NL-16-0626, License Amendment Request to Revise Technical Specification Section 5.5.12 for Permanent Extension of Type a and Type C Leak Rate Test Frequencies: Difference between revisions
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==6.0 REFERENCES== | ==6.0 REFERENCES== | ||
Attachments: | Attachments: | ||
: 1. Technical Specifications Pages Markups 2. Bases Page Markups (For Information Only) 3. Plant Hatch Units 1 & 2 Risk Assessment to Support ILRT (Type A) Interval Extension Request 4. Technical Specifications Pages Clean Copies Hatch Nuclear Plant Units 1 and 2 1.0 | : 1. Technical Specifications Pages Markups 2. Bases Page Markups (For Information Only) 3. Plant Hatch Units 1 & 2 Risk Assessment to Support ILRT (Type A) Interval Extension Request 4. Technical Specifications Pages Clean Copies Hatch Nuclear Plant Units 1 and 2 1.0 | ||
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* Adopt an extension of the containment isolation valve (CIV) leakage testing (Type C) frequency from the 60 months currently permitted by 10 CFR 50, Appendix J, 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. | * Adopt an extension of the containment isolation valve (CIV) leakage testing (Type C) frequency from the 60 months currently permitted by 10 CFR 50, Appendix J, 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. | ||
* Adopt the use of American National Standards Institute/American Nuclear Society (ANSI/ANS) 56.8-2002, Containment System Leakage Testing Requirements. | * Adopt the use of American National Standards Institute/American Nuclear Society (ANSI/ANS) 56.8-2002, Containment System Leakage Testing Requirements. | ||
* Adopt a more conservative grace interval of 9 months, for Type A, Type B and Type C leakage tests in accordance with NEI 94-01, Revision 3-A. The proposed change to the TS contained herein would revise HNP TS 5.5.12, by replacing the references to Regulatory Guide (RG) 1.163, Performance-Based Containment Leak-Test Program, (Reference | * Adopt a more conservative grace interval of 9 months, for Type A, Type B and Type C leakage tests in accordance with NEI 94-01, Revision 3-A. The proposed change to the TS contained herein would revise HNP TS 5.5.12, by replacing the references to Regulatory Guide (RG) 1.163, Performance-Based Containment Leak-Test Program, (Reference | ||
: 1) and 10 CFR 50, Appendix J, Option B with a reference to NEI topical report NEI 94-01, Revision 3-A (Reference 2), dated July 2012, and the conditions and limitations specified in NEI 94-01, Revision 2-A (Reference 8), dated October 2008, as the documents used by HNP to implement the performance-based leakage testing program in accordance with Option B of 1 O CFR 50, Appendix J. This license amendment request (LAR) also proposes the following administrative changes to TS 5.5.12: | : 1) and 10 CFR 50, Appendix J, Option B with a reference to NEI topical report NEI 94-01, Revision 3-A (Reference 2), dated July 2012, and the conditions and limitations specified in NEI 94-01, Revision 2-A (Reference 8), dated October 2008, as the documents used by HNP to implement the performance-based leakage testing program in accordance with Option B of 1 O CFR 50, Appendix J. This license amendment request (LAR) also proposes the following administrative changes to TS 5.5.12: | ||
* Deleting the information regarding the performance of the next HNP Unit 1 and Unit 2 Type A test to be performed no later than April 2008 for Unit 1 and no later than November 2010 for Unit 2, as both Type A tests have already occurred. | * Deleting the information regarding the performance of the next HNP Unit 1 and Unit 2 Type A test to be performed no later than April 2008 for Unit 1 and no later than November 2010 for Unit 2, as both Type A tests have already occurred. | ||
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* Deleting the information regarding the performance of the next HNP Unit 1 Type A test no later than April 2008 and the next HNP Unit 2 Type A test no later than November 2010, as both Type A tests have already occurred. | * Deleting the information regarding the performance of the next HNP Unit 1 Type A test no later than April 2008 and the next HNP Unit 2 Type A test no later than November 2010, as both Type A tests have already occurred. | ||
The proposed change will revise TS 5.5.12 to state, in part: Enclosure Page 4 of 81 "A program shall be established to implement the leakage testing of the containment as required by 10 CFR 50.54(0) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. | The proposed change will revise TS 5.5.12 to state, in part: Enclosure Page 4 of 81 "A program shall be established to implement the leakage testing of the containment as required by 10 CFR 50.54(0) 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." Markups of TS 5.5.12 for both HNP Units 1 and 2 are provided in Attachment | 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." Markups of TS 5.5.12 for both HNP Units 1 and 2 are provided in Attachment | ||
: 1. Markups of TS Bases for SR 3.6.1.1 Primary Containment, and SR 3.6.1.1.1 for both HNP Units 1 and 2 are provided in Attachment 2 for informational purposes only. Based upon approval of this LAR, these TS Bases changes will be implemented in accordance with the TS Bases Control Program. Attachment 3 contains the plant specific risk assessment conducted to support this proposed change. This risk assessment followed the guidelines of NRC RG 1.17 4, Revision 2 (Reference | : 1. Markups of TS Bases for SR 3.6.1.1 Primary Containment, and SR 3.6.1.1.1 for both HNP Units 1 and 2 are provided in Attachment 2 for informational purposes only. Based upon approval of this LAR, these TS Bases changes will be implemented in accordance with the TS Bases Control Program. Attachment 3 contains the plant specific risk assessment conducted to support this proposed change. This risk assessment followed the guidelines of NRC RG 1.17 4, Revision 2 (Reference | ||
: 3) and NRC RG 1.200, Revision 2 (Reference 4). The risk assessment concluded that increasing the ILRT interval to 15 years is considered to represent an insignificant change in risk for HNP. 3.0 TECHNICAL EVALUATION | : 3) and NRC RG 1.200, Revision 2 (Reference 4). The risk assessment concluded that increasing the ILRT interval to 15 years is considered to represent an insignificant change in risk for HNP. 3.0 TECHNICAL EVALUATION | ||
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====3.1.1 Drywall==== | ====3.1.1 Drywall==== | ||
The drywall is a steel pressure vessel with a spherical lower portion 65 feet (ft.) in diameter and a cylindrical upper portion 35 ft. 7 inches (in.) in diameter for Unit 1 and 37 ft 1 in. in diameter for Unit 2. The overall height of the drywall is approximately 111 ft. The design, fabrication, inspection, and testing of the Unit 1 drywall comply with the requirements of the American Society of Mechanical Engineers (ASME) Code, Section Ill, Subsection 8, Requirements for Class 8 Vessels, which pertains to containment vessels for nuclear power stations. | The drywall is a steel pressure vessel with a spherical lower portion 65 feet (ft.) in diameter and a cylindrical upper portion 35 ft. 7 inches (in.) in diameter for Unit 1 and 37 ft 1 in. in diameter for Unit 2. The overall height of the drywall is approximately 111 ft. The design, fabrication, inspection, and testing of the Unit 1 drywall comply with the requirements of the American Society of Mechanical Engineers (ASME) Code, Section Ill, Subsection 8, Requirements for Class 8 Vessels, which pertains to containment vessels for nuclear power stations. | ||
The primary containment is fabricated of SA-516 grade 70 plates. The design, fabrication, inspection, and testing of the Unit 2 drywall vessel comply with requirements of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code, Section Ill, Nuclear Power Plant Components, Subsection NE, Requirements for Class MC Components, 1971 Edition, including 1971 Summer Addenda which pertain to containment vessels for nuclear power plants. The steel head and shell of the drywall are fabricated of SA-516 GR70 steel plate. The Unit 1 drywall is designed for an internal pressure of 56 pounds per square inch gage (psig) coincident with a temperature of 281 degrees Fahrenheit | The primary containment is fabricated of SA-516 grade 70 plates. The design, fabrication, inspection, and testing of the Unit 2 drywall vessel comply with requirements of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code, Section Ill, Nuclear Power Plant Components, Subsection NE, Requirements for Class MC Components, 1971 Edition, including 1971 Summer Addenda which pertain to containment vessels for nuclear power plants. The steel head and shell of the drywall are fabricated of SA-516 GR70 steel plate. The Unit 1 drywall is designed for an internal pressure of 56 pounds per square inch gage (psig) coincident with a temperature of 281 degrees Fahrenheit | ||
(°F) for Unit 1 and 340 °F for Unit 2, with applicable dead, live, and seismic loads imposed on the shell. Thermal stresses in the steel shell due to temperature gradients are also incorporated into the design. Thus, in accordance with the ASME Code, Section Ill, the maximum drywall pressure is 62 psig. Charpy V-notch impact tests were performed on specimens of all plate and forged materials. | (°F) for Unit 1 and 340 °F for Unit 2, with applicable dead, live, and seismic loads imposed on the shell. Thermal stresses in the steel shell due to temperature gradients are also incorporated into the design. Thus, in accordance with the ASME Code, Section Ill, the maximum drywall pressure is 62 psig. Charpy V-notch impact tests were performed on specimens of all plate and forged materials. | ||
Plates, forgings, and pipes of the drywall have an initial nil ductility transition temperature (NOTT) of -0°F when tested in accordance with the appropriate code for these materials. | Plates, forgings, and pipes of the drywall have an initial nil ductility transition temperature (NOTT) of -0°F when tested in accordance with the appropriate code for these materials. | ||
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Appendix J identifies three types of required tests: 1) Type A tests, intended to measure the primary containment overall integrated leakage rate; 2) Type B tests, intended to detect local leaks and to measure leakage across pressure-containing or leakage limiting boundaries (other than valves) for primary containment penetrations, and; 3) Type C tests, intended to measure containment isolation valve leakage rates. Types B and C tests identify the vast majority of potential containment leakage paths. Type A tests identify the overall (integrated) containment leakage rate and serve to ensure continued leakage integrity of the containment structure by evaluating those structural parts of the containment not covered by Type B and C testing. In 1995, 10 CFR 50, Appendix J, "Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors," was amended to provide a performance-based Option B for the containment leakage testing requirements. | Appendix J identifies three types of required tests: 1) Type A tests, intended to measure the primary containment overall integrated leakage rate; 2) Type B tests, intended to detect local leaks and to measure leakage across pressure-containing or leakage limiting boundaries (other than valves) for primary containment penetrations, and; 3) Type C tests, intended to measure containment isolation valve leakage rates. Types B and C tests identify the vast majority of potential containment leakage paths. Type A tests identify the overall (integrated) containment leakage rate and serve to ensure continued leakage integrity of the containment structure by evaluating those structural parts of the containment not covered by Type B and C testing. In 1995, 10 CFR 50, Appendix J, "Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors," 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. | 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 Enclosure Page 11 of 81 failure. The use* of the term "performance-based" in 1 O 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 8. Also in 1995, RG 1.163 (Reference | Performance-based test intervals are based on consideration of the operating history of the component and resulting risk from its Enclosure Page 11 of 81 failure. The use* of the term "performance-based" in 1 O 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 8. Also in 1995, RG 1.163 (Reference | ||
: 1) was issued. The RG endorsed NEI 94-01, Revision 0, (Reference | : 1) was issued. The RG endorsed NEI 94-01, Revision 0, (Reference | ||
: 5) with certain modifications and additions. | : 5) with certain modifications and additions. | ||
Option 8, 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 | Option 8, 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 | : 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 was considered in the establishment of the intervals allowed by RG 1.163 and NEI 94-01, but that this "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 8 to 10 CFR 50, Appendix J, subject to the limitations and conditions noted in Section 4.0 of the NRC Safety Evaluation Report (SER) on NEI 94-01. The NRC SER was included in the front matter of the NEI 94-01, Revision 2-A report. 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 (September 1995). It delineates a performance-based approach for determining Type A, Type 8, and Type C containment leakage rate surveillance testing frequencies. | : 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 was considered in the establishment of the intervals allowed by RG 1.163 and NEI 94-01, but that this "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 8 to 10 CFR 50, Appendix J, subject to the limitations and conditions noted in Section 4.0 of the NRC Safety Evaluation Report (SER) on NEI 94-01. The NRC SER was included in the front matter of the NEI 94-01, Revision 2-A report. 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 (September 1995). It delineates a performance-based approach for determining Type A, Type 8, and Type C containment leakage rate surveillance testing frequencies. | ||
Justification for extending test intervals is based on the performance history and risk insights. | 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 8 to 10 CFR 50, Appendix J and includes provisions for extending Type A ILRT intervals to up to 15 years. NEI 94-01 has been endorsed by RG 1.163 and NRC SERs of June 25, 2008 (Reference | 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 8 to 10 CFR 50, Appendix J and includes provisions for extending Type A ILRT intervals to up to 15 years. NEI 94-01 has been endorsed by RG 1.163 and NRC SERs of June 25, 2008 (Reference | ||
: 9) and June 8, 2012 (Reference | : 9) and June 8, 2012 (Reference | ||
: 10) as an acceptable methodology for complying with the provisions of Option 8 to 10 CFR 50. The regulatory positions stated in RG 1.163 as modified by NRC SERs dated June 25, 2008 and June 8, 2012 are incorporated in this document. | : 10) as an acceptable methodology for complying with the provisions of Option 8 to 10 CFR 50. The regulatory positions stated in RG 1.163 as modified by NRC SERs dated June 25, 2008 and June 8, 2012 are incorporated in this document. | ||
It delineates a performance-based approach for determining Type A, Type 8, and Type C containment leakage rate surveillance testing frequencies. | It delineates a performance-based approach for determining Type A, Type 8, and Type C containment leakage rate surveillance testing frequencies. | ||
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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 MS IVs) or to valves held to the base interval (30 months) due to unsatisfactory LLRT performance." The NRG has also provided the following concerning the extension of ILRT intervals to 15 years in NEI 94-01, Revision 3-A, NRG SER Section 4.0, Condition 2, which states, in part: | 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 MS IVs) or to valves held to the base interval (30 months) due to unsatisfactory LLRT performance." The NRG has also provided the following concerning the extension of ILRT intervals to 15 years in NEI 94-01, Revision 3-A, NRG SER Section 4.0, Condition 2, which states, in part: | ||
Enclosure Page 13 of 81 "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. | Enclosure Page 13 of 81 "The basis for acceptability of extending the ILRT interval out to once per 15 years was the enhanced and robust primary containment inspection program and the local leakage rate testing of penetrations. | ||
Most of the primary containment leakage experienced has been attributed to penetration leakage and penetrations are thought to be the most likely location of most containment leakage at any time." 3.2.2 Current HNP ILRT Requirements 10 CFR 50, Appendix J was revised, effective October 26, 1995, to allow licenses to choose containment leakage testing under either Option A, "Prescriptive Requirements," or Option B, "Performance-Based Requirements." On March 6, 1996 the NRC approved License Amendment No. 200 for HNP, Unit 1 and Amendment 141 for Unit 2 (Reference | Most of the primary containment leakage experienced has been attributed to penetration leakage and penetrations are thought to be the most likely location of most containment leakage at any time." 3.2.2 Current HNP ILRT Requirements 10 CFR 50, Appendix J was revised, effective October 26, 1995, to allow licenses to choose containment leakage testing under either Option A, "Prescriptive Requirements," or Option B, "Performance-Based Requirements." On March 6, 1996 the NRC approved License Amendment No. 200 for HNP, Unit 1 and Amendment 141 for Unit 2 (Reference | ||
: 19) authorizing the implementation of 10 CFR 50, Appendix J, Option B for Type A, B and C tests. Current TS 5.5.12 requires that a program be established to comply with the containment leakage rate testing requirements of 10 CFR 50.54(0) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. | : 19) authorizing the implementation of 10 CFR 50, Appendix J, Option B for Type A, B and C tests. Current TS 5.5.12 requires that a program be established to comply with the containment leakage rate testing requirements of 10 CFR 50.54(0) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. | ||
The program is required to be in accordance with the guidelines contained in RG 1.163. RG 1.163 endorses, with certain exceptions, NEI 94-01, Revision 0, as an acceptable method for complying with the provisions of Appendix J, Option 8. 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 | 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 8. 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. | : 5) rather than using test intervals specified in ANSI/ANS 56.8-1994. | ||
NEI 94-01, Section 11.0 refers to Section 9, which states that Type A testing shall be performed during a period of reactor shutdown at a frequency of at least once per ten years based on acceptable performance history. Acceptable performance history is defined as completion of two consecutive periodic Type A tests where the calculated performance leakage was less than 1.0la (where La is the maximum allowable leakage rate at design pressure). | NEI 94-01, Section 11.0 refers to Section 9, which states that Type A testing shall be performed during a period of reactor shutdown at a frequency of at least once per ten years based on acceptable performance history. Acceptable performance history is defined as completion of two consecutive periodic Type A tests where the calculated performance leakage was less than 1.0la (where La is the maximum allowable leakage rate at design pressure). | ||
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The evaluation documented in NUREG-1493 included a study of the dependence or reactor accident risks on containment leak tightness for differing types of containment types, including a post tensioned, shallow domed concrete containment similar to HNP's containment structures. | The evaluation documented in NUREG-1493 included a study of the dependence or reactor accident risks on containment leak tightness for differing types of containment types, including a post tensioned, shallow domed concrete containment similar to HNP's containment structures. | ||
NUREG-1493 concluded in Section 10.1.2 that reducing the frequency of Type A tests (ILRT} from the original three (3) tests per Enclosure Page 14 of 81 10 years to one (1) test per 20 years was found to lead to an imperceptible increase in risk. The estimated increase in risk is very small because ILRTs identify only a few potential containment leakage paths that cannot be identified by Types B and C testing, and the leaks that have been found by Type A tests have been only marginally above existing requirements. | NUREG-1493 concluded in Section 10.1.2 that reducing the frequency of Type A tests (ILRT} from the original three (3) tests per Enclosure Page 14 of 81 10 years to one (1) test per 20 years was found to lead to an imperceptible increase in risk. The estimated increase in risk is very small because ILRTs identify only a few potential containment leakage paths that cannot be identified by Types B and C testing, and the leaks that have been found by Type A tests have been only marginally above existing requirements. | ||
Given the insensitivity of risk to containment leakage rate and the small fraction of leakage paths detected solely by Type A testing, NUREG-1493 concluded that increasing the interval between ILRTs is possible with minimal impact on public risk. 3.2.3 HNP 10 CFR 50, Appendix J, Option B Licensing History March 6, 1996 The Commission issued on March 6, 1996 Amendments Nos. 200 and 141 to Facility Operating License Nos. DPR-57 and NFP-5 for the HNP, Units 1 and 2, respectively (Reference 19). The amendments revised the TS for containment systems to reflect the adoption of the requirements of 10 CFR 50, Appendix J, Option B, and the implementation of a performance-based containment leak-rate testing program at the HNP, Units 1 and 2. February 20, 2002 The Commission issued Amendment No. 226 to Facility Operating License No. DPR-57 for HNP, Unit 1 (Reference | 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. 3.2.3 HNP 10 CFR 50, Appendix J, Option B Licensing History March 6, 1996 The Commission issued on March 6, 1996 Amendments Nos. 200 and 141 to Facility Operating License Nos. DPR-57 and NFP-5 for the HNP, Units 1 and 2, respectively (Reference 19). The amendments revised the TS for containment systems to reflect the adoption of the requirements of 10 CFR 50, Appendix J, Option B, and the implementation of a performance-based containment leak-rate testing program at the HNP, Units 1 and 2. February 20, 2002 The Commission issued Amendment No. 226 to Facility Operating License No. DPR-57 for HNP, Unit 1 (Reference | ||
: 14) on February 20, 2002. This amendment revised TS 5.5.12, Primary Containment Leakage Rate testing Program, to allow a one-time deferral of the Type A Containment ILRT based on the risk-informed guidance in RG 1.174. Specifically, the proposed TS says that the first Type A test performed after the April 1993 Type A test shall be performed no later than April 2008. May 28, 2004 The Commission issued on May 28, 2004 Amendment No. 241 to Renewed Facility Operating License DPR-57 and Amendment No. 184 to Renewed Facility Operating License NPF-5 for HNP, Units 1 and 2, respectively (Reference 16). This amendment changed the peak calculated post-accident primary containment internal pressure values, Pa, in TS 5.5.12, "Primary Containment Leakage Rate Testing Program," for Units 1 and Unit 2. The proposed change supported a 10-psi increase in the nominal reactor steam dome operating pressure at each unit. The purpose of the pressure increase in the nominal reactor steam dome pressure is to allow'for additional flow control margin for the high-pressure turbine. This flow margin is needed to operate the plants at 100 percent of the increased (Reference | : 14) on February 20, 2002. This amendment revised TS 5.5.12, Primary Containment Leakage Rate testing Program, to allow a one-time deferral of the Type A Containment ILRT based on the risk-informed guidance in RG 1.174. Specifically, the proposed TS says that the first Type A test performed after the April 1993 Type A test shall be performed no later than April 2008. May 28, 2004 The Commission issued on May 28, 2004 Amendment No. 241 to Renewed Facility Operating License DPR-57 and Amendment No. 184 to Renewed Facility Operating License NPF-5 for HNP, Units 1 and 2, respectively (Reference 16). This amendment changed the peak calculated post-accident primary containment internal pressure values, Pa, in TS 5.5.12, "Primary Containment Leakage Rate Testing Program," for Units 1 and Unit 2. The proposed change supported a 10-psi increase in the nominal reactor steam dome operating pressure at each unit. The purpose of the pressure increase in the nominal reactor steam dome pressure is to allow'for additional flow control margin for the high-pressure turbine. This flow margin is needed to operate the plants at 100 percent of the increased (Reference | ||
: 13) rated thermal power level of 2804 MW (t). | : 13) rated thermal power level of 2804 MW (t). | ||
February 1, 2005 Enclosure Page 15 of 81. The Commission issued on February 1, 2005 Amendment No. 187 to Renewed Facility Operating License No. NPF-5 for HNP, Unit 2 (Reference 15). This amendment modified TS 5.5.12, Primary Containment Leakage Rate testing Program. The change would allow a one-time change in the Appendix J, Type A test (containment ILRT) interval from the required 10 years to a test interval of 15 years. Specifically, the exception states that the first Type A test performed after the November 2, 1995, Type A test shall be performed no later than November 2010. August 28, 2008 The Commission issued on August 28, 2008 Amendment No. 256 to Renewed Facility Operating License DPR-57 and Amendment No. 200 to Renewed Facility Operating License NPF-5 for HNP Units 1 and 2, respectively (Reference 17). The amendments revised the licensing basis with a full scope implementation of an alternative source term (AST) for HNP. TS 3.6.1.3 Primary Containment Isolation Valves The proposed license amendment revised the following TS that are associated with the analyses performed to support the AST. The proposed change for Unit 1, added a new SR 3.6.1 .3.13, which establishes a maximum combined leakage rate for all secondary containment bypass leakage paths of 0.02La. The proposed change for Unit 2, revised SR 3.6.1 .3.10 to increase the maximum combined leakage rate for all secondary containment bypass leakage paths from O.OQ9La to 0.02La. La is defined in 10 CFR 50, Appendix J. The secondary containment bypass leakage rate assumptions in the radiological dose consequences analysis for the LOCA form the basis for the revised TS limits. The increase in bypass leakage is necessary to allow for newly identified bypass leakage paths. The addition of this TS SR to Unit 1 reflects a required RG 1 .183 assumption in the accident analyses and standardizes the TS between units. The NRG staff's assessment found these changes acceptable since the proposed secondary bypass leakage rate limit of 0.02La was assumed in the accident analysis and regulatory criteria have been met. Another proposed change was to eliminate the per line main steam isolation valve (MSIV) leakage rate limits from the TS SR for both units (SR 3.6.1.3.10 and SR 3.6.1.3.11, respectively). | February 1, 2005 Enclosure Page 15 of 81. The Commission issued on February 1, 2005 Amendment No. 187 to Renewed Facility Operating License No. NPF-5 for HNP, Unit 2 (Reference 15). This amendment modified TS 5.5.12, Primary Containment Leakage Rate testing Program. The change would allow a one-time change in the Appendix J, Type A test (containment ILRT) interval from the required 10 years to a test interval of 15 years. Specifically, the exception states that the first Type A test performed after the November 2, 1995, Type A test shall be performed no later than November 2010. August 28, 2008 The Commission issued on August 28, 2008 Amendment No. 256 to Renewed Facility Operating License DPR-57 and Amendment No. 200 to Renewed Facility Operating License NPF-5 for HNP Units 1 and 2, respectively (Reference 17). The amendments revised the licensing basis with a full scope implementation of an alternative source term (AST) for HNP. TS 3.6.1.3 Primary Containment Isolation Valves The proposed license amendment revised the following TS that are associated with the analyses performed to support the AST. The proposed change for Unit 1, added a new SR 3.6.1 .3.13, which establishes a maximum combined leakage rate for all secondary containment bypass leakage paths of 0.02La. The proposed change for Unit 2, revised SR 3.6.1 .3.10 to increase the maximum combined leakage rate for all secondary containment bypass leakage paths from O.OQ9La to 0.02La. La is defined in 10 CFR 50, Appendix J. The secondary containment bypass leakage rate assumptions in the radiological dose consequences analysis for the LOCA form the basis for the revised TS limits. The increase in bypass leakage is necessary to allow for newly identified bypass leakage paths. The addition of this TS SR to Unit 1 reflects a required RG 1 .183 assumption in the accident analyses and standardizes the TS between units. The NRG staff's assessment found these changes acceptable since the proposed secondary bypass leakage rate limit of 0.02La was assumed in the accident analysis and regulatory criteria have been met. Another proposed change was to eliminate the per line main steam isolation valve (MSIV) leakage rate limits from the TS SR for both units (SR 3.6.1.3.10 and SR 3.6.1.3.11, respectively). | ||
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* The methodology used in EPRI TR-104285 (Reference 7), | * The methodology used in EPRI TR-104285 (Reference 7), | ||
* The NEI "Interim Guidance for Performing Risk Impact Assessments In Support of One-Time Extensions for Containment Integrated Leakage Rate Test Surveillance Intervals" (References 33, 37), | * The NEI "Interim Guidance for Performing Risk Impact Assessments In Support of One-Time Extensions for Containment Integrated Leakage Rate Test Surveillance Intervals" (References 33, 37), | ||
* The NRC regulatory guidance on the use of PAA as stated in RG 1.200 (Reference | * The NRC regulatory guidance on the use of PAA as stated in RG 1.200 (Reference | ||
: 4) as applied to ILRT interval extensions, and risk insights in support of a request for a change in the plant's licensing basis as outlined in RG 1.174 (Reference 3), | : 4) as applied to ILRT interval extensions, and risk insights in support of a request for a change in the plant's licensing basis as outlined in RG 1.174 (Reference 3), | ||
* The methodology used for Calvert Cliffs to estimate the likelihood and risk implications of corrosion-induced leakage of steel liners going undetected during the extended test interval (Reference 32), | * The methodology used for Calvert Cliffs to estimate the likelihood and risk implications of corrosion-induced leakage of steel liners going undetected during the extended test interval (Reference 32), | ||
* The methodology used in EPRI TR-1009325, Revision 2-A (Reference | * The methodology used in EPRI TR-1009325, Revision 2-A (Reference | ||
: 20) for performing a risk impact assessment of extended ILRT intervals. | : 20) for performing a risk impact assessment of extended ILRT intervals. | ||
*The EPRI TR-1009325 Revision 2-A methodology incorporates the specific limitations | *The EPRI TR-1009325 Revision 2-A methodology incorporates the specific limitations | ||
*and conditions outlined in the NRC acceptance of the EPRI TR-1009325 Revision 2 methodology documented in the NRC Final Safety Evaluation (Reference 9). The format of this document is consistent with the intent of the Risk Impact Assessment Template for evaluating extended ILRT intervals provided in Appendix Hof the EPRI TR methodology report (Reference 20). The NRG report on performance-based leak testing, NUREG-1493, analyzed the effects of containment leakage on the health and safety of the public and the benefits realized from the containment leak rate testing. In that analysis, it was determined that for a representative PWR plant, (i.e., Surry) containment isolation failures contribute less than 0.1 percent to the latent risks from reactor accidents. | *and conditions outlined in the NRC acceptance of the EPRI TR-1009325 Revision 2 methodology documented in the NRC Final Safety Evaluation (Reference 9). The format of this document is consistent with the intent of the Risk Impact Assessment Template for evaluating extended ILRT intervals provided in Appendix Hof the EPRI TR methodology report (Reference 20). The NRG report on performance-based leak testing, NUREG-1493, analyzed the effects of containment leakage on the health and safety of the public and the benefits realized from the containment leak rate testing. In that analysis, it was determined that for a representative PWR plant, (i.e., Surry) containment isolation failures contribute less than 0.1 percent to the latent risks from reactor accidents. | ||
Consequently, it is desirable to show that extending the ILRT interval will not lead to a substantial increase in risk from containment isolation failures for HNP. Earlier ILRT frequency extension submittals have used the EPRI TR-104285 (Reference | Consequently, it is desirable to show that extending the ILRT interval will not lead to a substantial increase in risk from containment isolation failures for HNP. Earlier ILRT frequency extension submittals have used the EPRI TR-104285 (Reference | ||
: 7) methodology to perform the risk assessment. | : 7) methodology to perform the risk assessment. | ||
In October 2008, EPRI TR-1018243 (Reference 20} was issued to update the generic methodology for ILRT extensions to 15 years using current performance data and to incorporate the specific limitations and conditions outlined by the NRC in the final safety evaluation of the methodology (Reference 9). This more recent EPRI document considers additional risk metrics and criteria including the change in population dose, large early release Enclosure Page 19 of 81 frequency (LERF), and conditional containment failure probability (CCFP), whereas EPRI TR-104285 considered only the change in population dose. In the SER 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 extend the ILRT surveillance interval to 15 years, subject to the limitations and conditions noted in Section 4.0 of the Safety Evaluation (SE). Table 3.3.1-1 addresses each of the four limitations and conditions for the use of EPRI 1009325, Revision 2. Table 3.3.1-1, EPRI Report No. 1009325 Revision 2 Limitations and Conditions Limitation/Condition lFrom Section 4.2 of SE) HNP Resoonse 1. The licensee submits documentation HNP PRA technical adequacy is addressed in indicating that the technical adequacy of Section 3.3.2 of this LAR and Attachment 3, their PRA is consistent with the "Plant Hatch Units 1 & 2 Risk Assessment to requirements of RG 1.200 relevant to the Support ILRT (Type A) Interval Extension I LRT extension. | In October 2008, EPRI TR-1018243 (Reference 20} was issued to update the generic methodology for ILRT extensions to 15 years using current performance data and to incorporate the specific limitations and conditions outlined by the NRC in the final safety evaluation of the methodology (Reference 9). This more recent EPRI document considers additional risk metrics and criteria including the change in population dose, large early release Enclosure Page 19 of 81 frequency (LERF), and conditional containment failure probability (CCFP), whereas EPRI TR-104285 considered only the change in population dose. In the SER 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 extend the ILRT surveillance interval to 15 years, subject to the limitations and conditions noted in Section 4.0 of the Safety Evaluation (SE). Table 3.3.1-1 addresses each of the four limitations and conditions for the use of EPRI 1009325, Revision 2. Table 3.3.1-1, EPRI Report No. 1009325 Revision 2 Limitations and Conditions Limitation/Condition lFrom Section 4.2 of SE) HNP Resoonse 1. The licensee submits documentation HNP PRA technical adequacy is addressed in indicating that the technical adequacy of Section 3.3.2 of this LAR and Attachment 3, their PRA is consistent with the "Plant Hatch Units 1 & 2 Risk Assessment to requirements of RG 1.200 relevant to the Support ILRT (Type A) Interval Extension I LRT extension. | ||
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The Hatch dose increase results are significantly less than 1.0 person-rem/yr. | The Hatch dose increase results are significantly less than 1.0 person-rem/yr. | ||
Moreover, the risk impact when compared to other severe accident risks is negligible. | Moreover, the risk impact when compared to other severe accident risks is negligible. | ||
The increase in CCFP when comparing the three in ten-year frequency to one in fifteen-year frequency is about 0.84% using the EPRI guidance values, and drops to about 0.10% using the EPRI Expert Elicitation values. The EPRI guidance states that increases in CCFP < 1.5 percentage points are very small. Therefore the increase for Hatch is determined to be very small. The representative containment leakage for Class 3b sequences used by HNP is 100 La, based on the recommendations in the latest EPRI report (Reference | The increase in CCFP when comparing the three in ten-year frequency to one in fifteen-year frequency is about 0.84% using the EPRI guidance values, and drops to about 0.10% using the EPRI Expert Elicitation values. The EPRI guidance states that increases in CCFP < 1.5 percentage points are very small. Therefore the increase for Hatch is determined to be very small. The representative containment leakage for Class 3b sequences used by HNP is 100 La, 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 La for the Class 3b sequences. | : 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 La for the Class 3b sequences. | ||
Limitation/Condition (From Section 4.2 of SEl 4. A licensee amendment request (LAR) is required in instances where containment over-pressure is relied upon for ECCS performance. | Limitation/Condition (From Section 4.2 of SEl 4. A licensee amendment request (LAR) is required in instances where containment over-pressure is relied upon for ECCS performance. | ||
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3.3.2.3 Plant Changes Not Yet Incorporated into the PRA Model As part of PRA model configuration control, SNC maintains a PRA model maintenance database that tracks all issues that have been identified that could impact the Hatch PRA model. Per SNC procedure RIE-001 the significance of the pending items in the database is evaluated to determine the impact on model results. Each pending item is prioritized for future model updates according to its significance to model results. A review of the current open items in the database for HNP identified no permanent plant design or operational changes that would significantly impact the results of the risk assessment performed for the ILRT interval extension evaluation. | 3.3.2.3 Plant Changes Not Yet Incorporated into the PRA Model As part of PRA model configuration control, SNC maintains a PRA model maintenance database that tracks all issues that have been identified that could impact the Hatch PRA model. Per SNC procedure RIE-001 the significance of the pending items in the database is evaluated to determine the impact on model results. Each pending item is prioritized for future model updates according to its significance to model results. A review of the current open items in the database for HNP identified no permanent plant design or operational changes that would significantly impact the results of the risk assessment performed for the ILRT interval extension evaluation. | ||
3.3.2.4 Previous Peer Review and Self Assessment of the HNP PRA Model The HNP PRA model was reviewed extensively during development and undergoes independent internal review during each update. The Hatch PRA was reviewed twice prior to issuance of the ASME PRA Standard for peer review. The initial peer review was conducted by the BWR Owners Group (BWROG) in April 2001. The review team used Revision A-3 NEI draft "Probabilistic Risk Assessment (PRA) *Peer Review Process Guidance" dated June 2, 2000 as the basis for review. This review was observed by a team from the NRC. In 2006, a gap analysis was performed against the available versions of the ASME PRA Standard and RG 1.200, Revision 0 (2003 trial version). | 3.3.2.4 Previous Peer Review and Self Assessment of the HNP PRA Model The HNP PRA model was reviewed extensively during development and undergoes independent internal review during each update. The Hatch PRA was reviewed twice prior to issuance of the ASME PRA Standard for peer review. The initial peer review was conducted by the BWR Owners Group (BWROG) in April 2001. The review team used Revision A-3 NEI draft "Probabilistic Risk Assessment (PRA) *Peer Review Process Guidance" dated June 2, 2000 as the basis for review. This review was observed by a team from the NRC. In 2006, a gap analysis was performed against the available versions of the ASME PRA Standard and RG 1.200, Revision 0 (2003 trial version). | ||
Enclosure Page 24 of 81 3.3.2.5 RG 1.200 PRA Review of the HNP PRA Model against the ASME PRA Standard Requirements A PRA Peer Review of all elements of the HNP Internal Events PRA PRA model including Internal Flooding against RG 1.200, Revision 2 clarifications, the ASME/ANS PRA Standard (Reference 30), and NEI 05-04 was performed in November 2009. A summary of the results of the PRA Peer Review (Reference | Enclosure Page 24 of 81 3.3.2.5 RG 1.200 PRA Review of the HNP PRA Model against the ASME PRA Standard Requirements A PRA Peer Review of all elements of the HNP Internal Events PRA PRA model including Internal Flooding against RG 1.200, Revision 2 clarifications, the ASME/ANS PRA Standard (Reference 30), and NEI 05-04 was performed in November 2009. A summary of the results of the PRA Peer Review (Reference | ||
: 21) previously provided to the NRC as part of the NEI Risk Informed Technical Specification (RITS) Initiative 5b LAR submittal (ML 103140510) for which SNC received a NRC SER as discussed in Attachment 3, Appendix B, section B.2.7 of this submittal, is shown below. Based on the results of the Peer Review, 95% of the SRs evaluated met Category II or better. There were 10 supporting requirements that were noted as "Not Met" and 5 that were noted "Met" at Category I only. All of the "Not Met" findings were resolved as part of the update of the Hatch Internal Events PRA Model, Revision 4.0, to Revision 4.1 as noted in Attachment 3, Appendix B, Tables B.2-1 and B.2-2 of this submittal. | : 21) previously provided to the NRC as part of the NEI Risk Informed Technical Specification (RITS) Initiative 5b LAR submittal (ML 103140510) for which SNC received a NRC SER as discussed in Attachment 3, Appendix B, section B.2.7 of this submittal, is shown below. Based on the results of the Peer Review, 95% of the SRs evaluated met Category II or better. There were 10 supporting requirements that were noted as "Not Met" and 5 that were noted "Met" at Category I only. All of the "Not Met" findings were resolved as part of the update of the Hatch Internal Events PRA Model, Revision 4.0, to Revision 4.1 as noted in Attachment 3, Appendix B, Tables B.2-1 and B.2-2 of this submittal. | ||
3.3.2.6 PRA Portions With Inadequate Technical Adequacy As previously noted, the NRC safety evaluation (Reference | 3.3.2.6 PRA Portions With Inadequate Technical Adequacy As previously noted, the NRC safety evaluation (Reference | ||
: 9) of the EPRI ILRT methodology specifies that Capability Category I is appropriate for the applicable PRA Standard supporting requirements. | : 9) of the EPRI ILRT methodology specifies that Capability Category I is appropriate for the applicable PRA Standard supporting requirements. | ||
Based on the update to the HNP Internal Events PRA model to Revision 4.1, following the 2009 PRA Peer Review, all PRA Standard supporting requirements are met at Capability Category 11 or higher, as applicable. | Based on the update to the HNP Internal Events PRA model to Revision 4.1, following the 2009 PRA Peer Review, all PRA Standard supporting requirements are met at Capability Category 11 or higher, as applicable. | ||
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====3.3.3 Summary==== | ====3.3.3 Summary==== | ||
of Plant-Specific Risk Assessment Results Enclosure Page 25 of 81 The findings of the HNP, Units 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 very small. The HNP plant-specific results for extending ILRT interval from the current 10 years to 15 years are summarized below: Based on the results from Attachment 3, Section 7.0, "Conclusions," and the sensitivity calculations presented in Section 6.0 "Sensitivities," the following conclusions regarding the assessment of the plant risk associated with permanently extending the Type A ILRT test frequency to 15 years: | of Plant-Specific Risk Assessment Results Enclosure Page 25 of 81 The findings of the HNP, Units 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 very small. The HNP plant-specific results for extending ILRT interval from the current 10 years to 15 years are summarized below: Based on the results from Attachment 3, Section 7.0, "Conclusions," and the sensitivity calculations presented in Section 6.0 "Sensitivities," the following conclusions regarding the assessment of the plant risk associated with permanently extending the Type A ILRT test frequency to 15 years: | ||
