94-01-1995, Section 9.2.3: The first Unit 2 Type A test performed after the May 17, 1993, Type A test shall be performed no later than May 16, 2008. Note: The LLRTs (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. Safety Evaluation Report (SER) dated October 28, 2004 (ML042960560) The NRC issued SER (NUREG-1796) related to the License Renewal of QCNPS, Units 1 and 2 on October 28, 2004 (Reference 18). This renewed license approves extended operation for both units until December 13, 2032. Per 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 AMR, as

required by 10 CFR 54.21(a)(1)." Additionally from UFSAR Appendix A, 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). UFSAR 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 (ML062070290) The NRC issued amendments 233 and 229 for QCNPS Units 1 and 2, respectively, on September 11, 2006 (Reference 40). 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 10 CFR 50.67, "Accident source term." Applicable parts of these amendments pertaining to containment and this LAR are: (1) a change to the maximum allowable containment leak rate from 1 percent primary containment air weight per day to 3 percent primary containment air ATTACHMENT 1 Evaluation of Proposed Change Page 14 weight per day (Section 3.3.6 of the SE), and (2) a change to the allowable leak rate limits for the MSIVs from 11.5 scfh individual/46 scfh combined to a new limit of 34 scfh individual/86 scfh combined (Section 3.3.7 of the SE). 3.3.4 QCNPS ILRT History As noted previously, the QCNPS TS 5.5.12 currently requires Types A, B, and C testing in accordance with RG 1.163, which endorses the methodology for complying with 10 CFR 50, Appendix J, Option B. Since the adoption of Option B, the performance leakage rates are calculated in accordance with NEI 94-01, Section 9.1.1 for Type A testing. Table 3.3-1 lists the past periodic Type A ILRT results for QCNPS, Units 1 and 2.

Table 3.3-1 QCNPS Units 1 and 2 Type A ILRT Test History Unit Test Date 1 Leakage 95% Upper Confidence Limit (wt%/Day) 2 Total Leakage As Found (wt%/Day) 3 Total Leakage As Left (wt%/Day) 4 Acceptance Limit As Found/As Left (L a) 1 March 22-23, 1986 0.2975 Note 9 Note 9 1.0/0.75 1 1 September 14, 1987 5 December 5-6, 1987 2.13 0.3508 - 1.0591 10 - 0.4745 1.0/0.75 1.0/0.75 1 November 14-15, 1989 0.4480 5.412 11 0.5411 1.0/0.75 1 Feb 28-Mar 2, 1991 0.6069 0.9185 12 0.6853 1.0/0.75 1 December 5-8, 1992 0.2944 0.6926 13 0.4015 1.0/0.75 1 July 23-24, 1994 0.3382 0.6168 14 0.4082 1.0/0.75 1 May 18-19, 2009 0.6462 1.1419 0.9801 3.0/2.25 6 2 May 26-28, 1985 0.4092 1.032 15 0.549 1.0/0.75 2 October 12-13, 1986 7 October 14-15, 1986 0.9480 0.3618 1.2351 0.7614 - 0.4743 1.0/0.75 1.0/0.75 2 June 12-13, 1988 0.4621 3.497 16 0.5409 1.0/0.75 2 April 27-28, 1990 0.4452 Notes 8,9 and 17 0.5330 1.0/0.75 2 April 1-6, 1992 0.2458 0.5555 0.3412 1.0/0.75 2 May 17-19, 1993 0.5064 0.7359 18 0.6269 1.0/0.75 2 March 23, 2008 0.387 0.5992 0.5632 3.0/2.25 6

ATTACHMENT 1 Evaluation of Proposed Change Page 15 Note 1: ILRT As Found test leakage value determined by end of test unadjusted 95% upper confidence limit. No Type B and C penalties or level change penalties were assigned or included in this leak rate test value. Note 2: ILRT As Found leak rate test data contains 95% upper confidence limit and all penalties assigned including leakage value adjustments from Type B and C component repairs performed prior to ILRT test and level changes during ILRT

test. Note 3: ILRT As Left leak rate test data containing 95% upper confidence limit and all adjusted penalties (e.g., level changes and isolated volumes). Note 4: The maximum primary containment leakage rate was 1.0 L a for As Found ILRT testing and 0.75 L a for As Left testing for startup. L a was initially 1 percent of primary containment air weight per day, and was later revised to 3 percent of primary containment air weight per day (See Section 3.3.3 of this LAR for further description). Current TS leakage rate acceptance criteria as discussed in TS 5.5.12 for a Type A test for unit startup is 0.75 L a (i.e., 2.25 percent containment air weight per day). Note 5: ILRT performed at the beginning of September 1987 Unit 1 outage resulted in As Found ILRT failure. (LER 87-019 written). Follow-up ILRT performed at the end of the refueling passed leakage criteria. Note 6: Allowable leakage criteria was changed from 1.0 L a to 3.0 L a (See Section 3.3.3 of this LAR SE dated September 11, 2006 for further description) Note 7: ILRT performed on October 11-13, 1986 Unit 2 outage resulted in As Found ILRT failure. (LER 86-015 written). Drywell head gasket replaced and ILRT retested on October 14-15, 1986, and passed leakage criteria. Note 8: As Found value was excessive Type C LLRT leakage. Some components when LLRT tested had an As Found leakage value beyond test equipment capability.

Since As Found leakage was excessive, no comparative information can be provided for Noted item in Table. Note 9: ILRT Test Data package does not provide this value or sufficient data to determine comparative information for the Table when considering As found and/or As left ILRT test results. Note 10: Unit 1 LER 1987-016 written on excessive LLRT Leakage. Note 11: Unit 1 LER 1989-014 written on excessive LLRT Leakage.

Note 12: Unit 1 LER 1990-029 written on excessive LLRT Leakage.

Note 13: Unit 1 LER 1992-020 written on excessive LLRT Leakage.

Note 14: Unit 1 LER 1994-005 written on excessive LLRT Leakage. Note 15: Unit 2 LERs 1985-006 and 1985-007 written on excessive LLRT Leakage. Note 16: Unit 2 LER 1988-007 written on excessive LLRT Leakage.

Note 17: Unit 2 LER 1990-003 written on excessive LLRT Leakage.

Note 18: Unit 2 LER 1993-007 written on excessive LLRT Leakage.

ATTACHMENT 1 Evaluation of Proposed Change Page 16 Summary of ILRT Data History Table 3.3-1 presents the history of ILRT testing performed on each unit for approximately the past 30 years of operation at QCNPS. The third column of the Table identified as Leakage 95% Upper Confidence Limit (UCL) is test data without adjustments from any required penalties. This data indicates that the containment vessel performance, outside of the ILRT As Found failures in Unit 1 in 1987 and Unit 2 in 1986, has passed containment leakage acceptance criteria. The Unit 1 ILRT As Found cause of failure was not conclusively identified (LER 87-019). The Unit 2 ILRT As Found cause of failure determined a major source of leakage was a leaking drywell head gasket seal (LER 86-015). Shown in the fourth column of the Table, identified as Total Leakage As Found, are adjustments made to the UCL leakage based on Type B and C LLRT testing which resulted in a significant increase in the ILRT As Found leakage values. This increase is due to the poor performance of Type B and C tested components resulting in penalties adjusted against the As Found ILRT test results (LERs Noted). In the early 1990s, QCNPS took aggressive maintenance action to successively bring the sealing performance of LLRT test program components under control resulting in significantly lower As Found leakage from the troublesome components. 3.3.5 Drywell Bypass Leakage Rate Test The leak tightness of the drywell is periodically verified by performance of the Drywell Bypass Leakage Rate Test (DBLRT). This test assists in the ongoing activities to monitor primary containment integrity by ensuring that the measured drywell bypass leakage is bounded by the safety analysis assumptions. The drywell integrity is further verified by a number of additional tests, including drywell airlock door seal leakage tests, overall drywell airlock leakage tests, drywell isolation valve tests and periodic visual inspections of exposed accessible interior and exterior drywell surfaces. The DBLRT surveillance frequency and scheduling of TS SR 3.6.1.1.2 is controlled under the Surveillance Frequency Control Program (SFCP). As defined in QCNPS TS 5.5.14, "Surveillance Frequency Control Program," changes to the DBLRT frequency listed in the SCFP shall be made in accordance with NEI 04-10, "Risk-Informed Method for control of Surveillance

Frequencies," Revision 1. 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 QCNPS 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 (Reference 2), (2) the methodology outlined in EPRI TR-104285 (Reference 7) as updated by the EPRI Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals (EPRI TR-1018243) (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 plant's licensing basis as outlined in RG 1.174 (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 (Reference 32). The ATTACHMENT 1 Evaluation of Proposed Change Page 17 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 (Reference 11). Details of the QCNPS Units 1 and 2 risk assessment, providing an assessment of the risk associated with implementing a permanent extension of the QCNPS containment Type A ILRT interval from ten years to fifteen y ears, are contained in Attachment 3. The NRC report on performance-based leak testing, NUREG-1493 (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 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 1 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 QCNPS. The current analysis is being performed to confirm these conclusions based on QCNPS specific PRA models and available data. Earlier ILRT frequency extension submittals have used the EPRI TR-104285 (Reference 7) methodology to perform the risk assessment. In October 2008, EPRI 1018243 (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 (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 QCNPS Unit 1 and Unit 2 employs the EPRI 1018243 methodology, with the affected system, structure, or component (SSC) being the primary containment boundary. In the SE issued by NRC letter dated June 25, 2008 (Reference 9), the NRC concluded that the methodology in EPRI TR-1009325, Revision 2, was acceptable for referencing by licensees proposing to amend their TS to permanently extend the ILRT surveillance interval to 15 years, subject to the limitations and conditions noted in Section 4.0 of the SE. Table 3.4-1 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 EPRI Report No. 1009325 Revision 2 Limitations and Conditions Limitation and Condition (From Section 4.2 of SE) QCNPS Response 1. The licensee submits documentation indicating that the technical adequacy of their PRA is consistent with the

requirements of RG 1.200 relevant to the ILRT extension application. QCNPS PRA technical adequacy is addressed in Section 3.4.2 of this LAR and Attachment 3, "Risk Assessment for QCNPS

Regarding the ILRT (Type A) Permanent

Extension Request," Appendix A, "PRA Technical Adequacy."

ATTACHMENT 1 Evaluation of Proposed Change Page 18 Table 3.4-1 EPRI Report No. 1009325 Revision 2 Limitations and Conditions Limitation and Condition (From Section 4.2 of SE) QCNPS Response 2.a The licensee submits documentation indicating that the estimated risk increase associated with permanently extending the ILRT surveillance interval to 15 years is small, and consistent with the clarification provided in Section 3.2.4.5 of this SE. Since the ILRT extension has negligible

impact on core damage frequency (CDF), the relevant criterion is LERF. The increase in internal events LERF resulting from a change in the Type A ILRT interval for the base case with corrosion included is 3.0E-08/yr, which falls within the "very small" change region of the acceptance guidelines

in RG 1.174.

If the EPRI Expert Elicitation methodology is used, the change is estimated as 6.56E-09/yr, which falls further within the very small change region of the acceptance guidelines in RG 1.174. 2.b Specifically, a small increase in population dose should be defined as an increase in population dose of less than or equal to either 1.0 person-rem per year or 1% of the total population dose, whichever is less restrictive. 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 QCNPS, is 1.0E-02 person-rem/yr (0.31%) using the EPRI guidance with the base case corrosion included.

The change in dose risk drops to 2.7E-03 person-rem/yr (0.08%) when using the EPRI Expert Elicitation methodology. The change in dose risk meets both of the related acceptance criteria for change in population dose of less than 1.0 person-rem/yr or less than 1% person-rem/yr. 2.c In addition, a small increase in CCFP should be defined as a value marginally greater than that accepted in a previous one-time 15-year ILRT extension requests. This would require that the increase in CCFP be less than or equal to

1.5 percentage

point.

