ML061740424

Request for Amendment to Technical Specifications 5.5.13, Primary Containment Leakage Rate Testing Program.

ML061740424
Person / Time
Site:	LaSalle
Issue date:	04/21/2006
From:	Bauer J A Exelon Generation Co, Exelon Nuclear
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
RS-06-048
Download: ML061740424 (28)

Text

Exelon Generation www.exeloncorp.com Nuclear 4300 Winfieid Road Warrenvi~le, iL 60555 10 CFR 50.90 RS-06-048 April 21, 2006 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D. C. 20555 LaSalle County Station, Unit 2 Facility Operating License Nos. NPF-18 NRC Docket No. 50-374

Subject:

Request for Amendment to Technical Specification 5.5.13, "Primary Containment Leakage Rate Testing Program"

References:

(1) Letter from K. R. Jury (Exelon Generation Company, LLC (EGC)) to USNRC, "Request for Amendment to Technical Specifications Section 5.5.13, 'Primary Containment Leakage Rate Testing Program'," dated October 24, 2002 (2) Letter from T. W. Simpkin (EGC) to USNRC, "Response to Request for Additional Information to Support Request for Amendment to Technical Specifications Section 5.5.13, 'Primary Containment Leakage Rate Testing Program'," dated June 20, 2003 (3) Letter from W. A. Macon, Jr. (USNRC) to J. L. Skolds (EGC), "LaSalle County Station, Units 1 and 2, Issuance of Amendments Re: Integrated Leakage Rate Test Interval," dated November 19, 2003 In accordance with 10 CFR 50.90, "Application for amendment of license or construction permit," Exelon Generation Company, LLC, (EGC) hereby requests the following amendment to Appendix A, Technical Specifications (TS), of Facility Operating License No. NPF-18 for LaSalle County Station (LSCS) Unit 2. Specifically, the proposed change will revise TS 5.5.13, "Primary Containment Leakage Rate Testing Program," to reflect a one-time extension of the LSCS Unit 2 primary containment Type A Integrated Leak Rate Test (ILRT) date from the current requirement of no later than December 7, 2008, to prior to startup following the twelfth LSCS Unit 2 refueling outage (L2R12).-d/10/-

April 21, 2006 U. S. Nuclear Regulatory Commission Page 2 TS Section 5.5.13 establishes the leakage rate testing of the primary containments as required by 10 CFR 50.54, "Conditions of licenses," paragraph (o) and 10 CFR 50, Appendix J, Option B,"Performance Based Requirements," as modified by approved exemptions.

Additionally, the testing conforms with the guidelines contained in Regulatory Guide 1.163, "Performance-Based Containment Leak-Testing Program," dated September 1995.In Reference 1, EGC submitted a License Amendment Request (LAR) to defer the Type A ILRT schedule for LSCS Units 1 and 2 in anticipation of a rule change to 10 CFR 50 extending the Type A ILRT frequency to at least 15 years. In response to an NRC Request for Additional Information, EGC provided additional information regarding the LAR in Reference

2. The requested schedule deferral provided a proposed test date for each unit, consistent with a 15-year test schedule.

For LSCS Unit 2, the specified test date was changed to "no later than December 7, 2008." The NRC approved the LAR in Reference 3.Due to minor variations in refueling outage schedules since approval of the original LAR, the LSCS Unit 2 twelfth refueling outage (L2R12), in which the deferred Type A ILRT would be performed, will not start until March 2009. Approval of this LAR will enable LSCS Unit 2 to operate until L2R12.EGC has assessed the risk implications of extending the LSCS Unit 2 Type A ILRT interval from a baseline interval of three times in ten years to once in 15 years plus 15 months (i.e., 16.25 years). This evaluation indicated that the analyzed Type A ILRT interval extension has a minimal impact on public risk. Since the proposed Type A ILRT extension represents only approximately 20% of the analyzed extension, the proposed change is conservative with respect to the EGC risk assessment.

The information supporting the proposed TS changes is subdivided as follows.Attachment 1 provides an evaluation of the proposed changes.Attachment 2 contains the copy of the marked up TS page.Attachment 3 provides the retyped TS page.Attachment 4 provides the risk assessment supporting the proposed changes.The proposed TS changes have been reviewed by the LaSalle County Station Plant Operations Review Committee and approved by the Nuclear Safety Review Board in accordance with the EGC Quality Assurance Program.EGC is notifying the State of Illinois of this application for amendment by transmitting a copy of this letter and its attachments to the designated State Official.We request approval of the proposed changes by February 1, 2007, with an implementation period of 60 days.

April 21, 2006 U. S. Nuclear Regulatory Commission Page 3 Should you have any questions concerning this submittal, please contact Mr. J. L. Schrage at (630) 657-2821.I declare under penalty of perjury that the foregoing is true and correct. Executed on the 21st day of April 2006.Sincerely, eph A. Bauer Manager, Licensing Exelon Generation Company, LLC Attachments:

Attachment 1 Attachment 2 Attachment 3 Attachment 4 Evaluation of Proposed Changes Markup of Proposed Technical Specification Page Changes Retyped Page for Technical Specification Changes LaSalle ILRT Interval Extension Risk Assessment ATTACHMENT 1 Evaluation of Proposed Changes

2.0 DESCRIPTION

OF PROPOSED AMENDMENT

3.0 BACKGROUND

4.0 TECHNICAL

ANALYSIS 5.0 REGULATORY ANALYSIS 5.1 No Significant Hazards Consideration

5.2 Regulatory

Requirements and Criteria 6.0 ENVIRONMENTAL CONSIDERATION

8.0 REFERENCES

Page 1 ATTACHMENT 1 Evaluation of Proposed Changes

1.0 INTRODUCTION

In accordance with 10 CFR 50.90, "Application for amendment of license or construction permit," Exelon Generation Company, LLC, (EGC) hereby requests the following amendment to Appendix A, Technical Specifications (TS), of Facility Operating License No.NPF-1 8 for LaSalle County Station (LSCS) Unit 2. Specifically, the proposed changes will revise TS 5.5.13,"Primary Containment Leakage Rate Testing Program," to reflect a one-time extension of the LSCS Unit 2 primary containment Type A Integrated Leak Rate Test (ILRT) date from the current requirement of "no later than December 7, 2008" to "prior to startup following L2R1 2" (i.e., the twelfth LSCS Unit 2 refueling outage).TS Section 5.5.13 establishes the leakage rate testing of the primary containments as required by 10 CFR 50.54, "Conditions of licenses," paragraph (o) and 10 CFR 50, Appendix J, Option B,"Performance Based Requirements," as modified by approved exemptions.