* RG 1.174 (Reference | * RG 1.174 (Reference | ||
: 3) provides guidance for determining the risk impact of plant-specific changes to the licensing basis. RG 1.17 4 defines "very small" changes in risk as resulting in increases of CDF below 1 o-6/yr and increases in LERF below 1 o-7/yr. Because the ILRT does not impact CDF, the relevant criterion is LERF. The increase in internal events LERF resulting from a change in the Type A ILRT test frequency from three in ten years to one in fifteen years is conservatively estimated as 6.39E-08/yr using the EPRI guidance as written and including potential corrosion impacts. The LERF increase using the EPRI Expert Elicitation values is substantially less (i.e., 7.52E-09/yr). | : 3) provides guidance for determining the risk impact of plant-specific changes to the licensing basis. RG 1.17 4 defines "very small" changes in risk as resulting in increases of CDF below 1 o-6/yr and increases in LERF below 1 o-7/yr. Because the ILRT does not impact CDF, the relevant criterion is LERF. The increase in internal events LERF resulting from a change in the Type A ILRT test frequency from three in ten years to one in fifteen years is conservatively estimated as 6.39E-08/yr using the EPRI guidance as written and including potential corrosion impacts. The LERF increase using the EPRI Expert Elicitation values is substantially less (i.e., 7.52E-09/yr). | ||
Using both approaches, the estimated change in LERF is determined to be "very small" using the acceptance guidelines of RG 1.17 4. | Using both approaches, the estimated change in LERF is determined to be "very small" using the acceptance guidelines of RG 1.17 4. | ||
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* The increase in the CCFP when comparing the three in ten-year frequency to one in fifteen-year frequency is about 0.84% using the EPRI guidance values, and drops to about 0.10% using the EPRI Expert Elicitation values. The EPRI guidance states that increases in CCFP < 1 .5 percentage points are very small. Therefore, the increase for Hatch is determined to be very small. | * The increase in the CCFP when comparing the three in ten-year frequency to one in fifteen-year frequency is about 0.84% using the EPRI guidance values, and drops to about 0.10% using the EPRI Expert Elicitation values. The EPRI guidance states that increases in CCFP < 1 .5 percentage points are very small. Therefore, the increase for Hatch is determined to be very small. | ||
* The potential impact on LERF from external events was quantitatively assessed utilizing information from the Individual Plant Examination of External Events (IPEEE). The total increase in LERF due to internal and external events using Enclosure Page 26 of 81 the EPRI guidance values is estimated to be 9.SE-8/yr, which remains in the "very small" change region (i.e., < 1 E-7/yr) of the RG 1.174 acceptance guidelines. | * The potential impact on LERF from external events was quantitatively assessed utilizing information from the Individual Plant Examination of External Events (IPEEE). The total increase in LERF due to internal and external events using Enclosure Page 26 of 81 the EPRI guidance values is estimated to be 9.SE-8/yr, which remains in the "very small" change region (i.e., < 1 E-7/yr) of the RG 1.174 acceptance guidelines. | ||
Therefore, increasing the ILRT interval to 15 years is considered to represent an insignificant change in risk for HNP. 3.3.4 Previous Assessments The NRG in NUREG-1493 (Reference | Therefore, increasing the ILRT interval to 15 years is considered to represent an insignificant change in risk for HNP. 3.3.4 Previous Assessments The NRG in NUREG-1493 (Reference | ||
: 6) has previously concluded that: | : 6) has previously concluded that: | ||
* Reducing the frequency of Type A tests (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 Type B and C testing, and the leaks that have been found by Type A tests have been only marginally above existing requirements. | * Reducing the frequency of Type A tests (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 Type B and C testing, and the leaks that have been found by Type A tests have been only marginally above existing requirements. | ||
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A listing of applicable sections of 10 CFR 50.55a and Code Cases as well as relief requests, Enclosure Page 29 of 81 exemptions, and alternatives can be found in Volume 1 of the ISi Plan. This plan also includes examinations not required by Subsection IWE that SNC has elected to perform due to specific industry concerns. | A listing of applicable sections of 10 CFR 50.55a and Code Cases as well as relief requests, Enclosure Page 29 of 81 exemptions, and alternatives can be found in Volume 1 of the ISi Plan. This plan also includes examinations not required by Subsection IWE that SNC has elected to perform due to specific industry concerns. | ||
Relief Request By letter dated July 16, 2015, as supplemented by letter dated December 16, 2015, SNC submitted a request to the NRC for relief from the requirements of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code (B&PV Code) at HNP, Units 1 and 2. SNC requested to use the current ASME B&PV code of record, the 2001 edition through the 2003 addenda, in combination with the 2007 edition through the 2008 addenda for certain inservice inspection and containment inservice inspection activities from January 1, 2016, through November 30, 2017. The NRG staff reviewed the subject request and concludes, as set forth in the enclosed safety evaluation, that the licensee has adequately addressed all of the regulatory requirements set forth in 10 CFR 50.55a(z)(1 | Relief Request By letter dated July 16, 2015, as supplemented by letter dated December 16, 2015, SNC submitted a request to the NRC for relief from the requirements of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code (B&PV Code) at HNP, Units 1 and 2. SNC requested to use the current ASME B&PV code of record, the 2001 edition through the 2003 addenda, in combination with the 2007 edition through the 2008 addenda for certain inservice inspection and containment inservice inspection activities from January 1, 2016, through November 30, 2017. The NRG staff reviewed the subject request and concludes, as set forth in the enclosed safety evaluation, that the licensee has adequately addressed all of the regulatory requirements set forth in 10 CFR 50.55a(z)(1 | ||
). Therefore, the NRC staff authorized the use of Relief Request HNP-ISl-AL T-5-01 at HNP, Units 1 and .2, from January 1, 2016, to November 30, 2017. (Reference | ). Therefore, the NRC staff authorized the use of Relief Request HNP-ISl-AL T-5-01 at HNP, Units 1 and .2, from January 1, 2016, to November 30, 2017. (Reference | ||
: 35) The application of Relief Request HNP-ISl-AL T-5-01 as applicable to Sub-section IWE is displayed in the following table: Table 3.4.2-1, Proposed ASME Section XI, Sub-section IWE, Code Of Record For HNP ASME Section XI Code Provision ASME Section XI Code Edition/ Addenda 1 Sub-section Article 2001 Edition/ 2001 Edition/ 2007 Edition/ No Addenda 2003 2008 Addenda Addenda IWE Requirements IWE-1000 x2 for Class MC IWE-2000 x2 Components IWE-3000 x IWE-5000 x 1 SNC will also comply with all NRG conditions, limitations, and restrictions specified in 10 CFR 50.55a as they apply to the specific edition and addenda referenced. | : 35) The application of Relief Request HNP-ISl-AL T-5-01 as applicable to Sub-section IWE is displayed in the following table: Table 3.4.2-1, Proposed ASME Section XI, Sub-section IWE, Code Of Record For HNP ASME Section XI Code Provision ASME Section XI Code Edition/ Addenda 1 Sub-section Article 2001 Edition/ 2001 Edition/ 2007 Edition/ No Addenda 2003 2008 Addenda Addenda IWE Requirements IWE-1000 x2 for Class MC IWE-2000 x2 Components IWE-3000 x IWE-5000 x 1 SNC will also comply with all NRG conditions, limitations, and restrictions specified in 10 CFR 50.55a as they apply to the specific edition and addenda referenced. | ||
2 The selection, planning, and scheduling of ISi examinations/tests will comply with these ASME Section XI articles (e.g. IWB-1000 and 2000) from the 2007 Edition/2008 Addenda or applicable NRG approved alternatives that are specified in the HNP ISl/Cll Program Plans. Implementation Schedule The current 10-year inspection interval began January 1, 2016 and goes through December 31, 2025. All inspections required during the previous containment inspection Enclosure Page 30 of 81 interval were completed during the previous interval. | 2 The selection, planning, and scheduling of ISi examinations/tests will comply with these ASME Section XI articles (e.g. IWB-1000 and 2000) from the 2007 Edition/2008 Addenda or applicable NRG approved alternatives that are specified in the HNP ISl/Cll Program Plans. Implementation Schedule The current 10-year inspection interval began January 1, 2016 and goes through December 31, 2025. All inspections required during the previous containment inspection Enclosure Page 30 of 81 interval were completed during the previous interval. | ||
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Enclosure Page 37 of 81 Virtually 100% of the exterior vent system (located inside the suppression pool) surfaces are accessible for visual examination from the 114' -0" interior catwalk, or from the top of the vent header if the provisions of 10 CFR 50.55a(b)(2)(ix)(B) are applied. Visual examination of the exterior vent system surfaces located outside the suppression pool are accessible from the inner circumference catwalk, the top of the vent pipe and the 87' -0" floor elevation if the provisions of 10 CFR 50.55a(b)(2)(ix)(B) are applied. Visual examination of the interior vent system is accessible from the drywell. Visual examination of the vent system from these vantage points should provide adequate access to perform visual examination of these surfaces. | Enclosure Page 37 of 81 Virtually 100% of the exterior vent system (located inside the suppression pool) surfaces are accessible for visual examination from the 114' -0" interior catwalk, or from the top of the vent header if the provisions of 10 CFR 50.55a(b)(2)(ix)(B) are applied. Visual examination of the exterior vent system surfaces located outside the suppression pool are accessible from the inner circumference catwalk, the top of the vent pipe and the 87' -0" floor elevation if the provisions of 10 CFR 50.55a(b)(2)(ix)(B) are applied. Visual examination of the interior vent system is accessible from the drywell. Visual examination of the vent system from these vantage points should provide adequate access to perform visual examination of these surfaces. | ||
There have been no reports of significant degradation of the exterior or interior surfaces of the vent system during examination and classification as IWE, Category E-A is warranted at the present time. Category E-A Specific Evaluation and Examination Position Item E1.10 Evaluation Item E1.10 includes the containment vessel pressure retaining boundary and the examinations listed in items E1.11 and E1.12. The examinations described in E1.11 and E1 .12 are applicable as described in the appropriate sections below. Item E1 .11 Evaluation (General Visual Examination) | There have been no reports of significant degradation of the exterior or interior surfaces of the vent system during examination and classification as IWE, Category E-A is warranted at the present time. Category E-A Specific Evaluation and Examination Position Item E1.10 Evaluation Item E1.10 includes the containment vessel pressure retaining boundary and the examinations listed in items E1.11 and E1.12. The examinations described in E1.11 and E1 .12 are applicable as described in the appropriate sections below. Item E1 .11 Evaluation (General Visual Examination) | ||
Table IWE-2500-1, Item E1 .11 references the below listed footnotes relative to containment surface examination requirements. | Table IWE-2500-1, Item E1 .11 references the below listed footnotes relative to containment surface examination requirements. | ||
: 1. Examinations shall include all accessible interior and exterior surfaces of Class MC components, parts, and appurtenances, and metallic shell and penetration liners of Class CC components. | : 1. Examinations shall include all accessible interior and exterior surfaces of Class MC components, parts, and appurtenances, and metallic shell and penetration liners of Class CC components. | ||
The following items shall be considered for examination: (a) integral attachments and structures are parts of reinforcing structure, such as stiffening rings, manhole frames, and reinforcement around openings. (b) surfaces of attachment welds between structural attachments and the pressure retaining boundary or reinforcing structure, except for nonstructural or temporary attachments as defined in NE-4435 and minor permanent attachments as defined in CC-4543.4. (c) surfaces of containment structural and pressure boundary welds, including longitudinal welds (Category A), circumferential welds (Category B), flange welds (Category C), and nozzle-to-shell welds (Category D) as defined in NE-3351 for Class MC; and surfaces of Flued Head and Bellows Seal Circumferential Welds joined to the Penetration. | The following items shall be considered for examination: (a) integral attachments and structures are parts of reinforcing structure, such as stiffening rings, manhole frames, and reinforcement around openings. (b) surfaces of attachment welds between structural attachments and the pressure retaining boundary or reinforcing structure, except for nonstructural or temporary attachments as defined in NE-4435 and minor permanent attachments as defined in CC-4543.4. (c) surfaces of containment structural and pressure boundary welds, including longitudinal welds (Category A), circumferential welds (Category B), flange welds (Category C), and nozzle-to-shell welds (Category D) as defined in NE-3351 for Class MC; and surfaces of Flued Head and Bellows Seal Circumferential Welds joined to the Penetration. | ||
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Electrical penetrations used at Plant Hatch are weld-in design, do not utilize pressure retaining bolting, and are not specifically listed in the examination tables. These penetrations are part of the general visual examinations performed on a periodic basis. All bolted connections are also included in the Appendix J leakrate testing program. Appendix J leakrate testing is required anytime the connection is disassembled, and at least every 10 years if not disassembled, which confirms containment leak tight integrity. | Electrical penetrations used at Plant Hatch are weld-in design, do not utilize pressure retaining bolting, and are not specifically listed in the examination tables. These penetrations are part of the general visual examinations performed on a periodic basis. All bolted connections are also included in the Appendix J leakrate testing program. Appendix J leakrate testing is required anytime the connection is disassembled, and at least every 10 years if not disassembled, which confirms containment leak tight integrity. | ||
Item E 1.12 Evaluation (VT-3 Visual Examination) | Item E 1.12 Evaluation (VT-3 Visual Examination) | ||
Table IWE-2500-1, Item E1 .12 references the below listed footnotes relative to containment surface examination requirements. | Table IWE-2500-1, Item E1 .12 references the below listed footnotes relative to containment surface examination requirements. | ||
: 1. Examinations shall include all accessible interior and exterior surfaces of Class MC components, parts, and appurtenances, and metallic shell and penetration liners of Class CC components. | : 1. Examinations shall include all accessible interior and exterior surfaces of Class MC components, parts, and appurtenances, and metallic shell and penetration liners of Class CC components. | ||
The following items shall be considered for examination: (a) integral attachments and structures are parts of reinforcing structure, such as stiffening rings, manhole frames, and reinforcement around openings. (b) surfaces of attachment welds between structural attachments and the pressure retaining boundary or reinforcing structure, except for nonstructural or temporary attachments as defined in NE-4435 and minor permanent attachments as defined in CC-4543.4. | The following items shall be considered for examination: (a) integral attachments and structures are parts of reinforcing structure, such as stiffening rings, manhole frames, and reinforcement around openings. (b) surfaces of attachment welds between structural attachments and the pressure retaining boundary or reinforcing structure, except for nonstructural or temporary attachments as defined in NE-4435 and minor permanent attachments as defined in CC-4543.4. | ||
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Ultrasonic Testing (UT) Enclosure Page 46 of 81 SNC has included supplemental provisions in the IWE program to check and monitor wall degradation of both Units 1 and 2 torus surfaces. | Ultrasonic Testing (UT) Enclosure Page 46 of 81 SNC has included supplemental provisions in the IWE program to check and monitor wall degradation of both Units 1 and 2 torus surfaces. | ||
Beginning with Unit 2 in 1998 and Unit 1 in 1999, SNC will perform ultrasonic (UT) thickness measurements in each torus bay of both Units 1 and 2. These measurements include selection of one grid location near the bottom in each torus bay. After the initial inspections, SNC will repeat the inspections every other outage to monitor degradation rates and their impact on Code minimum thickness. | Beginning with Unit 2 in 1998 and Unit 1 in 1999, SNC will perform ultrasonic (UT) thickness measurements in each torus bay of both Units 1 and 2. These measurements include selection of one grid location near the bottom in each torus bay. After the initial inspections, SNC will repeat the inspections every other outage to monitor degradation rates and their impact on Code minimum thickness. | ||
Conclusion The above plan, in conjunction with the ASME Section XI, Subsection IWE Program, is intended to assure the integrity of the torus. Based on evaluation of the results from all previous examinations, there is currently no indication that there are any degradation concerns which impact the wall thickness or structural integrity of the torus. 3.4.3 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 | Conclusion The above plan, in conjunction with the ASME Section XI, Subsection IWE Program, is intended to assure the integrity of the torus. Based on evaluation of the results from all previous examinations, there is currently no indication that there are any degradation concerns which impact the wall thickness or structural integrity of the torus. 3.4.3 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. | : 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: | 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: | ||
| Line 456: | Line 456: | ||
This was reported under LEA 2011-001-1 (Reference 34). 3.4.5 Type Band Type C Local Leak Rate Testing Program Implementation Review The following Tables 3.4.5-1 and 3.4.5-2 identify the components that were on extended intervals and have not demonstrated acceptable performance during the previous two . outages for HNP, Units 1 and 2 respectively: | This was reported under LEA 2011-001-1 (Reference 34). 3.4.5 Type Band Type C Local Leak Rate Testing Program Implementation Review The following Tables 3.4.5-1 and 3.4.5-2 identify the components that were on extended intervals and have not demonstrated acceptable performance during the previous two . outages for HNP, Units 1 and 2 respectively: | ||
Table 3.4.5-1, Unit 1 Type B and C LLRT Program Implementation Review 1RF26 -2014 Component As-Admin As-left Cause of Corrective Scheduled found Limit SCCM Failure Action Interval SCCM SCCM 1 E41-F111 185,244 275 867 Seat Valve was 30 months Pen 221A (1) leakage, refurbished. | Table 3.4.5-1, Unit 1 Type B and C LLRT Program Implementation Review 1RF26 -2014 Component As-Admin As-left Cause of Corrective Scheduled found Limit SCCM Failure Action Interval SCCM SCCM 1 E41-F111 185,244 275 867 Seat Valve was 30 months Pen 221A (1) leakage, refurbished. | ||
MNPLR Broken Acceptance of 64 wedge refurbished (1) valve As-left leakage by evaluation Enclosure Page 50 of 81 Table 3.4.5-1, Unit 1 Type B and C LLRT Program Implementation Review 1RF26 -2014 Component As-Admin As-left Cause of Corrective Scheduled found Limit SCCM Failure Action Interval SCCM SCCM 1T48-F335B 00 575 0 Seat Valve and valve 30 months Pen 26 (2) leakage operator MNPLR (2) refurbished 110 1RF27-2016 Component As-Admin As-left Cause Corrective Scheduled found Limit SCCM of Action Interval SCCM SCCM Failure H48-F334A 700 575 700 Not Acceptance of 30 months Pen 26 MNPLR identified valve As-left 53 leakage by evaluation. | MNPLR Broken Acceptance of 64 wedge refurbished (1) valve As-left leakage by evaluation Enclosure Page 50 of 81 Table 3.4.5-1, Unit 1 Type B and C LLRT Program Implementation Review 1RF26 -2014 Component As-Admin As-left Cause of Corrective Scheduled found Limit SCCM Failure Action Interval SCCM SCCM 1T48-F335B 00 575 0 Seat Valve and valve 30 months Pen 26 (2) leakage operator MNPLR (2) refurbished 110 1RF27-2016 Component As-Admin As-left Cause Corrective Scheduled found Limit SCCM of Action Interval SCCM SCCM Failure H48-F334A 700 575 700 Not Acceptance of 30 months Pen 26 MNPLR identified valve As-left 53 leakage by evaluation. | ||
(1) 1 E41-F111 failed as-found testing with an identified leakage rate of 185244 seem. It was discovered during performance of 42SV-TET-001-1 that 1 E41 F111 could not be brought to test pressure due to leakage through seat of this valve. Per engineering request, a set of data was recorded at less than prescribed test pressure. | (1) 1 E41-F111 failed as-found testing with an identified leakage rate of 185244 seem. It was discovered during performance of 42SV-TET-001-1 that 1 E41 F111 could not be brought to test pressure due to leakage through seat of this valve. Per engineering request, a set of data was recorded at less than prescribed test pressure. | ||
At 47.5 psig measured leakage was 185,244 seem. The minimum pathway leakage rate for Penetration 221A was 64 seem. Excessive seat leakage was due to stellite breaking off the wedge on the downstream side. (2) 1T48-F111 failed as-found testing with a leakage rate of that could not be quantified. | At 47.5 psig measured leakage was 185,244 seem. The minimum pathway leakage rate for Penetration 221A was 64 seem. Excessive seat leakage was due to stellite breaking off the wedge on the downstream side. (2) 1T48-F111 failed as-found testing with a leakage rate of that could not be quantified. | ||
| Line 609: | Line 609: | ||
* Containment Inspection Program (Class MC/IWE) | * Containment Inspection Program (Class MC/IWE) | ||
* Containment Inspections per TS SR 3.6.1 .1.1 | * Containment Inspections per TS SR 3.6.1 .1.1 | ||
* Protective Coatings Program Enclosure Page 72 of 81 This experience is supplemented by risk analysis studies, including the HNP, Units 1 and 2 risk analysis provided in Attachment | * Protective Coatings Program Enclosure Page 72 of 81 This experience is supplemented by risk analysis studies, including the HNP, Units 1 and 2 risk analysis provided in Attachment | ||
: 3. The risk assessment concluded that increasing the ILRT interval to 15 years is considered to represent an insignificant change in risk for HNP. | : 3. The risk assessment concluded that increasing the ILRT interval to 15 years is considered to represent an insignificant change in risk for HNP. | ||
| Line 625: | Line 625: | ||
Type B and Type C testing ensures that individual penetrations are essentially leak tight. In addition, aggregate Type Band Type C leakage rates support the leakage tightness of primary containment by minimizing potential leakage paths. For EPRI Report No. 1009325, Revision 2, a risk-informed methodology using specific risk insights and industry ILRT performance data to revise ILRT surveillance frequencies, the NRC staff finds that the proposed methodology satisfies the key principles of risk-informed decision making applied to changes to TSs as delineated in RG 1.177 and RG 1.174. The NRC staff, therefore, found that this guidance was acceptable for referencing by licensees proposing to amend their TS in regards to containment leakage rate testing, subject to the limitations and conditions noted in Section 4.2 of the Safety Evaluation Report (SER). The NRC staff reviewed NEI TR 94-01, Revision 3, and determined that it described an acceptable approach for implementing the optional performance-based requirements of Option B to 10 CFR 50, Appendix J, as modified by the conditions and limitations summarized in Section 4.0 of the associated Safety Evaluation. | Type B and Type C testing ensures that individual penetrations are essentially leak tight. In addition, aggregate Type Band Type C leakage rates support the leakage tightness of primary containment by minimizing potential leakage paths. For EPRI Report No. 1009325, Revision 2, a risk-informed methodology using specific risk insights and industry ILRT performance data to revise ILRT surveillance frequencies, the NRC staff finds that the proposed methodology satisfies the key principles of risk-informed decision making applied to changes to TSs as delineated in RG 1.177 and RG 1.174. The NRC staff, therefore, found that this guidance was acceptable for referencing by licensees proposing to amend their TS in regards to containment leakage rate testing, subject to the limitations and conditions noted in Section 4.2 of the Safety Evaluation Report (SER). The NRC staff reviewed NEI TR 94-01, Revision 3, and determined that it described an acceptable approach for implementing the optional performance-based requirements of Option B to 10 CFR 50, Appendix J, as modified by the conditions and limitations summarized in Section 4.0 of the associated Safety Evaluation. | ||
This guidance included provisions for extending Type C LLRT intervals up to 75 months. Type C testing ensures that individual containment isolation valves are essentially leak tight. In addition, aggregate Type C leakage rates support the leakage tightness of primary containment by minimizing potential leakage paths. The NRC staff, therefore, found that this guidance, as modified to include two limitations and conditions, was acceptable for referencing by licensees proposing to amend their TS in regards to containment leakage rate testing. Any applicant may reference NEI TR 94-01, Revision 3, as modified by the associated SER and approved by the NRC, and the conditions and limitations 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: | This guidance included provisions for extending Type C LLRT intervals up to 75 months. Type C testing ensures that individual containment isolation valves are essentially leak tight. In addition, aggregate Type C leakage rates support the leakage tightness of primary containment by minimizing potential leakage paths. The NRC staff, therefore, found that this guidance, as modified to include two limitations and conditions, was acceptable for referencing by licensees proposing to amend their TS in regards to containment leakage rate testing. Any applicant may reference NEI TR 94-01, Revision 3, as modified by the associated SER and approved by the NRC, and the conditions and limitations 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 | * Surry Power Station, Units 1 and 2 (Reference | ||
: 24) | : 24) | ||
* Donald C. Cook Nuclear Plant, Units 1 and 2 (Reference | * Donald C. Cook Nuclear Plant, Units 1 and 2 (Reference | ||
: 25) | : 25) | ||
* Beaver Valley Power Station, Unit Nos. 1 and 2 (Reference | * Beaver Valley Power Station, Unit Nos. 1 and 2 (Reference | ||
: 26) | : 26) | ||
* Calvert Cliffs Nuclear Power Plant, Unit Nos. 1 and 2 (Reference | * Calvert Cliffs Nuclear Power Plant, Unit Nos. 1 and 2 (Reference | ||
: 27) | : 27) | ||
* Peach Bottom Atomic Power Station, Units 2 and 3 (Reference | * Peach Bottom Atomic Power Station, Units 2 and 3 (Reference | ||
: 28) | : 28) | ||
Enclosure Page 74 of 81 | Enclosure Page 74 of 81 | ||
* Comanche Peak Nuclear Power Plant, Units 1 and 2 (Reference | * Comanche Peak Nuclear Power Plant, Units 1 and 2 (Reference | ||
: 36) 4.3 No Significant Hazards Consideration Southern Nuclear Operating Company (SNC) has evaluated whether or not a significant hazards consideration is involved with the proposed amendment by focusing on the .three standards set forth in 10 CFR 50.92, "Issuance of amendment," as discussed below: 1. Does the proposed amendment involve a significant increase in the probability or consequences of an accident previously evaluated? | : 36) 4.3 No Significant Hazards Consideration Southern Nuclear Operating Company (SNC) has evaluated whether or not a significant hazards consideration is involved with the proposed amendment by focusing on the .three standards set forth in 10 CFR 50.92, "Issuance of amendment," as discussed below: 1. Does the proposed amendment involve a significant increase in the probability or consequences of an accident previously evaluated? | ||
Response: | Response: | ||
| Line 649: | Line 649: | ||
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 extensions do not significantly increase the consequences of an accident previously evaluated. | 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 extensions do not significantly increase the consequences of an accident previously evaluated. | ||
The proposed amendment also deletes exceptions previously granted to allow time extensions of the ILRT test frequency for both Units 1 and 2. These exceptions were for activities that have already taken place; therefore, their deletion is solely an administrative action that has no effect on any component and no physical impact on how the units are operated. | The proposed amendment also deletes exceptions previously granted to allow time extensions of the ILRT test frequency for both Units 1 and 2. These exceptions were for activities that have already taken place; therefore, their deletion is solely an administrative action that has no effect on any component and no physical impact on how the units are operated. | ||
Therefore, the proposed change does not result in a significant increase in the probability or consequences of an accident previously evaluated. | Therefore, the proposed change does not result in a significant increase in the probability or consequences of an accident previously evaluated. | ||
: 2. Does the proposed change create the possibility of a new or different kind of accident from any accident previously evaluated? | : 2. Does the proposed change create the possibility of a new or different kind of accident from any accident previously evaluated? | ||
Response: | Response: | ||
| Line 655: | Line 655: | ||
The proposed change does not involve a physical change to the plant (i.e., no new or different type of equipment will be installed) nor does it alter the design, configuration, or change the manner in which the plant is operated or controlled beyond the standard functional capabilities of the equipment. | The proposed change does not involve a physical change to the plant (i.e., no new or different type of equipment will be installed) nor does it alter the design, configuration, or change the manner in which the plant is operated or controlled beyond the standard functional capabilities of the equipment. | ||
The proposed amendment also deletes exceptions previously granted to allow time extensions of the ILRT test frequency for both Units 1 and 2. These exceptions were for activities that would have already taken place by the time this amendment is approved; therefore, their deletion is solely an administrative action that does not result in any change in how the units are operated. | The proposed amendment also deletes exceptions previously granted to allow time extensions of the ILRT test frequency for both Units 1 and 2. These exceptions were for activities that would have already taken place by the time this amendment is approved; therefore, their deletion is solely an administrative action that does not result in any change in how the units are operated. | ||
Enclosure Page 76 of 81 Therefore, the proposed change does not create the possibility of a new or different kind of accident from any previously evaluated. | Enclosure Page 76 of 81 Therefore, the proposed change does not create the possibility of a new or different kind of accident from any previously evaluated. | ||
: 3. Does the proposed change involve a significant reduction in a margin of safety? Response: | : 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 HNP, 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. | No. The proposed amendment to TS 5.5.12 involves the extension of the HNP, 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. | ||
| Line 675: | Line 675: | ||
==6.0 REFERENCES== | ==6.0 REFERENCES== | ||
: 1. Regulatory Guide 1.163, Performance-Based Containment Leak-Test Program, September 1995 2. NEI 94-01, Revision 3-A, Industry Guideline for Implementing Based Option of 10 CFR 50, Appendix J, 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, 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, March 2009 Enclosure Page 78 of 81 5. NEI 94-01, Revision 0, Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J, July 1995 6. NUREG-1493, Performance-Based Containment Leak-Test Program, January 1995 7. EPRI TR-104285, Risk Impact Assessment of Revised Containment Leak Rate Testing Intervals, August 1994 8. NEI 94-01, Revision 2-A, Industry Guideline for Implementing Based Option of 10 CFR 50, Appendix J, October 2008 9. Letter from M. J. Maxin (NRC) to J. C. Butler (NEI), dated June 25, 2008, 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) 10. Letter from S. Bahadur (NRC) to B. Bradley (NEI), dated June 8, 2012, Final Safety Evaluation of Nuclear Energy Institute (NEI) Report 94-01, Revision 3, Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, AppendixJ (TAC No. ME2164) 11. Boiling Water Reactors Owners' Group, BWROG PSA Peer Review Certification Implementation Guidelines, Revision 3, January 1997 12. Draft Regulatory Guide DG-1122, An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities, November 2002 13. Letter from S. Bloom (NRC) to H. Sumner (SNC), dated September 23, 2003, Edwin I. Hatch Nuclear Plant, Unit 1 and 2 -Issuance of Amendments Regarding Appendix K Measurement Uncertainty Recovery, (ML032590944) | : 1. Regulatory Guide 1.163, Performance-Based Containment Leak-Test Program, September 1995 2. NEI 94-01, Revision 3-A, Industry Guideline for Implementing Based Option of 10 CFR 50, Appendix J, 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, 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, March 2009 Enclosure Page 78 of 81 5. NEI 94-01, Revision 0, Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J, July 1995 6. NUREG-1493, Performance-Based Containment Leak-Test Program, January 1995 7. EPRI TR-104285, Risk Impact Assessment of Revised Containment Leak Rate Testing Intervals, August 1994 8. NEI 94-01, Revision 2-A, Industry Guideline for Implementing Based Option of 10 CFR 50, Appendix J, October 2008 9. Letter from M. J. Maxin (NRC) to J. C. Butler (NEI), dated June 25, 2008, 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) 10. Letter from S. Bahadur (NRC) to B. Bradley (NEI), dated June 8, 2012, Final Safety Evaluation of Nuclear Energy Institute (NEI) Report 94-01, Revision 3, Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, AppendixJ (TAC No. ME2164) 11. Boiling Water Reactors Owners' Group, BWROG PSA Peer Review Certification Implementation Guidelines, Revision 3, January 1997 12. Draft Regulatory Guide DG-1122, An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities, November 2002 13. Letter from S. Bloom (NRC) to H. Sumner (SNC), dated September 23, 2003, Edwin I. Hatch Nuclear Plant, Unit 1 and 2 -Issuance of Amendments Regarding Appendix K Measurement Uncertainty Recovery, (ML032590944) | ||
: 14. Letter from L. Olshan (NRC) to H. Sumner (SNC), dated February 20, 2002, Edwin I. Hatch Nuclear Plant, Unit 1-Issuance of Amendment Re: Amendment Revises TS 5.5.12 to Allow a One-Time Deferral of the Type A Containment Integrated Leak Rate Test Based on the Risk-Informed Guidance in Regulatory Guide 1.174. (TAC No. MB2842) 15. Letter from C. Gratton (NRC) to H. Sumner (SNC), dated February 1, 2005, Edwin I. Hatch Nuclear Plant, Unit 2 Re: Issuance of Amendment Revising the Enclosure Page 79 of 81 Technical Specifications for the Primary Containment Leakage Rate Testing Program (TAC No. MC2761) 16. Letter from C. Gratton (NRG) to H. Sumner (SNC), dated May 28, 2004, Edwin I. Hatch Nuclear Plant, Units 1 and 2 Re: Issuance of Amendments Revising the Technical Specifications for the Primary Containment Leakage Rate Testing Program (TAC Nos. MC1432 and MC1433) 17. Letter from R. Martin (NRG) to D. Madison (SNC), dated August 28, 2008, Edwin I. Hatch Nuclear Plant, Unit NOS. 1 AND 2, Issuance of Amendments Regarding Alternate Source Term (TAC Nos. MD2934 and MD2935) 18. Letter from R. Ennis (NRG) to M. Pacilio (Exelon), dated August 25, 2014, Peach Bottom Atomic Power Station, Units 1 and 2 -Issuance of Amendments Re: Extended Power Uprate (TAC Nos. ME9631 and ME9632) 19. Letter from K. Jabbour (NRG) to J. Beckham Jr. (Georgia Power), dated March 6, 1996, Edwin I. Hatch Nuclear Plant, Units 1 and 2 -Issuance of Amendment Regarding the Adoption of the Requirements of 10 CFR 50, Appendix J, Option B, and the Implementation of a Performance-based Containment Leak-rate Testing Program. (TAC NOS. M94046 and M94047) 20. Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals: | : 14. Letter from L. Olshan (NRC) to H. Sumner (SNC), dated February 20, 2002, Edwin I. Hatch Nuclear Plant, Unit 1-Issuance of Amendment Re: Amendment Revises TS 5.5.12 to Allow a One-Time Deferral of the Type A Containment Integrated Leak Rate Test Based on the Risk-Informed Guidance in Regulatory Guide 1.174. (TAC No. MB2842) 15. Letter from C. Gratton (NRC) to H. Sumner (SNC), dated February 1, 2005, Edwin I. Hatch Nuclear Plant, Unit 2 Re: Issuance of Amendment Revising the Enclosure Page 79 of 81 Technical Specifications for the Primary Containment Leakage Rate Testing Program (TAC No. MC2761) 16. Letter from C. Gratton (NRG) to H. Sumner (SNC), dated May 28, 2004, Edwin I. Hatch Nuclear Plant, Units 1 and 2 Re: Issuance of Amendments Revising the Technical Specifications for the Primary Containment Leakage Rate Testing Program (TAC Nos. MC1432 and MC1433) 17. Letter from R. Martin (NRG) to D. Madison (SNC), dated August 28, 2008, Edwin I. Hatch Nuclear Plant, Unit NOS. 1 AND 2, Issuance of Amendments Regarding Alternate Source Term (TAC Nos. MD2934 and MD2935) 18. Letter from R. Ennis (NRG) to M. Pacilio (Exelon), dated August 25, 2014, Peach Bottom Atomic Power Station, Units 1 and 2 -Issuance of Amendments Re: Extended Power Uprate (TAC Nos. ME9631 and ME9632) 19. Letter from K. Jabbour (NRG) to J. Beckham Jr. (Georgia Power), dated March 6, 1996, Edwin I. Hatch Nuclear Plant, Units 1 and 2 -Issuance of Amendment Regarding the Adoption of the Requirements of 10 CFR 50, Appendix J, Option B, and the Implementation of a Performance-based Containment Leak-rate Testing Program. (TAC NOS. M94046 and M94047) 20. Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals: | ||
Revision 2-A of 1009325. EPRI, Palo Alto, CA: October 2008. 1018243 21. Hatch Unit 1 Peer Review Report (2009), February 2010 22. Regulatory Guide 1.147, Revision 16, lnservice Inspection Code Case Acceptability, ASME Section XI, Division 1, October 2010 23. NUREG-1769, Safety Evaluation Report Related to the License Renewal of Peach Bottom Atomic Power Station, Units 1 and 2, March 2003 24. ML 14148A235, Letter to D. Heacock from S. Williams (NRG) dated July 3, 2014. Surry Power Station, Units 1 And 2 -Issuance of Amendment Regarding the Containment Type A and Type C Leak Rate Tests 25. ML15072A264, Letter to L. Weber from A. Dietrich (NRG) dated March 30, 2015. Donald C. Cook Nuclear Plant, Units 1 and 2 -Issuance of Amendments Re: Containment Leakage Rate Testing Program 26. ML15078A058, Letter to E. Larson from T. Lamb (NRG) dated April 8, 2015. Beaver Valley Power Station, Unit Nos. 1 And 2 -Issuance of Amendment Re: License Amendment Request to Extend Containment Leakage Rate Test Frequency Enclosure Page 80 of 81 27. ML 15154A661, Letter to G. Gellrich from A. Chereskin (NRG) dated July 16, 2015. Calvert Cliffs Nuclear Power Plant, Unit Nos. 1 and 2 -Issuance of Amendments Re: Extension of Containment Leakage Rate Testing Frequency | Revision 2-A of 1009325. EPRI, Palo Alto, CA: October 2008. 1018243 21. Hatch Unit 1 Peer Review Report (2009), February 2010 22. Regulatory Guide 1.147, Revision 16, lnservice Inspection Code Case Acceptability, ASME Section XI, Division 1, October 2010 23. NUREG-1769, Safety Evaluation Report Related to the License Renewal of Peach Bottom Atomic Power Station, Units 1 and 2, March 2003 24. ML 14148A235, Letter to D. Heacock from S. Williams (NRG) dated July 3, 2014. Surry Power Station, Units 1 And 2 -Issuance of Amendment Regarding the Containment Type A and Type C Leak Rate Tests 25. ML15072A264, Letter to L. Weber from A. Dietrich (NRG) dated March 30, 2015. Donald C. Cook Nuclear Plant, Units 1 and 2 -Issuance of Amendments Re: Containment Leakage Rate Testing Program 26. ML15078A058, Letter to E. Larson from T. Lamb (NRG) dated April 8, 2015. Beaver Valley Power Station, Unit Nos. 1 And 2 -Issuance of Amendment Re: License Amendment Request to Extend Containment Leakage Rate Test Frequency Enclosure Page 80 of 81 27. ML 15154A661, Letter to G. Gellrich from A. Chereskin (NRG) dated July 16, 2015. Calvert Cliffs Nuclear Power Plant, Unit Nos. 1 and 2 -Issuance of Amendments Re: Extension of Containment Leakage Rate Testing Frequency | ||
: 28. ML 15196A559, Letter to B. Hanson from R. Ennis (NRG) dated September 8, 2015. 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) 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, March 2009 31. Letter from A. Pietrangelo (NEI) to NEI Administrative Points of Contact, Time Extension of Containment Integrated Leak Rate Test Interval -Additional Information, November 30, 2001 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, Accession Number ML020920100, March 27, 2002 33. Letter from A. Pietrangelo (NEI) to NEI Administrative Points of Contact, Interim Guidance for Performing Risk Impact Assessments in Support of One-Time Extensions for Containment Integrated Leak Rate Test Surveillance Intervals, November 13, 2001 34. ML11347A198, Edwin I. Hatch Nuclear Plant -Unit 2, Licensee Event report 2011-001-01, Revision 1, Primary Containment Isolation Penetration Exceeded Overall Allowable Technical Specification Leakage Limits, December 9, 2011 35. ML 15352A294, Letter from M. Marley (NRG) to C. Pierce (SNC), Relief from the Requirements of the ASME Code (CAC Nos. MF6494 and MF6495), December 28,2015 36. ML 15309A073, Letter to R. Flores (Luminant) from B. Singal (NRG) dated December 30, 2015. 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) | : 28. ML 15196A559, Letter to B. Hanson from R. Ennis (NRG) dated September 8, 2015. 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) 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, March 2009 31. Letter from A. Pietrangelo (NEI) to NEI Administrative Points of Contact, Time Extension of Containment Integrated Leak Rate Test Interval -Additional Information, November 30, 2001 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, Accession Number ML020920100, March 27, 2002 33. Letter from A. Pietrangelo (NEI) to NEI Administrative Points of Contact, Interim Guidance for Performing Risk Impact Assessments in Support of One-Time Extensions for Containment Integrated Leak Rate Test Surveillance Intervals, November 13, 2001 34. ML11347A198, Edwin I. Hatch Nuclear Plant -Unit 2, Licensee Event report 2011-001-01, Revision 1, Primary Containment Isolation Penetration Exceeded Overall Allowable Technical Specification Leakage Limits, December 9, 2011 35. ML 15352A294, Letter from M. Marley (NRG) to C. Pierce (SNC), Relief from the Requirements of the ASME Code (CAC Nos. MF6494 and MF6495), December 28,2015 36. ML 15309A073, Letter to R. Flores (Luminant) from B. Singal (NRG) dated December 30, 2015. 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) | ||
Enclosure Page 81 of 81 37. Letter from A. Pietrangelo (NEI) to NEI Administrative Points of Contact, Time Extension of Containment Integrated Leak Rate Test Interval -Additional Information, November 30, 2001. | Enclosure Page 81 of 81 37. Letter from A. Pietrangelo (NEI) to NEI Administrative Points of Contact, Time Extension of Containment Integrated Leak Rate Test Interval -Additional Information, November 30, 2001. | ||