The increase in CCFP from the three in ten-year interval to one in fifteen years including corrosion effects using the EPRI guidance is 1.0%. This value drops to about 0.22% using the EPRI Expert Elicitation methodology. Both of these values are below the acceptance criteria of less than

1.5%.

ATTACHMENT 1 Evaluation of Proposed Change Page 19 Table 3.4-1 EPRI Report No. 1009325 Revision 2 Limitations and Conditions Limitation and Condition (From Section 4.2 of SE) QCNPS Response 3. The methodology in EPRI Report No. 1009325, Revision 2, is acceptable except for the calculation of the increase in expected population dose (per year of reactor operation). In order to make the

methodology acceptable, the average leak rate accident case (accident case 3b) used by the licensees shall be 100 L a instead of 35 L

a. The representative containment leakage for Class 3b sequences used by QCNPS is 100 L a, based on the recommendations in the latest EPRI report (Reference 20) and as recommended in the NRC SE on this topic (Reference 9). It should be noted that this is more conservative than the earlier previous industry ILRT extension requests, which utilized 35 L a for the Class 3b sequences. 4. A licensee amendment request (LAR) is required in instances where containment over-pressure is relied upon for ECCS

performance. QCNPS relies upon containment over-pressure for ECCS performance. See Section 3.2 of this LAR Attachment for

details. The RHR and Core Spray NPSH

analyses were evaluated by the NRC and approved in the SE for Amendments 202 and 198 for Units 1 and 2, respectively. 3.4.2 Technical Adequacy of the PRA The PRA Technical Adequacy evaluation is presented in Attachment 3, Appendix A, "PRA Technical Adequacy." 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 (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:

• 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.

• Document peer review findings and observations (F&Os) 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.

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

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

ATTACHMENT 1 Evaluation of Proposed Change Page 20 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 2014A version of the QCNPS PRA model is the most recent evaluation of the Unit 1 and Unit 2 risk profile at QCNPS for internal event challenges. The QCNPS 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 QCNPS 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 QCNPS 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 plant. This process is defined in the EGC 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 EGC nuclear generation sites. The overall EGC 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- EGC PRA model update tracking database) is created for all issues that are identified that could impact the PRA model. The URE database includes the identification of those plant changes that could impact the PRA model. A review of the open UREs indicates that there are no plant changes that have not yet been incorporated into the PRA model that would affect this application. FLEX modifications are in progress and will be incorporated in the QCNPS PRA in the future. The FLEX strategy will reduce CDF and is expected to lead to a reduction in the risk associated with the proposed ILRT extension. At this time, there is insufficient information to quantify the impact to this application, but the omission of FLEX credit in the model should in general result in added conservatism to the ILRT results.

ATTACHMENT 1 Evaluation of Proposed Change Page 21 3.4.2.5 Consistency with Applicable PRA Standards Several assessments of technical capability have been made for the QCNPS internal events PRA models. These assessments are as follows and are further discussed in the paragraphs below.

• An independent PRA peer review (Reference 31) was conducted under the auspices of the BWR Owners' Group (BWROG) in 2000, following the Industry PRA Peer Review process (References 33 and 23). This peer review included an assessment of the PRA model maintenance and update process.

• In 2004, a gap analysis was performed to assess gaps between the peer review scope/detail of the Industry PRA Peer Review results relative to the available version of the ASME PRA Standard (Reference 29) and the draft version of RG 1.200, DG-1122 (Reference 4).

• During 2005 and 2006, the QCNPS PRA model results were evaluated in the BWROG PRA cross-comparisons study performed in s upport of implementation of the mitigating system performance index (MSPI) process (Reference 34).

• In January 2010, a self-assessment analysis was performed against the available version of the ASME/ANS PRA Standard (Reference 30) in preparation for the QCNPS 2010 PRA periodic update.

• In May 2010, an independent Focused PRA Peer Review (Reference 35) of the QCNPS Internal Flooding PRA model was performed using the NEI 05-04 process (Reference 46), the ASME/ANS PRA Standard (Reference 30), and RG 1.200, Rev. 2 (Reference 4).

• The QC 2010 self-assessment (Reference 36) was updated to incorporate the results of the final Focused PRA Peer Review report of the Internal Flooding PRA model.

• Following the most recent 2014 PRA update, another self-assessment (Reference 38) was performed to reflect the status after the 2014A model. This self-assessment was performed against the ASME/ANS PRA Standard (Reference 30), and RG 1.200, Rev. 2 (Reference 4).

• In February 2017, an independent PRA peer review (Reference 47) of the QCNPS Internal Events PRA model was performed using the NEI 05-04 Rev. 2 (Reference 46) process, the ASME PRA Standard (Reference 30), and RG 1.200, Rev. 2 (Reference 4).

The peer review included all SRs except those related to internal flooding (which was previously peer reviewed in 2010). In addition, four SRs were assessed as not applicable to the QCNPS PRA. The results of that assessment are used as the basis for the capability assessment provided in Table A-2 of Attachment 3. With the 2010 IF and 2017 peer reviews, all elements of the QCNPS PRA have undergone a thorough PRA peer review. The results of the most recent 2017 PRA peer review are as

follows:

ATTACHMENT 1 Evaluation of Proposed Change Page 22 SR Capability - 92% of the 259 applicable SRs are graded at Capability Category II or greater - 3% of the SRs are graded at Capability Category I - 5% of the SRs are graded as "Not Met" Findings and Observations There were 34 Findings. Table A-2 of Attachment 3, Section A.2.5 provides an assessment of each finding to the ILRT application. 3.4.2.6 Applicability of Peer Review Findings and Observations Per the NRC SE for NEI 94-01, Revision 2 (Reference 9), the appropriate PRA quality to support an ILRT risk assessment is that the PRA Standard Supporting Requirements should meet Capability Category I or greater. There are 316 Technical Supporting Requirements plus

10 Maintenance and Update Supporting Requirements in the full power internal events (FPIE) portion of the ASME/ANS PRA Standard (Reference 30). The 2010 Focused PRA Peer Review resulted in three findings, 10 suggestions and one best practice. Three supporting requirements were not met:

• IFSO-A3, IFSN-A7, and IFQU-A3Table A-1 of Attachment 3 describes the findings associated with these SRs. The findings have been resolved and the findings have no impact to this application. Per the 2017 QCNPS PRA peer review, there are 13 SRs that are not met:

• IE-C2, IE-C11, IE-C12, IE-D2, SY-A4, HR-G6 , HR-G7, DA-C3, DA-C4, QU-B3, QU-C1,QU-E2, and QU-E4The 2017 QCNPS PRA peer review identified seven SRs that are met at Capability Category I only: *IE-B3, HR-D2, DA-D1, DA-D4, LE-C10, LE-C11, and LE-C12 The 2017 peer review findings are listed in Table A-2 of Attachment 3. The SRs as sociated with these findings are cross-referenced to the applicable findings within Table A-2. The 2017 peer review did not include a review of internal flooding SRs as this was performed in the 2010 Internal Flood focused peer review. The 2017 findings have not yet been resolved, but the potential impact upon the ILRT risk application results are assessed, as documented in Table A-2. No single finding was found to have a significant change to CDF if a model change was performed to address the finding. A number of finding resolutions will cause a small reduction in CDF. None of these findings are found to impact the conclusion of the ILRT risk application results. The cumulative impact of addressing all findings is judged to be minor and likely to red uce CDF.

ATTACHMENT 1 Evaluation of Proposed Change Page 23 3.4.2.7 External Events Although EPRI report 1018243 (Reference 11) recommends a quantitative assessment of the contribution of external events (for example, 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, Risk Impact Assessment, Section 5.7, "External Events Contribution." 3.4.2.8 PRA Quality Summary Based on the above, the QCNPS Units 1 and 2 PRA is of sufficient quality and scope for this application. The modeling is detailed; including a comprehensive set of initiating events (transients, LOCAs, and support system failures) including internal flood, system modeling, human reliability analysis and common cause evaluations. The QCNPS 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 (Reference 20) 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 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 QCNPS Unit 1 and Unit 2 to fifteen years satisfies the risk acceptance guidelines in RG 1.174. 3.4.3 Summary of Plant-Specific Risk Assessment Results The findings of the QCNPS, Unit 1 and 2 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 ten years to one in 15 years is small.

ATTACHMENT 1 Evaluation of Proposed Change Page 24 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:

• 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 QCNPS, 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 3.0E-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 6.6E-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.

• The change in dose risk for changing the Type A test frequency 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 QCNPS, is 1.0E-02 person-rem/yr (0.31%) 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 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 2.7E-3 person-rem/yr (0.08%) (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 1.0 person-rem/yr or less than 1% person-rem/yr identified in Attachment 3 of this LAR, Section 1.3.

• 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 1.0% (Attachment 3, Section 5.5), which is below the acceptance criteria of 1.5% identified in Attachment 3 of this LAR, Section 1.3.

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

• 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 5.7-6, the total increase in LERF due to internal events and the bounding external events assessment is 4.7E-07/yr. This value is in Region II of the RG 1.174 acceptance guidelines ("small" change in risk). The changes in dose risk ATTACHMENT 1 Evaluation of Proposed Change Page 25 and conditional containment failure frequency also remained below the acceptance criteria.

• 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 4.2E-06/yr, which is less than the RG 1.174 limit of 1.0E-05/yr given that the LERF is in Region II ("small" change in risk).

• 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 QCNPS. Therefore, 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 QCNPS risk profiles. 3.4.4 Previous Assessments The NRC in NUREG-1493 (Reference 6) has previously concluded that:

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

• Given the insensitivity of risk to containment leakage rate and the small fraction of leakage paths detected solely by Type A testing, increasing the interval between integrated leakage-rate tests is possible with minimal impact on public risk. The impact of relaxing the ILRT frequency beyond one in 20 years has not been evaluated. Beyond testing the performance of containment penetrations, ILRTs also test the integrity of the containment structure. The findings for QCNPS confirm these general findings on a plant specific basis for the ILRT interval extension considering the severe accidents evaluated for QCNPS, the QCNPS containment failure modes, and the local population surrounding QCNPS. Details of the QCNPS, Units 1 and 2, 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, QCNPS has assessed other non-risk based considerations relevant to the proposed amendment. QCNPS 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.

ATTACHMENT 1 Evaluation of Proposed Change Page 26 3.5.1 Safety-Related Coatings Inspection Program QCNPS has committed to follow RG 1.54, "Quality Assurance Requirements for Protective Coatings Applied to Water-Cooled Nuclear Power Plants," Revision 0. The RG describes a method to comply with requirements of Appendix B to 10 CFR 50, 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." QCNPS 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 (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 (submerged areas and vapor phase areas) and

the drywell. Primary Containment Interior Surface Coating Inspections are performed in the following areas: drywell liner interior surfaces, biological shield visible surfaces, subpile room surfaces, drywell head interior surface and the suppression chamber interior surface (including water line region and above). The submerged regions of the suppression chamber have been routinely inspected in accordance with site and approved vendor procedures, and coating repairs have been

proactively managed. Table 3.5-1 provides results from coating inspections that have been performed on QCNPS Units 1 and 2, during the second CISI Interval for the past 3 refueling outages. The Table lists for each Unit's outage, the coating inspection results for both the Torus Underwater and the Primary Containment Interior Surface Coating inspections.