Additionally, the testing conforms with the guidelines contained in Regulatory Guide (RG) 1.163, "Performance-Based Containment Leak-Testing Program," dated September 1995.In Reference 1, EGC submitted a License Amendment Request (LAR) to defer the Type A ILRT schedule for LSCS Units 1 and 2 in anticipation of a rule change to 10 CFR 50 extending the Type A ILRT frequency to at least 15 years. In response to an NRC Request for Additional Information, EGC provided additional information regarding the LAR in Reference

2. The requested schedule deferral provided a proposed test date for each unit, consistent with a 15-year test schedule.

For LSCS Unit 2, the specified test date was changed to "no later than December 7, 2008." The NRC approved the LAR in Reference 3.Due to minor variations in refueling outage schedules since the original LAR submittal, the LSCS Unit 2 twelfth refueling outage (L2R12), in which the deferred Type A ILRT would be performed, will not start until March 2009. Approval of this LAR will enable LSCS Unit 2 to operate until L2R12.

2.0 DESCRIPTION

OF PROPOSED AMENDMENT The proposed change revises an exception to TS 5.5.13 that modifies the test date for the next Type A ILRT for LSCS Unit 2, to prior to startup following L2R12. The proposed changes associated with the revised exception to TS 5.5.13 are identified below in bold and strikethrough type.5.5.13 Primary Containment Leakaae Rate Testing Program a. This program shall establish the leakage rate 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 Regulatory Guide 1.163, "Performance-Based Containment Leak-Testing Program," dated September 1995 as modified by the following exceptions:

Page 2 ATTACHMENT 1 Evaluation of Proposed Changes 1. NEI 94-01 -1995, Section 9.2.3: The first Unit 1 Type A ILRT test performed after June 14, 1994 Type A test shall be performed no later than June 13, 2009.2. NEI 94-01 -1995, Section 9.2.3: The first Unit 2 Type A test performed after December 8, 1993 Type A test shall be performed ne-later-tha Dec.mbor 7, 2008 prior to startup following L2R12.

3.0 BACKGROUND

LSCS Units 1 and 2 are General Electric BWR/5 plants with Mark II primary containments.

The Mark II primary containment consists of two compartments, the drywell and the suppression chamber. The drywell has the shape of a truncated cone, and is located above the cylindrically shaped suppression chamber. The drywell floor separates the drywell and the suppression chamber. The primary containment is penetrated by access piping and electrical penetrations.

The integrity of the primary containment penetrations and isolation valves is verified through Type B and Type C local leak rate tests (LLRTs) and the overall leak tight integrity of the primary containment is verified by a Type A ILRT, as required by 10 CFR 50, Appendix J,"Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors." These tests are performed to verify the essentially leak tight characteristics of the primary containment at the design basis accident pressure.

The last Type A ILRT for LSCS Unit 2 was December 8, 1993.Option B, "Performance Based Requirements," of Appendix J to 10 CFR 50 requires that a Type A ILRT be conducted at a periodic interval based on historical performance of the overall primary containment system. LSCS TS 5.5.13 requires that a program be established to comply with the primary containment leakage rate testing requirements of 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option B, as modified by exemptions.

Additionally, this program is in accordance with the guidelines contained in RG 1.163, "Performance-Based Containment Leak-Testing Program," dated September 1995. RG 1.163 endorses, with certain exceptions, Nuclear Energy Institute (NEI) 94-01, Revision 0, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J," dated July 26, 1995.NEI 94-01 specifies an initial test interval of 48 months for a Type A ILRT and allows an extension of the interval to ten years based on two consecutive successful tests. In Reference 1, EGC submitted an LAR to defer the Type A ILRT schedule for LSCS Units 1 and 2 in anticipation of a rule change to 10 CFR 50 extending the Type A ILRT frequency to at least 15 years. The requested schedule deferral provided a proposed test date for each unit, consistent with a 15-year test schedule.

For LSCS Unit 2, the specified test date was changed to "no later than December 7, 2008." The NRC approved the LAR in Reference 3.Due to minor variations in refueling outage schedules since the original LAR submittal, the LSCS Unit 2 twelfth refueling outage (L2R12), in which the deferred Type A ILRT would be performed, will not start until March 2009. Approval of this LAR will enable LSCS Unit 2 to operate until L2R12.Page 3 ATTACHMENT 1 Evaluation of Proposed Changes 4.0 TECHNICAL ANALYSIS 4.1 Primary Containment Pressure Suppression Testing The function of the primary containment is to isolate and contain fission products released from the Primary Coolant System (PCS) following a design basis Loss of Coolant Accident (LOCA) and to confine the postulated release of radioactive material to within limits. The primary containment incorporates a drywell section and a suppression chamber section. The drywell is located over the suppression chamber and is separated by the drywell floor. The suppression chamber contains a pool of water. The drywell floor is penetrated by downcomers, penetrations, and safety/relief valve (SRV) discharge lines. The downcomers originate in the drywell air space and terminate below the water level of the suppression chamber pool of water. The SRV discharge lines originate at the SRVs located on the steam lines within the drywell and terminate below the water level of the suppression chamber pool of water. The floor penetrations have blind flanges installed during plant operation.

The Drywell-Suppression Chamber Vacuum Breakers are vacuum relief valves that are located outside the primary containment in special piping and form an extension of the primary containment boundary.

The vacuum breakers connect the drywell airspace and suppression chamber airspace to prevent exceeding the drywell floor negative differential design pressure and backflooding of the suppression pool water into the drywell.During a LOCA, the downcomers direct steam from the drywell airspace to below the water level of the suppression chamber pool of water to condense the steam and thus, limit the containment pressure response.

Steam that enters the suppression chamber air space directly from the drywell airspace will bypass the condensing capabilities of the suppression chamber pool of water, thereby causing a higher containment pressure response.

The drywell-to-suppression chamber bypass leakage test verifies that the total bypass leakage between the drywell airspace and suppression chamber airspace is consistent with analysis assumptions.

In a license amendment dated November 7, 2001, the NRC approved TS revisions to the scheduling of the drywell-to-suppression chamber bypass leakage test and the drywell-to-suppression chamber vacuum breaker leakage test. The amendment requires the drywell-to-suppression chamber bypass leakage test to be conducted on a ten-year frequency and the drywell-to-suppression chamber vacuum breaker leakage tests to be conducted on a 24-month frequency.