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==1.1 REFERENCES== | ==1.1 REFERENCES== | ||
(continued) | |||
HATCH UNIT 1 8. ANSI/ANS 56.8 1994 , " American National Standard for Containment System t akage Testing Requirements," 1994. Ame r ican Nuclear Society , " Conta i nmen t System Leakage Test ing Requ i rements ," ANSI/ANS 56.8-2002. B 3.6-5 REVISION 69 BASES (cont i nued) ACTIONS SURVEILLANCE REQUIREMENTS Primary Conta i nment B 3.6.1.1 In the event primary containment is inoperable , p r imary conta i nment must be restored to OPERABLE status wi t hin 1 hour. The 1 hour Completion Time provides a period of time to correct the problem commensurate with the importance of maintaining primary containment OPERABILITY during MODES 1 , 2 , and 3. This time period also ensures that the probabi l ity of an accident (requiring primary containment OPERABILITY) occurring during periods where primary containment is inoperable is minima l. B.1 and B.2 If primary containment cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To ach i eve this status , the plant must be brought to at least MODE 3 within 12 hours and to MODE 4 with i n 36 hours. The allowed Comp l etion Times are reasonab l e , based on operating experience , to reach the required plant conditions from full power cond i tions in an orderly manner and without challenging plant systems. SR 3.6.1.1.1 Mainta i ning the primary containment OPERABLE requires compliance with the visual examinations and l eakage rate test requirements of the Primary Containment Leakage Rate Testing Program. Failu r e to meet air lock leakage test i ng (SR 3.6.1.2.1 ), secondary containment bypass leakage (SR 3.6.1.3.10), or main steam isolation valve leakage (SR 3.6.1.3.11) does not necessarily result in a failure of this SR. The impact of the failure to meet these SRs must be evaluated against the Type A , B , and C acceptance c r iteria of the Primary Conta in ment Leakage Rate Testing Program. The Primary Containment Leakage Rate Testing Program is based on the guidelines in Regulatory Gu i ao 1.163 (Ref. 6), NEI 94 01 (Ref. 7), ane 56.8 1994 (Ref. 8). Specific acceptance criteria for as found and as left leakage rates , as well as the methods of defining t h e leakage rates , are contained in the Primary Containment Leakage Rate Testing Program. At all other times between requi r ed leakage rate te s ts , the acceptance criteria are based on an overall Type A leakage l imit of 1.0 L a. At 1.0 L a. the o ff site dose consequences are bounded by the assumptions of the safety analysis. The Frequency is required by the Primary Containment Leakage Rate Tes ti ng Program. NEI 94-01 Revision 3-A (Ref. 7), the Limitations and Conditions of NEI 94-01 Revision 2-A (Ref.6), and ANSI/ _ANS 56.8-2002 HATCH UNIT 2 (continued) B 3.6-3 REVISION 7-BASES SURVEILLANCE REQUIREMENTS (continued) | HATCH UNIT 1 8. ANSI/ANS 56.8 1994 , " American National Standard for Containment System t akage Testing Requirements," 1994. Ame r ican Nuclear Society , " Conta i nmen t System Leakage Test ing Requ i rements ," ANSI/ANS 56.8-2002. B 3.6-5 REVISION 69 BASES (cont i nued) ACTIONS SURVEILLANCE REQUIREMENTS Primary Conta i nment B 3.6.1.1 In the event primary containment is inoperable , p r imary conta i nment must be restored to OPERABLE status wi t hin 1 hour. The 1 hour Completion Time provides a period of time to correct the problem commensurate with the importance of maintaining primary containment OPERABILITY during MODES 1 , 2 , and 3. This time period also ensures that the probabi l ity of an accident (requiring primary containment OPERABILITY) occurring during periods where primary containment is inoperable is minima l. B.1 and B.2 If primary containment cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To ach i eve this status , the plant must be brought to at least MODE 3 within 12 hours and to MODE 4 with i n 36 hours. The allowed Comp l etion Times are reasonab l e , based on operating experience , to reach the required plant conditions from full power cond i tions in an orderly manner and without challenging plant systems. SR 3.6.1.1.1 Mainta i ning the primary containment OPERABLE requires compliance with the visual examinations and l eakage rate test requirements of the Primary Containment Leakage Rate Testing Program. Failu r e to meet air lock leakage test i ng (SR 3.6.1.2.1 ), secondary containment bypass leakage (SR 3.6.1.3.10), or main steam isolation valve leakage (SR 3.6.1.3.11) does not necessarily result in a failure of this SR. The impact of the failure to meet these SRs must be evaluated against the Type A , B , and C acceptance c r iteria of the Primary Conta in ment Leakage Rate Testing Program. The Primary Containment Leakage Rate Testing Program is based on the guidelines in Regulatory Gu i ao 1.163 (Ref. 6), NEI 94 01 (Ref. 7), ane 56.8 1994 (Ref. 8). Specific acceptance criteria for as found and as left leakage rates , as well as the methods of defining t h e leakage rates , are contained in the Primary Containment Leakage Rate Testing Program. At all other times between requi r ed leakage rate te s ts , the acceptance criteria are based on an overall Type A leakage l imit of 1.0 L a. At 1.0 L a. the o ff site dose consequences are bounded by the assumptions of the safety analysis. The Frequency is required by the Primary Containment Leakage Rate Tes ti ng Program. NEI 94-01 Revision 3-A (Ref. 7), the Limitations and Conditions of NEI 94-01 Revision 2-A (Ref.6), and ANSI/ _ANS 56.8-2002 HATCH UNIT 2 (continued) B 3.6-3 REVISION 7-BASES SURVEILLANCE REQUIREMENTS (continued) | ||
REFERENCES SR 3.6.1.1.2 Primary Containment B 3.6.1.1 Maintaining the pressure suppression function of primary containment requires limiting the leakage from the drywall to the suppression chamber. Thus, if an event were to occur that pressurized the drywell, the steam would be directed through the downcomers into the suppression poo l. This SR measures drywell to suppression chamber differential pressure during a 10 minute period to ensure that the leakage paths that would bypass the suppression pool are within allowab l e limits. Satisfactory performance of this SR can be achieved by establishing a known differential pressure between the drywall and the suppression chamber and verifying that the pressure in either the suppression chamber or the drywell does not change by more than 0.25 inch of water per minute over a 10 minute period. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. 1. FSAR, Section 6.2. 2. FSAR, Section 15.1.39. 3. 10 CFR 50 , Appendix J , Option 8. 4. NRC No. 93-102 , "Final Policy Statement on Technica l Specification Improvements | REFERENCES SR 3.6.1.1.2 Primary Containment B 3.6.1.1 Maintaining the pressure suppression function of primary containment requires limiting the leakage from the drywall to the suppression chamber. Thus, if an event were to occur that pressurized the drywell, the steam would be directed through the downcomers into the suppression poo l. This SR measures drywell to suppression chamber differential pressure during a 10 minute period to ensure that the leakage paths that would bypass the suppression pool are within allowab l e limits. Satisfactory performance of this SR can be achieved by establishing a known differential pressure between the drywall and the suppression chamber and verifying that the pressure in either the suppression chamber or the drywell does not change by more than 0.25 inch of water per minute over a 10 minute period. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. 1. FSAR, Section 6.2. 2. FSAR, Section 15.1.39. 3. 10 CFR 50 , Appendix J , Option 8. 4. NRC No. 93-102 , "Final Policy Statement on Technica l Specification Improvements | ||
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===1.0 PURPOSE=== | ===1.0 PURPOSE=== | ||
OF ANALYSIS 1.1 PURPOSE The purpose of this analysis is to provide an assessment of the risk associated with extending , the currently allowed containment Type A integrated leak rate test (ILRT) interval to a permanent fifteen yearsC 1 l for Hatch Units 1 & 2. The extension would allow for substantial cost savings as the ILRT could be deferred for additional scheduled refueling outages. The risk assessment follows the guidelines from NEI 94-01 [1], the methodology used in EPRI TR-104285 [2], the NE! "Interim Guidance for Performing Risk Impact Assessments In Support of One-Time Extensions for Containment Integrated Leakage Rate Test Surveillance Intervals" [3, 21], the NRC regulatory guidance on the use of Probabilistic Risk Assessment (PRA) as stated in Regulatory Guide 1.200 [28] as applied to ILRT interval extensions, and risk insights in support of a request for a plant's licensing basis as outlined in Regulatory Guide (RG) 1.174 [4], the methodology used for Calvert Cliffs to estimate the likelihood and risk implications of corrosion-induced leakage of steel liners going undetected during the extended test interval [19], and the methodology used in EPRI TR-1009325, Revision 2-A [22] for performing a risk impact assessment of extended integrated leak rate testing intervals. | OF ANALYSIS 1.1 PURPOSE The purpose of this analysis is to provide an assessment of the risk associated with extending , the currently allowed containment Type A integrated leak rate test (ILRT) interval to a permanent fifteen yearsC 1 l for Hatch Units 1 & 2. The extension would allow for substantial cost savings as the ILRT could be deferred for additional scheduled refueling outages. The risk assessment follows the guidelines from NEI 94-01 [1], the methodology used in EPRI TR-104285 [2], the NE! "Interim Guidance for Performing Risk Impact Assessments In Support of One-Time Extensions for Containment Integrated Leakage Rate Test Surveillance Intervals" [3, 21], the NRC regulatory guidance on the use of Probabilistic Risk Assessment (PRA) as stated in Regulatory Guide 1.200 [28] as applied to ILRT interval extensions, and risk insights in support of a request for a plant's licensing basis as outlined in Regulatory Guide (RG) 1.174 [4], the methodology used for Calvert Cliffs to estimate the likelihood and risk implications of corrosion-induced leakage of steel liners going undetected during the extended test interval [19], and the methodology used in EPRI TR-1009325, Revision 2-A [22] for performing a risk impact assessment of extended integrated leak rate testing intervals. | ||
The EPRI TR-1009325 Revision 2-A methodology incorporates the specific limitations and conditions outlined in the NRC acceptance of the EPRI TR-1009325 Revision 2 methodology documented in the NRC Final Safety Evaluation | The EPRI TR-1009325 Revision 2-A methodology incorporates the specific limitations and conditions outlined in the NRC acceptance of the EPRI TR-1009325 Revision 2 methodology documented in the NRC Final Safety Evaluation | ||
[32]. The format of this document is consistent with the intent of the Risk Impact Assessment Template for evaluating extended integrated leak rate testing intervals provided in Appendix H of the EPRI methodology report [22]. | [32]. The format of this document is consistent with the intent of the Risk Impact Assessment Template for evaluating extended integrated leak rate testing intervals provided in Appendix H of the EPRI methodology report [22]. | ||
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Revisions to lOCFRSO, Appendix J (Option B) allow individual plants to extend the Integrated Leak Rate Test (ILRT) Type A surveillance testing frequency requirements from three-in-ten years to at least once in ten years. The revised Type A frequency is based on an acceptable performance history defined as two consecutive periodic Type A tests at least 24 months apart in which the calculated performance leakage was less than limiting containment leakage rate of 1.0La (allowable leakage). | Revisions to lOCFRSO, Appendix J (Option B) allow individual plants to extend the Integrated Leak Rate Test (ILRT) Type A surveillance testing frequency requirements from three-in-ten years to at least once in ten years. The revised Type A frequency is based on an acceptable performance history defined as two consecutive periodic Type A tests at least 24 months apart in which the calculated performance leakage was less than limiting containment leakage rate of 1.0La (allowable leakage). | ||
Cll The ILRT risk assessment is to be used to support a request to a 1 in 15 year ILRT test frequency on a permanent basis. The risk assessment methodology and results equally support a request to extend the ILRT test frequency to 1 in 15 years on a one time basis, as has been performed by many utilities. | Cll The ILRT risk assessment is to be used to support a request to a 1 in 15 year ILRT test frequency on a permanent basis. The risk assessment methodology and results equally support a request to extend the ILRT test frequency to 1 in 15 years on a one time basis, as has been performed by many utilities. | ||
1-1 The basis for a 10-year test interval is provided in Section 11.0 of NEI 94-01, Revision O, and was established in 1995 during development of the performance-based Option B to Appendix J. Section 11.0 of NEI 94-01 states that NUREG-1493 | 1-1 The basis for a 10-year test interval is provided in Section 11.0 of NEI 94-01, Revision O, and was established in 1995 during development of the performance-based Option B to Appendix J. Section 11.0 of NEI 94-01 states that NUREG-1493 | ||
[5], "Performance-Based Containment Leak Test Program," September 1995, provides the technical basis to support rulemaking to revise leakage rate testing requirements contained in Option B to Appendix J. The basis consisted of qualitative and quantitative assessments of the risk impact (in terms of increased public dose) associated with a range of extended leakage rate test intervals. | [5], "Performance-Based Containment Leak Test Program," September 1995, provides the technical basis to support rulemaking to revise leakage rate testing requirements contained in Option B to Appendix J. The basis consisted of qualitative and quantitative assessments of the risk impact (in terms of increased public dose) associated with a range of extended leakage rate test intervals. | ||
To supplement the NRC's rulemaking basis, NEI undertook a similar study. The results of that study are documented in Electric Power Research Institute (EPRI) Research Project Report TR-104285 | To supplement the NRC's rulemaking basis, NEI undertook a similar study. The results of that study are documented in Electric Power Research Institute (EPRI) Research Project Report TR-104285 | ||
[2]. The NRC report on performance-based leak testing, NUREG-1493, analyzed the effects of containment leakage on the health and safety of the public and the benefits realized from the containment leak rate testing. In that analysis, it was determined that for a representative PWR plant (i.e., Surry) containment isolation failures contribute less than 0.1 percent to the latent risks from reactor accidents. | [2]. The NRC report on performance-based leak testing, NUREG-1493, analyzed the effects of containment leakage on the health and safety of the public and the benefits realized from the containment leak rate testing. In that analysis, it was determined that for a representative PWR plant (i.e., Surry) containment isolation failures contribute less than 0.1 percent to the latent risks from reactor accidents. | ||
Consequently, it is desirable to show that extending the ILRT interval will not lead to a substantial increase in risk from containment isolation failures for the Hatch plants. Earlier ILRT frequency extension submittals have used the EPRI TR-104285 | Consequently, it is desirable to show that extending the ILRT interval will not lead to a substantial increase in risk from containment isolation failures for the Hatch plants. Earlier ILRT frequency extension submittals have used the EPRI TR-104285 | ||
[2] methodology to perform the risk assessment. | [2] methodology to perform the risk assessment. | ||
In October 2008, EPRI TR-1018243 | In October 2008, EPRI TR-1018243 | ||
[22] was issued to update the generic methodology for ILRT extensions to 15 years using current performance data and to incorporate the specific limitations and conditions outlined by the NRC in the final safety evaluation of the methodology | [22] was issued to update the generic methodology for ILRT extensions to 15 years using current performance data and to incorporate the specific limitations and conditions outlined by the NRC in the final safety evaluation of the methodology | ||
[32]. This more recent EPRI document considers additional risk metric? an_d criteria including 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 population dose. Hatch requested a one-time extension of the ILRT test frequency from 1 in 10 years to 1 in 15 years for Unit 1 [23] and Unit 2 [24]. The NRC approved the one-time extensions for both Unit 1 [33] and Unit 2 [34]. It should be noted that containment leak-tight integrity is also verified through periodic inservice inspections conducted in accordance with the requirements of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code Section XI. More specifically, 1-2 Subsection IWE provides the rules and requirements for inservice inspection of Class MC pressure-retaining components and their integral attachments, and of metallic shell and penetration liners of Class CC pressure-retaining components and their integral attachments in light-water cooled plants. Furthermore, NRC regulations 10 CFR 50.55a(b)(2)(ix)(E) require licensees to conduct visual inspections of the accessible areas of the interior of the containment. | [32]. This more recent EPRI document considers additional risk metric? an_d criteria including 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 population dose. Hatch requested a one-time extension of the ILRT test frequency from 1 in 10 years to 1 in 15 years for Unit 1 [23] and Unit 2 [24]. The NRC approved the one-time extensions for both Unit 1 [33] and Unit 2 [34]. It should be noted that containment leak-tight integrity is also verified through periodic inservice inspections conducted in accordance with the requirements of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code Section XI. More specifically, 1-2 Subsection IWE provides the rules and requirements for inservice inspection of Class MC pressure-retaining components and their integral attachments, and of metallic shell and penetration liners of Class CC pressure-retaining components and their integral attachments in light-water cooled plants. Furthermore, NRC regulations 10 CFR 50.55a(b)(2)(ix)(E) require licensees to conduct visual inspections of the accessible areas of the interior of the containment. | ||
In addition, Appendix J, Type B local leak tests performed to verify the leak-tight integrity of containment penetration bellows, airlocks, seals, and gaskets are also not affected by the change to the Type A test frequency. | In addition, Appendix J, Type B local leak tests performed to verify the leak-tight integrity of containment penetration bellows, airlocks, seals, and gaskets are also not affected by the change to the Type A test frequency. | ||
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In context, it is noted that a CCFP of 1/10 (10%) has been approved for application to evolutionary light water designs. Given these perspectives, a change in the CCFP of up to 1.5% (percentage point) is assumed to be small. This criterion is articulated in the NRC Final Safety Evaluation Report [32] associated with NEI 94-01 and the EPRI ILRT methodology. | In context, it is noted that a CCFP of 1/10 (10%) has been approved for application to evolutionary light water designs. Given these perspectives, a change in the CCFP of up to 1.5% (percentage point) is assumed to be small. This criterion is articulated in the NRC Final Safety Evaluation Report [32] associated with NEI 94-01 and the EPRI ILRT methodology. | ||
1-3 In addition, the total annual risk (person rem/yr population dose) is examined to demonstrate both the relative change and absolute change in this parameter. | 1-3 In addition, the total annual risk (person rem/yr population dose) is examined to demonstrate both the relative change and absolute change in this parameter. | ||
Examinations of NUREG-1493 and Safety Evaluation Reports (SER) for one-time interval extensions (summarized in Appendix G of EPRI 1018243 [22]) indicate a range of incremental increases in population dose that have been accepted by the NRcC 1>. The range of incremental population dose increases is from <= 0.01 to 0.2 person-rem/yr and/or 0.002 to 0.46% of the total accident dose. The total doses for the spectrum of all accidents (NUREG-1493 | Examinations of NUREG-1493 and Safety Evaluation Reports (SER) for one-time interval extensions (summarized in Appendix G of EPRI 1018243 [22]) indicate a range of incremental increases in population dose that have been accepted by the NRcC 1>. The range of incremental population dose increases is from <= 0.01 to 0.2 person-rem/yr and/or 0.002 to 0.46% of the total accident dose. The total doses for the spectrum of all accidents (NUREG-1493 | ||
[5], Figure 7-2) result in health effects that are at least two orders of magnitude less than the NRC Safety Goal risk. Given these perspectives, a very small population dose is defined as an increase from the baseline interval (3 tests per 10 years) dose of <= 1.0 person-rem/yr or 1 % of the total baseline dose, whichever is less restrictive for the risk impact assessment of the proposed extended ILRT interval. | [5], Figure 7-2) result in health effects that are at least two orders of magnitude less than the NRC Safety Goal risk. Given these perspectives, a very small population dose is defined as an increase from the baseline interval (3 tests per 10 years) dose of <= 1.0 person-rem/yr or 1 % of the total baseline dose, whichever is less restrictive for the risk impact assessment of the proposed extended ILRT interval. | ||
This criterion is articulated in the NRC Final Safety Evaluation Report [32] associated with NEI 94-01 and the EPRI ILRT methodology. | This criterion is articulated in the NRC Final Safety Evaluation Report [32] associated with NEI 94-01 and the EPRI ILRT methodology. | ||
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===2.0 METHODOLOGY=== | ===2.0 METHODOLOGY=== | ||
A simplified bounding analysis approach consistent with the latest EPRI approach [22] as accepted by the NRC [32] is used for evaluating the change in risk associated with increasing the test interval to fifteen years. The approach is consistent with that presented in EPRI TR-1018243 | A simplified bounding analysis approach consistent with the latest EPRI approach [22] as accepted by the NRC [32] is used for evaluating the change in risk associated with increasing the test interval to fifteen years. The approach is consistent with that presented in EPRI TR-1018243 | ||
[22], NUREG-1493 | [22], NUREG-1493 | ||
[5] and the Calvert Cliffs liner corrosion analysis [19]. The analysis uses results from a Level 2 analysis of core damage scenarios from the current Hatch Unit 1 PRA model and the subsequent containment responses for the various fission product release categories (including containment intact release). | [5] and the Calvert Cliffs liner corrosion analysis [19]. The analysis uses results from a Level 2 analysis of core damage scenarios from the current Hatch Unit 1 PRA model and the subsequent containment responses for the various fission product release categories (including containment intact release). | ||
This risk assessment is applicable to Hatch Units 1 & 2 because Unit 2 can be adequately represented by Unit 1 PRA results (see Section 4.2). The six general steps of this assessment are as follows: 1. Quantify the baseline risk in terms of the frequency of events (per reactor year) for each of the eight containment release scenario types identified in the EPRI report. 2. Develop plant-specific person-rem (population dose) per reactor year for each of the eight containment release scenario types from plant specific consequence analyses. | This risk assessment is applicable to Hatch Units 1 & 2 because Unit 2 can be adequately represented by Unit 1 PRA results (see Section 4.2). The six general steps of this assessment are as follows: 1. Quantify the baseline risk in terms of the frequency of events (per reactor year) for each of the eight containment release scenario types identified in the EPRI report. 2. Develop plant-specific person-rem (population dose) per reactor year for each of the eight containment release scenario types from plant specific consequence analyses. | ||
: 3. Evaluate the risk impact (i.e. the change in containment release scenario type frequency and population dose) of extending the ILRT interval to fifteen years. 4. Determine the change in risk in terms of Large Early Release Frequency (LERF) in accordance with RG 1.174 [4] and compare this change with the acceptance guidelines of RG 1.174. 5. Determine the impact on the Conditional Containment Failure Probability (CCFP) 6. Evaluate the sensitivity of the results to assumptions in the corrosion analysis, external events, and to the probability of undetected leaks from containment (due to corrosion breach) to LERF. This approach is based on the information and approaches contained in the previously mentioned studies. Furthermore, | : 3. Evaluate the risk impact (i.e. the change in containment release scenario type frequency and population dose) of extending the ILRT interval to fifteen years. 4. Determine the change in risk in terms of Large Early Release Frequency (LERF) in accordance with RG 1.174 [4] and compare this change with the acceptance guidelines of RG 1.174. 5. Determine the impact on the Conditional Containment Failure Probability (CCFP) 6. Evaluate the sensitivity of the results to assumptions in the corrosion analysis, external events, and to the probability of undetected leaks from containment (due to corrosion breach) to LERF. This approach is based on the information and approaches contained in the previously mentioned studies. Furthermore, | ||
* Consistent with the other industry containment leak risk assessments, the Hatch assessment uses LERF and delta LERF in accordance with the risk acceptance guidance of RG 1.174. Changes in population dose and conditional containment failure probability (CCFP) are also considered to show that defense-in-depth and the balance of prevention and mitigation is preserved. | * Consistent with the other industry containment leak risk assessments, the Hatch assessment uses LERF and delta LERF in accordance with the risk acceptance guidance of RG 1.174. Changes in population dose and conditional containment failure probability (CCFP) are also considered to show that defense-in-depth and the balance of prevention and mitigation is preserved. | ||
* This evaluation uses ground rules and methods to calculate changes in risk metrics that are consistent with those in the EPRI methodology | * This evaluation uses ground rules and methods to calculate changes in risk metrics that are consistent with those in the EPRI methodology | ||
[22]. 2-1 | [22]. 2-1 | ||
* The EPRI methodology | * The EPRI methodology | ||
[22] specifies that emergency core cooling system (ECCS) net positive suction head (NPSH) requirements be assessed regarding whether containment over pressure is credited in the design basis ECCS analysis, and if containment over pressure is credited, the potential impacts on the core damage frequency (CDF). As documented in Section 6.3.3.9 of the Hatch FSAR [36], containment over pressure is not required or credited for Unit 2 for either short term (i.e., < 10 minutes following LOCA initiation) or long term Residual Heat Removal (RHR) pump or Core Spray (CS) pump operation. | [22] specifies that emergency core cooling system (ECCS) net positive suction head (NPSH) requirements be assessed regarding whether containment over pressure is credited in the design basis ECCS analysis, and if containment over pressure is credited, the potential impacts on the core damage frequency (CDF). As documented in Section 6.3.3.9 of the Hatch FSAR [36], containment over pressure is not required or credited for Unit 2 for either short term (i.e., < 10 minutes following LOCA initiation) or long term Residual Heat Removal (RHR) pump or Core Spray (CS) pump operation. | ||
For Unit 1, the design basis calcu.lations indicate that 3.24 psig (7.5 ft) of containment over pressure is required to ensure adequate NPSH to the RHR pumps, and 3.2 psig (7.4 ft) of containment over pressure is required to ensure adequate NPSH to the CS pumps (at the peak calculated suppression pool temperature of 211.3 °F) for a period from about 2.5 hours to 20 hours after LOCA initiation. | For Unit 1, the design basis calcu.lations indicate that 3.24 psig (7.5 ft) of containment over pressure is required to ensure adequate NPSH to the RHR pumps, and 3.2 psig (7.4 ft) of containment over pressure is required to ensure adequate NPSH to the CS pumps (at the peak calculated suppression pool temperature of 211.3 °F) for a period from about 2.5 hours to 20 hours after LOCA initiation. | ||
| Line 821: | Line 821: | ||
* Plant specific dose calculations for containment intact cases are not available from the Hatch SAMA analysis. | * Plant specific dose calculations for containment intact cases are not available from the Hatch SAMA analysis. | ||
NUREG-1150 results for such cases are adequately representative for use in the Hatch analysis based on scaling the NUREG-1150 results to account for differences in regional population, power level, and allowed technical specification leakage. | NUREG-1150 results for such cases are adequately representative for use in the Hatch analysis based on scaling the NUREG-1150 results to account for differences in regional population, power level, and allowed technical specification leakage. | ||
* Accident classes describing radionuclide release end states are defined consistent with the EPRI methodology | * Accident classes describing radionuclide release end states are defined consistent with the EPRI methodology | ||
[22], as summarized in Section 4.2. | [22], as summarized in Section 4.2. | ||
* The representative containment leakage for Class 1 sequences is 1La. Class 3 accounts for increased leakage due to Type A inspection failures. | * The representative containment leakage for Class 1 sequences is 1La. Class 3 accounts for increased leakage due to Type A inspection failures. | ||
* The representative containment leakage for Class 3a sequences is 10La, based on the previously approved methodology performed for Indian Point Unit 3 [6, 7]. | * The representative containment leakage for Class 3a sequences is 10La, based on the previously approved methodology performed for Indian Point Unit 3 [6, 7]. | ||
* The representative containment leakage for Class 3b sequences is 100La, based on the NRC SER [32] and incorporated in the latest EPRI report [22]. Note that most of the previous one-time ILRT extension requests utilized 35La. 3-1 | * The representative containment leakage for Class 3b sequences is 100La, based on the NRC SER [32] and incorporated in the latest EPRI report [22]. Note that most of the previous one-time ILRT extension requests utilized 35La. 3-1 | ||
* The Class 3b can be very conservatively categorized as LERF based on the previously approved methodology | * The Class 3b can be very conservatively categorized as LERF based on the previously approved methodology | ||
[6, 7]. The Class 3b category increase is used as a surrogate for LERF in this application even though the releases associated with a 100La release would not necessarily be consistent with a "Large" release for Hatch. * * * | [6, 7]. The Class 3b category increase is used as a surrogate for LERF in this application even though the releases associated with a 100La release would not necessarily be consistent with a "Large" release for Hatch. * * * | ||
* The impact on population doses from containment bypass scenarios is not altered by the proposed ILRT extension. | * The impact on population doses from containment bypass scenarios is not altered by the proposed ILRT extension. | ||
Rather it is accounted for in the EPRI methodology as a separate entry for comparison purposes, as accepted in the NRC SER [32]. Because the containment bypass contribution to population dose is fixed, no changes to the conclusions from this analysis will result from this separate categorization. | Rather it is accounted for in the EPRI methodology as a separate entry for comparison purposes, as accepted in the NRC SER [32]. Because the containment bypass contribution to population dose is fixed, no changes to the conclusions from this analysis will result from this separate categorization. | ||
The reduction in ILRT frequency does not impact the reliability of containment isolation valves to close in response to a containment isolation signal. Consideration of the risk impact of the ILRT on shutdown risk is addressed in Section 6 using the generic results from EPRI TR-105189 | The reduction in ILRT frequency does not impact the reliability of containment isolation valves to close in response to a containment isolation signal. Consideration of the risk impact of the ILRT on shutdown risk is addressed in Section 6 using the generic results from EPRI TR-105189 | ||
[8]. The ILRT analysis evaluates very small changes in the risk metrics. To facilitate the calculation of these changes and the evaluation of sensitivity cases, the calculations are performed in a spreadsheet. | [8]. The ILRT analysis evaluates very small changes in the risk metrics. To facilitate the calculation of these changes and the evaluation of sensitivity cases, the calculations are performed in a spreadsheet. | ||
In general, the calculations provided in this report reproduce the calculation results of the spreadsheets. | In general, the calculations provided in this report reproduce the calculation results of the spreadsheets. | ||
| Line 836: | Line 836: | ||
===4.0 INPUTS=== | ===4.0 INPUTS=== | ||
This section summarizes the general resources available as input (Section 4.1) and the plant specific resources required (Section 4.2). 4.1 GENERAL RESOURCES AVAILABLE Various industry studies on containment leakage risk assessment are briefly summarized here: 1. NUREG/CR-3539 | This section summarizes the general resources available as input (Section 4.1) and the plant specific resources required (Section 4.2). 4.1 GENERAL RESOURCES AVAILABLE Various industry studies on containment leakage risk assessment are briefly summarized here: 1. NUREG/CR-3539 | ||
[10] 2. NU REG/CR-4220 | [10] 2. NU REG/CR-4220 | ||
[11] 3. NUREG-1273 | [11] 3. NUREG-1273 | ||
[12] 4. NUREG/CR-4330 | [12] 4. NUREG/CR-4330 | ||
[13] 5. EPRI TR-105189 | [13] 5. EPRI TR-105189 | ||
[8] 6. NUREG-1493 | [8] 6. NUREG-1493 | ||
[5] 7. EPRI TR-104285 | [5] 7. EPRI TR-104285 | ||
[2] 8. NUREG-1150 | [2] 8. NUREG-1150 | ||
[14] and NUREG/CR-4551 | [14] and NUREG/CR-4551 | ||
[26] 9. NEI Interim Guidance [3, 21] 10. Calvert Cliffs liner corrosion analysis [19] 11. NRC SER [32] on EPRI TR-1009325 | [26] 9. NEI Interim Guidance [3, 21] 10. Calvert Cliffs liner corrosion analysis [19] 11. NRC SER [32] on EPRI TR-1009325 | ||
: 12. EPRI 1018243 [22] The first study is applicable because it provides one basis for the threshold could be used in the Level 2 PRA for the size of containment leakage that is considered significant and to be included in the model. The second study is applicable because it provides a basis of the probability for significant pre-existing containment leakage at the time of a core damage accident. | : 12. EPRI 1018243 [22] The first study is applicable because it provides one basis for the threshold could be used in the Level 2 PRA for the size of containment leakage that is considered significant and to be included in the model. The second study is applicable because it provides a basis of the probability for significant pre-existing containment leakage at the time of a core damage accident. | ||
The third study is applicable because it is a subsequent study to NUREG/CR-4220 that undertook a more extensive evaluation of the same database. | The third study is applicable because it is a subsequent study to NUREG/CR-4220 that undertook a more extensive evaluation of the same database. | ||
| Line 853: | Line 853: | ||
The tenth study addresses the impact of age-related degradation of the containment steel on ILRT evaluations. | The tenth study addresses the impact of age-related degradation of the containment steel on ILRT evaluations. | ||
The eleventh study [32] documents the NRC Final Safety Evaluation of the EPRI 2007 version of ILRT risk assessment guidance (i.e., EPRI TR-1009325, Revision 2). The last study by EPRI complements the previous EPRI report [2], integrates the NEI interim guidance and NRC SER limitations and conditions, and provides a recommended methodology and template for evaluating the risk associated with a permanent 15-year ILRT interval. | The eleventh study [32] documents the NRC Final Safety Evaluation of the EPRI 2007 version of ILRT risk assessment guidance (i.e., EPRI TR-1009325, Revision 2). The last study by EPRI complements the previous EPRI report [2], integrates the NEI interim guidance and NRC SER limitations and conditions, and provides a recommended methodology and template for evaluating the risk associated with a permanent 15-year ILRT interval. | ||
NUREG/CR-3539 | NUREG/CR-3539 | ||
[10] Oak Ridge National Laboratory (ORNL) documented a study of the impact of containment leak rates on public risk in NUREG/CR-3539. | [10] Oak Ridge National Laboratory (ORNL) documented a study of the impact of containment leak rates on public risk in NUREG/CR-3539. | ||
This study uses information from WASH-1400 | This study uses information from WASH-1400 | ||
[15] as the basis for its risk sensitivity calculations. | [15] as the basis for its risk sensitivity calculations. | ||
ORNL concluded that the impact of leakage rates on LWR accident risks is relatively small. NUREG/CR-4220 | ORNL concluded that the impact of leakage rates on LWR accident risks is relatively small. NUREG/CR-4220 | ||
[11] NUREG/CR-4220 is a study performed by Pacific Northwest Laboratories for the NRC in 1985. The study reviewed over two thousand LERs, ILRT reports and other related records to calculate the unavailability of containment due to leakage. It assessed the "large" containment leak probability to be in the range of lE-3 to lE-2, with 5E-3 identified as the point estimate based on 4 events in 740 reactor years and conservatively assuming a one-year duration for each event. NUREG-1273 | [11] NUREG/CR-4220 is a study performed by Pacific Northwest Laboratories for the NRC in 1985. The study reviewed over two thousand LERs, ILRT reports and other related records to calculate the unavailability of containment due to leakage. It assessed the "large" containment leak probability to be in the range of lE-3 to lE-2, with 5E-3 identified as the point estimate based on 4 events in 740 reactor years and conservatively assuming a one-year duration for each event. NUREG-1273 | ||
[12] A subsequent NRC study, NUREG-1273, performed a more extensive evaluation of the NUREG/CR-4220 database. | [12] A subsequent NRC study, NUREG-1273, performed a more extensive evaluation of the NUREG/CR-4220 database. | ||
This assessment noted that about one-third of the reported events were leakages that were immediately detected and corrected. | This assessment noted that about one-third of the reported events were leakages that were immediately detected and corrected. | ||
In addition, this study noted that local leak rate tests can detect "essentially all potential degradations" of the containment isolation system. 4-2 NUREG/CR-4330 | In addition, this study noted that local leak rate tests can detect "essentially all potential degradations" of the containment isolation system. 4-2 NUREG/CR-4330 | ||
[131 NUREG/CR-4330 is a study that examined the risk impacts associated with increasing the allowable containment leakage rates. The details of this report have no direct impact on the modeling approach of the ILRT test interval extension, as NUREG/CR-4330 focuses on leakage rate and the ILRT test interval extension study focuses on the frequency of testing intervals. | [131 NUREG/CR-4330 is a study that examined the risk impacts associated with increasing the allowable containment leakage rates. The details of this report have no direct impact on the modeling approach of the ILRT test interval extension, as NUREG/CR-4330 focuses on leakage rate and the ILRT test interval extension study focuses on the frequency of testing intervals. | ||
However, the general conclusions of NUREG/CR-4330 are consistent with NUREG/CR-3539 and other similar containment leakage risk studies: " ... the effect of containment leakage on overall accident risk is small since risk is dominated by accident sequences that result in failure or bypass of containment." EPRI TR-105189 | However, the general conclusions of NUREG/CR-4330 are consistent with NUREG/CR-3539 and other similar containment leakage risk studies: " ... the effect of containment leakage on overall accident risk is small since risk is dominated by accident sequences that result in failure or bypass of containment." EPRI TR-105189 | ||
[81 The EPRI study TR-105189 is useful to the ILRT test interval extension risk assessment because this EPRI study provides insight regarding the impact of containment testing on shutdown risk. This study performed a quantitative evaluation (using the EPRI ORAM for two reference plants (a BWR-4 and a PWR) of the impact of extending ILRT and LLRT test intervals on shutdown risk. The result of the study concluded that a small but measurable safety benefit (shutdown CDF reduced by lE-8/yr to lE-7/yr) is realized from extending the test intervals from 3 per 10 years to 1 per 10 years. NUREG-1493 | [81 The EPRI study TR-105189 is useful to the ILRT test interval extension risk assessment because this EPRI study provides insight regarding the impact of containment testing on shutdown risk. This study performed a quantitative evaluation (using the EPRI ORAM for two reference plants (a BWR-4 and a PWR) of the impact of extending ILRT and LLRT test intervals on shutdown risk. The result of the study concluded that a small but measurable safety benefit (shutdown CDF reduced by lE-8/yr to lE-7/yr) is realized from extending the test intervals from 3 per 10 years to 1 per 10 years. NUREG-1493 | ||
[5] NUREG-1493 is the NRC's cost-benefit analysis for proposed alternatives to reduce containment leakage testing intervals and/or relax allowable leakage rates. conclusions are consistent with other similar containment leakage risk studies: The NRC | [5] NUREG-1493 is the NRC's cost-benefit analysis for proposed alternatives to reduce containment leakage testing intervals and/or relax allowable leakage rates. conclusions are consistent with other similar containment leakage risk studies: The NRC | ||
* Reduction in ILRT frequency from 3 per 10 years to 1 per 20 years results in an "imperceptible" increase in risk. | * Reduction in ILRT frequency from 3 per 10 years to 1 per 20 years results in an "imperceptible" increase in risk. | ||
* Given the insensitivity of risk to the containment leak rate and the small fraction of leak paths detected solely by Type A testing, increasing the interval between integrated leak rate tests is possible with minimal impact on public risk. EPRI TR-104285 | * Given the insensitivity of risk to the containment leak rate and the small fraction of leak paths detected solely by Type A testing, increasing the interval between integrated leak rate tests is possible with minimal impact on public risk. EPRI TR-104285 | ||
[2] Extending the risk assessment impact beyond shutdown (the earlier EPRI TR-105189 study), the EPRI TR-104285 study is a quantitative evaluation of the impact of extending ILRT and LLRT test intervals on at-power public risk. This study combined IPE Level 2 models with 4-3 NUREG-1150 | [2] Extending the risk assessment impact beyond shutdown (the earlier EPRI TR-105189 study), the EPRI TR-104285 study is a quantitative evaluation of the impact of extending ILRT and LLRT test intervals on at-power public risk. This study combined IPE Level 2 models with 4-3 NUREG-1150 | ||
[14] Level 3 population dose models to perform the analysis. | [14] Level 3 population dose models to perform the analysis. | ||
The study also used the approach of NUREG-1493 in calculating the increase in pre-existing leakage probability due to extending the ILRT and LLRT test intervals. | The study also used the approach of NUREG-1493 in calculating the increase in pre-existing leakage probability due to extending the ILRT and LLRT test intervals. | ||
EPRI TR-104285 used a simplified Containment Event Tree to subdivide representative core damage sequences into eight categories of containment response to a core damage accident: | EPRI TR-104285 used a simplified Containment Event Tree to subdivide representative core damage sequences into eight categories of containment response to a core damage accident: | ||