ATTACHMENT 1 Evaluation of Proposed Change Page 27 Table 3.5-1 QCNPS Units 1 and 2 Coating Inspection Results Refuel& Date Type of Inspection Coating Inspection Results Unit 1 Unit 1 Q1R21 May 2011 Torus Underwater Ref Document:

02-07-205.661, WO 01255482-02 100% of submerged shell inspected, desludged, 24 coating deficiencies found, no metal loss greater than 60 mil threshold (Reference 45), all repaired with Bio-Dur 561

Conclusion:

Although small localized random failures (less than 1% of the total surface area) have occurred primarily due to fractured blisters and delaminations resulting in random spot corrosion and pitting, the balance of the coating is currently providing adequate protection of the substrate.

Unit 1 Q1R21 May 2011 Coating Evaluation Ref Document: Williams Specialty Services Report, May 9, 2011 WO 01255481-01,

-02, -03, & -04.

Conclusion:

Overall the Coating Systems throughout Unit 1 are showing wear relative to the age of the Plant. Generally speaking the Coating Systems are in GOOD condition. There are no imminent coating concerns that would negatively affect the safe shutdown or startup of the Plant. - Some areas repaired immediately and some are listed as recommendations for repairs. WO 01282915-01 repaired in Q1R21. WO's generated for resolving and tracking into Q1R22: 1478888, 1478890, 1478892, 1478893, 1478894, 1478883, 1468884, 1478886, 1478894 and 1478887.

Unit 1 Q1R22 March 2013 Torus Underwater Ref Document: 02-07-205.789, WO 01492232-02 100% of submerged shell inspected, desludged, 60 coating deficiencies found, no metal loss greater than 60 mil threshold, all repaired with Bio-Dur 561

==

Conclusion:==

Although random localized failures (less than 1% of the total surface area) have occurred, primarily due to fractured blisters and random spot pitting, the balance of the coating is currently providing adequate protection of the substrate.

Unit 1 Q1R22 March 2013 Coating Evaluation Ref Document: Williams Specialty Services Report, March 11, 2013

==

Conclusion:==

Overall, the Coating Systems througho ut Unit 1 are in GOOD condition. Areas of concern have been identified in this and the previous Assessment Report. - Some areas were repaired immediately and some areas are listed as recommendations for repairs. Note: Q1R23 report discusses areas identified in previous coatings evaluation were repaired.

Unit 1 Q1R23 March 2015 Torus Underwater Ref Document: 02-14-233.75, WO 01649090-01 WO 01635232-02 100% of submerged shell inspected, desludged, 88 coating deficiencies found, no metal loss greater than 60 mil threshold, all repaired with Bio-Dur 561 -

Conclusion:

Although random localized small failures (less than 1% of the total surface area) have occurred, primarily due to random spot corrosion, the balance of the coating is currently providing adequate protection of the substrate and previously applied coating repairs are performing well.

Unit 1 Q1R23 March 2015 Coating Evaluation Ref Document: NUC2014435.04 Areas identified in previous coatings evaluation were repaired.

Conclusion:

The Q1R23 coating assessment identified areas of degraded coating requiring repair. No current coating conditions were identified that appear to affect structural integrity, plant operations, or the safe shutdown of the plant. - Some areas repaired immediately with remaining areas work orders written to address repair. (7 work orders for repair in Q1R24, they are: WO 01836118 thru WO 01836124)

ATTACHMENT 1 Evaluation of Proposed Change Page 28 Table 3.5-1 QCNPS Units 1 and 2 Coating Inspection Results Refuel& Date Type of Inspection Coating Inspection Results Unit 2 Unit 2 Q2R21 March 2012 Torus Underwater Ref Document: 02-07-205.722, WO 01333466-02 100% of submerged shell inspected, desludged, 1708 coating deficiencies found, no metal loss greater than 60 mil threshold, all repaired with Bio-Dur 561

Conclusion:

Although small localized random failures (less than 1% of the total surface area) have occurred primarily due to zinc depletion of Carbo Zinc 11 SG spot repairs resulting in random spot corrosion and pitting, the balance of the coating is currently providing adequate protection of the substrate.

Unit 2 Q2R21 March 2012 Coating Evaluation Ref Document: Williams Specialty Services report, March 19, 2012 WO 01336189-01, 02, -03, & -04.

Conclusion:

There are no immediate coating concerns that would impede the safe operation, start up or shut down of the plant. Some areas repaired immediately and some are listed as recommendations for repairs. WO's written for tracking into Q2R22:

1544425, 1538829-01, 1538829-02, 1538829-03, 1538829-04, 01549120-01, 01549120-02, 1574656, 1574637, 1574638, 1574655, 1574639, 1574654, 1574640, 1574641, 1574652, 1574653 Unit 2 Q2R22 April 2014 Torus Underwater Ref Document:

02-14-233.3, WO 01549120-01 & -022 100% of submerged shell inspected, desludged, 1675 coating deficiencies found, no metal loss greater than 60 mil threshold, all deficiencies repaired with Bio-Dur 561

Conclusion:

Although small localized random failures (less than 1% of the total surface area) have occurred primarily due to zinc depletion of Carbo Zinc 11 SG spot repairs resulting in random spot corrosion and pitting, the balance of the coating is currently providing adequate protection of the substrate.

Unit 2 Q2R22 April 7, 2014 Coating Evaluation Ref Document: Williams Specialty Services report, April 7, 2014 WO 1538829-01, -02, -03, -04 Summary: There are no imminent coating concerns that would impede or prevent the safe operation, shutdown or startup of the Plant. WOs generated for resolving and tracking into Q2R23: 1751889-01, 1751890-01, 1751891-01, 1751893-01, 1751894-01, 1751895-01, 1751897-01, 1751896-01 and 175898-01 Unit 2 Q2R23 March 2016 Torus Underwater Ref Document: 02-14-233.145, WO 1750163-02 100% of submerged shell inspected, desludged, 1807 coating deficiencies found, no metal loss greater than 60-mil threshold, all deficiencies repaired with Bio-Dur 561

Conclusion:

Although random localized small failures (less than 1% of the total surface area) have occurred primarily due to random spot corrosion, the balance of the coating is currently providing adequate protection of the substrate.

ATTACHMENT 1 Evaluation of Proposed Change Page 29 Table 3.5-1 QCNPS Units 1 and 2 Coating Inspection Results Refuel& Date Type of Inspection Coating Inspection Results Unit 2 Q2R23 March 2016 Coating Evaluation Ref Document: NUC2016104 WO 01732678-01, -02, -03 & -04 Underwater Engineering Services, Inc. April 2016 All elevations of the Drywell Liner Plate, Drywell Head Interior, Torus Vapor Phase and Vent Header Interior were inspected to identify degraded coatings. Areas identified in previous coatings evaluations were repaired in accordance with UESI approved procedure and EGC specifications.

Conclusion:

The Q1R23 coating assessment identified areas of degraded coating requiring repair. No current coating conditions were identified that appear to affect structural integrity, plant operations, or the safe shutdown of the plant. There is considerable amount of mechanical damage to the liner plate coating due to scaffolding poles and insulation hitting the liner during outages. These areas are being continually repaired. WOs previously written for surface preparation and coating repair were 1751889-01, 1751890-01, 1751891-01, 1751893-01, 1751894-01, 1751895-01, 1751896-01, 1751897-01, 175898-01, 01751900-01, 01751901-01, 01751903-01, 01751904-01.

3.5.2 Containment

Inservice Inspection 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 QCNPS, Units 1, 2, and Common (1/2). Unit Common components are included in the Unit 1 sections, reports, and tables. The ISI Program Plan also includes Containment Inservice Inspection (CISI), Risk-Informed Inservice Inspections (RISI), Augmented Inservice Inspections (AUG), and System Pressure Testing (SPT) requirements imposed on or committed

to by QCNPS. 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 American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code,Section XI ISI Program. The QCNPS, Units 1 and 2 are currently in the fifth ISI interval, which commenced on April 2, 2013, and ends on April 1, 2023. Additionally, QCNPS, Units 1 and 2 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 QCNPS 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 QCNPS 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 augmented examination areas, component accessibility, and examination review. QCNPS 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 CISI Plan.

ATTACHMENT 1 Evaluation of Proposed Change Page 30 The second interval CISI Program Plan was developed in accordance with 10 CFR 50.55a 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 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 SEs, and utilizes Inspection Program B (described in Section XI, IWE-2412).

Table 3.5-2 10 CFR 50.55a Requirements (Applicable to Containment Inspection Program) 10 CFR 50.55a Paragraphs Limitations, Modifications, and Clarifications 10 CFR 50.55a(b)(2)(ix)(A) (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 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. 10 CFR 50.55a(b)(2)(ix)(B) (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 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. 10 CFR 50.55a(b)(2)(ix)(F) (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 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. 10 CFR 50.55a(b)(2)(ix)(G) (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-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. 10 CFR 50.55a(b)(2)(ix)(H) (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 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.

ATTACHMENT 1 Evaluation of Proposed Change Page 31 Table 3.5-2 10 CFR 50.55a Requirements (Applicable to Containment Inspection Program) 10 CFR 50.55a Paragraphs Limitations, Modifications, and Clarifications 10 CFR 50.55a(b)(2)(ix)(I) (CISI)

Examination of metal containments and the liners of concrete containments: The ultrasonic examination acceptance 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 inspection of containment structures and components are performed per 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 QCNPS units are in the second 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 3.5-3 shown below. There will be no change to the schedule for these inspections as a result of the extended ILRT interval.

ATTACHMENT 1 Evaluation of Proposed Change Page 32 Table 3.5-3 Summary of IWE Examinations on Primary Containment Unit 1 Q1R21 IWE Inspections on WO 01244920-02; May 2011 - Per Exam schedule only inspections required were those for preservice and of repair/replacement activities. Database Component No.

Item Results of Inspect Resolution None Q1R22 IWE Inspections on WO 01453925-02; March 2013 - Per Exam schedule only inspections required were those for preservice and of repair/replacement activities. Database Component No.

Item Results of Inspect Resolution None Q1R23 IWE Inspections on WO 01633313-02; March 2015 - Inspected: Containment liner, Vent Header Interior - All bays & interior surfaces, Torus Interior (normally wetted area), X-2 Hatch area under moisture barrier after removal. Two recordable indications were noted for further action, as follows: Database Component No.

Item Results of Inspect Resolution 1X-2 PALF-Moisture Barrier X-002 Floor Moisture Barrier Recordable Indication -

Moisture Barrier cracked and missing in spots IR 2463927; replaced barrier and passed reinspection in WO 01812660-01 1-1600-T Torus Bay 13 Recordable Indication - small area found with coating and primer missing inside vent header Evaluated as acceptable. Wrote AR 02471483 to repair in Q1R24.

ATTACHMENT 1 Evaluation of Proposed Change Page 33 Table 3.5-3 Summary of IWE Examinations on Primary Containment Unit 2 Q2R21 IWE Inspections on WO 01337032-01 thru -06; March 2012 - (1) Exam conducted outside of Primary Containment. Area included Reactor Building, Basement, top of torus and refuel floor where the drywell head is located after removal; (2) Exam conducted inside of the torus vent header (centipede), from torus catwalk and of torus below the waterline; (3) Exam conducted from inside of the drywell. Applicable areas include all levels of the drywell. (Basement through 4 th level). Results from all these inspections: no issues identified. Database Component No.

Item Results of Inspect Resolution None Q2R22 IWE Containment Inspections on WO 01549517-01, April 2014 - Exam conducted inside (all levels) and outside of both the drywell and the torus. Results: 17 Recordable Indications noted, 15 were characterized mostly as coating missing/surface corrosion with no metal loss and dispositioned with no action required. Two were noted for further action, they are: Database Component No Item Results of Inspect Resolution 2X-2 PALF-Moisture Barrier X-002 Floor Moisture Barrier Recordable Indication IR1647016; replaced barrier and passed reinspection 2TORLB01 -

ESURFACE Torus Shell Recordable Indication - Coating blister with water behind it, Bay 1 IR 1644607; removed blisters no metal loss, recoated Q2R23 IWE Containment Inspections on WO 01746044-02, March 2016 - Results: Exam conducted inside (all levels) and outside of both the drywell and the torus. Results: 16 Recordable Indications noted that were characterized as surface corrosion with no metal loss.