The proposed changes do not modify either of these test frequencies, as the next required testing of the drywell-to-suppression chamber bypass leakage test is consistent with the proposed changes and the drywell-to-suppression chamber vacuum breaker leakage test is conducted independently of the Type A ILRT primary containment test.Additionally, the proposed changes do not modify the acceptance criteria of either of these tests.Page 4 ATTACHMENT 1 Evaluation of Proposed Changes Therefore, the proposed changes do not modify the current test frequencies or test acceptance criteria of the primary containment pressure suppression components and systems.4.2 10 CFR 50, Appendix J, Option B The testing requirements of 10 CFR 50, Appendix J provide assurance that leakage through the primary containment, including systems and components that penetrate the primary containment, does not exceed allowable leakage rate values specified in the TS and Bases. The allowable leakage rate is limited such that the leakage assumptions in the safety analyses are not exceeded.

The limitation of primary containment leakage provides assurance that the primary containment would perform its design function following an accident, up to and including the design basis accident.10 CFR 50, Appendix J was revised, effective October 26, 1995, to allow licensees to choose primary containment leakage testing under Option A, "Prescriptive Requirements," or Option B. Amendments Nos. 110 and 95 for Units 1 and 2, respectively, were issued to permit implementation of 10 CFR 50, Appendix J, Option B.TS 5.5.13 currently requires the establishment of a Primary Containment Leakage Testing Program in accordance with 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions.

This program implements the guidelines contained in RG 1.163 which specifies a method acceptable to the NRC for complying with Option B by approving the use of NEI 94-01, subject to several regulatory positions stated in RG 1.163.10 CFR 50, Appendix J, Section V. B specifies that RG 1.163, or other implementing documents used to develop a performance-based leakage testing program must be included, by general reference, in the plant's TS. Additionally, deviations from guidelines endorsed in a regulatory guide are to be submitted as a revision to the plant's TS.Therefore, this application does not require an exemption from 10 CFR 50, Appendix J, Option B.The adoption of the Option B performance-based primary containment leakage rate testing program by LSCS did not alter the basic method by which Appendix J leakage rate testing is performed or its acceptance criteria, but it did alter the test frequency of primary containment leakage in Type A, B, and C tests. The required testing frequency is based upon an evaluation which utilizes the "as found" leakage history to determine the frequency for leakage testing which provides assurance that leakage limits will be maintained.

The allowable frequency for Type A ILRT is based, in part, upon a generic evaluation documented in NUREG-1493, "Performance-Based Leak-Test Program." NUREG-1493 made the following observations with regard to changing the test frequency:

Reducing the Type A ILRT frequency to once per twenty years was found to lead to an imperceptible increase in risk. The estimated increase in risk is small because Type A ILRTs identify only a few potential leakage paths that cannot be identified by Type B and C testing, and the leaks that have been found by Type A ILRTs have Page 5 ATTACHMENT 1 Evaluation of Proposed Changes only been marginally above the existing requirements.

Given the insensitivity of risk to primary containment leakage rate, and the same fraction of leakage detected solely by Type A ILRTs, increasing the interval between Type A ILRTs had minimal impact on public risk.While Type B and C tests identify the vast majority (i.e., greater than 95%) of all potential leakage paths, performance-based alternatives are feasible without significant risk impacts. Since leakage contributes less than 0.1 percent of overall risk under existing requirements, the overall effect is very small.The required surveillance frequency for Type A ILRTs in NEI 94-01 is at least once per ten years based on an acceptable performance history (i.e., two consecutive periodic Type A ILRTs at least 24 months apart or refueling cycles where the calculated performance leakage rate was less than 1.0 La) and consideration of the performance factors in NEI 94-01, Section 11.3. In November 2003, the NRC approved a one-time deferral of the Type A ILRT schedule for LSCS Units 1 and 2 in anticipation of a rule change to 10 CFR 50 by extending the Type A ILRT frequency to at least 15 years. The schedule deferral provided a test date for each unit, consistent with a 15-year test schedule.

For LSCS Unit 2, the specified test date was changed to "no later than December 7, 2008." This proposed change requests a one-time extension of the 15-year test schedule due to minor variations in refueling outage schedules since the approval of the 15-year test schedule.4.3 Integrated Leak Rate History Type A ILRT testing is performed to verify the integrity of the containment structure in its Loss of Coolant Accident (LOCA) configuration.

Industry test experience has demonstrated that Type B and C tests detect a large percentage of containment leakage and that the percentage of containment leakage detected only by integrated containment leakage testing is very small. Results of previous LSCS Unit 2 ILRTs demonstrate that the LSCS Unit 2 containment structure remains essentially a leak tight barrier and represents minimal risk to increased leakage. These plant specific results support the conclusions of NUREG-1493.

4.4 Type B and C Testing Type B and C testing assures containment penetrations such as flanges, sealing mechanisms and containment isolation valves are essentially leak tight. Type B and C tests identify the vast majority of all potential leakage paths.The most recent Type B LLRT tests of LSCS Unit 2 seals and gaskets resulted in a measured leakage of 0.0017 La, while the most recent Type C tests of LSCS Unit 2 valves resulted in a measured leakage of 0.1903 La. Therefore, the most recent Type B and Type C tests resulted in a total leakage of 0.192 La compared to the maximum allowable Type B and Type C leakage of 0.60 La.Page 6 ATTACHMENT 1 Evaluation of Proposed Changes In Reference 2, EGC provided a response to an NRC RAI question regarding the Type B examination schedule for seals, gaskets and pressure retaining bolts. As stated in Reference 2, the initial test frequency for performing a leak test on seals and gaskets, which are Type B components, is a base interval of 30 months. The interval may be extended to up to 120 months based on acceptable performance.

Acceptable performance for extending this interval is established by passing two as-found LLRTs with leakage less than or equal to the established administrative limits and that are at least 24 months apart or a normal refueling interval.

Type B components whose test intervals are extended to greater than 60 months are tested on a staggered basis to allow for early detection of common mode failure mechanism.

If a test result is greater than the administrative limit for the components, the test interval is re-established at 30 months. Additionally, any repair or disassembly of a component with a seal, gasket, or bolted connection requires a post-maintenance Appendix J Type B test. The proposed license amendment does not affect the current examination schedule of these components.

In a License Amendment dated October 14, 2004, the NRC approved a TS revision that allowed LSCS to test potential valve atmospheric leakage paths (i.e., valve stem packing for valves that are not exposed to reverse direction Type B or C leakage test pressure)during the regularly scheduled Type A ILRT.The Type B and C testing requirements at LSCS will not be changed as a result of the proposed license amendment.