: 1. Containment intact and isolated 2. Containment isolation failures dependent upon the core damage accident 3. Type A (ILRT) related containment isolation failures 4. Type B (LLRT) related containment isolation failures 5. Type C (LLRT) related containment isolation failures 6. Other penetration related containment isolation failures 7. Containment failure due to core damage accident phenomena | : 1. Containment intact and isolated 2. Containment isolation failures dependent upon the core damage accident 3. Type A (ILRT) related containment isolation failures 4. Type B (LLRT) related containment isolation failures 5. Type C (LLRT) related containment isolation failures 6. Other penetration related containment isolation failures 7. Containment failure due to core damage accident phenomena | ||
: 8. Containment bypass Consistent with the other containment leakage risk assessment studies, this study concluded: "These study results show that the proposed CLRT [containment leak rate tests] frequency changes would have a minimal safety impact. The change in risk determined by the analyses is small in both absolute and relative terms. For example, for the PWR analyzed, the change is about 0.02 person-rem per year ... " NUREG-1150 | : 8. Containment bypass Consistent with the other containment leakage risk assessment studies, this study concluded: "These study results show that the proposed CLRT [containment leak rate tests] frequency changes would have a minimal safety impact. The change in risk determined by the analyses is small in both absolute and relative terms. For example, for the PWR analyzed, the change is about 0.02 person-rem per year ... " NUREG-1150 | ||
[14] and NUREG/CR-4551 | [14] and NUREG/CR-4551 | ||
[26] NUREG-1150 | [26] NUREG-1150 | ||
[14] and the technical basis, NUREG/CR-4551 | [14] and the technical basis, NUREG/CR-4551 | ||
[26], provide an ex-plant consequence analysis for a spectrum of accidents including a severe accident with the containment remaining intact (i.e., Tech Spec leakage). | [26], provide an ex-plant consequence analysis for a spectrum of accidents including a severe accident with the containment remaining intact (i.e., Tech Spec leakage). | ||
This ex-plant consequence calculation is calculated for the SO-mile radial area surrounding Peach Bottom. The ex-plant consequence calculation for the containment remaining intact represents a very small contributor to the overall risk spectrum. | This ex-plant consequence calculation is calculated for the SO-mile radial area surrounding Peach Bottom. The ex-plant consequence calculation for the containment remaining intact represents a very small contributor to the overall risk spectrum. | ||
Because it is a small contributor, this ex-plant calculation (i.e., total person-rem) is considered adequate to represent Hatch if population, reactor power, and the Technical Specification leakage are scaled to represent Hatch. (The meteorology and other site differences are assumed not to play a significant role in this evaluation). | Because it is a small contributor, this ex-plant calculation (i.e., total person-rem) is considered adequate to represent Hatch if population, reactor power, and the Technical Specification leakage are scaled to represent Hatch. (The meteorology and other site differences are assumed not to play a significant role in this evaluation). | ||
4-4 NEI Interim Guidance [3, 211 NEI "Interim Guidance for Performing Risk Impact Assessments in Support of One-Time Extensions of Containment Integrated Leakage Rate Test Surveillance Intervals" [3] was developed to provide utilities with revised guidance regarding licensing submittals. | 4-4 NEI Interim Guidance [3, 211 NEI "Interim Guidance for Performing Risk Impact Assessments in Support of One-Time Extensions of Containment Integrated Leakage Rate Test Surveillance Intervals" [3] was developed to provide utilities with revised guidance regarding licensing submittals. | ||
Additional information from NEI on the "Interim Guidance" was supplied in Reference | Additional information from NEI on the "Interim Guidance" was supplied in Reference | ||
[21]. A nine step process is defined which includes changes in the following areas of the previous EPRI guidance: | [21]. A nine step process is defined which includes changes in the following areas of the previous EPRI guidance: | ||
* Impact of extending surveillance intervals on dose | * Impact of extending surveillance intervals on dose | ||
* Method used to calculate the frequencies of leakages detectable only by ILRTs | * Method used to calculate the frequencies of leakages detectable only by ILRTs | ||
* Provisions for using NUREG-1150 dose calculations to support the population dose determination. | * Provisions for using NUREG-1150 dose calculations to support the population dose determination. | ||
The guidance provided in this document builds on the EPRI risk impact assessment methodology | The guidance provided in this document builds on the EPRI risk impact assessment methodology | ||
[2] and the NRC performance-based containment leakage test program [5], and considers approaches utilized in various submittals, including Indian Point 3 (and associated NRC SER) [6,7] and Crystal River [20]. Calvert Cliffs Liner Corrosion Analysis [19] This submittal to the NRC describes a method for determining the change in likelihood, due to extending the ILRT, of detecting liner corrosion, and the corresponding change in risk. The methodology was developed for Calvert Cliffs in response to a request for additional information regarding how the potential leakage due to age-related degradation mechanisms were factored into the risk assessment for the ILRT one-time extension. | [2] and the NRC performance-based containment leakage test program [5], and considers approaches utilized in various submittals, including Indian Point 3 (and associated NRC SER) [6,7] and Crystal River [20]. Calvert Cliffs Liner Corrosion Analysis [19] This submittal to the NRC describes a method for determining the change in likelihood, due to extending the ILRT, of detecting liner corrosion, and the corresponding change in risk. The methodology was developed for Calvert Cliffs in response to a request for additional information regarding how the potential leakage due to age-related degradation mechanisms were factored into the risk assessment for the ILRT one-time extension. | ||
The Calvert Cliffs analysis was performed for a concrete cylinder and dome and a concrete basemat, each with a steel liner. Licensees may consider approved LARs for one-time extensions involving containment types similar to their facility. | The Calvert Cliffs analysis was performed for a concrete cylinder and dome and a concrete basemat, each with a steel liner. Licensees may consider approved LARs for one-time extensions involving containment types similar to their facility. | ||
The Hatch assessment has addressed the specific differences from the Calvert Cliffs design, and the Calvert Cliffs methodology was adapted to address the specific design features. | The Hatch assessment has addressed the specific differences from the Calvert Cliffs design, and the Calvert Cliffs methodology was adapted to address the specific design features. | ||
4-5 NRC SER on ILRT Risk Assessment | 4-5 NRC SER on ILRT Risk Assessment | ||
[32] This report documents the NRC review and acceptance of the EPRI ILRT Risk Assessment methodology of EPRI TR-1009325 Revision 2. Based on the NRC review, four conditions and limitations were identified, summarized here as: 1. Licensees must submit documentation supporting appropriate technical adequacy of the PRA. 2. Acceptance criteria for population dose risk and CCFP were revised. 3. Assumed leakage for EPRI Class 3b is revised from 35La to lOOLa. 4. A license amendment request (LAR) is required in instances where containment over pressure is relied upon for ECCS performance. | [32] This report documents the NRC review and acceptance of the EPRI ILRT Risk Assessment methodology of EPRI TR-1009325 Revision 2. Based on the NRC review, four conditions and limitations were identified, summarized here as: 1. Licensees must submit documentation supporting appropriate technical adequacy of the PRA. 2. Acceptance criteria for population dose risk and CCFP were revised. 3. Assumed leakage for EPRI Class 3b is revised from 35La to lOOLa. 4. A license amendment request (LAR) is required in instances where containment over pressure is relied upon for ECCS performance. | ||
EPRI TR-1018243 | EPRI TR-1018243 | ||
[221 (EPRI TR-1009325 Revision 2-A) This report presents a generally applicable assessment of risk involved in extension of ILRT test intervals to 15 years on a permanent basis. Appendix H of this document provides guidance for performing plant-specific supplemental risk impact assessments and builds on the previous EPRI risk impact assessment methodology TR-104285 | [221 (EPRI TR-1009325 Revision 2-A) This report presents a generally applicable assessment of risk involved in extension of ILRT test intervals to 15 years on a permanent basis. Appendix H of this document provides guidance for performing plant-specific supplemental risk impact assessments and builds on the previous EPRI risk impact assessment methodology TR-104285 | ||
[2], the NEI Interim Guidance [3,21], and the NRC performance-based containment leakage test program [5], and considers approaches utilized in various submittals, including Indian Point 3 (and associated NRC SER) [6,7] and Crystal River [20]. The EPRI report codifies minor changes to the ILRT methodology specified by the NRC in the NRC ILRT risk assessment approach SER [32]. The approach included in this EPRI guidance document is used in the Hatch assessment to determine the estimated increase in risk associated with the ILRT extension. | [2], the NEI Interim Guidance [3,21], and the NRC performance-based containment leakage test program [5], and considers approaches utilized in various submittals, including Indian Point 3 (and associated NRC SER) [6,7] and Crystal River [20]. The EPRI report codifies minor changes to the ILRT methodology specified by the NRC in the NRC ILRT risk assessment approach SER [32]. The approach included in this EPRI guidance document is used in the Hatch assessment to determine the estimated increase in risk associated with the ILRT extension. | ||
This document includes the bases for the values assigned in determining the probability of leakage for the EPRI Class 3a and 3b scenarios in this analysis as described in Section 5. 4.2 PLANT-SPECIFIC INPUTS The Hatch specific information used to perform this ILRT interval extension risk assessment includes the following: | This document includes the bases for the values assigned in determining the probability of leakage for the EPRI Class 3a and 3b scenarios in this analysis as described in Section 5. 4.2 PLANT-SPECIFIC INPUTS The Hatch specific information used to perform this ILRT interval extension risk assessment includes the following: | ||
| Line 900: | Line 900: | ||
* Population Dose within a 50-mile radius [9, 29, 30] | * Population Dose within a 50-mile radius [9, 29, 30] | ||
* ILRT results to demonstrate adequacy of the administrative and hardware interfaces 4-6 Hatch Internal Events Level 1 PRA Model The Unit 1 Internal Events Level 1 PRA model [16] is an event tree / linked fault tree model characteristic of the as-built, as-operated plant. This Level 1 PRA model incorporates the resolution of findings associated with the PRA Peer Review of 2009. The total internal events core damage frequency (CDF) used in this analysis is 7.57E-06/yrC | * ILRT results to demonstrate adequacy of the administrative and hardware interfaces 4-6 Hatch Internal Events Level 1 PRA Model The Unit 1 Internal Events Level 1 PRA model [16] is an event tree / linked fault tree model characteristic of the as-built, as-operated plant. This Level 1 PRA model incorporates the resolution of findings associated with the PRA Peer Review of 2009. The total internal events core damage frequency (CDF) used in this analysis is 7.57E-06/yrC | ||
: 1) (at lE-12/yr truncation) for Unit 1, as reflected in the combined Unit 1Level1 and Level 2 PRA models [17]. (For reference, it is noted that the CDF for the Unit 2 model is 7.42E-06/yr | : 1) (at lE-12/yr truncation) for Unit 1, as reflected in the combined Unit 1Level1 and Level 2 PRA models [17]. (For reference, it is noted that the CDF for the Unit 2 model is 7.42E-06/yr | ||
[39], approximately 1.5% less than the Unit 1 CDF. The Unit 1 model is adequately representative of Unit 2 for the purposes of the ILRT risk assessment.) | [39], approximately 1.5% less than the Unit 1 CDF. The Unit 1 model is adequately representative of Unit 2 for the purposes of the ILRT risk assessment.) | ||
Hatch Internal Events Level 2 PRA Model The Unit 1 Level 2 PRA model [17] was developed to calculate the LERF contribution as well as the other release categories evaluated in the model. This Level 2 PRA model incorporates the resolution of findings associated with the PRA Peer Review of 2009. Table 4.2-la summarizes the pertinent Hatch Unit 1 Level 2 results in terms of end states. The total Large Early Release Frequency (LERF) in Table 4.2-la for Unit 1 is 1.12E-6/yr. | Hatch Internal Events Level 2 PRA Model The Unit 1 Level 2 PRA model [17] was developed to calculate the LERF contribution as well as the other release categories evaluated in the model. This Level 2 PRA model incorporates the resolution of findings associated with the PRA Peer Review of 2009. Table 4.2-la summarizes the pertinent Hatch Unit 1 Level 2 results in terms of end states. The total Large Early Release Frequency (LERF) in Table 4.2-la for Unit 1 is 1.12E-6/yr. | ||
The Unit 2 model LERF value is 1.03E-06/yr | The Unit 2 model LERF value is 1.03E-06/yr | ||
[31], approximately 8% less than the Unit 1 LERF. The lower Unit 2 LERF value is primarily attributed to a plant design difference. | [31], approximately 8% less than the Unit 1 LERF. The lower Unit 2 LERF value is primarily attributed to a plant design difference. | ||
The Unit 2 feedwater injection lines have an additional check valve which lowers the break outside containment (BOC) contribution to LERF for Unit 2. This design difference does not impact the risk assessment because the ILRT interval does not impact the BOC LERF contribution. | The Unit 2 feedwater injection lines have an additional check valve which lowers the break outside containment (BOC) contribution to LERF for Unit 2. This design difference does not impact the risk assessment because the ILRT interval does not impact the BOC LERF contribution. | ||
Cl) The Unit 1 Level 1 CDF value of 7.57E-06/yr used in the Levei 2 evaiuation | Cl) The Unit 1 Level 1 CDF value of 7.57E-06/yr used in the Levei 2 evaiuation | ||
[17] is slightly higher than the Level 1 CDF value of 7.53E-06/yr from the latest version of the Hatch Unit 1 Internal Events Level 1 PRA model [16]. To support the Level 2 quantification, Level 1 sequences are binned into accident classes. However, this separate quantification of the individual accident classes may result in duplicate or non-minimal cutsets to be binned into more than one accident class. This may result in the numerical sum of all individual accident classes to be higher than the CDF if all the cutsets were merged together. | [17] is slightly higher than the Level 1 CDF value of 7.53E-06/yr from the latest version of the Hatch Unit 1 Internal Events Level 1 PRA model [16]. To support the Level 2 quantification, Level 1 sequences are binned into accident classes. However, this separate quantification of the individual accident classes may result in duplicate or non-minimal cutsets to be binned into more than one accident class. This may result in the numerical sum of all individual accident classes to be higher than the CDF if all the cutsets were merged together. | ||
However, the apparent deviation of the Level 1 CDF quantified for the Level 2 model is less than 1 % and is judged not to significantly alter the results. 4-7 The Level 2 release category end states are defined [38] as follows: Release Magnitude High Moderate/Medium Low Low-Low Release Timing Early Intermediate Late CsI Release Fraction > 10% 1% to 10% 0.1% to 1% < 0.1% Time (hrs) <5 5 to 24 > 24 Table 4.2-lb summarizes the core damage frequency contributions by the PRA accident class. 4-8 Table 4.2-la HATCH LEVEL 2 DETAILED RELEASE CATEGORIESC 1> RELEASE FREQUENCY CATEGORY DEFINITION | However, the apparent deviation of the Level 1 CDF quantified for the Level 2 model is less than 1 % and is judged not to significantly alter the results. 4-7 The Level 2 release category end states are defined [38] as follows: Release Magnitude High Moderate/Medium Low Low-Low Release Timing Early Intermediate Late CsI Release Fraction > 10% 1% to 10% 0.1% to 1% < 0.1% Time (hrs) <5 5 to 24 > 24 Table 4.2-lb summarizes the core damage frequency contributions by the PRA accident class. 4-8 Table 4.2-la HATCH LEVEL 2 DETAILED RELEASE CATEGORIESC 1> RELEASE FREQUENCY CATEGORY DEFINITION | ||
(/YR) (1) INTACT Containment remains intact. 1.18E-06 H-E High-early release (i.e., LERF). Dominant accident class 1.12E-06 contributors are as follows: | (/YR) (1) INTACT Containment remains intact. 1.18E-06 H-E High-early release (i.e., LERF). Dominant accident class 1.12E-06 contributors are as follows: | ||
* Class 1A (loss of RPV injection, RPV at high pressure): | * Class 1A (loss of RPV injection, RPV at high pressure): | ||
| Line 921: | Line 921: | ||
LL-I Low Low-intermediate release. Dominant accident class 1.0SE-08 contributor is Class 1D at 1.02E-08/yr. | LL-I Low Low-intermediate release. Dominant accident class 1.0SE-08 contributor is Class 1D at 1.02E-08/yr. | ||
LL-L Low Low-late release. Dominant accident class contributor is 4.63E-09 Class 1A at 4.86E-09/yr. | LL-L Low Low-late release. Dominant accident class contributor is 4.63E-09 Class 1A at 4.86E-09/yr. | ||
Total Total Release Category Frequency (No Intact) 6.40E-06 Total Total CDF 7.SSE-06 From Table 5 of Reference | Total Total Release Category Frequency (No Intact) 6.40E-06 Total Total CDF 7.SSE-06 From Table 5 of Reference | ||
[17] for Unit 1. The High-Late release category had zero frequency and is therefore not listed. 4-9 Table 4.2-lb HATCH CDF CONTRIBUTIONS BY PRA ACCIDENT CLAssC 1> PRA FREQUENCY ACCIDENT (/YR) CLASS DESCRIPTION IA Transients | [17] for Unit 1. The High-Late release category had zero frequency and is therefore not listed. 4-9 Table 4.2-lb HATCH CDF CONTRIBUTIONS BY PRA ACCIDENT CLAssC 1> PRA FREQUENCY ACCIDENT (/YR) CLASS DESCRIPTION IA Transients | ||
-core melt with vessel at high pressure 1.07E-06 IBE Station blackout -early 1.18E-08 IBL Station blackout -late 4.89E-07 IC with loss of injection | -core melt with vessel at high pressure 1.07E-06 IBE Station blackout -early 1.18E-08 IBL Station blackout -late 4.89E-07 IC with loss of injection | ||
: 1. 73E-07 ID lrransients | : 1. 73E-07 ID lrransients | ||
-core melt with vessel at low pressure 1.35E-06 IIA Core melt after containment failure due to loss of DHR 3.39E-06 Ill Core melt after containment failure due to loss of DHR and 4.11E-10 LOCA IIIB LOCA -core melt with vessel remaining at high pressure 1.SOE-08 me LOCA -core melt with vessel at low pressure 2.75E-09 IV | -core melt with vessel at low pressure 1.35E-06 IIA Core melt after containment failure due to loss of DHR 3.39E-06 Ill Core melt after containment failure due to loss of DHR and 4.11E-10 LOCA IIIB LOCA -core melt with vessel remaining at high pressure 1.SOE-08 me LOCA -core melt with vessel at low pressure 2.75E-09 IV | ||
-containment fails before core damage 3.SSE-07 v LOCA outside containment 7.12E-07 Total Total CDF 7.57E-06 (1) From Table 5 of Reference | -containment fails before core damage 3.SSE-07 v LOCA outside containment 7.12E-07 Total Total CDF 7.57E-06 (1) From Table 5 of Reference | ||
[17] for Unit 1. 4-10 Population Dose Conditional population dose results for containment failure end states are available for Hatch based on the Hatch SAMA evaluation performed for Units 1 & 2 and submitted to the NRC in 2000 [9], and subsequent responses to Requests for Additional Information (RAis) [29, 30]. Conditional population dose results for an intact containment end state (not quantified for the SAMA analysis) are available via ex-plant consequence results for Peach Bottom [26] and can be scaled to represent Hatch. The Hatch specific and Peach Bottom surrogate conditional population dose results may be combined with the most recent Hatch Level 2 analysis results [17] to develop population dose risk for use in the ILRT assessment. | [17] for Unit 1. 4-10 Population Dose Conditional population dose results for containment failure end states are available for Hatch based on the Hatch SAMA evaluation performed for Units 1 & 2 and submitted to the NRC in 2000 [9], and subsequent responses to Requests for Additional Information (RAis) [29, 30]. Conditional population dose results for an intact containment end state (not quantified for the SAMA analysis) are available via ex-plant consequence results for Peach Bottom [26] and can be scaled to represent Hatch. The Hatch specific and Peach Bottom surrogate conditional population dose results may be combined with the most recent Hatch Level 2 analysis results [17] to develop population dose risk for use in the ILRT assessment. | ||
The SAMA dose analysis utilized the projected population to year 2030 (i.e., 498,834 people in the 50 mile radial region) and a Hatch power level of 2,763 MWth. The population projection is adequately representative for use in the ILRT assessment. | The SAMA dose analysis utilized the projected population to year 2030 (i.e., 498,834 people in the 50 mile radial region) and a Hatch power level of 2,763 MWth. The population projection is adequately representative for use in the ILRT assessment. | ||
The Hatch power level used in the SAMA analysis is slightly less than the current and anticipated Hatch power level in the future, which is 2,804 MWth. The SAMA dose values may be scaled for use in the ILRT analysis by applying a reactor power level scaling factor of 1.015 (i.e., 2,804 MWth / 2,763 MWth). The Hatch SAMA population dose results are presented in Table 4.2-2. These dose results are based on MACCS2 calculations and accident sequence frequencies applicable at the time. Included in Table 4.2-2 is a column presenting the ILRT assessment dose values after applying the reactor power level scaling factor. It is noted that the release categories represented in the Hatch SAMA analysis all represent high magnitude releases. | The Hatch power level used in the SAMA analysis is slightly less than the current and anticipated Hatch power level in the future, which is 2,804 MWth. The SAMA dose values may be scaled for use in the ILRT analysis by applying a reactor power level scaling factor of 1.015 (i.e., 2,804 MWth / 2,763 MWth). The Hatch SAMA population dose results are presented in Table 4.2-2. These dose results are based on MACCS2 calculations and accident sequence frequencies applicable at the time. Included in Table 4.2-2 is a column presenting the ILRT assessment dose values after applying the reactor power level scaling factor. It is noted that the release categories represented in the Hatch SAMA analysis all represent high magnitude releases. | ||
Doses associated with large releases from containment failure can be conservatively represented by this data. The population dose associated with an intact containment (Technical Specification leakage) case can be estimated based on scaling the NUREG/CR-4551 dose results for Peach Bottom from Accident Progression Bin (APB) #8 (Core is damaged, Vessel is breached, no containment failure)C 1 l. The Peach Bottom dose for APB #8 is not specifically identified in NUREG/CR-4551, but can be back-calculated to be 4,940 person-rem as presented in Table 4.2-3. (lJ APB #8 is described in more detail in NUREG/CR-4551 | Doses associated with large releases from containment failure can be conservatively represented by this data. The population dose associated with an intact containment (Technical Specification leakage) case can be estimated based on scaling the NUREG/CR-4551 dose results for Peach Bottom from Accident Progression Bin (APB) #8 (Core is damaged, Vessel is breached, no containment failure)C 1 l. The Peach Bottom dose for APB #8 is not specifically identified in NUREG/CR-4551, but can be back-calculated to be 4,940 person-rem as presented in Table 4.2-3. (lJ APB #8 is described in more detail in NUREG/CR-4551 | ||
[26] Section 2.4.3. 4-11 The APB #8 person-rem result can be used as an approximation of the dose for Hatch if it is scaled for regional population, reactor power level, and allowable containment leakage rate (La). Values for these attributes for Peach Bottom (as evaluated in NUREG/CR-4551) and Hatch are summarized in Table 4.2-4, where the applicable scaling factors are calculated. | [26] Section 2.4.3. 4-11 The APB #8 person-rem result can be used as an approximation of the dose for Hatch if it is scaled for regional population, reactor power level, and allowable containment leakage rate (La). Values for these attributes for Peach Bottom (as evaluated in NUREG/CR-4551) and Hatch are summarized in Table 4.2-4, where the applicable scaling factors are calculated. | ||
Applying the calculated scaling factors, the population dose for Hatch for an intact containment technical specification release is 1,150 pers-rem (i.e, 4,940 pers-rem | Applying the calculated scaling factors, the population dose for Hatch for an intact containment technical specification release is 1,150 pers-rem (i.e, 4,940 pers-rem | ||
| Line 937: | Line 937: | ||
* 2.4 = 1,150 pers-rem). | * 2.4 = 1,150 pers-rem). | ||
Table 4.2-5 presents the current Hatch Level 2 release frequencies, the assigned dose for the category, and the calculated annual dose risk. The annual dose risk calculated in Table 4.2-5 is not directly used in the ILRT assessment since the EPRI methodology utilizes a different release category scheme, but is presented for completeness. | Table 4.2-5 presents the current Hatch Level 2 release frequencies, the assigned dose for the category, and the calculated annual dose risk. The annual dose risk calculated in Table 4.2-5 is not directly used in the ILRT assessment since the EPRI methodology utilizes a different release category scheme, but is presented for completeness. | ||
EPRI Release Category Definitions Table 4.2-6 defines the accident classes used in the ILRT extension evaluation, which are consistent with the EPRI methodology | EPRI Release Category Definitions Table 4.2-6 defines the accident classes used in the ILRT extension evaluation, which are consistent with the EPRI methodology | ||
[22]. These containment failure classifications are used in this analysis to determine the risk impact of extending the Containment Type A test interval as described in Section 5 of this report. Hatch ILRT Results The surveillance frequency for Type A testing in NE! 94-01 under option B criteria is at least once per ten years based on an acceptable performance history (i.e. two consecutive periodic Type A tests at lec:ist 24 months apart where the calculated performance leakage rate was less than 1.0 La) and consideration of the performance factors in NEI 94-01, Section 11.3. Based on completion of two successful ILRTs at Hatch Unit 1 and Unit 2, the ILRT interval became once per ten years. Subsequently, a one time ILRT interval frequency of once per fifteen years was approved for both Hatch Unit 1 and Unit 2 [33, 34] based on demonstrating acceptable risk impacts. Each Hatch unit has successfully completed another ILRT (i.e., Unit 1 in March 2008, Unit 2 in March 2009) since these one time ILRT interval extension approvals. | [22]. These containment failure classifications are used in this analysis to determine the risk impact of extending the Containment Type A test interval as described in Section 5 of this report. Hatch ILRT Results The surveillance frequency for Type A testing in NE! 94-01 under option B criteria is at least once per ten years based on an acceptable performance history (i.e. two consecutive periodic Type A tests at lec:ist 24 months apart where the calculated performance leakage rate was less than 1.0 La) and consideration of the performance factors in NEI 94-01, Section 11.3. Based on completion of two successful ILRTs at Hatch Unit 1 and Unit 2, the ILRT interval became once per ten years. Subsequently, a one time ILRT interval frequency of once per fifteen years was approved for both Hatch Unit 1 and Unit 2 [33, 34] based on demonstrating acceptable risk impacts. Each Hatch unit has successfully completed another ILRT (i.e., Unit 1 in March 2008, Unit 2 in March 2009) since these one time ILRT interval extension approvals. | ||
4-12 Table 4.2-2 | 4-12 Table 4.2-2 | ||
| Line 944: | Line 944: | ||
OF SAMA MACCS2 CALCULATIONS AND ILRT SCALED VALUES SAMA Frequency SAMA Dose Level 2 End State Seq# Sequence Description (per yr) <10> (Person-Rem) | OF SAMA MACCS2 CALCULATIONS AND ILRT SCALED VALUES SAMA Frequency SAMA Dose Level 2 End State Seq# Sequence Description (per yr) <10> (Person-Rem) | ||
Containment Bypass 5 BOC 1.66E-7C 6 l 1.15E+6C 2 l Early Cont. Failure 2 SBO 1.79E-6<6 l 1.06E+6<3 l 4 Loss of Cont. Heat 7.43E-7<6 l 1.02E+6<4 l Removal (CHR) 11 ATWS 7.43E-7C 6 l 7.02E+5<5 l Late Cont. Failure 12 High pressure transient 2.0E-7<1 l 5.7E+5 with loss of CH R 14 SBO with cont. isolation 3.1E-9(ll failure Intact Cont. (DW Vent) 15 High pressure transient 9.24E-10C 6 l 1.13E+6C 9 l with venting No Containment Failure NA NA NA NAC 7 l NA <1 l SAMA RAI response to Q#4 [29]. C 2 l SAMA RAI response to Q#14; Sequence #5 [29] clarification provided to NRC by SNC [30]. C 3 l SAMA RAI response to Q#l4; Sequence #2 [29]. <4 l SAMA RAI response to Q#14; Sequence #4 [29]. <5 l SAMA RAI response to Q#l4; Sequence #11 [29]. (GJ SAMA RAI response to Q#l.b-1 [29]. C 7 l Not calculated for SAMA. csi SAMA RAI clarification provided by SNC to Question #5 [30]. <9 l SAMA RAI response to Q#l4; Sequence 15 [29]. Adjusted Dose for ILRT Assessment (Person-Rem) | Containment Bypass 5 BOC 1.66E-7C 6 l 1.15E+6C 2 l Early Cont. Failure 2 SBO 1.79E-6<6 l 1.06E+6<3 l 4 Loss of Cont. Heat 7.43E-7<6 l 1.02E+6<4 l Removal (CHR) 11 ATWS 7.43E-7C 6 l 7.02E+5<5 l Late Cont. Failure 12 High pressure transient 2.0E-7<1 l 5.7E+5 with loss of CH R 14 SBO with cont. isolation 3.1E-9(ll failure Intact Cont. (DW Vent) 15 High pressure transient 9.24E-10C 6 l 1.13E+6C 9 l with venting No Containment Failure NA NA NA NAC 7 l NA <1 l SAMA RAI response to Q#4 [29]. C 2 l SAMA RAI response to Q#14; Sequence #5 [29] clarification provided to NRC by SNC [30]. C 3 l SAMA RAI response to Q#l4; Sequence #2 [29]. <4 l SAMA RAI response to Q#14; Sequence #4 [29]. <5 l SAMA RAI response to Q#l4; Sequence #11 [29]. (GJ SAMA RAI response to Q#l.b-1 [29]. C 7 l Not calculated for SAMA. csi SAMA RAI clarification provided by SNC to Question #5 [30]. <9 l SAMA RAI response to Q#l4; Sequence 15 [29]. Adjusted Dose for ILRT Assessment (Person-Rem) | ||
<11> 1.17E+6 1.08E+6 1.04E+6 7.13E+5 5.8E+5 1.15E+6 NA TOTAL SAMA Annual Risk (Person-Rem/Yr) | <11> 1.17E+6 1.08E+6 1.04E+6 7.13E+5 5.8E+5 1.15E+6 NA TOTAL SAMA Annual Risk (Person-Rem/Yr) | ||
[29, 30] 0.19 1.90 0.76 0.52 3.18 total 0.ll2(B) 0.0008 0.001 NAC 7 l 3.48 <10 l It is noted that the Hatch PRA model tias been updated since the SAMA analysis and the accident sequence frequencies and the Table 4.2-3 PEACH BOTTOM APB #8 SO-MILE POPULATION DOSE CALCULATIONC 1> ALL APBS APB #8 SO-MILE APB #8 SO-APB #8 CONTRIBUTION DOSE RISK MILE DOSE APB #8 50-FREQUENCY TO SO-MILE (PERS-RISK (PERS-MILE DOSE (/YR) DOSE RISK REM/YR) REM/YR) (PERS-REM) 7.99E-7C 2) 5E-4C 3 l 7_9C 4 l 3.95E-3C 5 l 4.94E+3C 6 l Cll NUREG/CR-4551 | [29, 30] 0.19 1.90 0.76 0.52 3.18 total 0.ll2(B) 0.0008 0.001 NAC 7 l 3.48 <10 l It is noted that the Hatch PRA model tias been updated since the SAMA analysis and the accident sequence frequencies and the Table 4.2-3 PEACH BOTTOM APB #8 SO-MILE POPULATION DOSE CALCULATIONC 1> ALL APBS APB #8 SO-MILE APB #8 SO-APB #8 CONTRIBUTION DOSE RISK MILE DOSE APB #8 50-FREQUENCY TO SO-MILE (PERS-RISK (PERS-MILE DOSE (/YR) DOSE RISK REM/YR) REM/YR) (PERS-REM) 7.99E-7C 2) 5E-4C 3 l 7_9C 4 l 3.95E-3C 5 l 4.94E+3C 6 l Cll NUREG/CR-4551 | ||
[26] does not document dose results as a function of accident progression bin as such, the dose result for APB #8 is back calculated from the documented APB frequency and dose risk results. <2> From Figure 2.5-6 of NUREG/CR-4551 Vol. 4, Rev. 1, Part 1. Frequency for APB #8 of 7.99E-7/yr is calculated as 0.184 contribution of 4.34E-6/yr CDF. <3 l From Table 5.2-3 for the mean fractional contribution to risk (MFCR) of NUREG/CR-4551 Vol. 4, Rev. 1, Part 1. <4 J From Table 5.1-1 for mean value 50-mile population dose of NUREG/CR-4551 Vol. 4, Rev. 1, Part 1. <5 J APB dose risk is calculated by multiplying the APB dose risk fractional contribution (column 2) by the total 50-mile radius dose risk of 7.9 person-rem/yr (column 3). (GJ Calculated by dividing the APB #8 dose risk (column 4) by the APB #8 frequency (column 1) Table 4.2-4 HATCH APB-#8 DOSE SCALING FACTORS Reactor SO-mile Power TS Leakage Plant Population (MWth) (wt 0/o/day) Hatch 498.834(!) | [26] does not document dose results as a function of accident progression bin as such, the dose result for APB #8 is back calculated from the documented APB frequency and dose risk results. <2> From Figure 2.5-6 of NUREG/CR-4551 Vol. 4, Rev. 1, Part 1. Frequency for APB #8 of 7.99E-7/yr is calculated as 0.184 contribution of 4.34E-6/yr CDF. <3 l From Table 5.2-3 for the mean fractional contribution to risk (MFCR) of NUREG/CR-4551 Vol. 4, Rev. 1, Part 1. <4 J From Table 5.1-1 for mean value 50-mile population dose of NUREG/CR-4551 Vol. 4, Rev. 1, Part 1. <5 J APB dose risk is calculated by multiplying the APB dose risk fractional contribution (column 2) by the total 50-mile radius dose risk of 7.9 person-rem/yr (column 3). (GJ Calculated by dividing the APB #8 dose risk (column 4) by the APB #8 frequency (column 1) Table 4.2-4 HATCH APB-#8 DOSE SCALING FACTORS Reactor SO-mile Power TS Leakage Plant Population (MWth) (wt 0/o/day) Hatch 498.834(!) | ||
2 804(2) 1.2% C 2> Peach Bottom 4,359,67-?(3) 3,293C 4 l 0.5%(S) Scaling Factor 0.114 0.852 2.4 <1> Hatch SAMA year 2030 population | 2 804(2) 1.2% C 2> Peach Bottom 4,359,67-?(3) 3,293C 4 l 0.5%(S) Scaling Factor 0.114 0.852 2.4 <1> Hatch SAMA year 2030 population | ||
[9] <2> Hatch current and anticipated future value. <3 J NUREG/CR-4551, Vol. 2, Rev. 1, Part 7, Appendix A.3 (SITE MACCS2 File) for Peach Bottom. Population total for 50-mile radius developed in Appendix A of this report. <4 J NUREG/CR-4551, Vol. 4, Rev. 1, Part 2, Section A.3.1. <5 l NUREG/CR-4551, Vol. 4, Rev. 1, Part 2, page B.2-9 for no containment failure. 4-14 Table 4.2-5 HATCH POPULATION DOSE RISK AT 50 MILES RELEASE POPULATION DOSE CATEGORY 2030 POPULATION RISK RELEASE FREQUENCIES ASSIGNED DOSE DOSE ASSIGNMENT (PERSON-REM/YR) | [9] <2> Hatch current and anticipated future value. <3 J NUREG/CR-4551, Vol. 2, Rev. 1, Part 7, Appendix A.3 (SITE MACCS2 File) for Peach Bottom. Population total for 50-mile radius developed in Appendix A of this report. <4 J NUREG/CR-4551, Vol. 4, Rev. 1, Part 2, Section A.3.1. <5 l NUREG/CR-4551, Vol. 4, Rev. 1, Part 2, page B.2-9 for no containment failure. 4-14 Table 4.2-5 HATCH POPULATION DOSE RISK AT 50 MILES RELEASE POPULATION DOSE CATEGORY 2030 POPULATION RISK RELEASE FREQUENCIES ASSIGNED DOSE DOSE ASSIGNMENT (PERSON-REM/YR) | ||
CATEGORY (PER YEAR) (PERSON-REM)C 1> BASIS (2) INTACT H-E H-1 M-E M-1 M-L L-E L-1 L-L LL-E LL-I LL-L Total (1) (2) (3) (4) 1.18E-06 1.15E+03 Peach Bottom 1.35E-03 1.12E-06 1.17E+06 Hatch SAMA BOC 1.31 E+OO 2.83E-06 5.80E+05 Hatch SAMA late CF 1.64E+OO 1.19E-06 5.80E+05 Hatch SAMA late CF (SJ. 6.90E-01 9.64E-07 5.80E+05 Hatch SAMA late CF(3 l 5.59E-01 4.64E-08 5.80E+05 Hatch SAMA late CF(3 l 2.69E-02 1.01 E-08 5.80E+05 Hatch SAMA late CF (4 l 5.86E-03 9.56E-08 5.80E+05 Hatch SAMA late CF(4 l 5.54E-02 6.94E-09 5.80E+05 Hatch SAMA late CF(4 l 4.03E-03 1.33E-07 5.80E+05 Hatch SAMA late CF(4 l 7.71 E-02 1.0SE-08 5.80E+05 Hatch SAMA late CF (4 l 6.09E-03 4.63E-09 5.80E+05 Hatch SAMA late CF(4 l 2.69E-03 7.58E-06 ----4.37E+OO Includes a scaling factor of 0.233 for application of the Peach Bottom dose results to the Intact Containment case, and includes a scaling factor of 1.015 for other release categories to account for a reactor power level increase since the Hatch SAMA analysis was performed. | CATEGORY (PER YEAR) (PERSON-REM)C 1> BASIS (2) INTACT H-E H-1 M-E M-1 M-L L-E L-1 L-L LL-E LL-I LL-L Total (1) (2) (3) (4) 1.18E-06 1.15E+03 Peach Bottom 1.35E-03 1.12E-06 1.17E+06 Hatch SAMA BOC 1.31 E+OO 2.83E-06 5.80E+05 Hatch SAMA late CF 1.64E+OO 1.19E-06 5.80E+05 Hatch SAMA late CF (SJ. 6.90E-01 9.64E-07 5.80E+05 Hatch SAMA late CF(3 l 5.59E-01 4.64E-08 5.80E+05 Hatch SAMA late CF(3 l 2.69E-02 1.01 E-08 5.80E+05 Hatch SAMA late CF (4 l 5.86E-03 9.56E-08 5.80E+05 Hatch SAMA late CF(4 l 5.54E-02 6.94E-09 5.80E+05 Hatch SAMA late CF(4 l 4.03E-03 1.33E-07 5.80E+05 Hatch SAMA late CF(4 l 7.71 E-02 1.0SE-08 5.80E+05 Hatch SAMA late CF (4 l 6.09E-03 4.63E-09 5.80E+05 Hatch SAMA late CF(4 l 2.69E-03 7.58E-06 ----4.37E+OO Includes a scaling factor of 0.233 for application of the Peach Bottom dose results to the Intact Containment case, and includes a scaling factor of 1.015 for other release categories to account for a reactor power level increase since the Hatch SAMA analysis was performed. | ||
| Line 954: | Line 954: | ||
a factor of two less than that for other high magnitude releases and is considered reasonable for use for medium magnitude release cases. This is comparable to SAMA population dose results developed for Quad Cities and Dresden Generating Stations [35] (both Mark I containment designs) where moderate magnitude releases had population dose results approximately one half to nearly equal to high magnitude release population doses. All Hatch SAMA dose cases represent high releases. | a factor of two less than that for other high magnitude releases and is considered reasonable for use for medium magnitude release cases. This is comparable to SAMA population dose results developed for Quad Cities and Dresden Generating Stations [35] (both Mark I containment designs) where moderate magnitude releases had population dose results approximately one half to nearly equal to high magnitude release population doses. All Hatch SAMA dose cases represent high releases. | ||
Use of the late containment failure for low and low-low magnitude release cases is acceptable because the associated frequencies for these release categories are low compared to other release categories. | Use of the late containment failure for low and low-low magnitude release cases is acceptable because the associated frequencies for these release categories are low compared to other release categories. | ||
The population dose associated with low or low-low releases compose less than 3% of the total as developed in this table. 4-15 Table 4.2-6 EPRI CONTAINMENT FAILURE CLASSIFICATIONS | The population dose associated with low or low-low releases compose less than 3% of the total as developed in this table. 4-15 Table 4.2-6 EPRI CONTAINMENT FAILURE CLASSIFICATIONS | ||
[22] CLASS DESCRIPTION 1 Containment remains intact including accident sequences that do not lead to containment failure in the long term. The release of fission products (and attendant consequences) is determined by the maximum allowable leakage rate values La, under Appendix J for that plant 2 Containment isolation failures (as reported in the IPEs) include those accidents in which there is a failure to isolate the containment. | [22] CLASS DESCRIPTION 1 Containment remains intact including accident sequences that do not lead to containment failure in the long term. The release of fission products (and attendant consequences) is determined by the maximum allowable leakage rate values La, under Appendix J for that plant 2 Containment isolation failures (as reported in the IPEs) include those accidents in which there is a failure to isolate the containment. | ||
3 Independent (or random) isolation failures include those accidents in which the pre-existing isolation failure to seal (i.e. provide a leak-tight containment) is not dependent on the sequence in progress. | 3 Independent (or random) isolation failures include those accidents in which the pre-existing isolation failure to seal (i.e. provide a leak-tight containment) is not dependent on the sequence in progress. | ||
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* Consistent with the Calvert Cliffs analysis, a half failure is assumed for the drywell floor concealed steel corrosion due to the lack of identified failures. | * Consistent with the Calvert Cliffs analysis, a half failure is assumed for the drywell floor concealed steel corrosion due to the lack of identified failures. | ||
* The two corrosion events over a 5.5 year data period are used to estimate the steel liner flaw probability in the Calvert Cliffs analysis and are assumed to be applicable to the Hatch containment analysis. | * The two corrosion events over a 5.5 year data period are used to estimate the steel liner flaw probability in the Calvert Cliffs analysis and are assumed to be applicable to the Hatch containment analysis. | ||
These events, one at North Anna Unit 2 and one at Brunswick Unit 2 (Mark I containment design), were initiated from the non-visible (backside) portion of the containment liner. It is noted that two additional events have occurred in recent years (based on a data search covering approximately 9 years documented in Reference | These events, one at North Anna Unit 2 and one at Brunswick Unit 2 (Mark I containment design), were initiated from the non-visible (backside) portion of the containment liner. It is noted that two additional events have occurred in recent years (based on a data search covering approximately 9 years documented in Reference | ||
[27]). In November 2006, the Turkey Point 4 containment building liner developed a hole when a sump pump support plate was moved. In May 2009, a hole approximately 3/8" by 1" in size was identified in the Beaver Vaiiey 1 containment liner. For risk evaluation purposes, these two more recent events occurring over a 9 year period are judged to be adequately represented by the two events in the 5.5 year period of the Calvert Cliffs analysis incorporated in the EPRI guidance. | [27]). In November 2006, the Turkey Point 4 containment building liner developed a hole when a sump pump support plate was moved. In May 2009, a hole approximately 3/8" by 1" in size was identified in the Beaver Vaiiey 1 containment liner. For risk evaluation purposes, these two more recent events occurring over a 9 year period are judged to be adequately represented by the two events in the 5.5 year period of the Calvert Cliffs analysis incorporated in the EPRI guidance. | ||
4-19 | 4-19 | ||
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This approach avoids a detailed analysis of containment failure timing and operator recovery actions. 4-20 Table 4.4-1 STEEL CONTAINMENT CORROSION BASE CASE STEP DESCRIPTION 1 Historical Steel Flaw Likelihood 2 3 4 Failure Data: Containment location specific (consistent with Calvert Cliffs analysis). | This approach avoids a detailed analysis of containment failure timing and operator recovery actions. 4-20 Table 4.4-1 STEEL CONTAINMENT CORROSION BASE CASE STEP DESCRIPTION 1 Historical Steel Flaw Likelihood 2 3 4 Failure Data: Containment location specific (consistent with Calvert Cliffs analysis). | ||
Age Adjusted Steel Flaw Likelihood During 15-year interval, assume failure rate doubles every five years (14.9% increase per year). The average for 5th to 10th year is set to the historical failure rate (consistent with Calvert Cliffs analysis). | Age Adjusted Steel Flaw Likelihood During 15-year interval, assume failure rate doubles every five years (14.9% increase per year). The average for 5th to 10th year is set to the historical failure rate (consistent with Calvert Cliffs analysis). | ||
Flaw Likelihood at 3, 10, and 15 years Uses age adjusted flaw likelihood (Step 2), assuming failure rate doubles every five years (consistent with Calvert Cliffs analysis -See Table 6 of Reference | Flaw Likelihood at 3, 10, and 15 years Uses age adjusted flaw likelihood (Step 2), assuming failure rate doubles every five years (consistent with Calvert Cliffs analysis -See Table 6 of Reference | ||
[19]). Likelihood of Breach in Containment Given Steel Flaw The failure probability of the DW walls, head, and torus is assumed to be 1% (compared to 1.1 % in the Calvert Cliffs analysis). | [19]). Likelihood of Breach in Containment Given Steel Flaw The failure probability of the DW walls, head, and torus is assumed to be 1% (compared to 1.1 % in the Calvert Cliffs analysis). | ||
The DW floor failure probability is assumed to be a factor of ten less, 0.1%, (compared to 0.11% in the Calvert Cliffs analysis). | The DW floor failure probability is assumed to be a factor of ten less, 0.1%, (compared to 0.11% in the Calvert Cliffs analysis). | ||
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===5.0 RESULTS=== | ===5.0 RESULTS=== | ||
The application of the approach based on the guidance contained in EPRI TR-1018243 | The application of the approach based on the guidance contained in EPRI TR-1018243 | ||
[22], EPRI-TR-104285 | [22], EPRI-TR-104285 | ||