All were dispositioned with no action required. Database Component No Item Results of Inspect Resolution None 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 3.5-4 identifies the period start and end dates for the second CISI interval as defined by Inspection ISI Program Plan. Table 3.5-5 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 paragraph IWA-2430(c)(1) of ASME Section XI, 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 ATTACHMENT 1 Evaluation of Proposed Change Page 34 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.

Table 3.5-4 Units 1 and 2 Second CISI Interval/Period/Outage Matrix (For ISI Class MC Component Examinations)

Unit 1 Period Interval Period Unit 2 Outage Number Outage or Projected Start Date Start Date to End Date Start Date to End Date Start Dateto End Date Outage or Projected Start Date Outage NumberQ1R20 April 2009 1 ST 9/9/08 to 9/8/11 2 nd (Unit 1) 9/9/08 to 9/8/18 2 nd (Unit 2) 9/9/08 to 9/8/18 1 ST 9/9/08 to 9/8/11 March 2010 Q2R20 Q1R21 May 2011 2 nd 9/9/11 to 9/8/15 March 2012 Q2R21 Q1R22 March 2013 2 nd 9/9/11 to 9/8/15 April 2014 Q2R22 Q1R23 March 2015 3 rd 9/9/15 to 9/8/18 March 2016 Q2R23 Q1R24 Scheduled 3/17 3 rd 9/9/15 to 9/8/18 Scheduled 3/18 Q2R24 Table 3.5-5 Units 1 and 2 Third CISI Interval/Period/Outage Matrix (For ISI Class MC Component Examinations) (Approximate) 1 Unit 1 Period Interval Period Unit 2 Outage Number Outage or Projected Start Date Start Date to End Date Start Date to End Date Start Dateto End Date Outage or Projected Start Date Outage NumberQ1R25 Scheduled 3/19 1 ST 9/9/18 to 9/8/21 2 nd (Unit 1) 9/9/18 to 9/8/28 1 ST 9/9/18 to 9/8/21 Scheduled 3/20 Q2R25 Q1R26 Scheduled 3/21 2 nd 9/9/21 to 9/8/25 Scheduled 3/22 Q2R26 Q1R27 Scheduled 2/23 2 nd 9/9/21 to Scheduled 3/24 Q2R27 ATTACHMENT 1 Evaluation of Proposed Change Page 35 Table 3.5-5 Units 1 and 2 Third CISI Interval/Period/Outage Matrix (For ISI Class MC Component Examinations) (Approximate) 1 Unit 1 Period Interval Period Unit 2 Outage Number Outage or Projected Start Date Start Date to End Date Start Date to End Date Start Dateto End Date Outage or Projected Start Date Outage NumberQ1R28 Scheduled 2/25 9/8/25 2 n d (Unit 2) 9/9/18 to 9/8/28 3 rd 9/9/25 to 9/8/28 Scheduled 3/26 Q2R28 Q1R29 Scheduled 2/27 3 rd 9/9/25 to 9/8/28 Scheduled 3/28 Q2R29 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 The QCNPS 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 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 Units 1 and 2 in Table 3.5-6.

Table 3.5-6 Units 1 and 2 IWE Inservice Inspection Summary Examination Category (with Examination Category Description)

Item Number Description Exam RequirementsTotal Number of Components (Unit 1 includes common) Relief Request/ TAP Number Notes E-A Containment Surfaces E1.11 Containment Vessel Pressure Retaining Boundary - Accessible Surface Areas General VisualUnit 1: 295 Unit 2: 294 E1.11 Containment Vessel Pressure Retaining Boundary -

Bolted Connections, Surfaces Visual, VT-3 Unit 1: 69 Unit 2: 70 10 10 E1.12 Containment Vessel Pressure Retaining Boundary - Wetted Surfaces of Submerged Areas Visual, VT-3 Unit 1: 16 Unit 2: 16 11 11 ATTACHMENT 1 Evaluation of Proposed Change Page 36 Table 3.5-6 Units 1 and 2 IWE Inservice Inspection Summary Examination Category (with Examination Category Description)

Item Number Description Exam RequirementsTotal Number of Components (Unit 1 includes common) Relief Request/ TAP Number NotesE1.20 Containment Vessel Pressure Retaining Boundary -

BWR Vent System Accessible Surface Areas Visual, VT-3 Unit 1: 121 Unit 2: 113 11 11 E1.30 Containment Vessel Pressure Retaining Boundary -

Moisture Barriers General VisualUnit 1: 4 Unit 2: 4 E-C Containment E4.11 Containment Surface Areas - Visible Surfaces Visual, VT-1 Unit 1: 0 Unit 2: 3 12 Surfaces Requiring Augmented Examination E4.12 Containment Surface Areas - Surface Area Grid Ultrasonic Unit 1: 0 Unit 2: 0 Note 10: Bolted connections examined per 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 11: 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). Note 12: Item Number E4.11 requires VT-1 visual examination in lieu of Detailed Visual examination, as modified by 10 CFR 50.55a(b)(2)(ix)(G).

An additional monitoring of the containment liner applicable to QCNPS, was the inspections instituted at Dresden Nuclear Power Station Unit 3 of the inaccessible annulus area to ensure

that potential corrosion does not occur. As part of Plant Licensing Renewal, NUREG-1796 (Reference 18), Section 3.0, Aging Management Review, page 3-403, a description is provided of the monitoring at Dresden consisting of the inspection of a sample of locations in the cylindrical and upper spherical areas of the drywell, using ultrasonic measurements of the drywell shell thickness made from accessible areas of the drywell interior. QCNPS Units 1 and 2 as well as Dresden Unit 2 credit the inspections performed on Dresden 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 QCNPS.

ATTACHMENT 1 Evaluation of Proposed Change Page 37 3.5.2.1 Code Cases The only Code Case implemented in the QCNPS containment ISI Program is N-649, which is an EGC fleet relief request identified as I5R-13. This relief request is briefly shown on Table 3.5-7 and is further described in detail below Table 3.5-7. 3.5.2.2 Relief Requests Table 3.5-7 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. Explanation of use of Code Case N-649 in Accordance with 10 CFR 50.55a(a)(3)(i): ASME Section XI, paragraph IWE-5240, "Visual Examination," requires that a detailed visual examination (IWE-2310) be performed during an IWE-5220 required pressure test on areas affected by repair/replacement activities. ASME Code Case N-649, "Alternative Requirements for IWE-5240 Visual Examination Section XI, Division 1," allows for a VT-3, VT-1, general visual or detailed visual examination depending on the timing of the pressure test. Pursuant to 10 CFR 50.55a(a)(3)(i), relief is requested on the basis that the proposed alternative will provide an acceptable level of quality and safety. ASME Section XI, paragraph IWE-5240 requires that a detailed visual examination of repaired areas be completed during a post repair pressure test performed subsequent to IWE repairs. ILRTs required by 10 CFR 50, Appendix J, are often performed following repairs in order to fulfill the post-repair testing requirement. However, the IWE-5240 visual examination cannot be performed because the containment liners/shell are inaccessible during the post repair pressure tests (i.e., personnel are not able to be inside the containment during the ILRT). In recognition of the inability to perform visual examinations of containment liners/shells during the post repair pressure test required by paragraph IWE-5240, ASME Code Case N-649 was issued to allow the visual examination to be performed during or after the pressure test on the areas affected by the repair/replacement activity. ASME Section XI did not address this inability in the Code until the 2004 Edition through the 2006 Table 3.5-7 Second Ten-Year CISI Interval Relief Request Relief Request Revision/

Date Status (Program) Description/

Approval Summary I5R-13 EGC Fleet Relief Request 0 September 5, 2014 Authorized Examination to Utilize ASME Code Case N-649, Revision 0. Alternative Requirements for IWE-5240 Visual Examination. RG 1.147, Revision 16. Authorized April 30, 2014 ATTACHMENT 1 Evaluation of Proposed Change Page 38 Addenda was issued; therefore, ASME Code Case N-649 is needed when using the 2001 Edition through the 2003 Addenda of ASME Section XI, which is applicable to

Quad Cities Nuclear Generating Station. The "Applicability Index for Section XI Cases," states that ASME Code Case N-649 is applicable up to and including the 1998 Edition with the 2000 Addenda of ASME Section XI; however, the code of record for QCNPS CISI Program is the 2001 Edition through the 2003 Addenda thus necessitating the need for this relief request. The Edition/Addenda referenced in the Code Case text itself also ends at the 1998 Edition with the 2000 Addenda. However, the requirements of paragraph IWE-5240 are identical in both the 1998 Edition through the 2000 Addenda and the 2001 Edition through the 2003 Addenda. Therefore, it is concluded that the proposed alternative provides an acceptable level of quality and safety. The EGC Fleet relief request I5R-13, inclusive of QCNPS, requested that the applicability of ASME Code Case N-649 be extended to the 2001 Edition through 2003 Addenda for use during the station's second CISI interval. This relief request was subsequently authorized with an SE issued by the NRC on April 30, 2014. Additionally, NRC RG 1.147, Revision 16, "lnservice In spection Code Case Acceptability, ASME Section XI, Division 1," lists ASME Code Case N-649 as acceptable for use with no conditions or limitations. No technical changes are being made to the Code Case. 3.5.2.3 Identification of Class MC and/or CC Exempt Components The containment section 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. 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 no components being recommended on a programmatic basis, for the Augmented Program within Examination Category E-C, that would appear on table IWE-2500-1. A significant condition is a condition that is identified as requiring application of additional augmented examination requirements under paragraph IWE-1240. In the First CISI Interval, during the QCNPS Unit 2 Outage, Q2R19 Torus underwater IWE examinations, recordable indications were identif ied on the surface areas in the Torus Shell at Bays 3, 6, and 16. Portions of the Torus surface area near these Bays have been identified as augmented surface areas requiring examination in accordance with paragraph IWE-1240.

These surface areas have been categorized in accordance with Table IWE-2500-1, Examination Category E-C, Item Number E4.11, requiring visual examination of 100% of the surface areas identified during each inspection period until the areas examined remain essentially unchanged for the next three inspection periods. In the Second CISI Interval, augmented surface areas require visual examination of 100% of the surface areas identified during each inspection period until the areas examined remain essentially unchanged for the next inspection period. Once an ATTACHMENT 1 Evaluation of Proposed Change Page 39 augmented area remains unchanged for one full period, the areas fall back to the normal Examination Category E-A examination schedule. The second CISI Interval coating examinations performed during the Units 1 and 2 previous 3 refueling outages, are discussed in the previous section of this report (Section 3.5.1) and are summarized in Table 3.5-1. The augmented inspection area is the wetted (i.e., immersion zone) and submerged portions of the suppression chamber. These areas have undergone examinations to quantify and evaluate coating problems and pitting. The inspections found coating deficiencies with no metal loss greater than the defined pre-established acceptance criteria(Reference 45). All deficiencies were repaired during each inspection before unit startup. 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 QCNPS 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 per NUREG-1796, (Reference 18) QCNPS 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 QCNPS 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 resulting from past inspections at QCNPS associated with IWE and the integrity of the primary containment, are listed in Table 3.5-8 below.