4.5 Containment

Inspections

4.5.1 Appendix

J Visual Inspections As part of the Appendix J Program, LSCS performs visual inspections of accessible interior and exterior surfaces of the containment system for structural problems that may affect either the containment structural leakage integrity or performance of the Type A ILRT Test. These examinations are conducted prior to initiating a Type A ILRT test, and during two other refueling outages before the next Type A ILRT test, based on a ten-year frequency.

EGC conducted visual inspections of the accessible interior and exterior surfaces of the Unit 2 containment system during the tenth Unit 2 refueling outage (L2R10) in March 2005.These included visual inspections of submerged areas of the Suppression Pool.These visual inspections indicated that that there were no structural problems that could have affected the containment structural leakage integrity.

The inspection requirements and ten-year frequency will not be changed as a result of the proposed change.Page 7 ATTACHMENT 1 Evaluation of Proposed Changes 4.5.2 Containment Inservice Inspection Program A comprehensive primary containment inspection is performed in accordance with the requirements of American Society of Mechanical Engineers (ASME)Section XI, "Inservice Inspection," Subsections IWE, "Requirements for Class MC and Metallic Liners of Class CC Components of Light-Water Cooled Power Plants," and Subsection IWL, "Requirements of Class CC Concrete Components of Light-Water Cooled Power Plants." The LSCS Containment Inservice Inspection (CISI) Program was developed in accordance with the 1992 Edition, 1992 Addenda of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code, Section X1, Subsection IWE and IWL, as modified by NRC final rulemaking to 10 CFR 50.55a published in the Federal Register on August 8, 1996. The first CISI interval plan was developed based on the 1992 Edition, 1992 Addenda of the ASME code. The NRC, in Reference 7, approved the use of the 1998 Edition of the ASME code, as supplemented by EGC commitments, as an approved alternative to the 1992 Edition, 1992 Addenda of the ASME code for the first containment inspection interval.

The NRC approval did not require the initiation of a new interval and the thus the 1992 Edition, 1992 Addenda is considered the code of record for the first interval.

The supplemental LSCS commitments identified in the granted relief are of a similar nature to the modifications and limitations in 10 CFR 50.55a(b)(2) for the 1998 Edition through the 2000 Addenda of the Code. The LSCS commitments and the NRC approval are documented in References 4, 5, 6, and 7.The LSCS CISI was established in 1996 and the initial inspections were completed for both LSCS units by September 2001. The containment components subject to inspection are associated with the leak tight barrier including integral attachments and structural integrity.

The program also inspects the Class MC pressure retaining components, including metallic shell and penetration liners of Class CC pressure retaining components and their integral attachments.

As stated above, future CISI inspections will be performed to the 1998 Edition of the ASME Code Section XI, Subsections IWE and IWL as modified by approved NRC relief requests.During the initial inspections of the Units 1 and 2 concrete containments, various indications were observed, documented and evaluated.

All findings were determined to be acceptable and no loss of structural integrity of containment was observed.

The following provides a summary of the inspection findings for the LSCS Unit 2 initial baseline inspections, as well as the acceptance criteria.LSCS Unit 2 Initial Baseline Inspection Findings Cracks in Concrete -Horizontal cracks were the majority of the cracks observed with some pattern/vertical cracks. These cracks are normal shrinkage cracks for concrete walls. One significant crack (3/4 inch wide)observed in a corbel but does not impact the capacity of the containment or Page 8 ATTACHMENT 1 Evaluation of Proposed Changes reactor building was recommended for repair to prevent reinforcing steel degradation.

The cracks reported ranged from 1-1/2 inch to 20 feet long by 0.015 to 0.030 inch wide and determined to be acceptable." Concrete Spalling, Popouts and Voids -Various concrete spalls and popouts were observed.

The maximum spall dimension observed was 1/2 inch deep and three feet in length. The maximum void dimension observed was 1-1/2 inches deep and two inches in diameter.

All spalls, popouts and voids were determined to be acceptable." Concrete Coating and Staining -Containment coating was found to be in generally good condition.

Peeling and cracking of coating was observed to be minimal. Staining of the concrete walls due to minor grease leakage from tendon cans was subsequently cleaned. The coating and staining were determined to be acceptable.

Acceptance Criteria The acceptance criteria used for concrete are in accordance with Subsection IWL-3000 of the ASME code. As discussed in the NRC Safety Evaluation in Reference 7, LSCS's general and detailed visual examination procedures have been developed from the guidelines of ACI 201.1 R-92, "Guide For Making a Condition Survey of Concrete in Service," and ACI 349.3R-96, "Evaluation of Existing Nuclear Safety-Related Concrete Structures." These procedures follow a tiered approach for recording of concrete degradation.

If the recording criteria are exceeded, further review is required by the Responsible Engineer.The LSCS Responsible Engineer found the condition of the concrete surface acceptable with no evidence of damage or degradation sufficient to warrant further evaluation.

This evaluation included the corbel crack identified above.Thus, no inspection of any reinforcing bar was performed.

LSCS Unit 2 Subsequent Inspection In June 2005, EGC completed the second periodic inspection of the LSCS Unit 2 Primary Containment.

This inspection utilized an NRC-approved relief request which enabled EGC to use the 1998 Edition, No Addenda of ASME Section XI Subsection IWL, in lieu of the 1992 Edition with 1992 Addenda. The second inspection was performed by conducting a line-by-line comparison of observations that were found in the initial baseline inspection.

Additionally, EGC documented any new indication that may have occurred after the initial inspection.

Various indications were observed and documented.

EGC evaluated all indications and determined that these indications were acceptable, and did not represent a loss of structural integrity.

There will be no change to the schedule for these inspections as a result of the proposed changes. EGC will conduct CISI inspections of the Unit 2 containment Page 9 ATTACHMENT 1 Evaluation of Proposed Changes system during the eleventh Unit 2 refueling outage (L2R1 1), scheduled to begin in February 2007.4.5.3 Coatings Inspections The containment coatings inspection program was developed in accordance with the requirements of the 1998 ASME Code Edition of Subsection IWE and IWL as supplemented by specific details contained in the CISI. The inspection results for Unit 2, performed in November 2000, found the containment coatings to be in good condition with no observed extensive coating indications.

The inspections did identify some minor physical damage on various containment liners and other surfaces.

The damage was characterized as small chips in the topcoat causing exposure of the primer coating. In areas where this type of indication was observed, the primer is intact, with no rusting of the substrate.