[2] and previous risk assessment submittals on this subject [6, 7, 19, 20, 23] have led to the following results. The results are displayed according to the eight accident classes defined in the EPRI report. Table 5.0-1 lists these accident classes. The analysis performed examined Hatch specific accident sequences in which the containment remains intact or the containment is impaired. | [2] and previous risk assessment submittals on this subject [6, 7, 19, 20, 23] have led to the following results. The results are displayed according to the eight accident classes defined in the EPRI report. Table 5.0-1 lists these accident classes. The analysis performed examined Hatch specific accident sequences in which the containment remains intact or the containment is impaired. | ||
Specifically, the break down of the severe accidents contributing to risk were considered in the following manner: | Specifically, the break down of the severe accidents contributing to risk were considered in the following manner: | ||
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==6.0 REFERENCES== | ==6.0 REFERENCES== | ||
Attachments: | Attachments: | ||
: 1. Technical Specifications Pages Markups 2. Bases Page Markups (For Information Only) 3. Plant Hatch Units 1 & 2 Risk Assessment to Support ILRT (Type A) Interval Extension Request 4. Technical Specifications Pages Clean Copies Hatch Nuclear Plant Units 1 and 2 1.0 | : 1. Technical Specifications Pages Markups 2. Bases Page Markups (For Information Only) 3. Plant Hatch Units 1 & 2 Risk Assessment to Support ILRT (Type A) Interval Extension Request 4. Technical Specifications Pages Clean Copies Hatch Nuclear Plant Units 1 and 2 1.0 | ||
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* Adopt an extension of the containment isolation valve (CIV) leakage testing (Type C) frequency from the 60 months currently permitted by 10 CFR 50, Appendix J, 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. | * Adopt an extension of the containment isolation valve (CIV) leakage testing (Type C) frequency from the 60 months currently permitted by 10 CFR 50, Appendix J, 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. | ||
* Adopt the use of American National Standards Institute/American Nuclear Society (ANSI/ANS) 56.8-2002, Containment System Leakage Testing Requirements. | * Adopt the use of American National Standards Institute/American Nuclear Society (ANSI/ANS) 56.8-2002, Containment System Leakage Testing Requirements. | ||
* Adopt a more conservative grace interval of 9 months, for Type A, Type B and Type C leakage tests in accordance with NEI 94-01, Revision 3-A. The proposed change to the TS contained herein would revise HNP TS 5.5.12, by replacing the references to Regulatory Guide (RG) 1.163, Performance-Based Containment Leak-Test Program, (Reference | * Adopt a more conservative grace interval of 9 months, for Type A, Type B and Type C leakage tests in accordance with NEI 94-01, Revision 3-A. The proposed change to the TS contained herein would revise HNP TS 5.5.12, by replacing the references to Regulatory Guide (RG) 1.163, Performance-Based Containment Leak-Test Program, (Reference | ||
: 1) and 10 CFR 50, Appendix J, Option B with a reference to NEI topical report NEI 94-01, Revision 3-A (Reference 2), dated July 2012, and the conditions and limitations specified in NEI 94-01, Revision 2-A (Reference 8), dated October 2008, as the documents used by HNP to implement the performance-based leakage testing program in accordance with Option B of 1 O CFR 50, Appendix J. This license amendment request (LAR) also proposes the following administrative changes to TS 5.5.12: | : 1) and 10 CFR 50, Appendix J, Option B with a reference to NEI topical report NEI 94-01, Revision 3-A (Reference 2), dated July 2012, and the conditions and limitations specified in NEI 94-01, Revision 2-A (Reference 8), dated October 2008, as the documents used by HNP to implement the performance-based leakage testing program in accordance with Option B of 1 O CFR 50, Appendix J. This license amendment request (LAR) also proposes the following administrative changes to TS 5.5.12: | ||
* Deleting the information regarding the performance of the next HNP Unit 1 and Unit 2 Type A test to be performed no later than April 2008 for Unit 1 and no later than November 2010 for Unit 2, as both Type A tests have already occurred. | * Deleting the information regarding the performance of the next HNP Unit 1 and Unit 2 Type A test to be performed no later than April 2008 for Unit 1 and no later than November 2010 for Unit 2, as both Type A tests have already occurred. | ||
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* Deleting the information regarding the performance of the next HNP Unit 1 Type A test no later than April 2008 and the next HNP Unit 2 Type A test no later than November 2010, as both Type A tests have already occurred. | * Deleting the information regarding the performance of the next HNP Unit 1 Type A test no later than April 2008 and the next HNP Unit 2 Type A test no later than November 2010, as both Type A tests have already occurred. | ||
The proposed change will revise TS 5.5.12 to state, in part: Enclosure Page 4 of 81 "A program shall be established to implement the leakage testing of the containment as required by 10 CFR 50.54(0) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. | The proposed change will revise TS 5.5.12 to state, in part: Enclosure Page 4 of 81 "A program shall be established to implement the leakage testing of the containment as required by 10 CFR 50.54(0) 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." Markups of TS 5.5.12 for both HNP Units 1 and 2 are provided in Attachment | 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." Markups of TS 5.5.12 for both HNP Units 1 and 2 are provided in Attachment | ||
: 1. Markups of TS Bases for SR 3.6.1.1 Primary Containment, and SR 3.6.1.1.1 for both HNP Units 1 and 2 are provided in Attachment 2 for informational purposes only. Based upon approval of this LAR, these TS Bases changes will be implemented in accordance with the TS Bases Control Program. Attachment 3 contains the plant specific risk assessment conducted to support this proposed change. This risk assessment followed the guidelines of NRC RG 1.17 4, Revision 2 (Reference | : 1. Markups of TS Bases for SR 3.6.1.1 Primary Containment, and SR 3.6.1.1.1 for both HNP Units 1 and 2 are provided in Attachment 2 for informational purposes only. Based upon approval of this LAR, these TS Bases changes will be implemented in accordance with the TS Bases Control Program. Attachment 3 contains the plant specific risk assessment conducted to support this proposed change. This risk assessment followed the guidelines of NRC RG 1.17 4, Revision 2 (Reference | ||
: 3) and NRC RG 1.200, Revision 2 (Reference 4). The risk assessment concluded that increasing the ILRT interval to 15 years is considered to represent an insignificant change in risk for HNP. 3.0 TECHNICAL EVALUATION | : 3) and NRC RG 1.200, Revision 2 (Reference 4). The risk assessment concluded that increasing the ILRT interval to 15 years is considered to represent an insignificant change in risk for HNP. 3.0 TECHNICAL EVALUATION | ||
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====3.1.1 Drywall==== | ====3.1.1 Drywall==== | ||
The drywall is a steel pressure vessel with a spherical lower portion 65 feet (ft.) in diameter and a cylindrical upper portion 35 ft. 7 inches (in.) in diameter for Unit 1 and 37 ft 1 in. in diameter for Unit 2. The overall height of the drywall is approximately 111 ft. The design, fabrication, inspection, and testing of the Unit 1 drywall comply with the requirements of the American Society of Mechanical Engineers (ASME) Code, Section Ill, Subsection 8, Requirements for Class 8 Vessels, which pertains to containment vessels for nuclear power stations. | The drywall is a steel pressure vessel with a spherical lower portion 65 feet (ft.) in diameter and a cylindrical upper portion 35 ft. 7 inches (in.) in diameter for Unit 1 and 37 ft 1 in. in diameter for Unit 2. The overall height of the drywall is approximately 111 ft. The design, fabrication, inspection, and testing of the Unit 1 drywall comply with the requirements of the American Society of Mechanical Engineers (ASME) Code, Section Ill, Subsection 8, Requirements for Class 8 Vessels, which pertains to containment vessels for nuclear power stations. | ||
The primary containment is fabricated of SA-516 grade 70 plates. The design, fabrication, inspection, and testing of the Unit 2 drywall vessel comply with requirements of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code, Section Ill, Nuclear Power Plant Components, Subsection NE, Requirements for Class MC Components, 1971 Edition, including 1971 Summer Addenda which pertain to containment vessels for nuclear power plants. The steel head and shell of the drywall are fabricated of SA-516 GR70 steel plate. The Unit 1 drywall is designed for an internal pressure of 56 pounds per square inch gage (psig) coincident with a temperature of 281 degrees Fahrenheit | The primary containment is fabricated of SA-516 grade 70 plates. The design, fabrication, inspection, and testing of the Unit 2 drywall vessel comply with requirements of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code, Section Ill, Nuclear Power Plant Components, Subsection NE, Requirements for Class MC Components, 1971 Edition, including 1971 Summer Addenda which pertain to containment vessels for nuclear power plants. The steel head and shell of the drywall are fabricated of SA-516 GR70 steel plate. The Unit 1 drywall is designed for an internal pressure of 56 pounds per square inch gage (psig) coincident with a temperature of 281 degrees Fahrenheit | ||
(°F) for Unit 1 and 340 °F for Unit 2, with applicable dead, live, and seismic loads imposed on the shell. Thermal stresses in the steel shell due to temperature gradients are also incorporated into the design. Thus, in accordance with the ASME Code, Section Ill, the maximum drywall pressure is 62 psig. Charpy V-notch impact tests were performed on specimens of all plate and forged materials. | (°F) for Unit 1 and 340 °F for Unit 2, with applicable dead, live, and seismic loads imposed on the shell. Thermal stresses in the steel shell due to temperature gradients are also incorporated into the design. Thus, in accordance with the ASME Code, Section Ill, the maximum drywall pressure is 62 psig. Charpy V-notch impact tests were performed on specimens of all plate and forged materials. | ||
Plates, forgings, and pipes of the drywall have an initial nil ductility transition temperature (NOTT) of -0°F when tested in accordance with the appropriate code for these materials. | Plates, forgings, and pipes of the drywall have an initial nil ductility transition temperature (NOTT) of -0°F when tested in accordance with the appropriate code for these materials. | ||
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Appendix J identifies three types of required tests: 1) Type A tests, intended to measure the primary containment overall integrated leakage rate; 2) Type B tests, intended to detect local leaks and to measure leakage across pressure-containing or leakage limiting boundaries (other than valves) for primary containment penetrations, and; 3) Type C tests, intended to measure containment isolation valve leakage rates. Types B and C tests identify the vast majority of potential containment leakage paths. Type A tests identify the overall (integrated) containment leakage rate and serve to ensure continued leakage integrity of the containment structure by evaluating those structural parts of the containment not covered by Type B and C testing. In 1995, 10 CFR 50, Appendix J, "Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors," was amended to provide a performance-based Option B for the containment leakage testing requirements. | Appendix J identifies three types of required tests: 1) Type A tests, intended to measure the primary containment overall integrated leakage rate; 2) Type B tests, intended to detect local leaks and to measure leakage across pressure-containing or leakage limiting boundaries (other than valves) for primary containment penetrations, and; 3) Type C tests, intended to measure containment isolation valve leakage rates. Types B and C tests identify the vast majority of potential containment leakage paths. Type A tests identify the overall (integrated) containment leakage rate and serve to ensure continued leakage integrity of the containment structure by evaluating those structural parts of the containment not covered by Type B and C testing. In 1995, 10 CFR 50, Appendix J, "Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors," 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. | 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 Enclosure Page 11 of 81 failure. The use* of the term "performance-based" in 1 O 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 8. Also in 1995, RG 1.163 (Reference | Performance-based test intervals are based on consideration of the operating history of the component and resulting risk from its Enclosure Page 11 of 81 failure. The use* of the term "performance-based" in 1 O 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 8. Also in 1995, RG 1.163 (Reference | ||
: 1) was issued. The RG endorsed NEI 94-01, Revision 0, (Reference | : 1) was issued. The RG endorsed NEI 94-01, Revision 0, (Reference | ||
: 5) with certain modifications and additions. | : 5) with certain modifications and additions. | ||
Option 8, 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 | Option 8, 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 | : 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 was considered in the establishment of the intervals allowed by RG 1.163 and NEI 94-01, but that this "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 8 to 10 CFR 50, Appendix J, subject to the limitations and conditions noted in Section 4.0 of the NRC Safety Evaluation Report (SER) on NEI 94-01. The NRC SER was included in the front matter of the NEI 94-01, Revision 2-A report. 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 (September 1995). It delineates a performance-based approach for determining Type A, Type 8, and Type C containment leakage rate surveillance testing frequencies. | : 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 was considered in the establishment of the intervals allowed by RG 1.163 and NEI 94-01, but that this "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 8 to 10 CFR 50, Appendix J, subject to the limitations and conditions noted in Section 4.0 of the NRC Safety Evaluation Report (SER) on NEI 94-01. The NRC SER was included in the front matter of the NEI 94-01, Revision 2-A report. 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 (September 1995). It delineates a performance-based approach for determining Type A, Type 8, and Type C containment leakage rate surveillance testing frequencies. | ||
Justification for extending test intervals is based on the performance history and risk insights. | 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 8 to 10 CFR 50, Appendix J and includes provisions for extending Type A ILRT intervals to up to 15 years. NEI 94-01 has been endorsed by RG 1.163 and NRC SERs of June 25, 2008 (Reference | 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 8 to 10 CFR 50, Appendix J and includes provisions for extending Type A ILRT intervals to up to 15 years. NEI 94-01 has been endorsed by RG 1.163 and NRC SERs of June 25, 2008 (Reference | ||
: 9) and June 8, 2012 (Reference | : 9) and June 8, 2012 (Reference | ||
: 10) as an acceptable methodology for complying with the provisions of Option 8 to 10 CFR 50. The regulatory positions stated in RG 1.163 as modified by NRC SERs dated June 25, 2008 and June 8, 2012 are incorporated in this document. | : 10) as an acceptable methodology for complying with the provisions of Option 8 to 10 CFR 50. The regulatory positions stated in RG 1.163 as modified by NRC SERs dated June 25, 2008 and June 8, 2012 are incorporated in this document. | ||
It delineates a performance-based approach for determining Type A, Type 8, and Type C containment leakage rate surveillance testing frequencies. | It delineates a performance-based approach for determining Type A, Type 8, and Type C containment leakage rate surveillance testing frequencies. | ||
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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 MS IVs) or to valves held to the base interval (30 months) due to unsatisfactory LLRT performance." The NRG has also provided the following concerning the extension of ILRT intervals to 15 years in NEI 94-01, Revision 3-A, NRG SER Section 4.0, Condition 2, which states, in part: | 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 MS IVs) or to valves held to the base interval (30 months) due to unsatisfactory LLRT performance." The NRG has also provided the following concerning the extension of ILRT intervals to 15 years in NEI 94-01, Revision 3-A, NRG SER Section 4.0, Condition 2, which states, in part: | ||
Enclosure Page 13 of 81 "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. | Enclosure Page 13 of 81 "The basis for acceptability of extending the ILRT interval out to once per 15 years was the enhanced and robust primary containment inspection program and the local leakage rate testing of penetrations. | ||
Most of the primary containment leakage experienced has been attributed to penetration leakage and penetrations are thought to be the most likely location of most containment leakage at any time." 3.2.2 Current HNP ILRT Requirements 10 CFR 50, Appendix J was revised, effective October 26, 1995, to allow licenses to choose containment leakage testing under either Option A, "Prescriptive Requirements," or Option B, "Performance-Based Requirements." On March 6, 1996 the NRC approved License Amendment No. 200 for HNP, Unit 1 and Amendment 141 for Unit 2 (Reference | Most of the primary containment leakage experienced has been attributed to penetration leakage and penetrations are thought to be the most likely location of most containment leakage at any time." 3.2.2 Current HNP ILRT Requirements 10 CFR 50, Appendix J was revised, effective October 26, 1995, to allow licenses to choose containment leakage testing under either Option A, "Prescriptive Requirements," or Option B, "Performance-Based Requirements." On March 6, 1996 the NRC approved License Amendment No. 200 for HNP, Unit 1 and Amendment 141 for Unit 2 (Reference | ||
: 19) authorizing the implementation of 10 CFR 50, Appendix J, Option B for Type A, B and C tests. Current TS 5.5.12 requires that a program be established to comply with the containment leakage rate testing requirements of 10 CFR 50.54(0) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. | : 19) authorizing the implementation of 10 CFR 50, Appendix J, Option B for Type A, B and C tests. Current TS 5.5.12 requires that a program be established to comply with the containment leakage rate testing requirements of 10 CFR 50.54(0) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. | ||
The program is required to be in accordance with the guidelines contained in RG 1.163. RG 1.163 endorses, with certain exceptions, NEI 94-01, Revision 0, as an acceptable method for complying with the provisions of Appendix J, Option 8. 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 | 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 8. 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. | : 5) rather than using test intervals specified in ANSI/ANS 56.8-1994. | ||
NEI 94-01, Section 11.0 refers to Section 9, which states that Type A testing shall be performed during a period of reactor shutdown at a frequency of at least once per ten years based on acceptable performance history. Acceptable performance history is defined as completion of two consecutive periodic Type A tests where the calculated performance leakage was less than 1.0la (where La is the maximum allowable leakage rate at design pressure). | NEI 94-01, Section 11.0 refers to Section 9, which states that Type A testing shall be performed during a period of reactor shutdown at a frequency of at least once per ten years based on acceptable performance history. Acceptable performance history is defined as completion of two consecutive periodic Type A tests where the calculated performance leakage was less than 1.0la (where La is the maximum allowable leakage rate at design pressure). | ||
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The evaluation documented in NUREG-1493 included a study of the dependence or reactor accident risks on containment leak tightness for differing types of containment types, including a post tensioned, shallow domed concrete containment similar to HNP's containment structures. | The evaluation documented in NUREG-1493 included a study of the dependence or reactor accident risks on containment leak tightness for differing types of containment types, including a post tensioned, shallow domed concrete containment similar to HNP's containment structures. | ||
NUREG-1493 concluded in Section 10.1.2 that reducing the frequency of Type A tests (ILRT} from the original three (3) tests per Enclosure Page 14 of 81 10 years to one (1) test per 20 years was found to lead to an imperceptible increase in risk. The estimated increase in risk is very small because ILRTs identify only a few potential containment leakage paths that cannot be identified by Types B and C testing, and the leaks that have been found by Type A tests have been only marginally above existing requirements. | NUREG-1493 concluded in Section 10.1.2 that reducing the frequency of Type A tests (ILRT} from the original three (3) tests per Enclosure Page 14 of 81 10 years to one (1) test per 20 years was found to lead to an imperceptible increase in risk. The estimated increase in risk is very small because ILRTs identify only a few potential containment leakage paths that cannot be identified by Types B and C testing, and the leaks that have been found by Type A tests have been only marginally above existing requirements. | ||
Given the insensitivity of risk to containment leakage rate and the small fraction of leakage paths detected solely by Type A testing, NUREG-1493 concluded that increasing the interval between ILRTs is possible with minimal impact on public risk. 3.2.3 HNP 10 CFR 50, Appendix J, Option B Licensing History March 6, 1996 The Commission issued on March 6, 1996 Amendments Nos. 200 and 141 to Facility Operating License Nos. DPR-57 and NFP-5 for the HNP, Units 1 and 2, respectively (Reference 19). The amendments revised the TS for containment systems to reflect the adoption of the requirements of 10 CFR 50, Appendix J, Option B, and the implementation of a performance-based containment leak-rate testing program at the HNP, Units 1 and 2. February 20, 2002 The Commission issued Amendment No. 226 to Facility Operating License No. DPR-57 for HNP, Unit 1 (Reference | 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. 3.2.3 HNP 10 CFR 50, Appendix J, Option B Licensing History March 6, 1996 The Commission issued on March 6, 1996 Amendments Nos. 200 and 141 to Facility Operating License Nos. DPR-57 and NFP-5 for the HNP, Units 1 and 2, respectively (Reference 19). The amendments revised the TS for containment systems to reflect the adoption of the requirements of 10 CFR 50, Appendix J, Option B, and the implementation of a performance-based containment leak-rate testing program at the HNP, Units 1 and 2. February 20, 2002 The Commission issued Amendment No. 226 to Facility Operating License No. DPR-57 for HNP, Unit 1 (Reference | ||
: 14) on February 20, 2002. This amendment revised TS 5.5.12, Primary Containment Leakage Rate testing Program, to allow a one-time deferral of the Type A Containment ILRT based on the risk-informed guidance in RG 1.174. Specifically, the proposed TS says that the first Type A test performed after the April 1993 Type A test shall be performed no later than April 2008. May 28, 2004 The Commission issued on May 28, 2004 Amendment No. 241 to Renewed Facility Operating License DPR-57 and Amendment No. 184 to Renewed Facility Operating License NPF-5 for HNP, Units 1 and 2, respectively (Reference 16). This amendment changed the peak calculated post-accident primary containment internal pressure values, Pa, in TS 5.5.12, "Primary Containment Leakage Rate Testing Program," for Units 1 and Unit 2. The proposed change supported a 10-psi increase in the nominal reactor steam dome operating pressure at each unit. The purpose of the pressure increase in the nominal reactor steam dome pressure is to allow'for additional flow control margin for the high-pressure turbine. This flow margin is needed to operate the plants at 100 percent of the increased (Reference | : 14) on February 20, 2002. This amendment revised TS 5.5.12, Primary Containment Leakage Rate testing Program, to allow a one-time deferral of the Type A Containment ILRT based on the risk-informed guidance in RG 1.174. Specifically, the proposed TS says that the first Type A test performed after the April 1993 Type A test shall be performed no later than April 2008. May 28, 2004 The Commission issued on May 28, 2004 Amendment No. 241 to Renewed Facility Operating License DPR-57 and Amendment No. 184 to Renewed Facility Operating License NPF-5 for HNP, Units 1 and 2, respectively (Reference 16). This amendment changed the peak calculated post-accident primary containment internal pressure values, Pa, in TS 5.5.12, "Primary Containment Leakage Rate Testing Program," for Units 1 and Unit 2. The proposed change supported a 10-psi increase in the nominal reactor steam dome operating pressure at each unit. The purpose of the pressure increase in the nominal reactor steam dome pressure is to allow'for additional flow control margin for the high-pressure turbine. This flow margin is needed to operate the plants at 100 percent of the increased (Reference | ||
: 13) rated thermal power level of 2804 MW (t). | : 13) rated thermal power level of 2804 MW (t). | ||
February 1, 2005 Enclosure Page 15 of 81. The Commission issued on February 1, 2005 Amendment No. 187 to Renewed Facility Operating License No. NPF-5 for HNP, Unit 2 (Reference 15). This amendment modified TS 5.5.12, Primary Containment Leakage Rate testing Program. The change would allow a one-time change in the Appendix J, Type A test (containment ILRT) interval from the required 10 years to a test interval of 15 years. Specifically, the exception states that the first Type A test performed after the November 2, 1995, Type A test shall be performed no later than November 2010. August 28, 2008 The Commission issued on August 28, 2008 Amendment No. 256 to Renewed Facility Operating License DPR-57 and Amendment No. 200 to Renewed Facility Operating License NPF-5 for HNP Units 1 and 2, respectively (Reference 17). The amendments revised the licensing basis with a full scope implementation of an alternative source term (AST) for HNP. TS 3.6.1.3 Primary Containment Isolation Valves The proposed license amendment revised the following TS that are associated with the analyses performed to support the AST. The proposed change for Unit 1, added a new SR 3.6.1 .3.13, which establishes a maximum combined leakage rate for all secondary containment bypass leakage paths of 0.02La. The proposed change for Unit 2, revised SR 3.6.1 .3.10 to increase the maximum combined leakage rate for all secondary containment bypass leakage paths from O.OQ9La to 0.02La. La is defined in 10 CFR 50, Appendix J. The secondary containment bypass leakage rate assumptions in the radiological dose consequences analysis for the LOCA form the basis for the revised TS limits. The increase in bypass leakage is necessary to allow for newly identified bypass leakage paths. The addition of this TS SR to Unit 1 reflects a required RG 1 .183 assumption in the accident analyses and standardizes the TS between units. The NRG staff's assessment found these changes acceptable since the proposed secondary bypass leakage rate limit of 0.02La was assumed in the accident analysis and regulatory criteria have been met. Another proposed change was to eliminate the per line main steam isolation valve (MSIV) leakage rate limits from the TS SR for both units (SR 3.6.1.3.10 and SR 3.6.1.3.11, respectively). | February 1, 2005 Enclosure Page 15 of 81. The Commission issued on February 1, 2005 Amendment No. 187 to Renewed Facility Operating License No. NPF-5 for HNP, Unit 2 (Reference 15). This amendment modified TS 5.5.12, Primary Containment Leakage Rate testing Program. The change would allow a one-time change in the Appendix J, Type A test (containment ILRT) interval from the required 10 years to a test interval of 15 years. Specifically, the exception states that the first Type A test performed after the November 2, 1995, Type A test shall be performed no later than November 2010. August 28, 2008 The Commission issued on August 28, 2008 Amendment No. 256 to Renewed Facility Operating License DPR-57 and Amendment No. 200 to Renewed Facility Operating License NPF-5 for HNP Units 1 and 2, respectively (Reference 17). The amendments revised the licensing basis with a full scope implementation of an alternative source term (AST) for HNP. TS 3.6.1.3 Primary Containment Isolation Valves The proposed license amendment revised the following TS that are associated with the analyses performed to support the AST. The proposed change for Unit 1, added a new SR 3.6.1 .3.13, which establishes a maximum combined leakage rate for all secondary containment bypass leakage paths of 0.02La. The proposed change for Unit 2, revised SR 3.6.1 .3.10 to increase the maximum combined leakage rate for all secondary containment bypass leakage paths from O.OQ9La to 0.02La. La is defined in 10 CFR 50, Appendix J. The secondary containment bypass leakage rate assumptions in the radiological dose consequences analysis for the LOCA form the basis for the revised TS limits. The increase in bypass leakage is necessary to allow for newly identified bypass leakage paths. The addition of this TS SR to Unit 1 reflects a required RG 1 .183 assumption in the accident analyses and standardizes the TS between units. The NRG staff's assessment found these changes acceptable since the proposed secondary bypass leakage rate limit of 0.02La was assumed in the accident analysis and regulatory criteria have been met. Another proposed change was to eliminate the per line main steam isolation valve (MSIV) leakage rate limits from the TS SR for both units (SR 3.6.1.3.10 and SR 3.6.1.3.11, respectively). | ||
| Line 1,245: | Line 1,245: | ||
* The methodology used in EPRI TR-104285 (Reference 7), | * The methodology used in EPRI TR-104285 (Reference 7), | ||
* The NEI "Interim Guidance for Performing Risk Impact Assessments In Support of One-Time Extensions for Containment Integrated Leakage Rate Test Surveillance Intervals" (References 33, 37), | * The NEI "Interim Guidance for Performing Risk Impact Assessments In Support of One-Time Extensions for Containment Integrated Leakage Rate Test Surveillance Intervals" (References 33, 37), | ||
* The NRC regulatory guidance on the use of PAA as stated in RG 1.200 (Reference | * The NRC regulatory guidance on the use of PAA as stated in RG 1.200 (Reference | ||
: 4) as applied to ILRT interval extensions, and risk insights in support of a request for a change in the plant's licensing basis as outlined in RG 1.174 (Reference 3), | : 4) as applied to ILRT interval extensions, and risk insights in support of a request for a change in the plant's licensing basis as outlined in RG 1.174 (Reference 3), | ||
* The methodology used for Calvert Cliffs to estimate the likelihood and risk implications of corrosion-induced leakage of steel liners going undetected during the extended test interval (Reference 32), | * The methodology used for Calvert Cliffs to estimate the likelihood and risk implications of corrosion-induced leakage of steel liners going undetected during the extended test interval (Reference 32), | ||
* The methodology used in EPRI TR-1009325, Revision 2-A (Reference | * The methodology used in EPRI TR-1009325, Revision 2-A (Reference | ||
: 20) for performing a risk impact assessment of extended ILRT intervals. | : 20) for performing a risk impact assessment of extended ILRT intervals. | ||
*The EPRI TR-1009325 Revision 2-A methodology incorporates the specific limitations | *The EPRI TR-1009325 Revision 2-A methodology incorporates the specific limitations | ||
*and conditions outlined in the NRC acceptance of the EPRI TR-1009325 Revision 2 methodology documented in the NRC Final Safety Evaluation (Reference 9). The format of this document is consistent with the intent of the Risk Impact Assessment Template for evaluating extended ILRT intervals provided in Appendix Hof the EPRI TR methodology report (Reference 20). The NRG report on performance-based leak testing, NUREG-1493, analyzed the effects of containment leakage on the health and safety of the public and the benefits realized from the containment leak rate testing. In that analysis, it was determined that for a representative PWR plant, (i.e., Surry) containment isolation failures contribute less than 0.1 percent to the latent risks from reactor accidents. | *and conditions outlined in the NRC acceptance of the EPRI TR-1009325 Revision 2 methodology documented in the NRC Final Safety Evaluation (Reference 9). The format of this document is consistent with the intent of the Risk Impact Assessment Template for evaluating extended ILRT intervals provided in Appendix Hof the EPRI TR methodology report (Reference 20). The NRG report on performance-based leak testing, NUREG-1493, analyzed the effects of containment leakage on the health and safety of the public and the benefits realized from the containment leak rate testing. In that analysis, it was determined that for a representative PWR plant, (i.e., Surry) containment isolation failures contribute less than 0.1 percent to the latent risks from reactor accidents. | ||
Consequently, it is desirable to show that extending the ILRT interval will not lead to a substantial increase in risk from containment isolation failures for HNP. Earlier ILRT frequency extension submittals have used the EPRI TR-104285 (Reference | Consequently, it is desirable to show that extending the ILRT interval will not lead to a substantial increase in risk from containment isolation failures for HNP. Earlier ILRT frequency extension submittals have used the EPRI TR-104285 (Reference | ||
: 7) methodology to perform the risk assessment. | : 7) methodology to perform the risk assessment. | ||
In October 2008, EPRI TR-1018243 (Reference 20} was issued to update the generic methodology for ILRT extensions to 15 years using current performance data and to incorporate the specific limitations and conditions outlined by the NRC in the final safety evaluation of the methodology (Reference 9). This more recent EPRI document considers additional risk metrics and criteria including the change in population dose, large early release Enclosure Page 19 of 81 frequency (LERF), and conditional containment failure probability (CCFP), whereas EPRI TR-104285 considered only the change in population dose. In the SER 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 extend the ILRT surveillance interval to 15 years, subject to the limitations and conditions noted in Section 4.0 of the Safety Evaluation (SE). Table 3.3.1-1 addresses each of the four limitations and conditions for the use of EPRI 1009325, Revision 2. Table 3.3.1-1, EPRI Report No. 1009325 Revision 2 Limitations and Conditions Limitation/Condition lFrom Section 4.2 of SE) HNP Resoonse 1. The licensee submits documentation HNP PRA technical adequacy is addressed in indicating that the technical adequacy of Section 3.3.2 of this LAR and Attachment 3, their PRA is consistent with the "Plant Hatch Units 1 & 2 Risk Assessment to requirements of RG 1.200 relevant to the Support ILRT (Type A) Interval Extension I LRT extension. | In October 2008, EPRI TR-1018243 (Reference 20} was issued to update the generic methodology for ILRT extensions to 15 years using current performance data and to incorporate the specific limitations and conditions outlined by the NRC in the final safety evaluation of the methodology (Reference 9). This more recent EPRI document considers additional risk metrics and criteria including the change in population dose, large early release Enclosure Page 19 of 81 frequency (LERF), and conditional containment failure probability (CCFP), whereas EPRI TR-104285 considered only the change in population dose. In the SER 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 extend the ILRT surveillance interval to 15 years, subject to the limitations and conditions noted in Section 4.0 of the Safety Evaluation (SE). Table 3.3.1-1 addresses each of the four limitations and conditions for the use of EPRI 1009325, Revision 2. Table 3.3.1-1, EPRI Report No. 1009325 Revision 2 Limitations and Conditions Limitation/Condition lFrom Section 4.2 of SE) HNP Resoonse 1. The licensee submits documentation HNP PRA technical adequacy is addressed in indicating that the technical adequacy of Section 3.3.2 of this LAR and Attachment 3, their PRA is consistent with the "Plant Hatch Units 1 & 2 Risk Assessment to requirements of RG 1.200 relevant to the Support ILRT (Type A) Interval Extension I LRT extension. | ||
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The Hatch dose increase results are significantly less than 1.0 person-rem/yr. | The Hatch dose increase results are significantly less than 1.0 person-rem/yr. | ||
Moreover, the risk impact when compared to other severe accident risks is negligible. | Moreover, the risk impact when compared to other severe accident risks is negligible. | ||
The increase in CCFP when comparing the three in ten-year frequency to one in fifteen-year frequency is about 0.84% using the EPRI guidance values, and drops to about 0.10% using the EPRI Expert Elicitation values. The EPRI guidance states that increases in CCFP < 1.5 percentage points are very small. Therefore the increase for Hatch is determined to be very small. The representative containment leakage for Class 3b sequences used by HNP is 100 La, based on the recommendations in the latest EPRI report (Reference | The increase in CCFP when comparing the three in ten-year frequency to one in fifteen-year frequency is about 0.84% using the EPRI guidance values, and drops to about 0.10% using the EPRI Expert Elicitation values. The EPRI guidance states that increases in CCFP < 1.5 percentage points are very small. Therefore the increase for Hatch is determined to be very small. The representative containment leakage for Class 3b sequences used by HNP is 100 La, 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 La for the Class 3b sequences. | : 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 La for the Class 3b sequences. | ||
Limitation/Condition (From Section 4.2 of SEl 4. A licensee amendment request (LAR) is required in instances where containment over-pressure is relied upon for ECCS performance. | Limitation/Condition (From Section 4.2 of SEl 4. A licensee amendment request (LAR) is required in instances where containment over-pressure is relied upon for ECCS performance. | ||
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3.3.2.3 Plant Changes Not Yet Incorporated into the PRA Model As part of PRA model configuration control, SNC maintains a PRA model maintenance database that tracks all issues that have been identified that could impact the Hatch PRA model. Per SNC procedure RIE-001 the significance of the pending items in the database is evaluated to determine the impact on model results. Each pending item is prioritized for future model updates according to its significance to model results. A review of the current open items in the database for HNP identified no permanent plant design or operational changes that would significantly impact the results of the risk assessment performed for the ILRT interval extension evaluation. | 3.3.2.3 Plant Changes Not Yet Incorporated into the PRA Model As part of PRA model configuration control, SNC maintains a PRA model maintenance database that tracks all issues that have been identified that could impact the Hatch PRA model. Per SNC procedure RIE-001 the significance of the pending items in the database is evaluated to determine the impact on model results. Each pending item is prioritized for future model updates according to its significance to model results. A review of the current open items in the database for HNP identified no permanent plant design or operational changes that would significantly impact the results of the risk assessment performed for the ILRT interval extension evaluation. | ||
3.3.2.4 Previous Peer Review and Self Assessment of the HNP PRA Model The HNP PRA model was reviewed extensively during development and undergoes independent internal review during each update. The Hatch PRA was reviewed twice prior to issuance of the ASME PRA Standard for peer review. The initial peer review was conducted by the BWR Owners Group (BWROG) in April 2001. The review team used Revision A-3 NEI draft "Probabilistic Risk Assessment (PRA) *Peer Review Process Guidance" dated June 2, 2000 as the basis for review. This review was observed by a team from the NRC. In 2006, a gap analysis was performed against the available versions of the ASME PRA Standard and RG 1.200, Revision 0 (2003 trial version). | 3.3.2.4 Previous Peer Review and Self Assessment of the HNP PRA Model The HNP PRA model was reviewed extensively during development and undergoes independent internal review during each update. The Hatch PRA was reviewed twice prior to issuance of the ASME PRA Standard for peer review. The initial peer review was conducted by the BWR Owners Group (BWROG) in April 2001. The review team used Revision A-3 NEI draft "Probabilistic Risk Assessment (PRA) *Peer Review Process Guidance" dated June 2, 2000 as the basis for review. This review was observed by a team from the NRC. In 2006, a gap analysis was performed against the available versions of the ASME PRA Standard and RG 1.200, Revision 0 (2003 trial version). | ||
Enclosure Page 24 of 81 3.3.2.5 RG 1.200 PRA Review of the HNP PRA Model against the ASME PRA Standard Requirements A PRA Peer Review of all elements of the HNP Internal Events PRA PRA model including Internal Flooding against RG 1.200, Revision 2 clarifications, the ASME/ANS PRA Standard (Reference 30), and NEI 05-04 was performed in November 2009. A summary of the results of the PRA Peer Review (Reference | Enclosure Page 24 of 81 3.3.2.5 RG 1.200 PRA Review of the HNP PRA Model against the ASME PRA Standard Requirements A PRA Peer Review of all elements of the HNP Internal Events PRA PRA model including Internal Flooding against RG 1.200, Revision 2 clarifications, the ASME/ANS PRA Standard (Reference 30), and NEI 05-04 was performed in November 2009. A summary of the results of the PRA Peer Review (Reference | ||
: 21) previously provided to the NRC as part of the NEI Risk Informed Technical Specification (RITS) Initiative 5b LAR submittal (ML 103140510) for which SNC received a NRC SER as discussed in Attachment 3, Appendix B, section B.2.7 of this submittal, is shown below. Based on the results of the Peer Review, 95% of the SRs evaluated met Category II or better. There were 10 supporting requirements that were noted as "Not Met" and 5 that were noted "Met" at Category I only. All of the "Not Met" findings were resolved as part of the update of the Hatch Internal Events PRA Model, Revision 4.0, to Revision 4.1 as noted in Attachment 3, Appendix B, Tables B.2-1 and B.2-2 of this submittal. | : 21) previously provided to the NRC as part of the NEI Risk Informed Technical Specification (RITS) Initiative 5b LAR submittal (ML 103140510) for which SNC received a NRC SER as discussed in Attachment 3, Appendix B, section B.2.7 of this submittal, is shown below. Based on the results of the Peer Review, 95% of the SRs evaluated met Category II or better. There were 10 supporting requirements that were noted as "Not Met" and 5 that were noted "Met" at Category I only. All of the "Not Met" findings were resolved as part of the update of the Hatch Internal Events PRA Model, Revision 4.0, to Revision 4.1 as noted in Attachment 3, Appendix B, Tables B.2-1 and B.2-2 of this submittal. | ||
3.3.2.6 PRA Portions With Inadequate Technical Adequacy As previously noted, the NRC safety evaluation (Reference | 3.3.2.6 PRA Portions With Inadequate Technical Adequacy As previously noted, the NRC safety evaluation (Reference | ||
: 9) of the EPRI ILRT methodology specifies that Capability Category I is appropriate for the applicable PRA Standard supporting requirements. | : 9) of the EPRI ILRT methodology specifies that Capability Category I is appropriate for the applicable PRA Standard supporting requirements. | ||
Based on the update to the HNP Internal Events PRA model to Revision 4.1, following the 2009 PRA Peer Review, all PRA Standard supporting requirements are met at Capability Category 11 or higher, as applicable. | Based on the update to the HNP Internal Events PRA model to Revision 4.1, following the 2009 PRA Peer Review, all PRA Standard supporting requirements are met at Capability Category 11 or higher, as applicable. | ||
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====3.3.3 Summary==== | ====3.3.3 Summary==== | ||