Table 3.5-8 Units 1 and 2 Augmented Containment Inspection Program Matrix Examination Category (with Examination Category Description)

Aug Number Description Exam RequirementsTotal Number of Components Relief Request/ TAP Number Notes E-C Containment Surfaces Requiring Augmented Examination E4.11 Containment Surface Areas - Torus Bays 3, 6, and 16 Visual, VT-1 Unit 1: 0

Unit 2: 3 N/A 12 Note 12: Item Number E4.11 requires VT-1 visual examination in lieu of Detailed Visual examination, as modified by 10 CFR 50.55a(b)(2)(ix)(G).

ATTACHMENT 1 Evaluation of Proposed Change Page 40 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. QCNPS addressed, in Calculation QDC-1600-M-1617 (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, QCNPS 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, QCNPS shall provide the following in the Owners Activity Report-1, as required by 10 CFR 50.55a(b)(2)(ix)(A):

• A description of the type and estimated extent of degradation, and the conditions that led to the degradation;

• An evaluation of each area, and the result of the evaluation; and

• A description of necessary corrective actions. An evaluation has been performed to determine if QCNPS 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. QCNPS 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 owner's groups and ASME Code committees to maintain cognizance of ongoing developments within the nuclear industry. Industry operating experience is also continuously reviewed to determine its applicably to QCNPS. Adjustments to inspection plans and availability of new, ATTACHMENT 1 Evaluation of Proposed Change Page 41 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 QCNPS, 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 EGC's 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 (Reference 1) with reference to NEI 94-01, Revision 3-A (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:

• Section 9.2.1, "Pretest Inspection and Test Methodology"

• Section 9.2.3.2, "Supplemental Inspection Requirements" In addition to the inspections performed by the IWE/IWL Containment Inspection Program, procedure ER-AA-380, "Primary Containment Leakrate Testing Program," QCTS 500-14, "Unit 1 IPCRT Engineering Pre-Test Procedure," and QCTS 500-04, "Unit 2 IPCRT Engineering Pre-Test Procedure," 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 QCNPS 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 ATTACHMENT 1 Evaluation of Proposed Change Page 42 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 QCNPS TS 5.5.12, the allowable maximum pathway total Types B and C leakage is 0.6 L a (Note: For QCNPS, 0.6 L a is defined as 823.79 scfh and L a is defined as 1372.99 scfh).

As discussed in NUREG-1493 (Reference 6), Type B and Type C tests can identify the vast majority of all potential containment leakage paths. Type B and Type C testing will continue to provide a high degree of assurance that containment integrity is maintained. A review of the QCNPS Type B and Type C test results from 2007 through 2015 for Unit 1 and from 2008 through 2016 for Unit 2 has shown an exceptional amount of margin between the actual As-Found (AF) and As-Left (AL) outage summations and the regulatory requirements. A review of these years As-Found/As-Left test values can be summarized as:

• Unit 1 As-Found minimum pathway leak rate shows an average of 33.4% of 0.6 L a with a high of 66.1% of 0.6 L a or 0.3966 of L

a.

• Unit 1 As-Left maximum pathway leak rate shows an average of 39.7% of 0.6 L a with a high of 41.3% of 0.6 L a or 0.2480 of L

a.

• Unit 2 As-Found minimum pathway leak rate shows an average of 31.2% of 0.6 L a with a high of 57.1% of 0.6 L a or 0.3428 of L

a.

• Unit 2 As-Left maximum pathway leak rate shows an average of 43.2% of 0.6 L a with a high of 51.6% of 0.6 L a or 0.3098 of L

a. Tables 3.5-9 and 3.5-10 provide LLRT data trend summaries for QCNPS Unit 1 since 2007 (last ILRT was 2009) and for Unit 2 since 2008 (last ILRT was 2008).

Table 3.5-9 Unit 1 Types B and C LLRT Combined As-Found/As-Left Trend Summary Refueling Outage & Year R19 2007 R20 2009 2 R21 2011 R22 2013 R23 2015 AF Min Path (scfh) 134.057 229.078 184.265 544.56 283.592 3 Fraction of L a 1 0.0976 0.1668 0.1342 0.3966 0.2066 AL Max Path (scfh) 326.378 336.520 340.523 313.45 321.375 Fraction of L a 0.2377 0.2451 0.2480 0.2283 0.2341 AL Min Path (scfh) 109.190 155.464 145.136 161.06 175.127 Fraction of L a 0.0795 0.1132 0.1057 0.1173 0.1276 ATTACHMENT 1 Evaluation of Proposed Change Page 43 Note 1: 0.6 L a = 823.79 scfh and L a = 1372.99 scfh Note 2: Q1R20 in 2009 was also an ILRT outage Note 3: MSIV leakage exceeded individual TS limit (LER 2015-003 written)

Table 3.5-10 Unit 2 Type B and C LLRT Combined As-Found/As-Left Trend Summary Refueling Outage & Year R19 2008 2 R20 2010 R21 2012 R22 2014 R23 2016 AF Min Path (scfh) 106.137 189.452 200.995 3 470.624 315.866 4 Fraction of L a 1 0.0773 0.1380 0.1464 0.3428 0.2301 AL Max Path (scfh) 238.033 361.436 425.348 370.039 384.262 Fraction of L a 0.1434 0.2633 0.3098 0.2695 0.2799 AL Min Path (scfh) 93.478 131.765 158.523 102.088 125.432 Fraction of L a 0.0681 0.0960 0.1155 0.0744 0.0914 Note 1: 0.6 L a = 823.79 scfh and L a = 1372.99 scfh Note 2: Q2R19 in 2008 was also an ILRT outage Note 3: MSIV leakage exceeded individual TS limit (LER 2012-001 written) Note 4: MSIV leakage exceeded individual TS limit (LER 2016-001 written) This summary shows that there has been no As-Found failure that resulted in exceeding the TS 5.5.12 limit of 0.6 L a and demonstrates a history of successful tests. 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 3.5-11 and 3.5-12 identify Units 1 and 2 components, respectively, which were on Appendix J, Option B performance-based extended test intervals, but have not demonstrated acceptable performance during the previous two outages. The component test intervals for the components shown have been reduced to 30 months.

ATTACHMENT 1 Evaluation of Proposed Change Page 44 Table 3.5-11 Unit 1 Type B and C LLRT Program Implementation Review 2013-Q1R22 Component As-found scfh Admin Limit Alert/Actionscfh As-left scfh Cause of Failure Corrective Action Scheduled Interval AOV Gate Valve 1-2001-16 DW Equip. Drain System 295.1 5/10 5.34 Combined leakage w/2001-15. Found valve packing leak. IR 1488331 CO WO 01624041-6 Adjusted packing, flushed valve. SR frequency change 082070.

47.3 scfh combined w/2001-15 valve 30 month Check Valve 1-2499-22A Containment Air Monitoring 30.69 (12/2012) 5/10 0.037 (12/2012) Grit in seat 12/10/2012 PM WO 01397148 replaced valve, IR 1450089 AF failed - grit in seat 30 month 2015-Q1R23 Component As-found scfh Admin Limit Alert/Action scfh As-left scfh Cause of Failure Corrective Action Scheduled Interval None Table 3.5-12 Unit 2 Type B and C LLRT Program Implementation Review 2014-Q2R22 Component As-found scfh Admin Limit Alert/Actionscfh As-left scfh Cause of Failure Corrective Action Scheduled Interval Air Operated

Globe 2-0220-44, Primary Sample 31.0 5/10 0.091 Possible seat alignment problem. Rebuilt, replaced valve trim set. WO 1683615, IR 1643838-02 30 month Air Operated Plug 2-2001-4 DW Floor Drain System 16.4 5/10 0.021 Normal wear, corrected by adjusting seat. Rebuild Vlv WO 01728919 , MOD EC 342787 - Replacement of Air Operator WO 00575141 IR 01645048-02 SR 085167 30 month ATTACHMENT 1 Evaluation of Proposed Change Page 45 Table 3.5-12 Unit 2 Type B and C LLRT Program Implementation Review Air Operated Valve Gate Vlv 2-2001-15 DW Equip. Drain System (Combined with 2-2001-16) 37.360 5/10 37.360 Accepted leakage into total leakage amount and deferred repair to future outage EC 24384 is for installing new plug valves (future) WO 99232471 SR 084935 set to 30 month 30 month Air Operated

Valve Gate Vlv 2-2001-16 DW Equip. Drain System (Combined with 2-2001-15) 37.360 5/10 37.360

- Accepted leakage into total leakage amount and deferred repair to future outage AR 01646791 defer repair to future outage. MD WO 99232471 to replace w/plug valve WO 01730123-01 adjusted packing to original set value. SR 084935 30 month Check Valve Duo Disc 2-3799-31 RBCCW Supply Undetermin ed AF min was 1.079 15/30 0.131 Found a bound butterfly duo disc WO 01693929-Q2R22C, CAT IDs 1444507 Chamfered Disc, ECR 394799, & 379505 IR 01649483-02 30 month 2016-Q2R23 Component As-found scfh Admin Limit Alert/Action scfh As-left scfh Cause of Failure Corrective Action Scheduled Interval Air Operated Globe Valve 2-8804 O2 Analyzer 143.7 5/10 0.067 Appears to be debris on seat WO1911482 Cleaned up seat, repacked valve, IR 02646542 30 month The percentage of the total number of QCNPS Appendix J Type B tested components that are on 120-month extended performance-based test intervals is approximately 72% for Unit 1 and

71% for Unit 2. The percentage of the total number of QCNPS Appendix J Type C tested components that are on 60-month extended performance-based test intervals is approximately 64% for Unit 1 and

67% for Unit 2. 3.5.6 On-Line Monitoring of Primary Containment Atmosphere During power operation, the primary containment atmosphere is inerted with nitrogen to ensure that oxygen concentration is at or below 4%, by volume. TS 3.6.1.4 requires that drywell ATTACHMENT 1 Evaluation of Proposed Change Page 46 pressure be maintained at or below 1.5 psig. Because of this operational requirement, primary containment is typically maintained at an average positive pressure of 1.2 to 1.4 psig. Primary pressure is continuously indicated and periodically monitored from the Main Control Room. Abnormal high or low drywell pressure is annunciated in the Main Control Room. Primary containment pressure is periodically monitored in accordance with plant surveillance tests per plant PM. Daily surveillance logs for Modes 1, 2 and 3 include drywell pressure as one of the parameters logged once per shift. If a primary containment leak were identified, then the TS 3.6.1.A.1 action for an inoperable primary containment would be entered. 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 QCNPS Primary Containment, the following site specific and industry events have been evaluated for impact:

• Information Notice (IN) 1992-20, "Inadequate Local Leak Rate Testing"

• IN 2010-12, "Containment Liner Corrosion"

• IN 2014-07, "Degradation of Leak-Chase Channel Systems for Floor Welds of Metal Containment Shell and Concrete Containment Metallic Liner"

• Through-wall Torus Shell Crack at James A. Fitzpatrick Nuclear Power Plant

• 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 is 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 issue discussed in IN 1992-20, Inadequate Local Leak Rate Testing, was based on events at four different plants: Quad Cities, Dresden Nuclear Station, Perry Nuclear Plant, and the Clinton 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. In the event at QCNPS, the two-ply bellows design was not properly subjected to LLRT pressure and the conclusion of the utility was that the two-ply bellows design could not be Type B LLRT tested as configured. In the events at both Dresden and Perry, flanges were not ATTACHMENT 1 Evaluation of Proposed Change Page 47 considered a leakage path when the Type C LLRT test was designed. This omission led to a leakage path that was not discovered until the plant performed an ILRT test. In the event at Clinton Power Station, relief valve discharge lines that were assumed to terminate below the suppression pool minimum drawdown level were discovered to terminate at a level above that datum. These lines needed to be reconfigured and the valves should have been Type C LLRT tested. To correct this problem, Clinton Power Station removed the vacuum breaker connections and the flanges and extended the pipes to ensure that a water seal would

be maintained. QCNPS Discussion At QCNPS, 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 exem ption granted from testing requirements of Appendix J (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 adsorbed 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. QCNPS Discussion: QCNPS was designed and constructed with a Mark I containment that is a freestanding steel primary containment that is not in contact with the concrete (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, (specifically QCNPS, Units 1 and 2) are not included in their review.