The inspection requirements of the containment coatings program will not be changed as a result of the proposed changes, including scheduled coating inspections during L2R1 1, which is scheduled to begin in February 2007.4.5.4 Maintenance Rule Inspections Maintenance Rule Baseline Inspections required by 10 CFR 50.65, Requirements for monitoring the effectiveness of maintenance at nuclear power plants," were completed in March of 1999. The inspections included the Reactor Buildings and Containment Structures.

It was concluded that these structures are being adequately maintained and capable of performing their intended functions.

This program ensures that containment structures are evaluated and maintained in conditions to perform their intended functions.

There will be no changes to the Maintenance Rule Program as a result of the proposed changes.4.6 Information Notice 92-20 NRC Information Notice 92-20, "Inadequate Local Leak Rate Testing," discussed the inadequate local leak rate testing of two-ply stainless steel bellows. LaSalle County Station does not have any bellows that act as a part of the containment.

4.7 Post-tensioned Containment Tendon Inspections During in-service inspection of post-tensioned containment tendons in 2003, EGC identified a non-conforming condition on LSCS Unit 1 due to water-induced corrosion of containment tendons, caused by the failure of water intrusion barriers.

In response to this non-conforming condition, EGC has implemented actions to: 1) repair the non-conforming condition;

2) evaluate the extent of condition to LSCS Unit 2; 3) resolve the root causes of the condition; and 4) expand the in-service inspection program for post-tensioned containment tendons. The in-service inspection schedule for post-tensioned containment tendons is normally once in five years. In response to the non-conforming Page 10 ATTACHMENT 1 Evaluation of Proposed Changes condition, EGC has increased the inspection frequency, such that the tendons will be inspected four times in the five years following identification of the non-conforming condition.

At the end of that period, EGC will evaluate the increased inspection frequency and identify the optimal frequency.

The post-tensioned containment tendon in-service inspection requirements will not be changed as a result of the proposed license amendment.

4.8 Risk Analysis EGC has conducted a risk assessment to determine the impact of a change to the LSCS Unit 2 Type A ILRT test schedule from a baseline ILRT frequency of three times in ten years to once in 16.25 years (i.e., 15 years plus 15 months) for the risk measures of Large Early Release Frequency (i.e., LERF), Total Population Dose, and Conditional Containment Failure Probability (i.e., CCFP). The risk assessment is provided in Attachment 4.In addition, this assessment also includes an estimate of the likelihood and the risk implications of corrosion-induced leakage of the steel containment liner occurring, and going undetected during the extended test interval.The impact of the analyzed extension to the LSCS Unit 2 Type A ILRT test schedule, as summarized below in Sections 4.8.1 through 4.8.4, is conservative with respect to the proposed extension.

The reference point used in the analysis was the baseline ILRT frequency of three times in ten years. In addition, the requested extension is significantly less than the analyzed extension of 15 months. Therefore, the proposed LSCS ILRT interval extension has a minimal impact on public risk, as summarized below.4.8.1 Risk Implications of Undetected Corrosion-Induced Leakage of Steel Liner The risk assessment provided in Attachment 4 includes an evaluation of the likelihood and risk implications of undetected corrosion-induced leakage of the steel liners during the extended test interval (i.e., 16.25 years). This evaluation utilized the same methodology used in the Calvert Cliffs liner corrosion analysis (i.e., Reference 8). The Calvert Cliffs analysis was performed for a concrete cylinder and dome and a concrete basemat, each with a steel liner. The LSCS primary containments are a pressure-suppression BWR/Mark II containment type that includes a steel-lined reinforced concrete structure.

The LSCS Unit 2 containment liner sections are completely welded together and anchored into the concrete.

There is no air space between the liner and the concrete structure.

The corrosion/oxidation effects associated with water being in contact with the carbon steel liner and the concrete reinforcing bars are minimized due to the lack of available oxygen between the concrete and the liner. Furthermore, the liner is intended to be a membrane and constitute a leak-Page 11 ATTACHMENT 1 Evaluation of Proposed Changes proof boundary for the drywell. The liner is nominally

'/4 inch thick and has been oversized to serve as formwork for concrete pouring during plant construction.

Key assumptions in this assessment were as follows.* Consistent with the Calvert Cliffs analysis, a half failure is assumed for basemat concealed liner corrosion due to the lack of identified failures." The two corrosion events used to estimate the liner flaw probability in the Calvert Cliffs analysis are assumed to be applicable to the LSCS containment analysis.

These events, one at North Anna Unit 2 and one at Brunswick Unit 2, were initiated from the non-visible (backside) portion of the containment liner." Consistent with the Calvert Cliffs analysis, the estimated historical flaw probability is calculated using a 5.5 year data period to reflect the years since September 1996 when 10 CFR 50.55a started requiring visual inspection.

Additional success data were not used to limit the aging impact of this corrosion issue, even though inspections were being performed prior to this date and there is no evidence that additional corrosion issues were identified." Consistent with the Calvert Cliffs analysis, the corrosion-induced steel liner flaw likelihood is assumed to double every five years. This is based solely on judgment and is included in this analysis to address the increased likelihood of corrosion as the steel liner ages. Sensitivity studies are included in the risk assessment that address doubling this rate every ten years and every two years.In the Calvert Cliffs analysis, the likelihood of the containment atmosphere reaching the outside atmosphere given that a liner flaw exists was estimated (based on an assessment of the containment fragility curve versus the ILRT pressure) as 1.1% for the containment walls and dome region and 0.11%(i.e., 1% of the cylinder failure probability) for the basemat. For LSCS the containment failure probabilities are conservatively assumed to be 1% for the drywell and wetwell outer walls, and since the basemat for the LSCS Mark I1 containment is in the suppression pool, it is judged that failure of this area would not lead to LERF. In any event, a 1% probability is assigned as a conservatism.

Consistent with the Calvert Cliffs analysis, a 5% visual inspection detection failure likelihood, given the flaw is visible, and a 10% likelihood of a non-detectable flaw are used. Again, this is considered conservative since essentially 100% of the LSCS containment interior surface is visible, whereas only 85% of the interior wall surface was estimated as being visible at Calvert Cliffs. Additionally, it should be noted that to date, all liner corrosion events have been detected through visual inspection.

Sensitivity studies are included in the risk assessment that evaluate total detection failure likelihood of 5% and 15%.Page 12 ATTACHMENT 1 Evaluation of Proposed Changes* Consistent with the Calvert Cliffs analysis, all non-detectable containment failures are assumed to result in early releases.