of Plant-Specific Risk Assessment Results Enclosure Page 25 of 81 The findings of the HNP, Units 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 very small. The HNP plant-specific results for extending ILRT interval from the current 10 years to 15 years are summarized below: Based on the results from Attachment 3, Section 7.0, "Conclusions," and the sensitivity calculations presented in Section 6.0 "Sensitivities," the following conclusions regarding the assessment of the plant risk associated with permanently extending the Type A ILRT test frequency to 15 years: | of Plant-Specific Risk Assessment Results Enclosure Page 25 of 81 The findings of the HNP, Units 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 very small. The HNP plant-specific results for extending ILRT interval from the current 10 years to 15 years are summarized below: Based on the results from Attachment 3, Section 7.0, "Conclusions," and the sensitivity calculations presented in Section 6.0 "Sensitivities," the following conclusions regarding the assessment of the plant risk associated with permanently extending the Type A ILRT test frequency to 15 years: | ||
* RG 1.174 (Reference | * RG 1.174 (Reference | ||
: 3) provides guidance for determining the risk impact of plant-specific changes to the licensing basis. RG 1.17 4 defines "very small" changes in risk as resulting in increases of CDF below 1 o-6/yr and increases in LERF below 1 o-7/yr. Because the ILRT does not impact CDF, the relevant criterion is LERF. The increase in internal events LERF resulting from a change in the Type A ILRT test frequency from three in ten years to one in fifteen years is conservatively estimated as 6.39E-08/yr using the EPRI guidance as written and including potential corrosion impacts. The LERF increase using the EPRI Expert Elicitation values is substantially less (i.e., 7.52E-09/yr). | : 3) provides guidance for determining the risk impact of plant-specific changes to the licensing basis. RG 1.17 4 defines "very small" changes in risk as resulting in increases of CDF below 1 o-6/yr and increases in LERF below 1 o-7/yr. Because the ILRT does not impact CDF, the relevant criterion is LERF. The increase in internal events LERF resulting from a change in the Type A ILRT test frequency from three in ten years to one in fifteen years is conservatively estimated as 6.39E-08/yr using the EPRI guidance as written and including potential corrosion impacts. The LERF increase using the EPRI Expert Elicitation values is substantially less (i.e., 7.52E-09/yr). | ||
Using both approaches, the estimated change in LERF is determined to be "very small" using the acceptance guidelines of RG 1.17 4. | Using both approaches, the estimated change in LERF is determined to be "very small" using the acceptance guidelines of RG 1.17 4. | ||
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* The increase in the CCFP when comparing the three in ten-year frequency to one in fifteen-year frequency is about 0.84% using the EPRI guidance values, and drops to about 0.10% using the EPRI Expert Elicitation values. The EPRI guidance states that increases in CCFP < 1 .5 percentage points are very small. Therefore, the increase for Hatch is determined to be very small. | * The increase in the CCFP when comparing the three in ten-year frequency to one in fifteen-year frequency is about 0.84% using the EPRI guidance values, and drops to about 0.10% using the EPRI Expert Elicitation values. The EPRI guidance states that increases in CCFP < 1 .5 percentage points are very small. Therefore, the increase for Hatch is determined to be very small. | ||
* The potential impact on LERF from external events was quantitatively assessed utilizing information from the Individual Plant Examination of External Events (IPEEE). The total increase in LERF due to internal and external events using Enclosure Page 26 of 81 the EPRI guidance values is estimated to be 9.SE-8/yr, which remains in the "very small" change region (i.e., < 1 E-7/yr) of the RG 1.174 acceptance guidelines. | * The potential impact on LERF from external events was quantitatively assessed utilizing information from the Individual Plant Examination of External Events (IPEEE). The total increase in LERF due to internal and external events using Enclosure Page 26 of 81 the EPRI guidance values is estimated to be 9.SE-8/yr, which remains in the "very small" change region (i.e., < 1 E-7/yr) of the RG 1.174 acceptance guidelines. | ||
Therefore, increasing the ILRT interval to 15 years is considered to represent an insignificant change in risk for HNP. 3.3.4 Previous Assessments The NRG in NUREG-1493 (Reference | Therefore, increasing the ILRT interval to 15 years is considered to represent an insignificant change in risk for HNP. 3.3.4 Previous Assessments The NRG in NUREG-1493 (Reference | ||
: 6) has previously concluded that: | : 6) has previously concluded that: | ||
* Reducing the frequency of Type A tests (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 Type B and C testing, and the leaks that have been found by Type A tests have been only marginally above existing requirements. | * Reducing the frequency of Type A tests (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 Type B and C testing, and the leaks that have been found by Type A tests have been only marginally above existing requirements. | ||
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A listing of applicable sections of 10 CFR 50.55a and Code Cases as well as relief requests, Enclosure Page 29 of 81 exemptions, and alternatives can be found in Volume 1 of the ISi Plan. This plan also includes examinations not required by Subsection IWE that SNC has elected to perform due to specific industry concerns. | A listing of applicable sections of 10 CFR 50.55a and Code Cases as well as relief requests, Enclosure Page 29 of 81 exemptions, and alternatives can be found in Volume 1 of the ISi Plan. This plan also includes examinations not required by Subsection IWE that SNC has elected to perform due to specific industry concerns. | ||
Relief Request By letter dated July 16, 2015, as supplemented by letter dated December 16, 2015, SNC submitted a request to the NRC for relief from the requirements of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code (B&PV Code) at HNP, Units 1 and 2. SNC requested to use the current ASME B&PV code of record, the 2001 edition through the 2003 addenda, in combination with the 2007 edition through the 2008 addenda for certain inservice inspection and containment inservice inspection activities from January 1, 2016, through November 30, 2017. The NRG staff reviewed the subject request and concludes, as set forth in the enclosed safety evaluation, that the licensee has adequately addressed all of the regulatory requirements set forth in 10 CFR 50.55a(z)(1 | Relief Request By letter dated July 16, 2015, as supplemented by letter dated December 16, 2015, SNC submitted a request to the NRC for relief from the requirements of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code (B&PV Code) at HNP, Units 1 and 2. SNC requested to use the current ASME B&PV code of record, the 2001 edition through the 2003 addenda, in combination with the 2007 edition through the 2008 addenda for certain inservice inspection and containment inservice inspection activities from January 1, 2016, through November 30, 2017. The NRG staff reviewed the subject request and concludes, as set forth in the enclosed safety evaluation, that the licensee has adequately addressed all of the regulatory requirements set forth in 10 CFR 50.55a(z)(1 | ||
). Therefore, the NRC staff authorized the use of Relief Request HNP-ISl-AL T-5-01 at HNP, Units 1 and .2, from January 1, 2016, to November 30, 2017. (Reference | ). Therefore, the NRC staff authorized the use of Relief Request HNP-ISl-AL T-5-01 at HNP, Units 1 and .2, from January 1, 2016, to November 30, 2017. (Reference | ||
: 35) The application of Relief Request HNP-ISl-AL T-5-01 as applicable to Sub-section IWE is displayed in the following table: Table 3.4.2-1, Proposed ASME Section XI, Sub-section IWE, Code Of Record For HNP ASME Section XI Code Provision ASME Section XI Code Edition/ Addenda 1 Sub-section Article 2001 Edition/ 2001 Edition/ 2007 Edition/ No Addenda 2003 2008 Addenda Addenda IWE Requirements IWE-1000 x2 for Class MC IWE-2000 x2 Components IWE-3000 x IWE-5000 x 1 SNC will also comply with all NRG conditions, limitations, and restrictions specified in 10 CFR 50.55a as they apply to the specific edition and addenda referenced. | : 35) The application of Relief Request HNP-ISl-AL T-5-01 as applicable to Sub-section IWE is displayed in the following table: Table 3.4.2-1, Proposed ASME Section XI, Sub-section IWE, Code Of Record For HNP ASME Section XI Code Provision ASME Section XI Code Edition/ Addenda 1 Sub-section Article 2001 Edition/ 2001 Edition/ 2007 Edition/ No Addenda 2003 2008 Addenda Addenda IWE Requirements IWE-1000 x2 for Class MC IWE-2000 x2 Components IWE-3000 x IWE-5000 x 1 SNC will also comply with all NRG conditions, limitations, and restrictions specified in 10 CFR 50.55a as they apply to the specific edition and addenda referenced. | ||
2 The selection, planning, and scheduling of ISi examinations/tests will comply with these ASME Section XI articles (e.g. IWB-1000 and 2000) from the 2007 Edition/2008 Addenda or applicable NRG approved alternatives that are specified in the HNP ISl/Cll Program Plans. Implementation Schedule The current 10-year inspection interval began January 1, 2016 and goes through December 31, 2025. All inspections required during the previous containment inspection Enclosure Page 30 of 81 interval were completed during the previous interval. | 2 The selection, planning, and scheduling of ISi examinations/tests will comply with these ASME Section XI articles (e.g. IWB-1000 and 2000) from the 2007 Edition/2008 Addenda or applicable NRG approved alternatives that are specified in the HNP ISl/Cll Program Plans. Implementation Schedule The current 10-year inspection interval began January 1, 2016 and goes through December 31, 2025. All inspections required during the previous containment inspection Enclosure Page 30 of 81 interval were completed during the previous interval. | ||
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Enclosure Page 37 of 81 Virtually 100% of the exterior vent system (located inside the suppression pool) surfaces are accessible for visual examination from the 114' -0" interior catwalk, or from the top of the vent header if the provisions of 10 CFR 50.55a(b)(2)(ix)(B) are applied. Visual examination of the exterior vent system surfaces located outside the suppression pool are accessible from the inner circumference catwalk, the top of the vent pipe and the 87' -0" floor elevation if the provisions of 10 CFR 50.55a(b)(2)(ix)(B) are applied. Visual examination of the interior vent system is accessible from the drywell. Visual examination of the vent system from these vantage points should provide adequate access to perform visual examination of these surfaces. | Enclosure Page 37 of 81 Virtually 100% of the exterior vent system (located inside the suppression pool) surfaces are accessible for visual examination from the 114' -0" interior catwalk, or from the top of the vent header if the provisions of 10 CFR 50.55a(b)(2)(ix)(B) are applied. Visual examination of the exterior vent system surfaces located outside the suppression pool are accessible from the inner circumference catwalk, the top of the vent pipe and the 87' -0" floor elevation if the provisions of 10 CFR 50.55a(b)(2)(ix)(B) are applied. Visual examination of the interior vent system is accessible from the drywell. Visual examination of the vent system from these vantage points should provide adequate access to perform visual examination of these surfaces. | ||
There have been no reports of significant degradation of the exterior or interior surfaces of the vent system during examination and classification as IWE, Category E-A is warranted at the present time. Category E-A Specific Evaluation and Examination Position Item E1.10 Evaluation Item E1.10 includes the containment vessel pressure retaining boundary and the examinations listed in items E1.11 and E1.12. The examinations described in E1.11 and E1 .12 are applicable as described in the appropriate sections below. Item E1 .11 Evaluation (General Visual Examination) | There have been no reports of significant degradation of the exterior or interior surfaces of the vent system during examination and classification as IWE, Category E-A is warranted at the present time. Category E-A Specific Evaluation and Examination Position Item E1.10 Evaluation Item E1.10 includes the containment vessel pressure retaining boundary and the examinations listed in items E1.11 and E1.12. The examinations described in E1.11 and E1 .12 are applicable as described in the appropriate sections below. Item E1 .11 Evaluation (General Visual Examination) | ||
Table IWE-2500-1, Item E1 .11 references the below listed footnotes relative to containment surface examination requirements. | Table IWE-2500-1, Item E1 .11 references the below listed footnotes relative to containment surface examination requirements. | ||
: 1. Examinations shall include all accessible interior and exterior surfaces of Class MC components, parts, and appurtenances, and metallic shell and penetration liners of Class CC components. | : 1. Examinations shall include all accessible interior and exterior surfaces of Class MC components, parts, and appurtenances, and metallic shell and penetration liners of Class CC components. | ||
The following items shall be considered for examination: (a) integral attachments and structures are parts of reinforcing structure, such as stiffening rings, manhole frames, and reinforcement around openings. (b) surfaces of attachment welds between structural attachments and the pressure retaining boundary or reinforcing structure, except for nonstructural or temporary attachments as defined in NE-4435 and minor permanent attachments as defined in CC-4543.4. (c) surfaces of containment structural and pressure boundary welds, including longitudinal welds (Category A), circumferential welds (Category B), flange welds (Category C), and nozzle-to-shell welds (Category D) as defined in NE-3351 for Class MC; and surfaces of Flued Head and Bellows Seal Circumferential Welds joined to the Penetration. | The following items shall be considered for examination: (a) integral attachments and structures are parts of reinforcing structure, such as stiffening rings, manhole frames, and reinforcement around openings. (b) surfaces of attachment welds between structural attachments and the pressure retaining boundary or reinforcing structure, except for nonstructural or temporary attachments as defined in NE-4435 and minor permanent attachments as defined in CC-4543.4. (c) surfaces of containment structural and pressure boundary welds, including longitudinal welds (Category A), circumferential welds (Category B), flange welds (Category C), and nozzle-to-shell welds (Category D) as defined in NE-3351 for Class MC; and surfaces of Flued Head and Bellows Seal Circumferential Welds joined to the Penetration. | ||
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Electrical penetrations used at Plant Hatch are weld-in design, do not utilize pressure retaining bolting, and are not specifically listed in the examination tables. These penetrations are part of the general visual examinations performed on a periodic basis. All bolted connections are also included in the Appendix J leakrate testing program. Appendix J leakrate testing is required anytime the connection is disassembled, and at least every 10 years if not disassembled, which confirms containment leak tight integrity. | Electrical penetrations used at Plant Hatch are weld-in design, do not utilize pressure retaining bolting, and are not specifically listed in the examination tables. These penetrations are part of the general visual examinations performed on a periodic basis. All bolted connections are also included in the Appendix J leakrate testing program. Appendix J leakrate testing is required anytime the connection is disassembled, and at least every 10 years if not disassembled, which confirms containment leak tight integrity. | ||
Item E 1.12 Evaluation (VT-3 Visual Examination) | Item E 1.12 Evaluation (VT-3 Visual Examination) | ||
Table IWE-2500-1, Item E1 .12 references the below listed footnotes relative to containment surface examination requirements. | Table IWE-2500-1, Item E1 .12 references the below listed footnotes relative to containment surface examination requirements. | ||
: 1. Examinations shall include all accessible interior and exterior surfaces of Class MC components, parts, and appurtenances, and metallic shell and penetration liners of Class CC components. | : 1. Examinations shall include all accessible interior and exterior surfaces of Class MC components, parts, and appurtenances, and metallic shell and penetration liners of Class CC components. | ||
The following items shall be considered for examination: (a) integral attachments and structures are parts of reinforcing structure, such as stiffening rings, manhole frames, and reinforcement around openings. (b) surfaces of attachment welds between structural attachments and the pressure retaining boundary or reinforcing structure, except for nonstructural or temporary attachments as defined in NE-4435 and minor permanent attachments as defined in CC-4543.4. | The following items shall be considered for examination: (a) integral attachments and structures are parts of reinforcing structure, such as stiffening rings, manhole frames, and reinforcement around openings. (b) surfaces of attachment welds between structural attachments and the pressure retaining boundary or reinforcing structure, except for nonstructural or temporary attachments as defined in NE-4435 and minor permanent attachments as defined in CC-4543.4. | ||
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Ultrasonic Testing (UT) Enclosure Page 46 of 81 SNC has included supplemental provisions in the IWE program to check and monitor wall degradation of both Units 1 and 2 torus surfaces. | Ultrasonic Testing (UT) Enclosure Page 46 of 81 SNC has included supplemental provisions in the IWE program to check and monitor wall degradation of both Units 1 and 2 torus surfaces. | ||
Beginning with Unit 2 in 1998 and Unit 1 in 1999, SNC will perform ultrasonic (UT) thickness measurements in each torus bay of both Units 1 and 2. These measurements include selection of one grid location near the bottom in each torus bay. After the initial inspections, SNC will repeat the inspections every other outage to monitor degradation rates and their impact on Code minimum thickness. | Beginning with Unit 2 in 1998 and Unit 1 in 1999, SNC will perform ultrasonic (UT) thickness measurements in each torus bay of both Units 1 and 2. These measurements include selection of one grid location near the bottom in each torus bay. After the initial inspections, SNC will repeat the inspections every other outage to monitor degradation rates and their impact on Code minimum thickness. | ||
Conclusion The above plan, in conjunction with the ASME Section XI, Subsection IWE Program, is intended to assure the integrity of the torus. Based on evaluation of the results from all previous examinations, there is currently no indication that there are any degradation concerns which impact the wall thickness or structural integrity of the torus. 3.4.3 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 | Conclusion The above plan, in conjunction with the ASME Section XI, Subsection IWE Program, is intended to assure the integrity of the torus. Based on evaluation of the results from all previous examinations, there is currently no indication that there are any degradation concerns which impact the wall thickness or structural integrity of the torus. 3.4.3 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. | : 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: | 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: | ||
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This was reported under LEA 2011-001-1 (Reference 34). 3.4.5 Type Band Type C Local Leak Rate Testing Program Implementation Review The following Tables 3.4.5-1 and 3.4.5-2 identify the components that were on extended intervals and have not demonstrated acceptable performance during the previous two . outages for HNP, Units 1 and 2 respectively: | This was reported under LEA 2011-001-1 (Reference 34). 3.4.5 Type Band Type C Local Leak Rate Testing Program Implementation Review The following Tables 3.4.5-1 and 3.4.5-2 identify the components that were on extended intervals and have not demonstrated acceptable performance during the previous two . outages for HNP, Units 1 and 2 respectively: | ||
Table 3.4.5-1, Unit 1 Type B and C LLRT Program Implementation Review 1RF26 -2014 Component As-Admin As-left Cause of Corrective Scheduled found Limit SCCM Failure Action Interval SCCM SCCM 1 E41-F111 185,244 275 867 Seat Valve was 30 months Pen 221A (1) leakage, refurbished. | Table 3.4.5-1, Unit 1 Type B and C LLRT Program Implementation Review 1RF26 -2014 Component As-Admin As-left Cause of Corrective Scheduled found Limit SCCM Failure Action Interval SCCM SCCM 1 E41-F111 185,244 275 867 Seat Valve was 30 months Pen 221A (1) leakage, refurbished. | ||
MNPLR Broken Acceptance of 64 wedge refurbished (1) valve As-left leakage by evaluation Enclosure Page 50 of 81 Table 3.4.5-1, Unit 1 Type B and C LLRT Program Implementation Review 1RF26 -2014 Component As-Admin As-left Cause of Corrective Scheduled found Limit SCCM Failure Action Interval SCCM SCCM 1T48-F335B 00 575 0 Seat Valve and valve 30 months Pen 26 (2) leakage operator MNPLR (2) refurbished 110 1RF27-2016 Component As-Admin As-left Cause Corrective Scheduled found Limit SCCM of Action Interval SCCM SCCM Failure H48-F334A 700 575 700 Not Acceptance of 30 months Pen 26 MNPLR identified valve As-left 53 leakage by evaluation. | MNPLR Broken Acceptance of 64 wedge refurbished (1) valve As-left leakage by evaluation Enclosure Page 50 of 81 Table 3.4.5-1, Unit 1 Type B and C LLRT Program Implementation Review 1RF26 -2014 Component As-Admin As-left Cause of Corrective Scheduled found Limit SCCM Failure Action Interval SCCM SCCM 1T48-F335B 00 575 0 Seat Valve and valve 30 months Pen 26 (2) leakage operator MNPLR (2) refurbished 110 1RF27-2016 Component As-Admin As-left Cause Corrective Scheduled found Limit SCCM of Action Interval SCCM SCCM Failure H48-F334A 700 575 700 Not Acceptance of 30 months Pen 26 MNPLR identified valve As-left 53 leakage by evaluation. | ||
(1) 1 E41-F111 failed as-found testing with an identified leakage rate of 185244 seem. It was discovered during performance of 42SV-TET-001-1 that 1 E41 F111 could not be brought to test pressure due to leakage through seat of this valve. Per engineering request, a set of data was recorded at less than prescribed test pressure. | (1) 1 E41-F111 failed as-found testing with an identified leakage rate of 185244 seem. It was discovered during performance of 42SV-TET-001-1 that 1 E41 F111 could not be brought to test pressure due to leakage through seat of this valve. Per engineering request, a set of data was recorded at less than prescribed test pressure. | ||
At 47.5 psig measured leakage was 185,244 seem. The minimum pathway leakage rate for Penetration 221A was 64 seem. Excessive seat leakage was due to stellite breaking off the wedge on the downstream side. (2) 1T48-F111 failed as-found testing with a leakage rate of that could not be quantified. | At 47.5 psig measured leakage was 185,244 seem. The minimum pathway leakage rate for Penetration 221A was 64 seem. Excessive seat leakage was due to stellite breaking off the wedge on the downstream side. (2) 1T48-F111 failed as-found testing with a leakage rate of that could not be quantified. | ||
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* Containment Inspection Program (Class MC/IWE) | * Containment Inspection Program (Class MC/IWE) | ||
* Containment Inspections per TS SR 3.6.1 .1.1 | * Containment Inspections per TS SR 3.6.1 .1.1 | ||
* Protective Coatings Program Enclosure Page 72 of 81 This experience is supplemented by risk analysis studies, including the HNP, Units 1 and 2 risk analysis provided in Attachment | * Protective Coatings Program Enclosure Page 72 of 81 This experience is supplemented by risk analysis studies, including the HNP, Units 1 and 2 risk analysis provided in Attachment | ||
: 3. The risk assessment concluded that increasing the ILRT interval to 15 years is considered to represent an insignificant change in risk for HNP. | : 3. The risk assessment concluded that increasing the ILRT interval to 15 years is considered to represent an insignificant change in risk for HNP. | ||
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Type B and Type C testing ensures that individual penetrations are essentially leak tight. In addition, aggregate Type Band Type C leakage rates support the leakage tightness of primary containment by minimizing potential leakage paths. For EPRI Report No. 1009325, Revision 2, a risk-informed methodology using specific risk insights and industry ILRT performance data to revise ILRT surveillance frequencies, the NRC staff finds that the proposed methodology satisfies the key principles of risk-informed decision making applied to changes to TSs as delineated in RG 1.177 and RG 1.174. The NRC staff, therefore, found that this guidance was acceptable for referencing by licensees proposing to amend their TS in regards to containment leakage rate testing, subject to the limitations and conditions noted in Section 4.2 of the Safety Evaluation Report (SER). The NRC staff reviewed NEI TR 94-01, Revision 3, and determined that it described an acceptable approach for implementing the optional performance-based requirements of Option B to 10 CFR 50, Appendix J, as modified by the conditions and limitations summarized in Section 4.0 of the associated Safety Evaluation. | Type B and Type C testing ensures that individual penetrations are essentially leak tight. In addition, aggregate Type Band Type C leakage rates support the leakage tightness of primary containment by minimizing potential leakage paths. For EPRI Report No. 1009325, Revision 2, a risk-informed methodology using specific risk insights and industry ILRT performance data to revise ILRT surveillance frequencies, the NRC staff finds that the proposed methodology satisfies the key principles of risk-informed decision making applied to changes to TSs as delineated in RG 1.177 and RG 1.174. The NRC staff, therefore, found that this guidance was acceptable for referencing by licensees proposing to amend their TS in regards to containment leakage rate testing, subject to the limitations and conditions noted in Section 4.2 of the Safety Evaluation Report (SER). The NRC staff reviewed NEI TR 94-01, Revision 3, and determined that it described an acceptable approach for implementing the optional performance-based requirements of Option B to 10 CFR 50, Appendix J, as modified by the conditions and limitations summarized in Section 4.0 of the associated Safety Evaluation. | ||
This guidance included provisions for extending Type C LLRT intervals up to 75 months. Type C testing ensures that individual containment isolation valves are essentially leak tight. In addition, aggregate Type C leakage rates support the leakage tightness of primary containment by minimizing potential leakage paths. The NRC staff, therefore, found that this guidance, as modified to include two limitations and conditions, was acceptable for referencing by licensees proposing to amend their TS in regards to containment leakage rate testing. Any applicant may reference NEI TR 94-01, Revision 3, as modified by the associated SER and approved by the NRC, and the conditions and limitations 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: | This guidance included provisions for extending Type C LLRT intervals up to 75 months. Type C testing ensures that individual containment isolation valves are essentially leak tight. In addition, aggregate Type C leakage rates support the leakage tightness of primary containment by minimizing potential leakage paths. The NRC staff, therefore, found that this guidance, as modified to include two limitations and conditions, was acceptable for referencing by licensees proposing to amend their TS in regards to containment leakage rate testing. Any applicant may reference NEI TR 94-01, Revision 3, as modified by the associated SER and approved by the NRC, and the conditions and limitations 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 | * Surry Power Station, Units 1 and 2 (Reference | ||
: 24) | : 24) | ||
* Donald C. Cook Nuclear Plant, Units 1 and 2 (Reference | * Donald C. Cook Nuclear Plant, Units 1 and 2 (Reference | ||
: 25) | : 25) | ||
* Beaver Valley Power Station, Unit Nos. 1 and 2 (Reference | * Beaver Valley Power Station, Unit Nos. 1 and 2 (Reference | ||
: 26) | : 26) | ||
* Calvert Cliffs Nuclear Power Plant, Unit Nos. 1 and 2 (Reference | * Calvert Cliffs Nuclear Power Plant, Unit Nos. 1 and 2 (Reference | ||
: 27) | : 27) | ||
* Peach Bottom Atomic Power Station, Units 2 and 3 (Reference | * Peach Bottom Atomic Power Station, Units 2 and 3 (Reference | ||
: 28) | : 28) | ||
Enclosure Page 74 of 81 | Enclosure Page 74 of 81 | ||
* Comanche Peak Nuclear Power Plant, Units 1 and 2 (Reference | * Comanche Peak Nuclear Power Plant, Units 1 and 2 (Reference | ||
: 36) 4.3 No Significant Hazards Consideration Southern Nuclear Operating Company (SNC) has evaluated whether or not a significant hazards consideration is involved with the proposed amendment by focusing on the .three standards set forth in 10 CFR 50.92, "Issuance of amendment," as discussed below: 1. Does the proposed amendment involve a significant increase in the probability or consequences of an accident previously evaluated? | : 36) 4.3 No Significant Hazards Consideration Southern Nuclear Operating Company (SNC) has evaluated whether or not a significant hazards consideration is involved with the proposed amendment by focusing on the .three standards set forth in 10 CFR 50.92, "Issuance of amendment," as discussed below: 1. Does the proposed amendment involve a significant increase in the probability or consequences of an accident previously evaluated? | ||
Response: | Response: | ||
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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 extensions do not significantly increase the consequences of an accident previously evaluated. | 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 extensions do not significantly increase the consequences of an accident previously evaluated. | ||
The proposed amendment also deletes exceptions previously granted to allow time extensions of the ILRT test frequency for both Units 1 and 2. These exceptions were for activities that have already taken place; therefore, their deletion is solely an administrative action that has no effect on any component and no physical impact on how the units are operated. | The proposed amendment also deletes exceptions previously granted to allow time extensions of the ILRT test frequency for both Units 1 and 2. These exceptions were for activities that have already taken place; therefore, their deletion is solely an administrative action that has no effect on any component and no physical impact on how the units are operated. | ||
Therefore, the proposed change does not result in a significant increase in the probability or consequences of an accident previously evaluated. | Therefore, the proposed change does not result in a significant increase in the probability or consequences of an accident previously evaluated. | ||
: 2. Does the proposed change create the possibility of a new or different kind of accident from any accident previously evaluated? | : 2. Does the proposed change create the possibility of a new or different kind of accident from any accident previously evaluated? | ||
Response: | Response: | ||
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The proposed change does not involve a physical change to the plant (i.e., no new or different type of equipment will be installed) nor does it alter the design, configuration, or change the manner in which the plant is operated or controlled beyond the standard functional capabilities of the equipment. | The proposed change does not involve a physical change to the plant (i.e., no new or different type of equipment will be installed) nor does it alter the design, configuration, or change the manner in which the plant is operated or controlled beyond the standard functional capabilities of the equipment. | ||
The proposed amendment also deletes exceptions previously granted to allow time extensions of the ILRT test frequency for both Units 1 and 2. These exceptions were for activities that would have already taken place by the time this amendment is approved; therefore, their deletion is solely an administrative action that does not result in any change in how the units are operated. | The proposed amendment also deletes exceptions previously granted to allow time extensions of the ILRT test frequency for both Units 1 and 2. These exceptions were for activities that would have already taken place by the time this amendment is approved; therefore, their deletion is solely an administrative action that does not result in any change in how the units are operated. | ||
Enclosure Page 76 of 81 Therefore, the proposed change does not create the possibility of a new or different kind of accident from any previously evaluated. | Enclosure Page 76 of 81 Therefore, the proposed change does not create the possibility of a new or different kind of accident from any previously evaluated. | ||
: 3. Does the proposed change involve a significant reduction in a margin of safety? Response: | : 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 HNP, 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. | No. The proposed amendment to TS 5.5.12 involves the extension of the HNP, 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. | ||
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==6.0 REFERENCES== | ==6.0 REFERENCES== | ||
: 1. Regulatory Guide 1.163, Performance-Based Containment Leak-Test Program, September 1995 2. NEI 94-01, Revision 3-A, Industry Guideline for Implementing Based Option of 10 CFR 50, Appendix J, 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, 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, March 2009 Enclosure Page 78 of 81 5. NEI 94-01, Revision 0, Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J, July 1995 6. NUREG-1493, Performance-Based Containment Leak-Test Program, January 1995 7. EPRI TR-104285, Risk Impact Assessment of Revised Containment Leak Rate Testing Intervals, August 1994 8. NEI 94-01, Revision 2-A, Industry Guideline for Implementing Based Option of 10 CFR 50, Appendix J, October 2008 9. Letter from M. J. Maxin (NRC) to J. C. Butler (NEI), dated June 25, 2008, 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) 10. Letter from S. Bahadur (NRC) to B. Bradley (NEI), dated June 8, 2012, Final Safety Evaluation of Nuclear Energy Institute (NEI) Report 94-01, Revision 3, Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, AppendixJ (TAC No. ME2164) 11. Boiling Water Reactors Owners' Group, BWROG PSA Peer Review Certification Implementation Guidelines, Revision 3, January 1997 12. Draft Regulatory Guide DG-1122, An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities, November 2002 13. Letter from S. Bloom (NRC) to H. Sumner (SNC), dated September 23, 2003, Edwin I. Hatch Nuclear Plant, Unit 1 and 2 -Issuance of Amendments Regarding Appendix K Measurement Uncertainty Recovery, (ML032590944) | : 1. Regulatory Guide 1.163, Performance-Based Containment Leak-Test Program, September 1995 2. NEI 94-01, Revision 3-A, Industry Guideline for Implementing Based Option of 10 CFR 50, Appendix J, 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, 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, March 2009 Enclosure Page 78 of 81 5. NEI 94-01, Revision 0, Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J, July 1995 6. NUREG-1493, Performance-Based Containment Leak-Test Program, January 1995 7. EPRI TR-104285, Risk Impact Assessment of Revised Containment Leak Rate Testing Intervals, August 1994 8. NEI 94-01, Revision 2-A, Industry Guideline for Implementing Based Option of 10 CFR 50, Appendix J, October 2008 9. Letter from M. J. Maxin (NRC) to J. C. Butler (NEI), dated June 25, 2008, 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) 10. Letter from S. Bahadur (NRC) to B. Bradley (NEI), dated June 8, 2012, Final Safety Evaluation of Nuclear Energy Institute (NEI) Report 94-01, Revision 3, Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, AppendixJ (TAC No. ME2164) 11. Boiling Water Reactors Owners' Group, BWROG PSA Peer Review Certification Implementation Guidelines, Revision 3, January 1997 12. Draft Regulatory Guide DG-1122, An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities, November 2002 13. Letter from S. Bloom (NRC) to H. Sumner (SNC), dated September 23, 2003, Edwin I. Hatch Nuclear Plant, Unit 1 and 2 -Issuance of Amendments Regarding Appendix K Measurement Uncertainty Recovery, (ML032590944) | ||
: 14. Letter from L. Olshan (NRC) to H. Sumner (SNC), dated February 20, 2002, Edwin I. Hatch Nuclear Plant, Unit 1-Issuance of Amendment Re: Amendment Revises TS 5.5.12 to Allow a One-Time Deferral of the Type A Containment Integrated Leak Rate Test Based on the Risk-Informed Guidance in Regulatory Guide 1.174. (TAC No. MB2842) 15. Letter from C. Gratton (NRC) to H. Sumner (SNC), dated February 1, 2005, Edwin I. Hatch Nuclear Plant, Unit 2 Re: Issuance of Amendment Revising the Enclosure Page 79 of 81 Technical Specifications for the Primary Containment Leakage Rate Testing Program (TAC No. MC2761) 16. Letter from C. Gratton (NRG) to H. Sumner (SNC), dated May 28, 2004, Edwin I. Hatch Nuclear Plant, Units 1 and 2 Re: Issuance of Amendments Revising the Technical Specifications for the Primary Containment Leakage Rate Testing Program (TAC Nos. MC1432 and MC1433) 17. Letter from R. Martin (NRG) to D. Madison (SNC), dated August 28, 2008, Edwin I. Hatch Nuclear Plant, Unit NOS. 1 AND 2, Issuance of Amendments Regarding Alternate Source Term (TAC Nos. MD2934 and MD2935) 18. Letter from R. Ennis (NRG) to M. Pacilio (Exelon), dated August 25, 2014, Peach Bottom Atomic Power Station, Units 1 and 2 -Issuance of Amendments Re: Extended Power Uprate (TAC Nos. ME9631 and ME9632) 19. Letter from K. Jabbour (NRG) to J. Beckham Jr. (Georgia Power), dated March 6, 1996, Edwin I. Hatch Nuclear Plant, Units 1 and 2 -Issuance of Amendment Regarding the Adoption of the Requirements of 10 CFR 50, Appendix J, Option B, and the Implementation of a Performance-based Containment Leak-rate Testing Program. (TAC NOS. M94046 and M94047) 20. Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals: | : 14. Letter from L. Olshan (NRC) to H. Sumner (SNC), dated February 20, 2002, Edwin I. Hatch Nuclear Plant, Unit 1-Issuance of Amendment Re: Amendment Revises TS 5.5.12 to Allow a One-Time Deferral of the Type A Containment Integrated Leak Rate Test Based on the Risk-Informed Guidance in Regulatory Guide 1.174. (TAC No. MB2842) 15. Letter from C. Gratton (NRC) to H. Sumner (SNC), dated February 1, 2005, Edwin I. Hatch Nuclear Plant, Unit 2 Re: Issuance of Amendment Revising the Enclosure Page 79 of 81 Technical Specifications for the Primary Containment Leakage Rate Testing Program (TAC No. MC2761) 16. Letter from C. Gratton (NRG) to H. Sumner (SNC), dated May 28, 2004, Edwin I. Hatch Nuclear Plant, Units 1 and 2 Re: Issuance of Amendments Revising the Technical Specifications for the Primary Containment Leakage Rate Testing Program (TAC Nos. MC1432 and MC1433) 17. Letter from R. Martin (NRG) to D. Madison (SNC), dated August 28, 2008, Edwin I. Hatch Nuclear Plant, Unit NOS. 1 AND 2, Issuance of Amendments Regarding Alternate Source Term (TAC Nos. MD2934 and MD2935) 18. Letter from R. Ennis (NRG) to M. Pacilio (Exelon), dated August 25, 2014, Peach Bottom Atomic Power Station, Units 1 and 2 -Issuance of Amendments Re: Extended Power Uprate (TAC Nos. ME9631 and ME9632) 19. Letter from K. Jabbour (NRG) to J. Beckham Jr. (Georgia Power), dated March 6, 1996, Edwin I. Hatch Nuclear Plant, Units 1 and 2 -Issuance of Amendment Regarding the Adoption of the Requirements of 10 CFR 50, Appendix J, Option B, and the Implementation of a Performance-based Containment Leak-rate Testing Program. (TAC NOS. M94046 and M94047) 20. Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals: | ||
Revision 2-A of 1009325. EPRI, Palo Alto, CA: October 2008. 1018243 21. Hatch Unit 1 Peer Review Report (2009), February 2010 22. Regulatory Guide 1.147, Revision 16, lnservice Inspection Code Case Acceptability, ASME Section XI, Division 1, October 2010 23. NUREG-1769, Safety Evaluation Report Related to the License Renewal of Peach Bottom Atomic Power Station, Units 1 and 2, March 2003 24. ML 14148A235, Letter to D. Heacock from S. Williams (NRG) dated July 3, 2014. Surry Power Station, Units 1 And 2 -Issuance of Amendment Regarding the Containment Type A and Type C Leak Rate Tests 25. ML15072A264, Letter to L. Weber from A. Dietrich (NRG) dated March 30, 2015. Donald C. Cook Nuclear Plant, Units 1 and 2 -Issuance of Amendments Re: Containment Leakage Rate Testing Program 26. ML15078A058, Letter to E. Larson from T. Lamb (NRG) dated April 8, 2015. Beaver Valley Power Station, Unit Nos. 1 And 2 -Issuance of Amendment Re: License Amendment Request to Extend Containment Leakage Rate Test Frequency Enclosure Page 80 of 81 27. ML 15154A661, Letter to G. Gellrich from A. Chereskin (NRG) dated July 16, 2015. Calvert Cliffs Nuclear Power Plant, Unit Nos. 1 and 2 -Issuance of Amendments Re: Extension of Containment Leakage Rate Testing Frequency | Revision 2-A of 1009325. EPRI, Palo Alto, CA: October 2008. 1018243 21. Hatch Unit 1 Peer Review Report (2009), February 2010 22. Regulatory Guide 1.147, Revision 16, lnservice Inspection Code Case Acceptability, ASME Section XI, Division 1, October 2010 23. NUREG-1769, Safety Evaluation Report Related to the License Renewal of Peach Bottom Atomic Power Station, Units 1 and 2, March 2003 24. ML 14148A235, Letter to D. Heacock from S. Williams (NRG) dated July 3, 2014. Surry Power Station, Units 1 And 2 -Issuance of Amendment Regarding the Containment Type A and Type C Leak Rate Tests 25. ML15072A264, Letter to L. Weber from A. Dietrich (NRG) dated March 30, 2015. Donald C. Cook Nuclear Plant, Units 1 and 2 -Issuance of Amendments Re: Containment Leakage Rate Testing Program 26. ML15078A058, Letter to E. Larson from T. Lamb (NRG) dated April 8, 2015. Beaver Valley Power Station, Unit Nos. 1 And 2 -Issuance of Amendment Re: License Amendment Request to Extend Containment Leakage Rate Test Frequency Enclosure Page 80 of 81 27. ML 15154A661, Letter to G. Gellrich from A. Chereskin (NRG) dated July 16, 2015. Calvert Cliffs Nuclear Power Plant, Unit Nos. 1 and 2 -Issuance of Amendments Re: Extension of Containment Leakage Rate Testing Frequency | ||
: 28. ML 15196A559, Letter to B. Hanson from R. Ennis (NRG) dated September 8, 2015. 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) 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, March 2009 31. Letter from A. Pietrangelo (NEI) to NEI Administrative Points of Contact, Time Extension of Containment Integrated Leak Rate Test Interval -Additional Information, November 30, 2001 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, Accession Number ML020920100, March 27, 2002 33. Letter from A. Pietrangelo (NEI) to NEI Administrative Points of Contact, Interim Guidance for Performing Risk Impact Assessments in Support of One-Time Extensions for Containment Integrated Leak Rate Test Surveillance Intervals, November 13, 2001 34. ML11347A198, Edwin I. Hatch Nuclear Plant -Unit 2, Licensee Event report 2011-001-01, Revision 1, Primary Containment Isolation Penetration Exceeded Overall Allowable Technical Specification Leakage Limits, December 9, 2011 35. ML 15352A294, Letter from M. Marley (NRG) to C. Pierce (SNC), Relief from the Requirements of the ASME Code (CAC Nos. MF6494 and MF6495), December 28,2015 36. ML 15309A073, Letter to R. Flores (Luminant) from B. Singal (NRG) dated December 30, 2015. 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) | : 28. ML 15196A559, Letter to B. Hanson from R. Ennis (NRG) dated September 8, 2015. 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) 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, March 2009 31. Letter from A. Pietrangelo (NEI) to NEI Administrative Points of Contact, Time Extension of Containment Integrated Leak Rate Test Interval -Additional Information, November 30, 2001 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, Accession Number ML020920100, March 27, 2002 33. Letter from A. Pietrangelo (NEI) to NEI Administrative Points of Contact, Interim Guidance for Performing Risk Impact Assessments in Support of One-Time Extensions for Containment Integrated Leak Rate Test Surveillance Intervals, November 13, 2001 34. ML11347A198, Edwin I. Hatch Nuclear Plant -Unit 2, Licensee Event report 2011-001-01, Revision 1, Primary Containment Isolation Penetration Exceeded Overall Allowable Technical Specification Leakage Limits, December 9, 2011 35. ML 15352A294, Letter from M. Marley (NRG) to C. Pierce (SNC), Relief from the Requirements of the ASME Code (CAC Nos. MF6494 and MF6495), December 28,2015 36. ML 15309A073, Letter to R. Flores (Luminant) from B. Singal (NRG) dated December 30, 2015. 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) | ||