ATTACHMENT 1 Evaluation of Proposed Change Page 48 QCNPS units have implemented periodic examinations during refueling outages on metallic containment structures or liners in accordance with the Section XI, Subsection IWE. The applicable EGC visual examination procedure requires the conditions described in the Information Notice 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. 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 PWRs are embedded in 3-to 4-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 (less than 1-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. QCNPS Discussion: No similar deficiencies are present at QCNPS, which is a BWR and does not have a leak-chase channel system inside containment. Containment is periodically inspected as part of the Containment Coatings 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 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.

ATTACHMENT 1 Evaluation of Proposed Change Page 49 QCNPS Discussion: The QCNPS system configurations would not introduce the type of event that occurred at JAF.

The HPCI system design does employ the use of a sparger on the turbine exhaust line. Visual VT-2 and VT-3 inspections were performed per the IWE Program on the Torus shell next to the HPCI exhaust penetrations and the support legs to the Torus shell with satisfactory results. No further actions were required. 3.6.5 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 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. QCNPS Discussion: In response to NRC Inspection and Enforcement Notice (IEN) 86-99 and GL 87-05, an extensive review was conducted by QCNPS 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," and UFSAR Appendix A, Section A.3.5.2.2, "Degradation Rates of Inaccessible Exterior Drywell Plate Surfaces." The UFSAR Section 6.2.1.2.1.2 states, in part: The QCNPS 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 corrosion rates. The review concluded that although the potential for degradation of the containment could be postulated to exist, in fact, no corrosion problems were determined to exist.

The results of the review determined that: the water present in the sand pocket or inside the drywell was noncorrosive (based on testing), and based on ultrasonic examination, there was no evidence of apparent corrosion. Also, to ensure active assessment of any future potential problems, surveillance procedures were initiated.

ATTACHMENT 1 Evaluation of Proposed Change Page 50 The UFSAR Appendix A, Section A.3.5.2.2 states, in part: Commonwealth Edison evaluated the potential effects of corrosion on exterior drywell steel surfaces in the "sand pockets" of Dresden Unit 3 drywell and found that 27 years of service remained before corrosion at the assumed rate would have a significant adverse effect on design basis stresses. The evaluation concluded that the findings were applicable to Dresden Unit 2 and Quad Cities Units 1 and 2 as well. A program was instituted for the Dresden Unit 3 inaccessible annulus areas to monitor potential corrosion. Dresden Unit 3 is considered the limiting case for potential drywell corrosion among the four Dresden and Quad Cities units. This inspection at QCNPS is a part of the ASME Section XI, Subsection IWE Program, commitment B.1.26. A surveillance procedure has been developed and PMIDs generated at QCNPS for monitoring leakage from the Dryer Separator Pit, the Spent Fuel Pool and the Drywell Liner Area Drains (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 2 refueling outages for each unit is shown in Table 3.6.5-1 below.

ATTACHMENT 1 Evaluation of Proposed Change Page 51 Table 3.6.5-1 Unit 1 and Unit 2 Leakage Detection (GL 87-05): (1) Sand Pocket - Procedure QCMPM 1600-03 and (2) Drywell Liner (Dryer Separator Pit, Spent Fuel Pool, Drywell Liner Area Drains) - Procedure QCTS 0820-11 Refuel Date PMID WO Results Q1R22 (1) Sand Pocket January 2013 0189679-02 01556416-01 3 drain lines tested satisfactorily, 1 line (Bay 16) failed (plugged) , addressed by AR01458852 (See Note 1)

Q1R22 (2) Drywell Liner March 2013 0189679-01 01556404-01 Met Acceptance Criteria - No leakage Q1R23 (1) Sand Pocket January 2015 0189679-02 01605627-01 3 drain lines tested satisfactorily, 1 line (Bay 16) failed (plugged), addressed by AR01458852 (See Note 1)

Q1R23 (2) Drywell Liner March 2015 0189679-01 01623623-01 Met Acceptance Criteria - IR 2463423 written for trending (See Note 2)

Q2R22 (1) Sand Pocket April 2014 0189680-02 01564143-01 All four drain lines met acceptance criteria - tested satisfactorily.

Q2 R22 (2) Drywell Liner April 2014 0189680-01 01556403-01 Met acceptance criteria, some hanging drips, addressed by IR 1643923 (See Note 3) Q2R23 (1) Sand Pocket March 2016 0189680-02 01758567-01 All four drain lines met acceptance criteria - tested satisfactorily.

Q2 R23 (2) Drywell Liner March 2016 0189680-01 01728707-01 Did not meet acceptance criteria, addressed by IRs 02644135, 02644136 and 02644137. (See Note 4) Note 1: AR01458852 - A 2013 surveillance result noted 1 of 4 drain lines was plugged. This is consistent with results reported to NRC in a follow-up letter to NRC related to GL87-05 (dated November 13, 1987). Engineering supports a positon that 1 of 4 plugged drain lines is not significant because if moisture were in the sand pocket it would drain from the other three open drain lines. No additional actions are necessary. Note 2: IR02463423 - There was no evidence of leakage from the drywell liner area drains, or the sand pocket drains. Leakage is believed to be ground water leakage. The structural integrity of the drywell pedestal is not affected by this issue Note 3: IR 01643923 - Hanging drips were observed and not seen to fall. Close to trend. Note 4: IR 02644135 - This leak is under monitoring to test the effectiveness of EC404162. At this time this leakage is expected. No actions are needed in Q2R23. IR02644236 and IR02644137: Water appears to be from ground water leak, is not affecting any equipment in the area and is being controlled by nearby floor drains. There appears to be no concerns with primary containment or the fuel pool from this issue at this time. Closed to information provided and AT02644136-02.

ATTACHMENT 1 Evaluation of Proposed Change Page 52 3.7 License Renewal Aging Management UFSAR Appendix A, "Updated Final Safety Analysis Report (UFSAR) Supplement," contains the UFSAR Supplement as required by 10 CFR 54.21(d) for the QCNPS 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 1 and 2" (Reference 18) that provided their SER of the QCNPS 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 for 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 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).

• 10 CFR 50, Appendix J (Supplement Appendix A.1.28) The 10 CFR 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."

• 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 program complies with ATTACHMENT 1 Evaluation of Proposed Change Page 53 ASME Section XI, Subsection IWE for steel containments (Class MC), 1992 Edition including 1992 Addenda. NOTE: The Second CISI Interval was updated for QCNPS, Units 1 and 2, with effective dates of September 9, 2008, through September 8, 2018. The ASME Section XI Code of Record for the Second CISI Interval is the 2001 Edition through the 2003 Addenda.

• 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 will be revised to include thorough visual inspection of Service Level I coatings near sumps or screens for the ECCS, preinspection review of previous reports so that trends can be identified, and analysis of suspected causes of any coating failures. NOTE: The program to maintain containment coatings was developed to meet the requirements of RG 1.54, Revision 0. This program is implemented at QCNPS with procedures ER-AA-330-008, "Exelon Safety-Related (Service Level I) Protective Coatings," and ER-QC-330-1000, "Primary Containment and Coating Inspections." 3.8 NRC SE 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 3.9-1 were satisfied:

ATTACHMENT 1 Evaluation of Proposed Change Page 54 Table 3.9-1 NEI 94-01 Revision 2-A Limitations and Conditions Limitation/Condition (From Section 4.0 of SE) QCNPS Response For calculating the Type A leakage rate, the licensee should use the definition in the NEI TR 94-01, Revision 2, in lieu of that in ANSI/ANS-56.8-2002. (Refer to SE Section 3.1.1.1.)

QCNPS will utilize the definition in NEI 94-01 Revision 3-A, Section 5.0. This definition has remained unchanged from Revision 2-A to Revision 3-A of NEI 94-01. The licensee submits a schedule of containment inspections to be performed prior to and between Type A tests. (Refer to SE Section 3.1.1.3.) Reference Section 3.5.2 (Tables 3.5-4 and 3.5-5) of this LAR submittal.

The licensee addresses the areas of the containment structure potentially subjected to degradation. (Refer to SE Section 3.1.3.) Reference Section 3.5.2 (Tables 3.5-4 and 3.5-5)

of this LAR submittal.

The licensee addresses any tests and inspections performed following major modifications to the containment structure, as applicable. (Refer to SE Section 3.1.4.) 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). This NRC Order is the result of the Fukushima Dai-ichi event. See Section 3.1.7 of this LAR submittal for additional details. (Note: Work on the hardened containment vent modification is currently on hold due to other licensing actions. Upon installation, this modification will be tested and maintained in accordance with the Appendix J and CISI Programs as applicable. The normal Type A test interval should be less than 15 years. If a licensee has to utilize the provision of Section 9.1 of NEI TR 94-01, Revision 2, related to extending the ILRT interval beyond 15 years, the licensee must demonstrate to the NRC staff that it is an unforeseen emergent condition. (Refer to SE Section 3.1.1.2.) QCNPS will follow the requirements of NEI 94-01 Revision 3-A, Section 9.1. This requirement has remained unchanged from Revision 2-A to Revision 3-A of NEI 94-01.

In accordance with the requirements of 94-01 Revision 2-A, SE Section 3.1.1.2, QCNPS will also demonstrate to the NRC that 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 construction and testing of containments for that design have been completed and applicants have confirmed the applicability of NEI 94-01, Revision 2, and EPRI Report No. 1009325, Revision 2, including the use of past containment ILRT data. Not applicable. QCNPS was not licensed under 10 CFR Part 52.

ATTACHMENT 1 Evaluation of Proposed Change Page 55 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 (Reference NEI 94-01 Revision 3-A, NRC SE 4.0, Limitations and Conditions): Topical Report Condition 1 NEI TR 94-01, Revision 3, is requesting that the allowable extended interval for Type C LLRTs be increased to 75 months, with a permissible extension (for non-routine emergent conditions) of nine months (84 months total). The staff is allowing the extended interval for Type C LLRTs be increased to 75 months with the requirement that a licensee's post-outage report include the margin between the Type B and Type C leakage rate summation and its regulatory limit. In addition, a corrective action plan shall be developed to restore the margin to an acceptable level. The staff is also allowing the non-routine emergent extension out to 84-months as applied to Type C valves at a site, with some exceptions that must be detailed in NEI TR 94-01, Revision 3. At no time shall an extension be allowed for Type C valves that are restricted categorically (e.g., BWR MSIVs), and those valves with a history of leakage, or any valves held to either a less than maximum interval or to the base refueling cycle interval. Only non-routine emergent conditions allow an extension to 84 months. Response to Condition 1 Condition 1 presents the following three (3) separate issues that are required to be addressed:

• ISSUE 1 - The allowance of an extended in terval 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.