This approach avoids a detailed analysis of containment failure timing and operator recovery actions.4.8.2 LERF The Type A ILRT schedule extension from three times in ten years to once in 16.25 years resulted in an LERF increase of 3.1 E-8/yr(1). The contribution to the change in LERF due to the corrosion effects is 4.2E-1 0/yr. This value is well within the criteria for a "very small change" established by RG 1.174, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Current Licensing Basis" (i.e., 1.OE-07).4.8.3 Total Population Dose The Type A ILRT schedule extension from three times in ten years to once in 16.25 years resulted in an increase in total integrated plant risk (total population dose) for those accident sequences influenced by a Type A ILRT of 0.08 person-rem/yr(2). The contribution to the change in dose rate due to the corrosion effects is 2.4E-04 person-rem/yr.

This is an insignificant increase, relative to the original value of 6.524 person-rem/year.4.8.4 CCFP The Type A ILRT schedule extension from three times in ten years to once in 16.25 years resulted an increase of 0.45% in CCFP. This increase is insignificant relative to the original CCFP value of 85.66%.4.8.5 Station Blackout Applicability The results of the risk analysis that are provided in Attachment 4 assume that no long-term station blackout (SBO) scenarios contribute to LERF. This assumption is based on timing considerations and not on source magnitude.

The LSCS long-term station blackout core damage accidents (i.e., Class IBL) result in non-LERF releases based on release timing and not on release magnitude (i.e., LSCS IBL core damage accidents have the potential to result in the entire spectrum of release magnitudes, including high magnitude releases; however, they can not result in early releases).

The following discussion focuses on the timing issues of Class IBL scenarios.

(1) The change in LERF from the base case to the 16.25 year ILRT interval is 3.1E-8/yr (i.e., 3.7516E-08 (2 -6.87E-09).

The change in dose rate from the base case to the 16.25 year ILRT interval is 0.08 person-rem/yr (i.e., 6.60 person-rem/yr

-6.52 person-rem/yr).

Page 13 ATTACHMENT 1 Evaluation of Proposed Changes Typical of many industry Probabilistic Risk Assesments (PRAs), the LSCS PRA uses a radionuclide release categorization scheme comprised of two factors: release timing and release magnitude.

Three timing categories are used, as follows: Early (E): Intermediate (I): Late (L): Less than six hours;Greater than or equal to six hours, but less than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />;and Greater than or equal to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.The above accident release categories are based upon past experience concerning offsite accident response.* 0 -six hours is conservatively assumed to include cases in which minimal offsite protective measures have been observed to be performed in non-nuclear accidents.

• Six -24 hours is a time frame in which much of the offsite nuclear plant protective measures can be assured to be accomplished.

• >24 hours are times at which the offsite measures are assumed to be effective.

The timing categories are relative to the declaration of the LSCS General Emergency Action Level.The LSCS IBL accident scenarios include only those sequences in which high pressure injection (i.e., Reactor Core Isolation Cooling) is available initially in the accident but subsequently fails. The representative IBL sequence for LSCS is sequence LOOP-17 of the LOOP event tree. Sequence LOOP-17 proceeds as follows.Event Time After Plant Trip-Loss of Offsite Power initiating event 0-Failure of emergency AC power (EDGs) 0-Failure of HPCS 0-RCIC Initiation

-1 min.-RPV/containment parameters exceed HCTL curve 7 hrs.-Battery depletion 7 hrs.-Failure to blowdown (no DC power) 7 hrs.-Loss of RCIC (all) injection 7 hrs.-Time for RPV level to drop to TAF 8.8 hrs.-Time to core damage (1800F) 9.9 hrs.Time to energetic containment failure (fastest, but low -10 hrs.frequency, release scenario)As can be seen from the above scenario, the LSCS IBL accident class results in a radionuclide release no earlier than ten hours after the LOOP initiator.

The ten Page 14 ATTACHMENT 1 Evaluation of Proposed Changes hour release for the IBL core damage accident makes the conservative assumption that an early energetic containment failure mode (in-vessel corium-steam explosion) occurs at about the time of core melt and dislocation to the lower head (i.e., a low probability containment failure mode for the IBL accident).

LSCS procedure EP-AA-1 005, "Radiological Emergency Planning Annex for LaSalle Station," (i.e., Recognition Category MG1) directs declaration of a General Emergency (i.e., the emergency classification with associated directives for evacuation) for the following station blackout conditions:

Loss of power from TR-241 and TR-242,* Emergency diesel generators fail to supply power to buses 241Y and 242Y, and* Restoration of power to bus 241Y or 242Y within four hours is judged NOT likely.The loss of offsite and emergency power to buses 241 Y and 242Y occurs at t=0 for sequence LOOP-1 7. The LSCS PRA assumes that the determination that AC power is not likely to be restored in the four-hour time frame is made at approximately one hour into the accident.

As such, a General Emergency is declared at one hour into the event. The evacuation process would be initiated within minutes after the declaration, because LSCS procedure EP-AA-1 11,"Emergency Classification and Protective Action Recommendations," states that the local authorities must be notified within 15 minutes after the General Emergency declaration.

It is likely that the evacuation process would be completed within four hours based on site-specific evacuation studies for weather and times of day variations.

The earliest possible release for the IBL scenario occurs at approximately ten hours (i.e., approximately five hours after evacuation is expected to be completed).

Therefore, the IBL core damage accident is not an Early release.Although the inclusion of long-term station blackout (SBO) scenarios in the Electric Power Research Institute (EPRI) Category 3a and 3b frequency calculations would not be typical or consistent with the Nuclear Energy Institute (NEI) ILRT risk assessment methodology, EGC has conducted a sensitivity study based on questions raised in NRC Requests for Additional Information with respect to similar LARs. The results of the sensitivity study are provided below.Note that these results include the concealed containment flaw evaluation." The calculated increase in LERF associated with a change in the ILRT frequency from the three times in ten years to the once in 16.25 years is 3.94E-08/yr.

This value is well within the criteria for a "very small change" established by RG 1.174, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Current Licensing Basis" (i.e., 1.OE-07)." The calculated increase in population dose rate associated with a change in the ILRT frequency from the three times in ten years to the once in 16.25 Page 15 ATTACHMENT 1 Evaluation of Proposed Changes years is 1.OE-01 person-rem/yr, which is an increase of 1.5% above the three times in ten years value of 6.524 person-rem/yr.

The increase in the containment failure probability (CCFP) is determined to be 0.56% (i.e., 86.25% for the once in 16.25 years frequency versus 85.69%for the three times in ten years frequency).