Enclosure Page 81 of 81 37. Letter from A. Pietrangelo (NEI) to NEI Administrative Points of Contact, Time Extension of Containment Integrated Leak Rate Test Interval -Additional Information, November 30, 2001. | Enclosure Page 81 of 81 37. Letter from A. Pietrangelo (NEI) to NEI Administrative Points of Contact, Time Extension of Containment Integrated Leak Rate Test Interval -Additional Information, November 30, 2001. | ||
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==1.1 REFERENCES== | ==1.1 REFERENCES== | ||
(continued) | |||
HATCH UNIT 1 8. ANSI/ANS 56.8 1994 , " American National Standard for Containment System t akage Testing Requirements," 1994. Ame r ican Nuclear Society , " Conta i nmen t System Leakage Test ing Requ i rements ," ANSI/ANS 56.8-2002. B 3.6-5 REVISION 69 BASES (cont i nued) ACTIONS SURVEILLANCE REQUIREMENTS Primary Conta i nment B 3.6.1.1 In the event primary containment is inoperable , p r imary conta i nment must be restored to OPERABLE status wi t hin 1 hour. The 1 hour Completion Time provides a period of time to correct the problem commensurate with the importance of maintaining primary containment OPERABILITY during MODES 1 , 2 , and 3. This time period also ensures that the probabi l ity of an accident (requiring primary containment OPERABILITY) occurring during periods where primary containment is inoperable is minima l. B.1 and B.2 If primary containment cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To ach i eve this status , the plant must be brought to at least MODE 3 within 12 hours and to MODE 4 with i n 36 hours. The allowed Comp l etion Times are reasonab l e , based on operating experience , to reach the required plant conditions from full power cond i tions in an orderly manner and without challenging plant systems. SR 3.6.1.1.1 Mainta i ning the primary containment OPERABLE requires compliance with the visual examinations and l eakage rate test requirements of the Primary Containment Leakage Rate Testing Program. Failu r e to meet air lock leakage test i ng (SR 3.6.1.2.1 ), secondary containment bypass leakage (SR 3.6.1.3.10), or main steam isolation valve leakage (SR 3.6.1.3.11) does not necessarily result in a failure of this SR. The impact of the failure to meet these SRs must be evaluated against the Type A , B , and C acceptance c r iteria of the Primary Conta in ment Leakage Rate Testing Program. The Primary Containment Leakage Rate Testing Program is based on the guidelines in Regulatory Gu i ao 1.163 (Ref. 6), NEI 94 01 (Ref. 7), ane 56.8 1994 (Ref. 8). Specific acceptance criteria for as found and as left leakage rates , as well as the methods of defining t h e leakage rates , are contained in the Primary Containment Leakage Rate Testing Program. At all other times between requi r ed leakage rate te s ts , the acceptance criteria are based on an overall Type A leakage l imit of 1.0 L a. At 1.0 L a. the o ff site dose consequences are bounded by the assumptions of the safety analysis. The Frequency is required by the Primary Containment Leakage Rate Tes ti ng Program. NEI 94-01 Revision 3-A (Ref. 7), the Limitations and Conditions of NEI 94-01 Revision 2-A (Ref.6), and ANSI/ _ANS 56.8-2002 HATCH UNIT 2 (continued) B 3.6-3 REVISION 7-BASES SURVEILLANCE REQUIREMENTS (continued) | HATCH UNIT 1 8. ANSI/ANS 56.8 1994 , " American National Standard for Containment System t akage Testing Requirements," 1994. Ame r ican Nuclear Society , " Conta i nmen t System Leakage Test ing Requ i rements ," ANSI/ANS 56.8-2002. B 3.6-5 REVISION 69 BASES (cont i nued) ACTIONS SURVEILLANCE REQUIREMENTS Primary Conta i nment B 3.6.1.1 In the event primary containment is inoperable , p r imary conta i nment must be restored to OPERABLE status wi t hin 1 hour. The 1 hour Completion Time provides a period of time to correct the problem commensurate with the importance of maintaining primary containment OPERABILITY during MODES 1 , 2 , and 3. This time period also ensures that the probabi l ity of an accident (requiring primary containment OPERABILITY) occurring during periods where primary containment is inoperable is minima l. B.1 and B.2 If primary containment cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To ach i eve this status , the plant must be brought to at least MODE 3 within 12 hours and to MODE 4 with i n 36 hours. The allowed Comp l etion Times are reasonab l e , based on operating experience , to reach the required plant conditions from full power cond i tions in an orderly manner and without challenging plant systems. SR 3.6.1.1.1 Mainta i ning the primary containment OPERABLE requires compliance with the visual examinations and l eakage rate test requirements of the Primary Containment Leakage Rate Testing Program. Failu r e to meet air lock leakage test i ng (SR 3.6.1.2.1 ), secondary containment bypass leakage (SR 3.6.1.3.10), or main steam isolation valve leakage (SR 3.6.1.3.11) does not necessarily result in a failure of this SR. The impact of the failure to meet these SRs must be evaluated against the Type A , B , and C acceptance c r iteria of the Primary Conta in ment Leakage Rate Testing Program. The Primary Containment Leakage Rate Testing Program is based on the guidelines in Regulatory Gu i ao 1.163 (Ref. 6), NEI 94 01 (Ref. 7), ane 56.8 1994 (Ref. 8). Specific acceptance criteria for as found and as left leakage rates , as well as the methods of defining t h e leakage rates , are contained in the Primary Containment Leakage Rate Testing Program. At all other times between requi r ed leakage rate te s ts , the acceptance criteria are based on an overall Type A leakage l imit of 1.0 L a. At 1.0 L a. the o ff site dose consequences are bounded by the assumptions of the safety analysis. The Frequency is required by the Primary Containment Leakage Rate Tes ti ng Program. NEI 94-01 Revision 3-A (Ref. 7), the Limitations and Conditions of NEI 94-01 Revision 2-A (Ref.6), and ANSI/ _ANS 56.8-2002 HATCH UNIT 2 (continued) B 3.6-3 REVISION 7-BASES SURVEILLANCE REQUIREMENTS (continued) | ||
REFERENCES SR 3.6.1.1.2 Primary Containment B 3.6.1.1 Maintaining the pressure suppression function of primary containment requires limiting the leakage from the drywall to the suppression chamber. Thus, if an event were to occur that pressurized the drywell, the steam would be directed through the downcomers into the suppression poo l. This SR measures drywell to suppression chamber differential pressure during a 10 minute period to ensure that the leakage paths that would bypass the suppression pool are within allowab l e limits. Satisfactory performance of this SR can be achieved by establishing a known differential pressure between the drywall and the suppression chamber and verifying that the pressure in either the suppression chamber or the drywell does not change by more than 0.25 inch of water per minute over a 10 minute period. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. 1. FSAR, Section 6.2. 2. FSAR, Section 15.1.39. 3. 10 CFR 50 , Appendix J , Option 8. 4. NRC No. 93-102 , "Final Policy Statement on Technica l Specification Improvements | REFERENCES SR 3.6.1.1.2 Primary Containment B 3.6.1.1 Maintaining the pressure suppression function of primary containment requires limiting the leakage from the drywall to the suppression chamber. Thus, if an event were to occur that pressurized the drywell, the steam would be directed through the downcomers into the suppression poo l. This SR measures drywell to suppression chamber differential pressure during a 10 minute period to ensure that the leakage paths that would bypass the suppression pool are within allowab l e limits. Satisfactory performance of this SR can be achieved by establishing a known differential pressure between the drywall and the suppression chamber and verifying that the pressure in either the suppression chamber or the drywell does not change by more than 0.25 inch of water per minute over a 10 minute period. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. 1. FSAR, Section 6.2. 2. FSAR, Section 15.1.39. 3. 10 CFR 50 , Appendix J , Option 8. 4. NRC No. 93-102 , "Final Policy Statement on Technica l Specification Improvements | ||
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===1.0 PURPOSE=== | ===1.0 PURPOSE=== | ||
OF ANALYSIS 1.1 PURPOSE The purpose of this analysis is to provide an assessment of the risk associated with extending , the currently allowed containment Type A integrated leak rate test (ILRT) interval to a permanent fifteen yearsC 1 l for Hatch Units 1 & 2. The extension would allow for substantial cost savings as the ILRT could be deferred for additional scheduled refueling outages. The risk assessment follows the guidelines from NEI 94-01 [1], the methodology used in EPRI TR-104285 [2], the NE! "Interim Guidance for Performing Risk Impact Assessments In Support of One-Time Extensions for Containment Integrated Leakage Rate Test Surveillance Intervals" [3, 21], the NRC regulatory guidance on the use of Probabilistic Risk Assessment (PRA) as stated in Regulatory Guide 1.200 [28] as applied to ILRT interval extensions, and risk insights in support of a request for a plant's licensing basis as outlined in Regulatory Guide (RG) 1.174 [4], the methodology used for Calvert Cliffs to estimate the likelihood and risk implications of corrosion-induced leakage of steel liners going undetected during the extended test interval [19], and the methodology used in EPRI TR-1009325, Revision 2-A [22] for performing a risk impact assessment of extended integrated leak rate testing intervals. | OF ANALYSIS 1.1 PURPOSE The purpose of this analysis is to provide an assessment of the risk associated with extending , the currently allowed containment Type A integrated leak rate test (ILRT) interval to a permanent fifteen yearsC 1 l for Hatch Units 1 & 2. The extension would allow for substantial cost savings as the ILRT could be deferred for additional scheduled refueling outages. The risk assessment follows the guidelines from NEI 94-01 [1], the methodology used in EPRI TR-104285 [2], the NE! "Interim Guidance for Performing Risk Impact Assessments In Support of One-Time Extensions for Containment Integrated Leakage Rate Test Surveillance Intervals" [3, 21], the NRC regulatory guidance on the use of Probabilistic Risk Assessment (PRA) as stated in Regulatory Guide 1.200 [28] as applied to ILRT interval extensions, and risk insights in support of a request for a plant's licensing basis as outlined in Regulatory Guide (RG) 1.174 [4], the methodology used for Calvert Cliffs to estimate the likelihood and risk implications of corrosion-induced leakage of steel liners going undetected during the extended test interval [19], and the methodology used in EPRI TR-1009325, Revision 2-A [22] for performing a risk impact assessment of extended integrated leak rate testing intervals. | ||
The EPRI TR-1009325 Revision 2-A methodology incorporates the specific limitations and conditions outlined in the NRC acceptance of the EPRI TR-1009325 Revision 2 methodology documented in the NRC Final Safety Evaluation | The EPRI TR-1009325 Revision 2-A methodology incorporates the specific limitations and conditions outlined in the NRC acceptance of the EPRI TR-1009325 Revision 2 methodology documented in the NRC Final Safety Evaluation | ||
[32]. The format of this document is consistent with the intent of the Risk Impact Assessment Template for evaluating extended integrated leak rate testing intervals provided in Appendix H of the EPRI methodology report [22]. | [32]. The format of this document is consistent with the intent of the Risk Impact Assessment Template for evaluating extended integrated leak rate testing intervals provided in Appendix H of the EPRI methodology report [22]. | ||
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Revisions to lOCFRSO, Appendix J (Option B) allow individual plants to extend the Integrated Leak Rate Test (ILRT) Type A surveillance testing frequency requirements from three-in-ten years to at least once in ten years. The revised Type A frequency is based on an acceptable performance history defined as two consecutive periodic Type A tests at least 24 months apart in which the calculated performance leakage was less than limiting containment leakage rate of 1.0La (allowable leakage). | Revisions to lOCFRSO, Appendix J (Option B) allow individual plants to extend the Integrated Leak Rate Test (ILRT) Type A surveillance testing frequency requirements from three-in-ten years to at least once in ten years. The revised Type A frequency is based on an acceptable performance history defined as two consecutive periodic Type A tests at least 24 months apart in which the calculated performance leakage was less than limiting containment leakage rate of 1.0La (allowable leakage). | ||
Cll The ILRT risk assessment is to be used to support a request to a 1 in 15 year ILRT test frequency on a permanent basis. The risk assessment methodology and results equally support a request to extend the ILRT test frequency to 1 in 15 years on a one time basis, as has been performed by many utilities. | Cll The ILRT risk assessment is to be used to support a request to a 1 in 15 year ILRT test frequency on a permanent basis. The risk assessment methodology and results equally support a request to extend the ILRT test frequency to 1 in 15 years on a one time basis, as has been performed by many utilities. | ||
1-1 The basis for a 10-year test interval is provided in Section 11.0 of NEI 94-01, Revision O, and was established in 1995 during development of the performance-based Option B to Appendix J. Section 11.0 of NEI 94-01 states that NUREG-1493 | 1-1 The basis for a 10-year test interval is provided in Section 11.0 of NEI 94-01, Revision O, and was established in 1995 during development of the performance-based Option B to Appendix J. Section 11.0 of NEI 94-01 states that NUREG-1493 | ||
[5], "Performance-Based Containment Leak Test Program," September 1995, provides the technical basis to support rulemaking to revise leakage rate testing requirements contained in Option B to Appendix J. The basis consisted of qualitative and quantitative assessments of the risk impact (in terms of increased public dose) associated with a range of extended leakage rate test intervals. | [5], "Performance-Based Containment Leak Test Program," September 1995, provides the technical basis to support rulemaking to revise leakage rate testing requirements contained in Option B to Appendix J. The basis consisted of qualitative and quantitative assessments of the risk impact (in terms of increased public dose) associated with a range of extended leakage rate test intervals. | ||
To supplement the NRC's rulemaking basis, NEI undertook a similar study. The results of that study are documented in Electric Power Research Institute (EPRI) Research Project Report TR-104285 | To supplement the NRC's rulemaking basis, NEI undertook a similar study. The results of that study are documented in Electric Power Research Institute (EPRI) Research Project Report TR-104285 | ||
[2]. The NRC report on performance-based leak testing, NUREG-1493, analyzed the effects of containment leakage on the health and safety of the public and the benefits realized from the containment leak rate testing. In that analysis, it was determined that for a representative PWR plant (i.e., Surry) containment isolation failures contribute less than 0.1 percent to the latent risks from reactor accidents. | [2]. The NRC report on performance-based leak testing, NUREG-1493, analyzed the effects of containment leakage on the health and safety of the public and the benefits realized from the containment leak rate testing. In that analysis, it was determined that for a representative PWR plant (i.e., Surry) containment isolation failures contribute less than 0.1 percent to the latent risks from reactor accidents. | ||
Consequently, it is desirable to show that extending the ILRT interval will not lead to a substantial increase in risk from containment isolation failures for the Hatch plants. Earlier ILRT frequency extension submittals have used the EPRI TR-104285 | Consequently, it is desirable to show that extending the ILRT interval will not lead to a substantial increase in risk from containment isolation failures for the Hatch plants. Earlier ILRT frequency extension submittals have used the EPRI TR-104285 | ||
[2] methodology to perform the risk assessment. | [2] methodology to perform the risk assessment. | ||
In October 2008, EPRI TR-1018243 | In October 2008, EPRI TR-1018243 | ||
[22] was issued to update the generic methodology for ILRT extensions to 15 years using current performance data and to incorporate the specific limitations and conditions outlined by the NRC in the final safety evaluation of the methodology | [22] was issued to update the generic methodology for ILRT extensions to 15 years using current performance data and to incorporate the specific limitations and conditions outlined by the NRC in the final safety evaluation of the methodology | ||
[32]. This more recent EPRI document considers additional risk metric? an_d criteria including 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 population dose. Hatch requested a one-time extension of the ILRT test frequency from 1 in 10 years to 1 in 15 years for Unit 1 [23] and Unit 2 [24]. The NRC approved the one-time extensions for both Unit 1 [33] and Unit 2 [34]. It should be noted that containment leak-tight integrity is also verified through periodic inservice inspections conducted in accordance with the requirements of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code Section XI. More specifically, 1-2 Subsection IWE provides the rules and requirements for inservice inspection of Class MC pressure-retaining components and their integral attachments, and of metallic shell and penetration liners of Class CC pressure-retaining components and their integral attachments in light-water cooled plants. Furthermore, NRC regulations 10 CFR 50.55a(b)(2)(ix)(E) require licensees to conduct visual inspections of the accessible areas of the interior of the containment. | [32]. This more recent EPRI document considers additional risk metric? an_d criteria including 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 population dose. Hatch requested a one-time extension of the ILRT test frequency from 1 in 10 years to 1 in 15 years for Unit 1 [23] and Unit 2 [24]. The NRC approved the one-time extensions for both Unit 1 [33] and Unit 2 [34]. It should be noted that containment leak-tight integrity is also verified through periodic inservice inspections conducted in accordance with the requirements of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code Section XI. More specifically, 1-2 Subsection IWE provides the rules and requirements for inservice inspection of Class MC pressure-retaining components and their integral attachments, and of metallic shell and penetration liners of Class CC pressure-retaining components and their integral attachments in light-water cooled plants. Furthermore, NRC regulations 10 CFR 50.55a(b)(2)(ix)(E) require licensees to conduct visual inspections of the accessible areas of the interior of the containment. | ||
In addition, Appendix J, Type B local leak tests performed to verify the leak-tight integrity of containment penetration bellows, airlocks, seals, and gaskets are also not affected by the change to the Type A test frequency. | In addition, Appendix J, Type B local leak tests performed to verify the leak-tight integrity of containment penetration bellows, airlocks, seals, and gaskets are also not affected by the change to the Type A test frequency. | ||
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In context, it is noted that a CCFP of 1/10 (10%) has been approved for application to evolutionary light water designs. Given these perspectives, a change in the CCFP of up to 1.5% (percentage point) is assumed to be small. This criterion is articulated in the NRC Final Safety Evaluation Report [32] associated with NEI 94-01 and the EPRI ILRT methodology. | In context, it is noted that a CCFP of 1/10 (10%) has been approved for application to evolutionary light water designs. Given these perspectives, a change in the CCFP of up to 1.5% (percentage point) is assumed to be small. This criterion is articulated in the NRC Final Safety Evaluation Report [32] associated with NEI 94-01 and the EPRI ILRT methodology. | ||
1-3 In addition, the total annual risk (person rem/yr population dose) is examined to demonstrate both the relative change and absolute change in this parameter. | 1-3 In addition, the total annual risk (person rem/yr population dose) is examined to demonstrate both the relative change and absolute change in this parameter. | ||
Examinations of NUREG-1493 and Safety Evaluation Reports (SER) for one-time interval extensions (summarized in Appendix G of EPRI 1018243 [22]) indicate a range of incremental increases in population dose that have been accepted by the NRcC 1>. The range of incremental population dose increases is from <= 0.01 to 0.2 person-rem/yr and/or 0.002 to 0.46% of the total accident dose. The total doses for the spectrum of all accidents (NUREG-1493 | Examinations of NUREG-1493 and Safety Evaluation Reports (SER) for one-time interval extensions (summarized in Appendix G of EPRI 1018243 [22]) indicate a range of incremental increases in population dose that have been accepted by the NRcC 1>. The range of incremental population dose increases is from <= 0.01 to 0.2 person-rem/yr and/or 0.002 to 0.46% of the total accident dose. The total doses for the spectrum of all accidents (NUREG-1493 | ||
[5], Figure 7-2) result in health effects that are at least two orders of magnitude less than the NRC Safety Goal risk. Given these perspectives, a very small population dose is defined as an increase from the baseline interval (3 tests per 10 years) dose of <= 1.0 person-rem/yr or 1 % of the total baseline dose, whichever is less restrictive for the risk impact assessment of the proposed extended ILRT interval. | [5], Figure 7-2) result in health effects that are at least two orders of magnitude less than the NRC Safety Goal risk. Given these perspectives, a very small population dose is defined as an increase from the baseline interval (3 tests per 10 years) dose of <= 1.0 person-rem/yr or 1 % of the total baseline dose, whichever is less restrictive for the risk impact assessment of the proposed extended ILRT interval. | ||
This criterion is articulated in the NRC Final Safety Evaluation Report [32] associated with NEI 94-01 and the EPRI ILRT methodology. | This criterion is articulated in the NRC Final Safety Evaluation Report [32] associated with NEI 94-01 and the EPRI ILRT methodology. | ||
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===2.0 METHODOLOGY=== | ===2.0 METHODOLOGY=== | ||
A simplified bounding analysis approach consistent with the latest EPRI approach [22] as accepted by the NRC [32] is used for evaluating the change in risk associated with increasing the test interval to fifteen years. The approach is consistent with that presented in EPRI TR-1018243 | A simplified bounding analysis approach consistent with the latest EPRI approach [22] as accepted by the NRC [32] is used for evaluating the change in risk associated with increasing the test interval to fifteen years. The approach is consistent with that presented in EPRI TR-1018243 | ||
[22], NUREG-1493 | [22], NUREG-1493 | ||
[5] and the Calvert Cliffs liner corrosion analysis [19]. The analysis uses results from a Level 2 analysis of core damage scenarios from the current Hatch Unit 1 PRA model and the subsequent containment responses for the various fission product release categories (including containment intact release). | [5] and the Calvert Cliffs liner corrosion analysis [19]. The analysis uses results from a Level 2 analysis of core damage scenarios from the current Hatch Unit 1 PRA model and the subsequent containment responses for the various fission product release categories (including containment intact release). | ||
This risk assessment is applicable to Hatch Units 1 & 2 because Unit 2 can be adequately represented by Unit 1 PRA results (see Section 4.2). The six general steps of this assessment are as follows: 1. Quantify the baseline risk in terms of the frequency of events (per reactor year) for each of the eight containment release scenario types identified in the EPRI report. 2. Develop plant-specific person-rem (population dose) per reactor year for each of the eight containment release scenario types from plant specific consequence analyses. | This risk assessment is applicable to Hatch Units 1 & 2 because Unit 2 can be adequately represented by Unit 1 PRA results (see Section 4.2). The six general steps of this assessment are as follows: 1. Quantify the baseline risk in terms of the frequency of events (per reactor year) for each of the eight containment release scenario types identified in the EPRI report. 2. Develop plant-specific person-rem (population dose) per reactor year for each of the eight containment release scenario types from plant specific consequence analyses. | ||
: 3. Evaluate the risk impact (i.e. the change in containment release scenario type frequency and population dose) of extending the ILRT interval to fifteen years. 4. Determine the change in risk in terms of Large Early Release Frequency (LERF) in accordance with RG 1.174 [4] and compare this change with the acceptance guidelines of RG 1.174. 5. Determine the impact on the Conditional Containment Failure Probability (CCFP) 6. Evaluate the sensitivity of the results to assumptions in the corrosion analysis, external events, and to the probability of undetected leaks from containment (due to corrosion breach) to LERF. This approach is based on the information and approaches contained in the previously mentioned studies. Furthermore, | : 3. Evaluate the risk impact (i.e. the change in containment release scenario type frequency and population dose) of extending the ILRT interval to fifteen years. 4. Determine the change in risk in terms of Large Early Release Frequency (LERF) in accordance with RG 1.174 [4] and compare this change with the acceptance guidelines of RG 1.174. 5. Determine the impact on the Conditional Containment Failure Probability (CCFP) 6. Evaluate the sensitivity of the results to assumptions in the corrosion analysis, external events, and to the probability of undetected leaks from containment (due to corrosion breach) to LERF. This approach is based on the information and approaches contained in the previously mentioned studies. Furthermore, | ||
* Consistent with the other industry containment leak risk assessments, the Hatch assessment uses LERF and delta LERF in accordance with the risk acceptance guidance of RG 1.174. Changes in population dose and conditional containment failure probability (CCFP) are also considered to show that defense-in-depth and the balance of prevention and mitigation is preserved. | * Consistent with the other industry containment leak risk assessments, the Hatch assessment uses LERF and delta LERF in accordance with the risk acceptance guidance of RG 1.174. Changes in population dose and conditional containment failure probability (CCFP) are also considered to show that defense-in-depth and the balance of prevention and mitigation is preserved. | ||
* This evaluation uses ground rules and methods to calculate changes in risk metrics that are consistent with those in the EPRI methodology | * This evaluation uses ground rules and methods to calculate changes in risk metrics that are consistent with those in the EPRI methodology | ||
[22]. 2-1 | [22]. 2-1 | ||
* The EPRI methodology | * The EPRI methodology | ||
[22] specifies that emergency core cooling system (ECCS) net positive suction head (NPSH) requirements be assessed regarding whether containment over pressure is credited in the design basis ECCS analysis, and if containment over pressure is credited, the potential impacts on the core damage frequency (CDF). As documented in Section 6.3.3.9 of the Hatch FSAR [36], containment over pressure is not required or credited for Unit 2 for either short term (i.e., < 10 minutes following LOCA initiation) or long term Residual Heat Removal (RHR) pump or Core Spray (CS) pump operation. | [22] specifies that emergency core cooling system (ECCS) net positive suction head (NPSH) requirements be assessed regarding whether containment over pressure is credited in the design basis ECCS analysis, and if containment over pressure is credited, the potential impacts on the core damage frequency (CDF). As documented in Section 6.3.3.9 of the Hatch FSAR [36], containment over pressure is not required or credited for Unit 2 for either short term (i.e., < 10 minutes following LOCA initiation) or long term Residual Heat Removal (RHR) pump or Core Spray (CS) pump operation. | ||
For Unit 1, the design basis calcu.lations indicate that 3.24 psig (7.5 ft) of containment over pressure is required to ensure adequate NPSH to the RHR pumps, and 3.2 psig (7.4 ft) of containment over pressure is required to ensure adequate NPSH to the CS pumps (at the peak calculated suppression pool temperature of 211.3 °F) for a period from about 2.5 hours to 20 hours after LOCA initiation. | For Unit 1, the design basis calcu.lations indicate that 3.24 psig (7.5 ft) of containment over pressure is required to ensure adequate NPSH to the RHR pumps, and 3.2 psig (7.4 ft) of containment over pressure is required to ensure adequate NPSH to the CS pumps (at the peak calculated suppression pool temperature of 211.3 °F) for a period from about 2.5 hours to 20 hours after LOCA initiation. | ||
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* Plant specific dose calculations for containment intact cases are not available from the Hatch SAMA analysis. | * Plant specific dose calculations for containment intact cases are not available from the Hatch SAMA analysis. | ||
NUREG-1150 results for such cases are adequately representative for use in the Hatch analysis based on scaling the NUREG-1150 results to account for differences in regional population, power level, and allowed technical specification leakage. | NUREG-1150 results for such cases are adequately representative for use in the Hatch analysis based on scaling the NUREG-1150 results to account for differences in regional population, power level, and allowed technical specification leakage. | ||
* Accident classes describing radionuclide release end states are defined consistent with the EPRI methodology | * Accident classes describing radionuclide release end states are defined consistent with the EPRI methodology | ||
[22], as summarized in Section 4.2. | [22], as summarized in Section 4.2. | ||
* The representative containment leakage for Class 1 sequences is 1La. Class 3 accounts for increased leakage due to Type A inspection failures. | * The representative containment leakage for Class 1 sequences is 1La. Class 3 accounts for increased leakage due to Type A inspection failures. | ||
* The representative containment leakage for Class 3a sequences is 10La, based on the previously approved methodology performed for Indian Point Unit 3 [6, 7]. | * The representative containment leakage for Class 3a sequences is 10La, based on the previously approved methodology performed for Indian Point Unit 3 [6, 7]. | ||
* The representative containment leakage for Class 3b sequences is 100La, based on the NRC SER [32] and incorporated in the latest EPRI report [22]. Note that most of the previous one-time ILRT extension requests utilized 35La. 3-1 | * The representative containment leakage for Class 3b sequences is 100La, based on the NRC SER [32] and incorporated in the latest EPRI report [22]. Note that most of the previous one-time ILRT extension requests utilized 35La. 3-1 | ||
* The Class 3b can be very conservatively categorized as LERF based on the previously approved methodology | * The Class 3b can be very conservatively categorized as LERF based on the previously approved methodology | ||
[6, 7]. The Class 3b category increase is used as a surrogate for LERF in this application even though the releases associated with a 100La release would not necessarily be consistent with a "Large" release for Hatch. * * * | [6, 7]. The Class 3b category increase is used as a surrogate for LERF in this application even though the releases associated with a 100La release would not necessarily be consistent with a "Large" release for Hatch. * * * | ||
* The impact on population doses from containment bypass scenarios is not altered by the proposed ILRT extension. | * The impact on population doses from containment bypass scenarios is not altered by the proposed ILRT extension. | ||
Rather it is accounted for in the EPRI methodology as a separate entry for comparison purposes, as accepted in the NRC SER [32]. Because the containment bypass contribution to population dose is fixed, no changes to the conclusions from this analysis will result from this separate categorization. | Rather it is accounted for in the EPRI methodology as a separate entry for comparison purposes, as accepted in the NRC SER [32]. Because the containment bypass contribution to population dose is fixed, no changes to the conclusions from this analysis will result from this separate categorization. | ||
The reduction in ILRT frequency does not impact the reliability of containment isolation valves to close in response to a containment isolation signal. Consideration of the risk impact of the ILRT on shutdown risk is addressed in Section 6 using the generic results from EPRI TR-105189 | The reduction in ILRT frequency does not impact the reliability of containment isolation valves to close in response to a containment isolation signal. Consideration of the risk impact of the ILRT on shutdown risk is addressed in Section 6 using the generic results from EPRI TR-105189 | ||
[8]. The ILRT analysis evaluates very small changes in the risk metrics. To facilitate the calculation of these changes and the evaluation of sensitivity cases, the calculations are performed in a spreadsheet. | [8]. The ILRT analysis evaluates very small changes in the risk metrics. To facilitate the calculation of these changes and the evaluation of sensitivity cases, the calculations are performed in a spreadsheet. | ||
In general, the calculations provided in this report reproduce the calculation results of the spreadsheets. | In general, the calculations provided in this report reproduce the calculation results of the spreadsheets. | ||
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===4.0 INPUTS=== | ===4.0 INPUTS=== | ||
This section summarizes the general resources available as input (Section 4.1) and the plant specific resources required (Section 4.2). 4.1 GENERAL RESOURCES AVAILABLE Various industry studies on containment leakage risk assessment are briefly summarized here: 1. NUREG/CR-3539 | This section summarizes the general resources available as input (Section 4.1) and the plant specific resources required (Section 4.2). 4.1 GENERAL RESOURCES AVAILABLE Various industry studies on containment leakage risk assessment are briefly summarized here: 1. NUREG/CR-3539 | ||
[10] 2. NU REG/CR-4220 | [10] 2. NU REG/CR-4220 | ||
[11] 3. NUREG-1273 | [11] 3. NUREG-1273 | ||
[12] 4. NUREG/CR-4330 | [12] 4. NUREG/CR-4330 | ||
[13] 5. EPRI TR-105189 | [13] 5. EPRI TR-105189 | ||
[8] 6. NUREG-1493 | [8] 6. NUREG-1493 | ||
[5] 7. EPRI TR-104285 | [5] 7. EPRI TR-104285 | ||
[2] 8. NUREG-1150 | [2] 8. NUREG-1150 | ||
[14] and NUREG/CR-4551 | [14] and NUREG/CR-4551 | ||
[26] 9. NEI Interim Guidance [3, 21] 10. Calvert Cliffs liner corrosion analysis [19] 11. NRC SER [32] on EPRI TR-1009325 | [26] 9. NEI Interim Guidance [3, 21] 10. Calvert Cliffs liner corrosion analysis [19] 11. NRC SER [32] on EPRI TR-1009325 | ||
: 12. EPRI 1018243 [22] The first study is applicable because it provides one basis for the threshold could be used in the Level 2 PRA for the size of containment leakage that is considered significant and to be included in the model. The second study is applicable because it provides a basis of the probability for significant pre-existing containment leakage at the time of a core damage accident. | : 12. EPRI 1018243 [22] The first study is applicable because it provides one basis for the threshold could be used in the Level 2 PRA for the size of containment leakage that is considered significant and to be included in the model. The second study is applicable because it provides a basis of the probability for significant pre-existing containment leakage at the time of a core damage accident. | ||
The third study is applicable because it is a subsequent study to NUREG/CR-4220 that undertook a more extensive evaluation of the same database. | The third study is applicable because it is a subsequent study to NUREG/CR-4220 that undertook a more extensive evaluation of the same database. | ||
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The tenth study addresses the impact of age-related degradation of the containment steel on ILRT evaluations. | The tenth study addresses the impact of age-related degradation of the containment steel on ILRT evaluations. | ||
The eleventh study [32] documents the NRC Final Safety Evaluation of the EPRI 2007 version of ILRT risk assessment guidance (i.e., EPRI TR-1009325, Revision 2). The last study by EPRI complements the previous EPRI report [2], integrates the NEI interim guidance and NRC SER limitations and conditions, and provides a recommended methodology and template for evaluating the risk associated with a permanent 15-year ILRT interval. | The eleventh study [32] documents the NRC Final Safety Evaluation of the EPRI 2007 version of ILRT risk assessment guidance (i.e., EPRI TR-1009325, Revision 2). The last study by EPRI complements the previous EPRI report [2], integrates the NEI interim guidance and NRC SER limitations and conditions, and provides a recommended methodology and template for evaluating the risk associated with a permanent 15-year ILRT interval. | ||
NUREG/CR-3539 | NUREG/CR-3539 | ||
[10] Oak Ridge National Laboratory (ORNL) documented a study of the impact of containment leak rates on public risk in NUREG/CR-3539. | [10] Oak Ridge National Laboratory (ORNL) documented a study of the impact of containment leak rates on public risk in NUREG/CR-3539. | ||
This study uses information from WASH-1400 | This study uses information from WASH-1400 | ||
[15] as the basis for its risk sensitivity calculations. | [15] as the basis for its risk sensitivity calculations. | ||
ORNL concluded that the impact of leakage rates on LWR accident risks is relatively small. NUREG/CR-4220 | ORNL concluded that the impact of leakage rates on LWR accident risks is relatively small. NUREG/CR-4220 | ||
[11] NUREG/CR-4220 is a study performed by Pacific Northwest Laboratories for the NRC in 1985. The study reviewed over two thousand LERs, ILRT reports and other related records to calculate the unavailability of containment due to leakage. It assessed the "large" containment leak probability to be in the range of lE-3 to lE-2, with 5E-3 identified as the point estimate based on 4 events in 740 reactor years and conservatively assuming a one-year duration for each event. NUREG-1273 | [11] NUREG/CR-4220 is a study performed by Pacific Northwest Laboratories for the NRC in 1985. The study reviewed over two thousand LERs, ILRT reports and other related records to calculate the unavailability of containment due to leakage. It assessed the "large" containment leak probability to be in the range of lE-3 to lE-2, with 5E-3 identified as the point estimate based on 4 events in 740 reactor years and conservatively assuming a one-year duration for each event. NUREG-1273 | ||
[12] A subsequent NRC study, NUREG-1273, performed a more extensive evaluation of the NUREG/CR-4220 database. | [12] A subsequent NRC study, NUREG-1273, performed a more extensive evaluation of the NUREG/CR-4220 database. | ||
This assessment noted that about one-third of the reported events were leakages that were immediately detected and corrected. | This assessment noted that about one-third of the reported events were leakages that were immediately detected and corrected. | ||
In addition, this study noted that local leak rate tests can detect "essentially all potential degradations" of the containment isolation system. 4-2 NUREG/CR-4330 | In addition, this study noted that local leak rate tests can detect "essentially all potential degradations" of the containment isolation system. 4-2 NUREG/CR-4330 | ||
[131 NUREG/CR-4330 is a study that examined the risk impacts associated with increasing the allowable containment leakage rates. The details of this report have no direct impact on the modeling approach of the ILRT test interval extension, as NUREG/CR-4330 focuses on leakage rate and the ILRT test interval extension study focuses on the frequency of testing intervals. | [131 NUREG/CR-4330 is a study that examined the risk impacts associated with increasing the allowable containment leakage rates. The details of this report have no direct impact on the modeling approach of the ILRT test interval extension, as NUREG/CR-4330 focuses on leakage rate and the ILRT test interval extension study focuses on the frequency of testing intervals. | ||
However, the general conclusions of NUREG/CR-4330 are consistent with NUREG/CR-3539 and other similar containment leakage risk studies: " ... the effect of containment leakage on overall accident risk is small since risk is dominated by accident sequences that result in failure or bypass of containment." EPRI TR-105189 | However, the general conclusions of NUREG/CR-4330 are consistent with NUREG/CR-3539 and other similar containment leakage risk studies: " ... the effect of containment leakage on overall accident risk is small since risk is dominated by accident sequences that result in failure or bypass of containment." EPRI TR-105189 | ||
[81 The EPRI study TR-105189 is useful to the ILRT test interval extension risk assessment because this EPRI study provides insight regarding the impact of containment testing on shutdown risk. This study performed a quantitative evaluation (using the EPRI ORAM for two reference plants (a BWR-4 and a PWR) of the impact of extending ILRT and LLRT test intervals on shutdown risk. The result of the study concluded that a small but measurable safety benefit (shutdown CDF reduced by lE-8/yr to lE-7/yr) is realized from extending the test intervals from 3 per 10 years to 1 per 10 years. NUREG-1493 | [81 The EPRI study TR-105189 is useful to the ILRT test interval extension risk assessment because this EPRI study provides insight regarding the impact of containment testing on shutdown risk. This study performed a quantitative evaluation (using the EPRI ORAM for two reference plants (a BWR-4 and a PWR) of the impact of extending ILRT and LLRT test intervals on shutdown risk. The result of the study concluded that a small but measurable safety benefit (shutdown CDF reduced by lE-8/yr to lE-7/yr) is realized from extending the test intervals from 3 per 10 years to 1 per 10 years. NUREG-1493 | ||
[5] NUREG-1493 is the NRC's cost-benefit analysis for proposed alternatives to reduce containment leakage testing intervals and/or relax allowable leakage rates. conclusions are consistent with other similar containment leakage risk studies: The NRC | [5] NUREG-1493 is the NRC's cost-benefit analysis for proposed alternatives to reduce containment leakage testing intervals and/or relax allowable leakage rates. conclusions are consistent with other similar containment leakage risk studies: The NRC | ||
* Reduction in ILRT frequency from 3 per 10 years to 1 per 20 years results in an "imperceptible" increase in risk. | * Reduction in ILRT frequency from 3 per 10 years to 1 per 20 years results in an "imperceptible" increase in risk. | ||
* Given the insensitivity of risk to the containment leak rate and the small fraction of leak paths detected solely by Type A testing, increasing the interval between integrated leak rate tests is possible with minimal impact on public risk. EPRI TR-104285 | * Given the insensitivity of risk to the containment leak rate and the small fraction of leak paths detected solely by Type A testing, increasing the interval between integrated leak rate tests is possible with minimal impact on public risk. EPRI TR-104285 | ||
[2] Extending the risk assessment impact beyond shutdown (the earlier EPRI TR-105189 study), the EPRI TR-104285 study is a quantitative evaluation of the impact of extending ILRT and LLRT test intervals on at-power public risk. This study combined IPE Level 2 models with 4-3 NUREG-1150 | [2] Extending the risk assessment impact beyond shutdown (the earlier EPRI TR-105189 study), the EPRI TR-104285 study is a quantitative evaluation of the impact of extending ILRT and LLRT test intervals on at-power public risk. This study combined IPE Level 2 models with 4-3 NUREG-1150 | ||
[14] Level 3 population dose models to perform the analysis. | [14] Level 3 population dose models to perform the analysis. | ||