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

• ISSUE 3 - Use of the allowed 9-month extension for eligible Type C valves is only authorized for non-routine emergent conditions with exceptions as detailed in NEI 94-01, Revision 3-A, Section 10.1. Response to Condition 1, ISSUE 1 The post-outage report shall include the margin between the Type B and Type C Minimum Pathway Leak Rate (MNPLR) summation value, as adjusted to include the estimate of applicable Type C leakage understatement, and its regulatory limit of 0.60 L

a. Response to Condition 1, ISSUE 2 When the potential leakage understatement adjusted Types B and C MNPLR total is greater than the QCNPS, Units 1 and 2, leakage summation limit of 0.5 L a, but less than the regulatory ATTACHMENT 1 Evaluation of Proposed Change Page 56 limit of 0.6 L a, then an analysis and determination of a corrective action plan shall be prepared to restore the leakage summation margin to less than the QCNPS 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 QCNPS, Units 1 and 2 will apply the 9-month allowable interval extension period only to eligible Type C components and only for non-routine emergent conditions. Such occurrences will be documented in the record of tests. Topical Report Condition 2 The basis for acceptability of extending the ILRT interval out to once per 15 years was the enhanced and robust primary containment inspection program and the local leakage rate testing of penetrations. Most of the primary containment leakage experienced has been attributed to penetration leakage and penetrations are thought to be the most likely location of most containment leakage at any time. The containment leakage condition monitoring regime involves a portion of the penetrations being tested each refueling outage, nearly all LLRTs being performed during plant outages. For the purposes of assessing and monitoring or trending overall containment leakage potential, the as-found minimum pathway leakage rates for the just tested penetrations are summed with the as-left minimum pathway leakage rates for penetrations tested during the previous 1 or 2 or even 3 refueling outages. Type C tests involve valves, which in the aggregate, will show increasing leakage potential due to normal wear and tear, some predictable and some not so predictable. Routine and appropriate maintenance may extend this increasing leakage potential. Allowing for longer intervals between LLRTs means 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 consistent ly show with their testing, any understatement of the LLRT total using a 5-year test frequency is thought to be conservatively accounted for.

Extending the LLRT intervals beyond 5 years to a 75-month interval should be similarly conservative provided an estimate is made of the potential understatement and its acceptability determined as part of the trending specified in NEI TR 94-01, Revision 3, Section 12.1. When routinely scheduling any LLRT valve interval beyond 60-months and up to 75-months, the primary containment leakage rate testing program trending or monitoring must include an estimate of the amount of understatement in the Types B and C total leakage, and must be included in a licensee's post-outage report. The report must include the reasoning and determination of the acceptability of the extension, demonstrating that the LLRT totals calculated represent the actual leakage potential of the penetrations.

ATTACHMENT 1 Evaluation of Proposed Change Page 57 Response to Condition 2 Condition 2 presents the following two (2) separate issues that are required to be addressed:

• ISSUE 1 - Extending the LLRT intervals bey ond 5 years to a 75-month interval should be similarly conservative provided an estimate is made of the potential understatement and its acceptability determined as part of the trending specified in NEI TR 94-01, Revision 3, Section 12.1.

• ISSUE 2 - When routinely scheduling any LLRT valve interval beyond 60 months and up to 75 months, the primary containment leakage rate testing program trending or monitoring must include an estimate of the amount of understatement in the Types B and C total, and must be included in a licensee's post-outage report. The report must include the reasoning and determination of the acceptability of the extension, demonstrating that the LLRT totals calculated represent the actual leakage potential of the penetrations. Response to Condition 2, ISSUE 1 The change in going from a 60-month extended test interval for Type C tested components to a 75-month interval, as authorized under NEI 94-01, Revision 3-A, represents an increase of 25%

in the LLRT periodicity. As such, QCNPS, Units 1 and 2 will conservatively apply a potential leakage understatement adjustment factor of 1.25 to the actual As-Left leak rate, which will increase the As-Left leakage total for each Type C component currently on greater than a 60-month test interval up to the 75-month extended test interval. This will result in a combined conservative Type C total for all 75-month LLRTs being "carried forward" and will be included whenever the total leakage summation is required to be updated (either while on-line or following an outage). When the potential leakage understatement adjusted leak rate total for those Type C components being tested on greater than a 60-mont h test interval up to the 75-month extended test interval is summed with the non-adjusted total of those Type C components being tested at less than or equal to a 60-month test interval, and the total of the Type B tested components, results in the MNPLR being greater than the QCNPS leakage summation limit of 0.50 L a , but less than the regulatory limit of 0.6 L a, then an analysis and corrective action plan shall be prepared to restore the leakage summation value to less than the QCNPS 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 (Reference 44). Response to Condition 2, ISSUE 2 If the potential leakage understatement adjusted leak rate MNPLR is less than the QCNPS leakage summation limit of 0.50 L a, 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.

ATTACHMENT 1 Evaluation of Proposed Change Page 58 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 cycle's 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 sha ll 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 QCNPS, 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 QCNPS, 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 L

a. 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 inte rvals 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. QCNPS 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 QCNPS, Units 1 and 2, 10 CFR 50, Appendix J testing program plan. Based on the previous ILRTs conducted at QCNPS, Units 1 and 2, 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 QCNPS inspection programs:

• Containment Inservice Inspection Program (IWE)

• Containment Inspections per TS SR 3.6.1.1.1

• Containment Coatings Inspection and Assessment Program ATTACHMENT 1 Evaluation of Proposed Change Page 59 This experience is supplemented by risk analysis studies, including the QCNPS 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 QCNPS risk profile.

4.0 REGULATORY EVALUATION

4.1 Applicable

Regulatory Requirements/Criteria The proposed change has been evaluated to determine whether applicable regulations and requirements continue to be met. 10 CFR 50.54(o) requires primary reactor containments for water-cooled power reactors to be subject to the requirements of Appendix J to 10 CFR 50, "Leakage Rate Testing of Containment of Water Cooled Nuclear Power Plants." Appendix J specifies containment leakage testing requirements, including the types required to ensure the leak-tight integrity of the primary reactor containment and systems and components which penetrate the containment. In addition, Appendix J discusses leakage rate acceptance criteria, test methodology, frequency of testing and reporting requirements for each type of test. The adoption of the Option B performance-based containment leakage rate testing for Type A, Type B and Type C testing did not alter the basic method by which Appendix J leakage rate testing is performed; however, it did alter the frequency at which Type A, Type B, and Type C containment leakage tests must be performed. Under the performance-based option of 10 CFR 50, Appendix J, the test frequency is based upon an evaluation that reviewed "as-found" leakage history to determine the frequency for leakage testing which provides assurance that leakage limits will be maintained. The change to the Type A test frequency did not directly result in an increase in containment leakage. Similarly, the proposed change to the Type C test frequencies will not directly result in an increase in containment leakage. EPRI TR-1009325, Revision 2-A (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 (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 Option B to 10 CFR 50, Appendix J. This guidance includes provisions for extending Type A ILRT intervals up to 15 years and incorporates the regulatory positions stated in RG 1.163. The NRC finds 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.

ATTACHMENT 1 Evaluation of Proposed Change Page 60 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 finds 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 SE. The NRC reviewed NEI TR 94-01, Revision 3, a nd determined that it described an acceptable approach for implementing the optional performance-based requirements of Option B to 10 CFR 50, Appendix J, as modified by the limitations and conditions summarized in Section 4.0 of the associated SE. This guidance included provisions for extending Type C LLRT intervals up to 75 months. Type C testing ensures that individual CIVs are essentially leak tight. In addition, aggregate Type C leakage rates support the leak age 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 SE 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 Option B to 10 CFR 50, Appendix J.

4.2 Precedent

This LAR is similar in nature to the following license amendments to extend the Type A Test Frequency to 15 years and the Type C test frequency to 75 months as previously authorized by the NRC:

• Surry Power Station, Units 1 and 2 (Reference 24)

• Donald C. Cook Nuclear Plant, Units 1 and 2 (Reference 25)

• Beaver Valley Power Station, Unit Nos. 1 and 2 (Reference 26)

• Calvert Cliffs Nuclear Power Plant, Unit Nos. 1 and 2 (Reference 27)

• Peach Bottom Atomic Power Station, Units 2 and 3 (Reference 28)

• Comanche Peak Nuclear Power Plant, Units 1 and 2 (Reference 39) 4.3 No Significant Hazards Consideration 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-29 and DPR-30 for Quad Cities Nuclear Power Station (QCNPS), Units 1 and 2, respectively. The proposed change revises Technical Specifications (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. According to 10 CFR 50.92, "Issuance of amendment," paragraph (c), a proposed amendment to an operating license involves no significant hazards consideration if operation of the facility in accordance with the proposed amendment would not:

ATTACHMENT 1 Evaluation of Proposed Change Page 61 (1) Involve a significant increase in the probability or consequences of any accident previously evaluated; or (2) Create the possibility of a new or different kind of accident from any accident previously evaluated; or (3) Involve a significant reduction in a margin of safety. EGC has evaluated the proposed change, using the criteria in 10 CFR 50.92, and has determined that the proposed change does not involve a significant hazards consideration. The following information is provided to support a finding of no significant hazards consideration. 1. Does the proposed change involve a significant increase in the probability or consequences of an accident previously evaluated?

Response: No

The proposed activity involves revision of the Quad Cities Nuclear Power Station (QCNPS) Technical Specification (TS) 5.5.12, Primary Containment Leakage Rate Testing Program, to allow the extension of the QCNPS, Units 1 and 2, Type A containment integrated leakage rate test 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 (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 (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 Integrated Leak Rate Test (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 QCNPS, is 1.0E-02 person-rem/yr (0.31%) using the Electric Power Research Institute (EPRI) guidance with the base case corrosion included. The change in dose risk drops to 2.7E-03 person-rem/yr (0.08%) 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 to this LAR). Therefore, this proposed extension does not involve a significant increase in the probability of an accident previously evaluated.

ATTACHMENT 1 Evaluation of Proposed Change Page 62 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 QCNPS, Units 1 and 2 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 amendments 220 and 214 to allow one-time extensions of the ILRT test frequency for QCNPS, Units 1 and 2, respectively. This exception was for an activity that has already taken place; therefore, this deletion is solely an administrative action that does not result in any change in how QCNPS, Units 1 and 2 are operated. Therefore, the proposed change does not involve 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 pr eviously evaluated? Response: No The proposed amendment to TS 5.5.12, "Primary Containment Leakage Rate Testing Program," involves the extension of the QCNPS, Units 1 and 2 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 plant's 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. The proposed amendment also deletes an exception previously granted under TS Amendments 220 and 214 to allow the one-time extension of the ILRT test frequency for ATTACHMENT 1 Evaluation of Proposed Change Page 63 QCNPS, Units 1 and 2, respectively. This exception was for an activity that has already taken place; therefore, this deletion is solely an administrative action that does not result in any change in how the QCNPS units are operated. Therefore, the proposed change does not create the possibility of a new or different kind of accident from any accident previously evaluated. 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 QCNPS, Units 1 and 2 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 QCNPS, Units 1 and 2. The proposed surveillance interval extension is bounded by the 15-year ILRT interval and the 75-month Type C test interval currently authorized within NEI 94-01, Revision 3-A. Industry experience supports the 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 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 exceptions previously granted to allow one-time extensions of the ILRT test frequency for QCNPS, Units 1 and 2. This exception was for an activity that has taken place; therefore, the deletion is solely an administrative action and does not change how QCNPS is operated and maintained. Thus, there is no reduction in any margin of safety. Therefore, the proposed change does not involve a significant reduction in a margin of safety. Based on the above evaluation, EGC concludes that the proposed amendment presents no significant hazards consideration under the standards set forth in 10 CFR 50.92, paragraph (c), and accordingly, a finding of no significant hazards consideration is justified.

ATTACHMENT 1 Evaluation of Proposed Change Page 64 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 Commission's regulations, and (3) the issuance of the amendment will not be inimical to the common defense and security or the health and safety of the public.