The inclusion of long-term SBO scenarios does not change the overall conclusion of the risk assessment; that is, the LSCS Type A ILRT interval extension to once in 16.25 years has a minimal impact on plant risk.5.0 REGULATORY ANALYSIS 5.1 NO SIGNIFICANT HAZARDS CONSIDERATION Exelon Generation Company, LLC (EGC) has evaluated the proposed changes to the Technical Specifications (TS) for LaSalle County Station (LSCS), Unit 2, and has determined that the proposed changes do not involve a significant hazards consideration and is providing the following information to support a finding of no significant hazards consideration.

Does the change involve a significant increase in the probability or consequences of an accident previously evaluated?

Response:

No The proposed changes will revise LSCS, Unit 2, TS 5.5.13, "Primary Containment Leakage Rate Testing Program," to reflect a one-time extension of the primary containment Type A Integrated Leak Rate Test (ILRT) date to "prior to startup following L2R12." The current Type A ILRT interval of 15 years, based on past performance, would be extended on a one-time basis by approximately 2% of the current interval.The function of the primary containment is to isolate and contain fission products released from the reactor Primary Coolant System (PCS) following a design basis Loss of Coolant Accident (LOCA) and to confine the postulated release of radioactive material to within limits. The test interval associated with Type A ILRTs is not a precursor of any accident previously evaluated.

Type A ILRTs provide assurance that the LSCS Unit 2 primary containment will not exceed allowable leakage rate values specified in the TS and will continue to perform their design function following an accident.

The risk assessment of the proposed changes has concluded that there is an insignificant increase in total population dose rate and an insignificant increase in the conditional containment failure probability.

Therefore, the proposed changes do not involve a significant increase in the probability or consequences of an accident previously evaluated.

Page 16 ATTACHMENT 1 Evaluation of Proposed Changes Does the change create the possibility of a new or different kind of accident from any accident previously evaluated?

Response:

No The proposed changes for a one-time extension of the Type A ILRT for LSCS Unit 2 will not affect the control parameters governing unit operation or the response of plant equipment to transient and accident conditions.

The proposed changes do not introduce any new equipment, modes of system operation or failure mechanisms.

Therefore, the proposed changes do not create the possibility of a new or different kind of accident from any previously evaluated.

Does the change involve a significant reduction in a margin of safety?Response:

No LSCS Unit 2 is a General Electric BWR/5 plant with a Mark II primary containment.

The Mark II primary containment consists of two compartments, the drywell and the suppression chamber. The drywell has the shape of a truncated cone, and is located above the cylindrically shaped suppression chamber. The drywell floor separates the drywell and the suppression chamber. The primary containment is penetrated by access, piping and electrical penetrations.

The integrity of the primary containment penetrations and isolation valves is verified through Type B and Type C local leak rate tests (LLRTs) and the overall leak tight integrity of the primary containment is verified by a Type A ILRT, as required by 10 CFR 50, Appendix J, "Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors." These tests are performed to verify the essentially leak tight characteristics of the primary containment at the design basis accident pressure.

The proposed changes for a one-time extension of the Type A ILRTs do not affect the method for Type A, B or C testing or the test acceptance criteria.EGC has conducted a risk assessment to determine the impact of a change to the LSCS Unit 2 Type A ILRT schedule from a baseline ILRT frequency of three times in ten years to once in 16.25 years (i.e., 15 years plus 15 months) for the risk measures of Large Early Release Frequency (i.e., LERF), Total Population Dose, and Conditional Containment Failure Probability (i.e., CCFP). This assessment indicated that the proposed LSCS ILRT interval extension has a minimal impact on public risk.Therefore, the proposed changes do not involve a significant reduction in a margin of safety.Based upon the above, EGC concludes that the proposed amendment presents no significant hazards consideration under the standards set forth in 10 CFR50.92(c), and, accordingly, a finding of "no significant hazards consideration" is justified.

Page 17 ATTACHMENT 1 Evaluation of Proposed Changes 5.2 REGULATORY REQUIREMENTS AND CRITERIA 10 CFR 50.36, 'Technical specifications," provides the regulatory requirements for the content required in a plant's Technical Specifications (TS). 10 CFR 50.36(c)(5),"Administrative controls," requires provisions relating to organization and management, procedures, recordkeeping, review and audit, and reporting necessary to assure operation of the facility in a safe manner will be included in a plant's TS.Additionally, 10 CFR 50, Appendix J, Section V. B, "Implementation," specifies that the regulatory guide or other implementing documents used to develop a performance-based leakage testing program must be included, by general reference, in the plant's TS.Additionally, deviations from guidelines endorsed in a regulatory guide are to be submitted as a revision to the plant's TS.The proposed changes will revise TS Section 5.5.13 to reflect a one-time extension from the program requirements for the Type A ILRT for LaSalle County Station (LSCS) Unit 2.The one-time extension deviates from the guidelines contained in Regulatory Guide (RG)1.163 and NEI 94-01. Thus, the proposed changes are consistent with the requirements of 10 CFR 36(c)(5) and 10 CFR 50, Appendix J, Section V. B.Additionally, in accordance with 10 CFR 50, Appendix J, Section V. B, the proposed changes to LSCS TS do not require a supporting request for an exemption to Option B of Appendix J, in accordance with 10 CFR 50.12, "Specific exemptions." 6.0 ENVIRONMENTAL CONSIDERATION EGC has evaluated this proposed operating license amendment consistent with the criteria for identification of licensing and regulatory actions requiring environmental assessment in accordance with 10 CFR 51.21, "Criteria for and identification of licensing and regulatory actions requiring environmental assessments." EGC has determined that this proposed change meets the criteria for categorical exclusion set forth in paragraph (c)(9) of 10 CFR 51.22, "Criterion for categorical exclusion; identification of licensing and regulatory actions eligible for categorical exclusion or otherwise not requiring environmental review," and as such, has determined that no irreversible consequences exist in accordance with paragraph (b) of 10 CFR 50.92, "Issuance of amendment." This determination is based on the fact that this change is being processed as an amendment to the license issued pursuant to 10 CFR 50, "Domestic Licensing of Production and Utilization Facilities," which changes a requirement with respect to installation or use of a facility component located in the restricted area, as defined in 10 CFR 20, "Standards for Protection Against Radiation," or which changes an inspection or surveillance requirement and the amendment meets the following criteria: Page 18 ATTACHMENT 1 Evaluation of Proposed Changes (I) The amendment involves no significant hazards consideration.