5.0 ENVIRONMENTAL CONSIDERATION

EGC 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, "Standards for Protection Against Radiation." 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, "Criterion for categorical exclusion; identification of licensing and regulatory actions eligible for categorical exclusion or otherwise not requiring environmental review,"

paragraph (c)(9). Therefore, pursuant to 10 CFR 51.22, paragraph (b), no environmental impact statement or environmental assessment needs to 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. Regulatory Guide 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. Regulatory Guide 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 ATTACHMENT 1 Evaluation of Proposed Change Page 65 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. Quad Cities Calculation QDC-1600-M-1617, "Determination of the Area of Primary Containment After Construction," dated January 24, 2008 [Calculation that determined 80%

of containment pressure boundary surface area is accessible] 13. Letter from J. F. Stang (NRC) to D. L. Farrer (Commonwealth Edison Company), "Issuance of Amendments [No. 169 and 165] 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 S. N. Bailey (NRC) to O. D. Kingsley (Commonwealth Edison Company), "Issuance of Amendments (TAC Nos. MA6082 and MA6083)," Enclosure 3 - Safety Evaluation Related to Amendments No 192 and No 188, dated December 21, 1999 (ML993630246 and ML993630259) 15. Letter from S. N. Bailey (NRC) to O. D. Kingsley (Exelon Generation Company, LLC), "Quad Cities Nuclear Power Station, Units 1 and 2 - Issuance of Amendments for Extended Power Uprate (TAC Nos. MB0842 and MB0843)," Enclosure 3 - Safety Evaluation Related to Amendments No 202 and No 198, dated December 21, 2001 (ML013530380 and ML013540222) 16. Letter from L. W. Rossbach (NRC) to J. L Skolds (Exelon Generation Company, LLC), "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 L. W. Rossbach (NRC) to C. M. Crane (Exelon Generation Company, LLC), "Quad Cities Nuclear Power Station, Units 1 and 2 - Issuance of Amendments [Nos. 220 and 214] Regarding Containment Leakage Rate Testing (TAC Nos. MB7861 and MB7862),"

dated March 8, 2004 (ML040280368) 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)

ATTACHMENT 1 Evaluation of Proposed Change Page 66 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 (Commonwealth Edison Company) to H. R. Denton (NRC), dated June 27, 1983, "Quad Cities Nuclear Power Station Units 1 and 2 Plant Unique Analysis Report," Revision 0, dated May 1983, UFSAR, Section 3.8.2, Reference 1. (Reference described on Page 3.8-28) 22. Letter from J. A. Zwolinski (NRC) to D. L. Farrar (Commonwealth Edison Company), February 15, 1986, "Mark I Containment Long Term Program," UFSAR Section 3.8.2, Reference 2 (Reference described on Page 3.8-28) 23. NEI 00-02, "Probabilistic Risk Assessment Peer Review Process Guidance," Rev. A3, dated March 2000 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. American Society of Mechanical Engineers, Standard for Probabilistic Risk Assessment for Nuclear Power Plant Applications, ASME RA-S-2002, New York, New York, April 2002 30. ASME/American Nuclear Society, Standard for Level 1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications, ASME/ANS RA-Sa-2009, dated March 2009. Addendum A to RA-S-2008 31. Quad Cities Nuclear Power Station PRA Peer Review Report, BWROG Final Report, dated February 2000 ATTACHMENT 1 Evaluation of Proposed Change Page 67 32. Letter from Mr. 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. Boiling Water Reactors Owners' Group, BWROG PSA Peer Review Certification Implementation Guidelines, Revision 3, dated January 1997 34. Reactor Oversight Program MSPI Bases Document, Quad Cities Generating Station, Revision 5b, dated December 15, 2011 35. Quad Cities Nuclear Power Station PRA Peer Review Report (Internal Flooding) Using ASME PRA Standards, dated November 2010 36. QC-PSA-13 Self-Assessment of the Quad Cities PRA Against the Combined ASME/ANS PRA Standard Requirements, Revision 0 37. QCNPS UFSAR Section 3.8, Figure 3.8-39, "Typical Electrical Penetration Assembly Canister" 38. QC-PSA-16, Self-Assessment of the Quad Cities PRA Against the Combined ASME/ANS PRA Standard Requirements Revision 5 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 Maitri Banerjee (NRC) to C.M. Crane (Exelon Generation Company, LLC) pertaining to Issuance of Amendments RE: Adoption of Alternative Source Term Methodology. Letter contained Safety Evaluation Report for Amendments No. 233 (Unit 1) and No. 229 (Unit 2), dated September 11, 2006 (ML062070290). Subsequent letter from Daniel S. Collins (NRC) to C. M. Crane (Exelon Nuclear, EGC) revising values on pages 9, 11 and 12 of SE. Changes have no impact on Appendix J and this LAR application (ML062680404) 41. Letter from D. B. Vassallo (NRC) to D. L. Farrar (Commonwealth Edison Company), "Re: Quad Cities Nuclear Power Station, Units 1 and 2," [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 tests for the containment airlock], dated June 12, 1984 (ML020930631) 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)]

ATTACHMENT 1 Evaluation of Proposed Change Page 68 43. ANSI/ANS 56.8-2002, "Containment System Leakage Testing Requirements," dated November 27, 2002 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. Calculation: "Torus Pitting Corrosion Acceptance Criteria for Quad Cities Nuclear Power Station Units 1 and 2," Calculation File No: 64.305.2029, Project No: 1598.0015, Revision 1, dated May 6, 1994 46. NEI 05-04, Process for Performing Internal Events PRA Peer Reviews Using the ASME/ANS PRA Standard, Revision 2, dated November 2008 47. Quad Cities Nuclear Generation Station PRA Peer Review Report (All applicable SRs except Internal Flooding), April 2017

ATTACHMENT 2 Markup of Proposed Technical Specifications Pages Quad Cities Nuclear Power Station, Units 1 and 2 Renewed Facility Operating License Nos. DPR-29 and DPR-30 REVISED TECHNICAL SPECIFICATIONS PAGES 5.5-11 5.5-12 Programs and Manuals 5.5 5.5 Programs and Manuals Quad Cities 1 and 2 5.5-11 Amendment No. 220/2145.5.11Safety 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; or2.A required system redundant to system(s) in turn supported by the inoperable supported system is also

inoperable; or3.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.5.5.12Primary Containment Leakage Rate Testing Programa.This program shall establish the leakage testing of the primary containment as required by 10 CFR 50.54(o) and 10CFR 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 94-01 -1995,Section 9.2.3: The first Unit 1Type A test performed after the July 23, 1994, Type A test shall be performed no later than July 22, 2009.(continued)

NEI 94-01, "Industry Guideline for

Implementing

Performance-Based

Option of 10 CFR 50, Appendix J,"

Revision 3-A, dated

July 2012, and the

conditions and

limitations specified

in NEI 94-01, Revision 2-A, dated

October 2008.

exemptions Programs and Manuals 5.5 5.5 Programs and Manuals Quad Cities 1 and 2 5.5-12 Amendment No. 238/2335.5.12Primary Containment Leakage Rate Testing Program (continued)2.NEI 94-01 -1995, Section 9.2.3: The first Unit 2Type A test performed after the May 17, 1993, Type A test shall be performed no later than May 16, 2008.b.The peak calculated primary containment internal pressure for the design basis loss of coolant accident, P a , is 43.9psig.c.The maximum allowable primary containment leakage rate, L a , at P a , 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 TypeA tests.2.Air lock testing acceptance criteria is the overall air lock leakage rate is

!0.05 La when tested at

1. Pa.e.The provisions of SR 3.0.3 are applicable to the Primary Containment Leakage Rate Testing Program.5.5.13Control Room Envelope Habitability Program A Control Room Envelope (CRE) Habitability Program shall be established and implemented to ensure that CRE habitability is maintained such that, with an OPERABLE Control Room Emergency Ventilation (CREV) System, CRE occupants can control the reactor safely under normal conditions and maintain it in a safe condition following a radiological event, hazardous chemical release, or a smoke challenge. The program shall ensure that adequate radiation protection is provided to permit access and occupancy of the CRE under design basis accident (DBA) conditions without personnel receiving radiation exposure in excess of 5 rem total effective dose equivalent (TEDE) for the duration of the accident. The program shall include the following elements:a.The definition of the CRE and the CRE boundary.b.Requirements for maintaining the CRE boundary in its design condition including configuration control andpreventive (continued)

ATTACHMENT 3 QC-LAR-03, "Risk Assessment for QCNPS Regarding the ILRT (Type A) Permanent Extension Request"

CLASS DESCRIPTION

ACCIDENT CLASS DESIGNATOR SUBCLASS DEFINITION 2014 MODEL (PER RX YR)

CLASS BASE CDF INTACT(6) LL/E LL/I LL/L L/E L/I L/L M/E M/I M/L H/E H/I H/L TOTAL RELEASE IA 1.08E-06 2.31E-07 0.00E+00 1.16E-08 8.74E-10 8.34E-09 0.00E+00 5.36E-10 1.43E-08 2.96E-07 6.63E-09 3.34E-08 4.76E-07 1.68E-10 8.48E-07 IBE 1.11E-07 1.35E-08 0.00E+00 1.84E-08 4.79E-11 4.19E-11 0.00E+00 3.20E-11 2.08E-11 1.53E-08 5.52E-10 8.91E-10 6.21E-08 2.22E-12 9.74E-08 IBL 2.86E-07 2.42E-08 0.00E+00 5.07E-09 4.71E-12 0.00E+00 2.33E-11 7.61E-12 0.00E+00 1.46E-08 2.35E-11 0.00E+00 2.42E-07 2.59E-1 2 2.62E-07 IC 2.11E-08 2.11E-08 0.00E+00 0.00E+00 0.00E+00 3.07E-11 0.00E+00 0.00E+00 0.00E+00 8.99E-12 0.00E+00 1.97E-12 0.00E+00 0.00E+00 4.17E-11 ID 4.63E-08 1.51E-08 0.00E+00 2.59E-09 1.14E-09 0.00E+00 0.00E+00 2.38E-09 0.00E+00 2.32E-09 6.16E-10 2.9 4E-09 1.92E-08 0.00E+00 3.12E-08 II 1.03E-06 0.00E+00 3.38E-12 3.40E-12 0.00E+00 0.00E+00 6.97E-12 0.00E+00 5.22E-07 1.29E-12 4.30E-08 4.64E-07 0.00E+00 1.03E-06 IIIA N/A 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 IIIB 8.17E-08 8.03E-08 0.00E+00 0.00E+00 0.00E+00 7.04E-10 0.00E+00 0.00E+00 0.00E+00 2.88E-10 0.00E+00 3.88E-10 1.29E-11 0.00E+00 1.39E-09 IIIC 1.04E-07 1.24E-08 0.00E+00 0.00E+00 3.65E-09 0.00E+00 0.00E+00 7.64E-09 0.00E+00 4.87E-08 1.74E-09 7.47E-09 2.27E-08 0.00E+00 9.19E-08 IIID\ 1.97E-08 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 1.97E-08 0.00E+00 0.00E+00 1.97E-08 IV(4) 8.43E-08 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 4.18E-08 8.99E-12 0.00E+00 4.25E-08 0.00E+00 0.00E+00 8.43E-08 V 4.70E-08 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 4.70E-08 0.00E+00 0.00E+00 4.70E-08 Total 2.92E-06(5) 3.98E-07 0.00E+00 3.7 6E-08 5.72E-09 9.12E-09 2.33E-11 1.06E-08 5.62E-08 8.99E-07 9.56E-09 1.97E-07 1.29E-06 1.72E-10 2.51E-06

CONSEQUENCE CATEGORY DOMINANT RELEASE CATEGORY MAAP CASE TIME OF INITIAL RELEASE TIME OF GEN. EMG. DECLARATION TIME OF END OF RELEASE EAL BASIS RELEASE FREQUENCY (PER RX YR)

Basic Event Probability FV