As demonstrated in Section 5.1 above, "No Significant Hazards Consideration," the proposed change does not involve any significant hazards consideration.(ii) There is no significant change in the types or significant increase in the amounts of any effluent that may be released offsite, or significant increase in individual or cumulative occupational radiation exposure The proposed changes will revise LSCS, Unit 2, TS 5.5.13, "Primary Containment Leakage Rate Testing Program," to reflect a one-time extension of the primary containment Type A ILRT date to "prior to startup following L2R12." The current Type A ILRT interval of 15 years, based on past performance, would be extended on a one-time basis by approximately 2% of the current interval.EGC has conducted a risk assessment to determine the impact of a change to the LSCS Unit 2 Type A ILRT schedule from a baseline ILRT frequency of three times in ten years to once in 16.25 years (i.e., 15 years plus 15 months) for the risk measures of Large Early Release Frequency (i.e., LERF), Total Population Dose, and Conditional Containment Failure Probability (i.e., CCFP). This assessment indicated that the proposed LSCS ILRT interval extension has a minimal impact on LERF and Total Population Dose.Based on the above assessment, the proposed change will not result in a significant change in the types or significant increase in the amounts of any effluent released offsite, or a significant increase in individual or cumulative occupational radiation exposure.7.0 PRECEDENT The proposed amendment incorporates into the LSCS TS changes that are similar to changes approved by the NRC for St. Lucie Station on December 23, 2005, River Bend Station on February 9, 2006, and Seabrook Station on March 24, 2006.

8.0 REFERENCES

(1) Letter from K. R. Jury (Exelon Generation Company, LLC (EGC)) to USNRC, "Request for Amendment to Technical Specifications Section 5.5.13, 'Primary Containment Leakage Rate Testing Program'," dated October 24, 2002 (2) Letter from T. W. Simpkin (EGC) to USNRC, "Response to Request for Additional Information to Support Request for Amendment to Technical Specifications Section 5.5.13, 'Primary Containment Leakage Rate Testing Program'," dated June 20, 2003 Page 19 ATTACHMENT 1 Evaluation of Proposed Changes (3) Letter from W. A. Macon, Jr. (USNRC) to J. L. Skolds (EGC), "LaSalle County Station, Units 1 and 2, Issuance of Amendments Re: Integrated Leakage Rate Test Interval," dated November 19, 2003 (4) Letter from R. M. Krich (CoinEd) to USNRC, "Request for Inservice Inspection Program relief Regarding Containment Inspections By Approved Alternate Means," dated May 8, 2000 (5) Letter from R. M. Krich (CornEd) to USNRC, "Response to Request for Additional Information Concerning Inservice Inspection Program Relief Regarding Containment Inspections By Approved Alternate Means," dated August 18, 2000 (6) Letter from R. M. Krich (CoinEd) to USNRC, "Supplemental Response to Request for Additional Information Concerning Inservice Inspection Program Relief Regarding Containment Inspections By Approved Alternate Means," dated August 30, 2000 (7) Letter from A. J. Mendiola (USNRC) to 0. D. Kingsley (ComEd), "Byron, Dresden and LaSalle -Evaluation of Relief Requests:

Use of 1998 Edition of Subsections IWE and IWL of the ASME Code for Containment Inspection," dated September 18, 2000.(8) Letter from C. H. Cruse (Calvert Cliffs Nuclear Power Plant) to USNRC, Response to Request for Additional Information Concerning the License Amendment Request for a One-Time Integrated Leakgae Rate Test Extension," dated March 27, 2002.Page 20 ATTACHMENT 2 MARKUP OF PROPOSED TECHNICAL SPECIFICATION PAGE CHANGES Revised TS Pages 5.5-13 Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.13 Primary Containment Leakage Rate Testing Program (continued)

2. NEI 94-01 -1995, Section 9.2.3: The first Unit 2 Type A test performed after December 8, 1993 T_ A test-av-r shall be pefre 3. The potential valve atmospheric leakage paths that are not exposed to reverse direction test pressure shall be tested during the regularly scheduled Type A test. The program shall contain the list of the potential valve atmospheric leakage paths, leakage rate measurement method, and acceptance criteria.

This exception shall be applicable only to valves that are not isolable from the primary containment free air space.b. The peak calculated primary containment internal pressure for the design basis loss of coolant accident, Pa, is 39.9 psig.c. The maximum allowable primary containment leakage rate, La, at P,, is 0.635% of primary containment

• air weight per day.d. Leakage rate acceptance criteria are: 1. Primary containment overall leakage rate acceptance criterion is < 1.0 La. During the first unit startup following testing in accordance with this program, the leakage rate acceptance criteria are 0.60 La for the combined Type B and Type C tests, and < 0.75 La for Type A tests.2. Air lock testing acceptance criteria are: a) Overall air lock leakage rate is < 0.05 La when tested at Pa.b) For each door, the seal leakage rate is s 5 scf per hour when the gap between the door seals is pressurized to 10 psig.e. The provisions of SR 3.0.3 are applicable to the Primary Containment Leakage Rate Testing Program.LaSalle 1 and 2 5.5-13 Amendment No /I ATTACHMENT 3 RETYPED PAGE FOR TECHNICAL SPECIFICATION CHANGES Retyped TS Pages 5.5-13 Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.13 Primary Containment Leakage Rate Testing Program (continued)

2. NEI 94-01 -1995, Section 9.2.3: The first Unit 2 Type A test performed after December 8, 1993 Type A test shall be performed prior to startup following L2R12.3. The potential valve atmospheric leakage paths that are not exposed to reverse direction test pressure shall be tested during the regularly scheduled Type A test. The program shall contain the list of the potential valve atmospheric leakage paths, leakage rate measurement method, and acceptance criteria.

This exception shall be applicable only to valves that are not isolable from the primary containment free air space.b. The peak calculated primary containment internal pressure for the design basis loss of coolant accident, P,, is 39.9 psig.c. The maximum allowable primary containment leakage rate, La, at P,, is 0.635% 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 L, for the combined Type B and Type C tests, and < 0.75 L, for Type A tests.2. Air lock testing acceptance criteria are: a) Overall air lock leakage rate is 0.05 L, when tested at > Pa_b) For each door, the seal leakage rate is 5 scf per hour when the gap between the door seals is pressurized to 10 psig.e. The provisions of SR 3.0.3 are applicable to the Primary Containment Leakage Rate Testing Program.LaSalle 1 and 2 5.5-13 Amendment No.XXX/XXX ATTACHMENT 4 LaSalle ILRT Interval Extension Risk Assessment