The study also used the approach of NUREG-1493 in calculating the increase in pre-existing leakage probability due to extending the ILRT and LLRT test intervals. | The study also used the approach of NUREG-1493 in calculating the increase in pre-existing leakage probability due to extending the ILRT and LLRT test intervals. | ||
EPRI TR-104285 used a simplified Containment Event Tree to subdivide representative core damage sequences into eight categories of containment response to a core damage accident: | EPRI TR-104285 used a simplified Containment Event Tree to subdivide representative core damage sequences into eight categories of containment response to a core damage accident: | ||
: 1. Containment intact and isolated 2. Containment isolation failures dependent upon the core damage accident 3. Type A (ILRT) related containment isolation failures 4. Type B (LLRT) related containment isolation failures 5. Type C (LLRT) related containment isolation failures 6. Other penetration related containment isolation failures 7. Containment failure due to core damage accident phenomena | : 1. Containment intact and isolated 2. Containment isolation failures dependent upon the core damage accident 3. Type A (ILRT) related containment isolation failures 4. Type B (LLRT) related containment isolation failures 5. Type C (LLRT) related containment isolation failures 6. Other penetration related containment isolation failures 7. Containment failure due to core damage accident phenomena | ||
: 8. Containment bypass Consistent with the other containment leakage risk assessment studies, this study concluded: "These study results show that the proposed CLRT [containment leak rate tests] frequency changes would have a minimal safety impact. The change in risk determined by the analyses is small in both absolute and relative terms. For example, for the PWR analyzed, the change is about 0.02 person-rem per year ... " NUREG-1150 | : 8. Containment bypass Consistent with the other containment leakage risk assessment studies, this study concluded: "These study results show that the proposed CLRT [containment leak rate tests] frequency changes would have a minimal safety impact. The change in risk determined by the analyses is small in both absolute and relative terms. For example, for the PWR analyzed, the change is about 0.02 person-rem per year ... " NUREG-1150 | ||
[14] and NUREG/CR-4551 | [14] and NUREG/CR-4551 | ||
[26] NUREG-1150 | [26] NUREG-1150 | ||
[14] and the technical basis, NUREG/CR-4551 | [14] and the technical basis, NUREG/CR-4551 | ||
[26], provide an ex-plant consequence analysis for a spectrum of accidents including a severe accident with the containment remaining intact (i.e., Tech Spec leakage). | [26], provide an ex-plant consequence analysis for a spectrum of accidents including a severe accident with the containment remaining intact (i.e., Tech Spec leakage). | ||
This ex-plant consequence calculation is calculated for the SO-mile radial area surrounding Peach Bottom. The ex-plant consequence calculation for the containment remaining intact represents a very small contributor to the overall risk spectrum. | This ex-plant consequence calculation is calculated for the SO-mile radial area surrounding Peach Bottom. The ex-plant consequence calculation for the containment remaining intact represents a very small contributor to the overall risk spectrum. | ||
Because it is a small contributor, this ex-plant calculation (i.e., total person-rem) is considered adequate to represent Hatch if population, reactor power, and the Technical Specification leakage are scaled to represent Hatch. (The meteorology and other site differences are assumed not to play a significant role in this evaluation). | Because it is a small contributor, this ex-plant calculation (i.e., total person-rem) is considered adequate to represent Hatch if population, reactor power, and the Technical Specification leakage are scaled to represent Hatch. (The meteorology and other site differences are assumed not to play a significant role in this evaluation). | ||
4-4 NEI Interim Guidance [3, 211 NEI "Interim Guidance for Performing Risk Impact Assessments in Support of One-Time Extensions of Containment Integrated Leakage Rate Test Surveillance Intervals" [3] was developed to provide utilities with revised guidance regarding licensing submittals. | 4-4 NEI Interim Guidance [3, 211 NEI "Interim Guidance for Performing Risk Impact Assessments in Support of One-Time Extensions of Containment Integrated Leakage Rate Test Surveillance Intervals" [3] was developed to provide utilities with revised guidance regarding licensing submittals. | ||
Additional information from NEI on the "Interim Guidance" was supplied in Reference | Additional information from NEI on the "Interim Guidance" was supplied in Reference | ||
[21]. A nine step process is defined which includes changes in the following areas of the previous EPRI guidance: | [21]. A nine step process is defined which includes changes in the following areas of the previous EPRI guidance: | ||
* Impact of extending surveillance intervals on dose | * Impact of extending surveillance intervals on dose | ||
* Method used to calculate the frequencies of leakages detectable only by ILRTs | * Method used to calculate the frequencies of leakages detectable only by ILRTs | ||
* Provisions for using NUREG-1150 dose calculations to support the population dose determination. | * Provisions for using NUREG-1150 dose calculations to support the population dose determination. | ||
The guidance provided in this document builds on the EPRI risk impact assessment methodology | The guidance provided in this document builds on the EPRI risk impact assessment methodology | ||
[2] and the NRC performance-based containment leakage test program [5], and considers approaches utilized in various submittals, including Indian Point 3 (and associated NRC SER) [6,7] and Crystal River [20]. Calvert Cliffs Liner Corrosion Analysis [19] This submittal to the NRC describes a method for determining the change in likelihood, due to extending the ILRT, of detecting liner corrosion, and the corresponding change in risk. The methodology was developed for Calvert Cliffs in response to a request for additional information regarding how the potential leakage due to age-related degradation mechanisms were factored into the risk assessment for the ILRT one-time extension. | [2] and the NRC performance-based containment leakage test program [5], and considers approaches utilized in various submittals, including Indian Point 3 (and associated NRC SER) [6,7] and Crystal River [20]. Calvert Cliffs Liner Corrosion Analysis [19] This submittal to the NRC describes a method for determining the change in likelihood, due to extending the ILRT, of detecting liner corrosion, and the corresponding change in risk. The methodology was developed for Calvert Cliffs in response to a request for additional information regarding how the potential leakage due to age-related degradation mechanisms were factored into the risk assessment for the ILRT one-time extension. | ||
The Calvert Cliffs analysis was performed for a concrete cylinder and dome and a concrete basemat, each with a steel liner. Licensees may consider approved LARs for one-time extensions involving containment types similar to their facility. | The Calvert Cliffs analysis was performed for a concrete cylinder and dome and a concrete basemat, each with a steel liner. Licensees may consider approved LARs for one-time extensions involving containment types similar to their facility. | ||
The Hatch assessment has addressed the specific differences from the Calvert Cliffs design, and the Calvert Cliffs methodology was adapted to address the specific design features. | The Hatch assessment has addressed the specific differences from the Calvert Cliffs design, and the Calvert Cliffs methodology was adapted to address the specific design features. | ||
4-5 NRC SER on ILRT Risk Assessment | 4-5 NRC SER on ILRT Risk Assessment | ||
[32] This report documents the NRC review and acceptance of the EPRI ILRT Risk Assessment methodology of EPRI TR-1009325 Revision 2. Based on the NRC review, four conditions and limitations were identified, summarized here as: 1. Licensees must submit documentation supporting appropriate technical adequacy of the PRA. 2. Acceptance criteria for population dose risk and CCFP were revised. 3. Assumed leakage for EPRI Class 3b is revised from 35La to lOOLa. 4. A license amendment request (LAR) is required in instances where containment over pressure is relied upon for ECCS performance. | [32] This report documents the NRC review and acceptance of the EPRI ILRT Risk Assessment methodology of EPRI TR-1009325 Revision 2. Based on the NRC review, four conditions and limitations were identified, summarized here as: 1. Licensees must submit documentation supporting appropriate technical adequacy of the PRA. 2. Acceptance criteria for population dose risk and CCFP were revised. 3. Assumed leakage for EPRI Class 3b is revised from 35La to lOOLa. 4. A license amendment request (LAR) is required in instances where containment over pressure is relied upon for ECCS performance. | ||
EPRI TR-1018243 | EPRI TR-1018243 | ||
[221 (EPRI TR-1009325 Revision 2-A) This report presents a generally applicable assessment of risk involved in extension of ILRT test intervals to 15 years on a permanent basis. Appendix H of this document provides guidance for performing plant-specific supplemental risk impact assessments and builds on the previous EPRI risk impact assessment methodology TR-104285 | [221 (EPRI TR-1009325 Revision 2-A) This report presents a generally applicable assessment of risk involved in extension of ILRT test intervals to 15 years on a permanent basis. Appendix H of this document provides guidance for performing plant-specific supplemental risk impact assessments and builds on the previous EPRI risk impact assessment methodology TR-104285 | ||
[2], the NEI Interim Guidance [3,21], and the NRC performance-based containment leakage test program [5], and considers approaches utilized in various submittals, including Indian Point 3 (and associated NRC SER) [6,7] and Crystal River [20]. The EPRI report codifies minor changes to the ILRT methodology specified by the NRC in the NRC ILRT risk assessment approach SER [32]. The approach included in this EPRI guidance document is used in the Hatch assessment to determine the estimated increase in risk associated with the ILRT extension. | [2], the NEI Interim Guidance [3,21], and the NRC performance-based containment leakage test program [5], and considers approaches utilized in various submittals, including Indian Point 3 (and associated NRC SER) [6,7] and Crystal River [20]. The EPRI report codifies minor changes to the ILRT methodology specified by the NRC in the NRC ILRT risk assessment approach SER [32]. The approach included in this EPRI guidance document is used in the Hatch assessment to determine the estimated increase in risk associated with the ILRT extension. | ||
This document includes the bases for the values assigned in determining the probability of leakage for the EPRI Class 3a and 3b scenarios in this analysis as described in Section 5. 4.2 PLANT-SPECIFIC INPUTS The Hatch specific information used to perform this ILRT interval extension risk assessment includes the following: | This document includes the bases for the values assigned in determining the probability of leakage for the EPRI Class 3a and 3b scenarios in this analysis as described in Section 5. 4.2 PLANT-SPECIFIC INPUTS The Hatch specific information used to perform this ILRT interval extension risk assessment includes the following: | ||
| Line 1,944: | Line 1,944: | ||
* Population Dose within a 50-mile radius [9, 29, 30] | * Population Dose within a 50-mile radius [9, 29, 30] | ||
* ILRT results to demonstrate adequacy of the administrative and hardware interfaces 4-6 Hatch Internal Events Level 1 PRA Model The Unit 1 Internal Events Level 1 PRA model [16] is an event tree / linked fault tree model characteristic of the as-built, as-operated plant. This Level 1 PRA model incorporates the resolution of findings associated with the PRA Peer Review of 2009. The total internal events core damage frequency (CDF) used in this analysis is 7.57E-06/yrC | * ILRT results to demonstrate adequacy of the administrative and hardware interfaces 4-6 Hatch Internal Events Level 1 PRA Model The Unit 1 Internal Events Level 1 PRA model [16] is an event tree / linked fault tree model characteristic of the as-built, as-operated plant. This Level 1 PRA model incorporates the resolution of findings associated with the PRA Peer Review of 2009. The total internal events core damage frequency (CDF) used in this analysis is 7.57E-06/yrC | ||
: 1) (at lE-12/yr truncation) for Unit 1, as reflected in the combined Unit 1Level1 and Level 2 PRA models [17]. (For reference, it is noted that the CDF for the Unit 2 model is 7.42E-06/yr | : 1) (at lE-12/yr truncation) for Unit 1, as reflected in the combined Unit 1Level1 and Level 2 PRA models [17]. (For reference, it is noted that the CDF for the Unit 2 model is 7.42E-06/yr | ||
[39], approximately 1.5% less than the Unit 1 CDF. The Unit 1 model is adequately representative of Unit 2 for the purposes of the ILRT risk assessment.) | [39], approximately 1.5% less than the Unit 1 CDF. The Unit 1 model is adequately representative of Unit 2 for the purposes of the ILRT risk assessment.) | ||
Hatch Internal Events Level 2 PRA Model The Unit 1 Level 2 PRA model [17] was developed to calculate the LERF contribution as well as the other release categories evaluated in the model. This Level 2 PRA model incorporates the resolution of findings associated with the PRA Peer Review of 2009. Table 4.2-la summarizes the pertinent Hatch Unit 1 Level 2 results in terms of end states. The total Large Early Release Frequency (LERF) in Table 4.2-la for Unit 1 is 1.12E-6/yr. | Hatch Internal Events Level 2 PRA Model The Unit 1 Level 2 PRA model [17] was developed to calculate the LERF contribution as well as the other release categories evaluated in the model. This Level 2 PRA model incorporates the resolution of findings associated with the PRA Peer Review of 2009. Table 4.2-la summarizes the pertinent Hatch Unit 1 Level 2 results in terms of end states. The total Large Early Release Frequency (LERF) in Table 4.2-la for Unit 1 is 1.12E-6/yr. | ||
The Unit 2 model LERF value is 1.03E-06/yr | The Unit 2 model LERF value is 1.03E-06/yr | ||
[31], approximately 8% less than the Unit 1 LERF. The lower Unit 2 LERF value is primarily attributed to a plant design difference. | [31], approximately 8% less than the Unit 1 LERF. The lower Unit 2 LERF value is primarily attributed to a plant design difference. | ||
The Unit 2 feedwater injection lines have an additional check valve which lowers the break outside containment (BOC) contribution to LERF for Unit 2. This design difference does not impact the risk assessment because the ILRT interval does not impact the BOC LERF contribution. | The Unit 2 feedwater injection lines have an additional check valve which lowers the break outside containment (BOC) contribution to LERF for Unit 2. This design difference does not impact the risk assessment because the ILRT interval does not impact the BOC LERF contribution. | ||
Cl) The Unit 1 Level 1 CDF value of 7.57E-06/yr used in the Levei 2 evaiuation | Cl) The Unit 1 Level 1 CDF value of 7.57E-06/yr used in the Levei 2 evaiuation | ||
[17] is slightly higher than the Level 1 CDF value of 7.53E-06/yr from the latest version of the Hatch Unit 1 Internal Events Level 1 PRA model [16]. To support the Level 2 quantification, Level 1 sequences are binned into accident classes. However, this separate quantification of the individual accident classes may result in duplicate or non-minimal cutsets to be binned into more than one accident class. This may result in the numerical sum of all individual accident classes to be higher than the CDF if all the cutsets were merged together. | [17] is slightly higher than the Level 1 CDF value of 7.53E-06/yr from the latest version of the Hatch Unit 1 Internal Events Level 1 PRA model [16]. To support the Level 2 quantification, Level 1 sequences are binned into accident classes. However, this separate quantification of the individual accident classes may result in duplicate or non-minimal cutsets to be binned into more than one accident class. This may result in the numerical sum of all individual accident classes to be higher than the CDF if all the cutsets were merged together. | ||
However, the apparent deviation of the Level 1 CDF quantified for the Level 2 model is less than 1 % and is judged not to significantly alter the results. 4-7 The Level 2 release category end states are defined [38] as follows: Release Magnitude High Moderate/Medium Low Low-Low Release Timing Early Intermediate Late CsI Release Fraction > 10% 1% to 10% 0.1% to 1% < 0.1% Time (hrs) <5 5 to 24 > 24 Table 4.2-lb summarizes the core damage frequency contributions by the PRA accident class. 4-8 Table 4.2-la HATCH LEVEL 2 DETAILED RELEASE CATEGORIESC 1> RELEASE FREQUENCY CATEGORY DEFINITION | However, the apparent deviation of the Level 1 CDF quantified for the Level 2 model is less than 1 % and is judged not to significantly alter the results. 4-7 The Level 2 release category end states are defined [38] as follows: Release Magnitude High Moderate/Medium Low Low-Low Release Timing Early Intermediate Late CsI Release Fraction > 10% 1% to 10% 0.1% to 1% < 0.1% Time (hrs) <5 5 to 24 > 24 Table 4.2-lb summarizes the core damage frequency contributions by the PRA accident class. 4-8 Table 4.2-la HATCH LEVEL 2 DETAILED RELEASE CATEGORIESC 1> RELEASE FREQUENCY CATEGORY DEFINITION | ||
(/YR) (1) INTACT Containment remains intact. 1.18E-06 H-E High-early release (i.e., LERF). Dominant accident class 1.12E-06 contributors are as follows: | (/YR) (1) INTACT Containment remains intact. 1.18E-06 H-E High-early release (i.e., LERF). Dominant accident class 1.12E-06 contributors are as follows: | ||
* Class 1A (loss of RPV injection, RPV at high pressure): | * Class 1A (loss of RPV injection, RPV at high pressure): | ||
| Line 1,965: | Line 1,965: | ||
LL-I Low Low-intermediate release. Dominant accident class 1.0SE-08 contributor is Class 1D at 1.02E-08/yr. | LL-I Low Low-intermediate release. Dominant accident class 1.0SE-08 contributor is Class 1D at 1.02E-08/yr. | ||
LL-L Low Low-late release. Dominant accident class contributor is 4.63E-09 Class 1A at 4.86E-09/yr. | LL-L Low Low-late release. Dominant accident class contributor is 4.63E-09 Class 1A at 4.86E-09/yr. | ||
Total Total Release Category Frequency (No Intact) 6.40E-06 Total Total CDF 7.SSE-06 From Table 5 of Reference | Total Total Release Category Frequency (No Intact) 6.40E-06 Total Total CDF 7.SSE-06 From Table 5 of Reference | ||
[17] for Unit 1. The High-Late release category had zero frequency and is therefore not listed. 4-9 Table 4.2-lb HATCH CDF CONTRIBUTIONS BY PRA ACCIDENT CLAssC 1> PRA FREQUENCY ACCIDENT (/YR) CLASS DESCRIPTION IA Transients | [17] for Unit 1. The High-Late release category had zero frequency and is therefore not listed. 4-9 Table 4.2-lb HATCH CDF CONTRIBUTIONS BY PRA ACCIDENT CLAssC 1> PRA FREQUENCY ACCIDENT (/YR) CLASS DESCRIPTION IA Transients | ||
-core melt with vessel at high pressure 1.07E-06 IBE Station blackout -early 1.18E-08 IBL Station blackout -late 4.89E-07 IC with loss of injection | -core melt with vessel at high pressure 1.07E-06 IBE Station blackout -early 1.18E-08 IBL Station blackout -late 4.89E-07 IC with loss of injection | ||
: 1. 73E-07 ID lrransients | : 1. 73E-07 ID lrransients | ||
-core melt with vessel at low pressure 1.35E-06 IIA Core melt after containment failure due to loss of DHR 3.39E-06 Ill Core melt after containment failure due to loss of DHR and 4.11E-10 LOCA IIIB LOCA -core melt with vessel remaining at high pressure 1.SOE-08 me LOCA -core melt with vessel at low pressure 2.75E-09 IV | -core melt with vessel at low pressure 1.35E-06 IIA Core melt after containment failure due to loss of DHR 3.39E-06 Ill Core melt after containment failure due to loss of DHR and 4.11E-10 LOCA IIIB LOCA -core melt with vessel remaining at high pressure 1.SOE-08 me LOCA -core melt with vessel at low pressure 2.75E-09 IV | ||
-containment fails before core damage 3.SSE-07 v LOCA outside containment 7.12E-07 Total Total CDF 7.57E-06 (1) From Table 5 of Reference | -containment fails before core damage 3.SSE-07 v LOCA outside containment 7.12E-07 Total Total CDF 7.57E-06 (1) From Table 5 of Reference | ||
[17] for Unit 1. 4-10 Population Dose Conditional population dose results for containment failure end states are available for Hatch based on the Hatch SAMA evaluation performed for Units 1 & 2 and submitted to the NRC in 2000 [9], and subsequent responses to Requests for Additional Information (RAis) [29, 30]. Conditional population dose results for an intact containment end state (not quantified for the SAMA analysis) are available via ex-plant consequence results for Peach Bottom [26] and can be scaled to represent Hatch. The Hatch specific and Peach Bottom surrogate conditional population dose results may be combined with the most recent Hatch Level 2 analysis results [17] to develop population dose risk for use in the ILRT assessment. | [17] for Unit 1. 4-10 Population Dose Conditional population dose results for containment failure end states are available for Hatch based on the Hatch SAMA evaluation performed for Units 1 & 2 and submitted to the NRC in 2000 [9], and subsequent responses to Requests for Additional Information (RAis) [29, 30]. Conditional population dose results for an intact containment end state (not quantified for the SAMA analysis) are available via ex-plant consequence results for Peach Bottom [26] and can be scaled to represent Hatch. The Hatch specific and Peach Bottom surrogate conditional population dose results may be combined with the most recent Hatch Level 2 analysis results [17] to develop population dose risk for use in the ILRT assessment. | ||
The SAMA dose analysis utilized the projected population to year 2030 (i.e., 498,834 people in the 50 mile radial region) and a Hatch power level of 2,763 MWth. The population projection is adequately representative for use in the ILRT assessment. | The SAMA dose analysis utilized the projected population to year 2030 (i.e., 498,834 people in the 50 mile radial region) and a Hatch power level of 2,763 MWth. The population projection is adequately representative for use in the ILRT assessment. | ||
The Hatch power level used in the SAMA analysis is slightly less than the current and anticipated Hatch power level in the future, which is 2,804 MWth. The SAMA dose values may be scaled for use in the ILRT analysis by applying a reactor power level scaling factor of 1.015 (i.e., 2,804 MWth / 2,763 MWth). The Hatch SAMA population dose results are presented in Table 4.2-2. These dose results are based on MACCS2 calculations and accident sequence frequencies applicable at the time. Included in Table 4.2-2 is a column presenting the ILRT assessment dose values after applying the reactor power level scaling factor. It is noted that the release categories represented in the Hatch SAMA analysis all represent high magnitude releases. | The Hatch power level used in the SAMA analysis is slightly less than the current and anticipated Hatch power level in the future, which is 2,804 MWth. The SAMA dose values may be scaled for use in the ILRT analysis by applying a reactor power level scaling factor of 1.015 (i.e., 2,804 MWth / 2,763 MWth). The Hatch SAMA population dose results are presented in Table 4.2-2. These dose results are based on MACCS2 calculations and accident sequence frequencies applicable at the time. Included in Table 4.2-2 is a column presenting the ILRT assessment dose values after applying the reactor power level scaling factor. It is noted that the release categories represented in the Hatch SAMA analysis all represent high magnitude releases. | ||
Doses associated with large releases from containment failure can be conservatively represented by this data. The population dose associated with an intact containment (Technical Specification leakage) case can be estimated based on scaling the NUREG/CR-4551 dose results for Peach Bottom from Accident Progression Bin (APB) #8 (Core is damaged, Vessel is breached, no containment failure)C 1 l. The Peach Bottom dose for APB #8 is not specifically identified in NUREG/CR-4551, but can be back-calculated to be 4,940 person-rem as presented in Table 4.2-3. (lJ APB #8 is described in more detail in NUREG/CR-4551 | Doses associated with large releases from containment failure can be conservatively represented by this data. The population dose associated with an intact containment (Technical Specification leakage) case can be estimated based on scaling the NUREG/CR-4551 dose results for Peach Bottom from Accident Progression Bin (APB) #8 (Core is damaged, Vessel is breached, no containment failure)C 1 l. The Peach Bottom dose for APB #8 is not specifically identified in NUREG/CR-4551, but can be back-calculated to be 4,940 person-rem as presented in Table 4.2-3. (lJ APB #8 is described in more detail in NUREG/CR-4551 | ||
[26] Section 2.4.3. 4-11 The APB #8 person-rem result can be used as an approximation of the dose for Hatch if it is scaled for regional population, reactor power level, and allowable containment leakage rate (La). Values for these attributes for Peach Bottom (as evaluated in NUREG/CR-4551) and Hatch are summarized in Table 4.2-4, where the applicable scaling factors are calculated. | [26] Section 2.4.3. 4-11 The APB #8 person-rem result can be used as an approximation of the dose for Hatch if it is scaled for regional population, reactor power level, and allowable containment leakage rate (La). Values for these attributes for Peach Bottom (as evaluated in NUREG/CR-4551) and Hatch are summarized in Table 4.2-4, where the applicable scaling factors are calculated. | ||
Applying the calculated scaling factors, the population dose for Hatch for an intact containment technical specification release is 1,150 pers-rem (i.e, 4,940 pers-rem | Applying the calculated scaling factors, the population dose for Hatch for an intact containment technical specification release is 1,150 pers-rem (i.e, 4,940 pers-rem | ||
| Line 1,981: | Line 1,981: | ||
* 2.4 = 1,150 pers-rem). | * 2.4 = 1,150 pers-rem). | ||
Table 4.2-5 presents the current Hatch Level 2 release frequencies, the assigned dose for the category, and the calculated annual dose risk. The annual dose risk calculated in Table 4.2-5 is not directly used in the ILRT assessment since the EPRI methodology utilizes a different release category scheme, but is presented for completeness. | Table 4.2-5 presents the current Hatch Level 2 release frequencies, the assigned dose for the category, and the calculated annual dose risk. The annual dose risk calculated in Table 4.2-5 is not directly used in the ILRT assessment since the EPRI methodology utilizes a different release category scheme, but is presented for completeness. | ||
EPRI Release Category Definitions Table 4.2-6 defines the accident classes used in the ILRT extension evaluation, which are consistent with the EPRI methodology | EPRI Release Category Definitions Table 4.2-6 defines the accident classes used in the ILRT extension evaluation, which are consistent with the EPRI methodology | ||
[22]. These containment failure classifications are used in this analysis to determine the risk impact of extending the Containment Type A test interval as described in Section 5 of this report. Hatch ILRT Results The surveillance frequency for Type A testing in NE! 94-01 under option B criteria is at least once per ten years based on an acceptable performance history (i.e. two consecutive periodic Type A tests at lec:ist 24 months apart where the calculated performance leakage rate was less than 1.0 La) and consideration of the performance factors in NEI 94-01, Section 11.3. Based on completion of two successful ILRTs at Hatch Unit 1 and Unit 2, the ILRT interval became once per ten years. Subsequently, a one time ILRT interval frequency of once per fifteen years was approved for both Hatch Unit 1 and Unit 2 [33, 34] based on demonstrating acceptable risk impacts. Each Hatch unit has successfully completed another ILRT (i.e., Unit 1 in March 2008, Unit 2 in March 2009) since these one time ILRT interval extension approvals. | [22]. These containment failure classifications are used in this analysis to determine the risk impact of extending the Containment Type A test interval as described in Section 5 of this report. Hatch ILRT Results The surveillance frequency for Type A testing in NE! 94-01 under option B criteria is at least once per ten years based on an acceptable performance history (i.e. two consecutive periodic Type A tests at lec:ist 24 months apart where the calculated performance leakage rate was less than 1.0 La) and consideration of the performance factors in NEI 94-01, Section 11.3. Based on completion of two successful ILRTs at Hatch Unit 1 and Unit 2, the ILRT interval became once per ten years. Subsequently, a one time ILRT interval frequency of once per fifteen years was approved for both Hatch Unit 1 and Unit 2 [33, 34] based on demonstrating acceptable risk impacts. Each Hatch unit has successfully completed another ILRT (i.e., Unit 1 in March 2008, Unit 2 in March 2009) since these one time ILRT interval extension approvals. | ||
4-12 Table 4.2-2 | 4-12 Table 4.2-2 | ||
| Line 1,988: | Line 1,988: | ||
OF SAMA MACCS2 CALCULATIONS AND ILRT SCALED VALUES SAMA Frequency SAMA Dose Level 2 End State Seq# Sequence Description (per yr) <10> (Person-Rem) | OF SAMA MACCS2 CALCULATIONS AND ILRT SCALED VALUES SAMA Frequency SAMA Dose Level 2 End State Seq# Sequence Description (per yr) <10> (Person-Rem) | ||
Containment Bypass 5 BOC 1.66E-7C 6 l 1.15E+6C 2 l Early Cont. Failure 2 SBO 1.79E-6<6 l 1.06E+6<3 l 4 Loss of Cont. Heat 7.43E-7<6 l 1.02E+6<4 l Removal (CHR) 11 ATWS 7.43E-7C 6 l 7.02E+5<5 l Late Cont. Failure 12 High pressure transient 2.0E-7<1 l 5.7E+5 with loss of CH R 14 SBO with cont. isolation 3.1E-9(ll failure Intact Cont. (DW Vent) 15 High pressure transient 9.24E-10C 6 l 1.13E+6C 9 l with venting No Containment Failure NA NA NA NAC 7 l NA <1 l SAMA RAI response to Q#4 [29]. C 2 l SAMA RAI response to Q#14; Sequence #5 [29] clarification provided to NRC by SNC [30]. C 3 l SAMA RAI response to Q#l4; Sequence #2 [29]. <4 l SAMA RAI response to Q#14; Sequence #4 [29]. <5 l SAMA RAI response to Q#l4; Sequence #11 [29]. (GJ SAMA RAI response to Q#l.b-1 [29]. C 7 l Not calculated for SAMA. csi SAMA RAI clarification provided by SNC to Question #5 [30]. <9 l SAMA RAI response to Q#l4; Sequence 15 [29]. Adjusted Dose for ILRT Assessment (Person-Rem) | Containment Bypass 5 BOC 1.66E-7C 6 l 1.15E+6C 2 l Early Cont. Failure 2 SBO 1.79E-6<6 l 1.06E+6<3 l 4 Loss of Cont. Heat 7.43E-7<6 l 1.02E+6<4 l Removal (CHR) 11 ATWS 7.43E-7C 6 l 7.02E+5<5 l Late Cont. Failure 12 High pressure transient 2.0E-7<1 l 5.7E+5 with loss of CH R 14 SBO with cont. isolation 3.1E-9(ll failure Intact Cont. (DW Vent) 15 High pressure transient 9.24E-10C 6 l 1.13E+6C 9 l with venting No Containment Failure NA NA NA NAC 7 l NA <1 l SAMA RAI response to Q#4 [29]. C 2 l SAMA RAI response to Q#14; Sequence #5 [29] clarification provided to NRC by SNC [30]. C 3 l SAMA RAI response to Q#l4; Sequence #2 [29]. <4 l SAMA RAI response to Q#14; Sequence #4 [29]. <5 l SAMA RAI response to Q#l4; Sequence #11 [29]. (GJ SAMA RAI response to Q#l.b-1 [29]. C 7 l Not calculated for SAMA. csi SAMA RAI clarification provided by SNC to Question #5 [30]. <9 l SAMA RAI response to Q#l4; Sequence 15 [29]. Adjusted Dose for ILRT Assessment (Person-Rem) | ||
<11> 1.17E+6 1.08E+6 1.04E+6 7.13E+5 5.8E+5 1.15E+6 NA TOTAL SAMA Annual Risk (Person-Rem/Yr) | <11> 1.17E+6 1.08E+6 1.04E+6 7.13E+5 5.8E+5 1.15E+6 NA TOTAL SAMA Annual Risk (Person-Rem/Yr) | ||
[29, 30] 0.19 1.90 0.76 0.52 3.18 total 0.ll2(B) 0.0008 0.001 NAC 7 l 3.48 <10 l It is noted that the Hatch PRA model tias been updated since the SAMA analysis and the accident sequence frequencies and the Table 4.2-3 PEACH BOTTOM APB #8 SO-MILE POPULATION DOSE CALCULATIONC 1> ALL APBS APB #8 SO-MILE APB #8 SO-APB #8 CONTRIBUTION DOSE RISK MILE DOSE APB #8 50-FREQUENCY TO SO-MILE (PERS-RISK (PERS-MILE DOSE (/YR) DOSE RISK REM/YR) REM/YR) (PERS-REM) 7.99E-7C 2) 5E-4C 3 l 7_9C 4 l 3.95E-3C 5 l 4.94E+3C 6 l Cll NUREG/CR-4551 | [29, 30] 0.19 1.90 0.76 0.52 3.18 total 0.ll2(B) 0.0008 0.001 NAC 7 l 3.48 <10 l It is noted that the Hatch PRA model tias been updated since the SAMA analysis and the accident sequence frequencies and the Table 4.2-3 PEACH BOTTOM APB #8 SO-MILE POPULATION DOSE CALCULATIONC 1> ALL APBS APB #8 SO-MILE APB #8 SO-APB #8 CONTRIBUTION DOSE RISK MILE DOSE APB #8 50-FREQUENCY TO SO-MILE (PERS-RISK (PERS-MILE DOSE (/YR) DOSE RISK REM/YR) REM/YR) (PERS-REM) 7.99E-7C 2) 5E-4C 3 l 7_9C 4 l 3.95E-3C 5 l 4.94E+3C 6 l Cll NUREG/CR-4551 | ||
[26] does not document dose results as a function of accident progression bin as such, the dose result for APB #8 is back calculated from the documented APB frequency and dose risk results. <2> From Figure 2.5-6 of NUREG/CR-4551 Vol. 4, Rev. 1, Part 1. Frequency for APB #8 of 7.99E-7/yr is calculated as 0.184 contribution of 4.34E-6/yr CDF. <3 l From Table 5.2-3 for the mean fractional contribution to risk (MFCR) of NUREG/CR-4551 Vol. 4, Rev. 1, Part 1. <4 J From Table 5.1-1 for mean value 50-mile population dose of NUREG/CR-4551 Vol. 4, Rev. 1, Part 1. <5 J APB dose risk is calculated by multiplying the APB dose risk fractional contribution (column 2) by the total 50-mile radius dose risk of 7.9 person-rem/yr (column 3). (GJ Calculated by dividing the APB #8 dose risk (column 4) by the APB #8 frequency (column 1) Table 4.2-4 HATCH APB-#8 DOSE SCALING FACTORS Reactor SO-mile Power TS Leakage Plant Population (MWth) (wt 0/o/day) Hatch 498.834(!) | [26] does not document dose results as a function of accident progression bin as such, the dose result for APB #8 is back calculated from the documented APB frequency and dose risk results. <2> From Figure 2.5-6 of NUREG/CR-4551 Vol. 4, Rev. 1, Part 1. Frequency for APB #8 of 7.99E-7/yr is calculated as 0.184 contribution of 4.34E-6/yr CDF. <3 l From Table 5.2-3 for the mean fractional contribution to risk (MFCR) of NUREG/CR-4551 Vol. 4, Rev. 1, Part 1. <4 J From Table 5.1-1 for mean value 50-mile population dose of NUREG/CR-4551 Vol. 4, Rev. 1, Part 1. <5 J APB dose risk is calculated by multiplying the APB dose risk fractional contribution (column 2) by the total 50-mile radius dose risk of 7.9 person-rem/yr (column 3). (GJ Calculated by dividing the APB #8 dose risk (column 4) by the APB #8 frequency (column 1) Table 4.2-4 HATCH APB-#8 DOSE SCALING FACTORS Reactor SO-mile Power TS Leakage Plant Population (MWth) (wt 0/o/day) Hatch 498.834(!) | ||
2 804(2) 1.2% C 2> Peach Bottom 4,359,67-?(3) 3,293C 4 l 0.5%(S) Scaling Factor 0.114 0.852 2.4 <1> Hatch SAMA year 2030 population | 2 804(2) 1.2% C 2> Peach Bottom 4,359,67-?(3) 3,293C 4 l 0.5%(S) Scaling Factor 0.114 0.852 2.4 <1> Hatch SAMA year 2030 population | ||
[9] <2> Hatch current and anticipated future value. <3 J NUREG/CR-4551, Vol. 2, Rev. 1, Part 7, Appendix A.3 (SITE MACCS2 File) for Peach Bottom. Population total for 50-mile radius developed in Appendix A of this report. <4 J NUREG/CR-4551, Vol. 4, Rev. 1, Part 2, Section A.3.1. <5 l NUREG/CR-4551, Vol. 4, Rev. 1, Part 2, page B.2-9 for no containment failure. 4-14 Table 4.2-5 HATCH POPULATION DOSE RISK AT 50 MILES RELEASE POPULATION DOSE CATEGORY 2030 POPULATION RISK RELEASE FREQUENCIES ASSIGNED DOSE DOSE ASSIGNMENT (PERSON-REM/YR) | [9] <2> Hatch current and anticipated future value. <3 J NUREG/CR-4551, Vol. 2, Rev. 1, Part 7, Appendix A.3 (SITE MACCS2 File) for Peach Bottom. Population total for 50-mile radius developed in Appendix A of this report. <4 J NUREG/CR-4551, Vol. 4, Rev. 1, Part 2, Section A.3.1. <5 l NUREG/CR-4551, Vol. 4, Rev. 1, Part 2, page B.2-9 for no containment failure. 4-14 Table 4.2-5 HATCH POPULATION DOSE RISK AT 50 MILES RELEASE POPULATION DOSE CATEGORY 2030 POPULATION RISK RELEASE FREQUENCIES ASSIGNED DOSE DOSE ASSIGNMENT (PERSON-REM/YR) | ||
CATEGORY (PER YEAR) (PERSON-REM)C 1> BASIS (2) INTACT H-E H-1 M-E M-1 M-L L-E L-1 L-L LL-E LL-I LL-L Total (1) (2) (3) (4) 1.18E-06 1.15E+03 Peach Bottom 1.35E-03 1.12E-06 1.17E+06 Hatch SAMA BOC 1.31 E+OO 2.83E-06 5.80E+05 Hatch SAMA late CF 1.64E+OO 1.19E-06 5.80E+05 Hatch SAMA late CF (SJ. 6.90E-01 9.64E-07 5.80E+05 Hatch SAMA late CF(3 l 5.59E-01 4.64E-08 5.80E+05 Hatch SAMA late CF(3 l 2.69E-02 1.01 E-08 5.80E+05 Hatch SAMA late CF (4 l 5.86E-03 9.56E-08 5.80E+05 Hatch SAMA late CF(4 l 5.54E-02 6.94E-09 5.80E+05 Hatch SAMA late CF(4 l 4.03E-03 1.33E-07 5.80E+05 Hatch SAMA late CF(4 l 7.71 E-02 1.0SE-08 5.80E+05 Hatch SAMA late CF (4 l 6.09E-03 4.63E-09 5.80E+05 Hatch SAMA late CF(4 l 2.69E-03 7.58E-06 ----4.37E+OO Includes a scaling factor of 0.233 for application of the Peach Bottom dose results to the Intact Containment case, and includes a scaling factor of 1.015 for other release categories to account for a reactor power level increase since the Hatch SAMA analysis was performed. | CATEGORY (PER YEAR) (PERSON-REM)C 1> BASIS (2) INTACT H-E H-1 M-E M-1 M-L L-E L-1 L-L LL-E LL-I LL-L Total (1) (2) (3) (4) 1.18E-06 1.15E+03 Peach Bottom 1.35E-03 1.12E-06 1.17E+06 Hatch SAMA BOC 1.31 E+OO 2.83E-06 5.80E+05 Hatch SAMA late CF 1.64E+OO 1.19E-06 5.80E+05 Hatch SAMA late CF (SJ. 6.90E-01 9.64E-07 5.80E+05 Hatch SAMA late CF(3 l 5.59E-01 4.64E-08 5.80E+05 Hatch SAMA late CF(3 l 2.69E-02 1.01 E-08 5.80E+05 Hatch SAMA late CF (4 l 5.86E-03 9.56E-08 5.80E+05 Hatch SAMA late CF(4 l 5.54E-02 6.94E-09 5.80E+05 Hatch SAMA late CF(4 l 4.03E-03 1.33E-07 5.80E+05 Hatch SAMA late CF(4 l 7.71 E-02 1.0SE-08 5.80E+05 Hatch SAMA late CF (4 l 6.09E-03 4.63E-09 5.80E+05 Hatch SAMA late CF(4 l 2.69E-03 7.58E-06 ----4.37E+OO Includes a scaling factor of 0.233 for application of the Peach Bottom dose results to the Intact Containment case, and includes a scaling factor of 1.015 for other release categories to account for a reactor power level increase since the Hatch SAMA analysis was performed. | ||
| Line 1,998: | Line 1,998: | ||
a factor of two less than that for other high magnitude releases and is considered reasonable for use for medium magnitude release cases. This is comparable to SAMA population dose results developed for Quad Cities and Dresden Generating Stations [35] (both Mark I containment designs) where moderate magnitude releases had population dose results approximately one half to nearly equal to high magnitude release population doses. All Hatch SAMA dose cases represent high releases. | a factor of two less than that for other high magnitude releases and is considered reasonable for use for medium magnitude release cases. This is comparable to SAMA population dose results developed for Quad Cities and Dresden Generating Stations [35] (both Mark I containment designs) where moderate magnitude releases had population dose results approximately one half to nearly equal to high magnitude release population doses. All Hatch SAMA dose cases represent high releases. | ||
Use of the late containment failure for low and low-low magnitude release cases is acceptable because the associated frequencies for these release categories are low compared to other release categories. | Use of the late containment failure for low and low-low magnitude release cases is acceptable because the associated frequencies for these release categories are low compared to other release categories. | ||
The population dose associated with low or low-low releases compose less than 3% of the total as developed in this table. 4-15 Table 4.2-6 EPRI CONTAINMENT FAILURE CLASSIFICATIONS | The population dose associated with low or low-low releases compose less than 3% of the total as developed in this table. 4-15 Table 4.2-6 EPRI CONTAINMENT FAILURE CLASSIFICATIONS | ||
[22] CLASS DESCRIPTION 1 Containment remains intact including accident sequences that do not lead to containment failure in the long term. The release of fission products (and attendant consequences) is determined by the maximum allowable leakage rate values La, under Appendix J for that plant 2 Containment isolation failures (as reported in the IPEs) include those accidents in which there is a failure to isolate the containment. | [22] CLASS DESCRIPTION 1 Containment remains intact including accident sequences that do not lead to containment failure in the long term. The release of fission products (and attendant consequences) is determined by the maximum allowable leakage rate values La, under Appendix J for that plant 2 Containment isolation failures (as reported in the IPEs) include those accidents in which there is a failure to isolate the containment. | ||
3 Independent (or random) isolation failures include those accidents in which the pre-existing isolation failure to seal (i.e. provide a leak-tight containment) is not dependent on the sequence in progress. | 3 Independent (or random) isolation failures include those accidents in which the pre-existing isolation failure to seal (i.e. provide a leak-tight containment) is not dependent on the sequence in progress. | ||
| Line 2,036: | Line 2,036: | ||
* Consistent with the Calvert Cliffs analysis, a half failure is assumed for the drywell floor concealed steel corrosion due to the lack of identified failures. | * Consistent with the Calvert Cliffs analysis, a half failure is assumed for the drywell floor concealed steel corrosion due to the lack of identified failures. | ||
* The two corrosion events over a 5.5 year data period are used to estimate the steel liner flaw probability in the Calvert Cliffs analysis and are assumed to be applicable to the Hatch containment analysis. | * The two corrosion events over a 5.5 year data period are used to estimate the steel liner flaw probability in the Calvert Cliffs analysis and are assumed to be applicable to the Hatch containment analysis. | ||
These events, one at North Anna Unit 2 and one at Brunswick Unit 2 (Mark I containment design), were initiated from the non-visible (backside) portion of the containment liner. It is noted that two additional events have occurred in recent years (based on a data search covering approximately 9 years documented in Reference | These events, one at North Anna Unit 2 and one at Brunswick Unit 2 (Mark I containment design), were initiated from the non-visible (backside) portion of the containment liner. It is noted that two additional events have occurred in recent years (based on a data search covering approximately 9 years documented in Reference | ||
[27]). In November 2006, the Turkey Point 4 containment building liner developed a hole when a sump pump support plate was moved. In May 2009, a hole approximately 3/8" by 1" in size was identified in the Beaver Vaiiey 1 containment liner. For risk evaluation purposes, these two more recent events occurring over a 9 year period are judged to be adequately represented by the two events in the 5.5 year period of the Calvert Cliffs analysis incorporated in the EPRI guidance. | [27]). In November 2006, the Turkey Point 4 containment building liner developed a hole when a sump pump support plate was moved. In May 2009, a hole approximately 3/8" by 1" in size was identified in the Beaver Vaiiey 1 containment liner. For risk evaluation purposes, these two more recent events occurring over a 9 year period are judged to be adequately represented by the two events in the 5.5 year period of the Calvert Cliffs analysis incorporated in the EPRI guidance. | ||
4-19 | 4-19 | ||
| Line 2,051: | Line 2,051: | ||
This approach avoids a detailed analysis of containment failure timing and operator recovery actions. 4-20 Table 4.4-1 STEEL CONTAINMENT CORROSION BASE CASE STEP DESCRIPTION 1 Historical Steel Flaw Likelihood 2 3 4 Failure Data: Containment location specific (consistent with Calvert Cliffs analysis). | This approach avoids a detailed analysis of containment failure timing and operator recovery actions. 4-20 Table 4.4-1 STEEL CONTAINMENT CORROSION BASE CASE STEP DESCRIPTION 1 Historical Steel Flaw Likelihood 2 3 4 Failure Data: Containment location specific (consistent with Calvert Cliffs analysis). | ||
Age Adjusted Steel Flaw Likelihood During 15-year interval, assume failure rate doubles every five years (14.9% increase per year). The average for 5th to 10th year is set to the historical failure rate (consistent with Calvert Cliffs analysis). | Age Adjusted Steel Flaw Likelihood During 15-year interval, assume failure rate doubles every five years (14.9% increase per year). The average for 5th to 10th year is set to the historical failure rate (consistent with Calvert Cliffs analysis). | ||
Flaw Likelihood at 3, 10, and 15 years Uses age adjusted flaw likelihood (Step 2), assuming failure rate doubles every five years (consistent with Calvert Cliffs analysis -See Table 6 of Reference | Flaw Likelihood at 3, 10, and 15 years Uses age adjusted flaw likelihood (Step 2), assuming failure rate doubles every five years (consistent with Calvert Cliffs analysis -See Table 6 of Reference | ||
[19]). Likelihood of Breach in Containment Given Steel Flaw The failure probability of the DW walls, head, and torus is assumed to be 1% (compared to 1.1 % in the Calvert Cliffs analysis). | [19]). Likelihood of Breach in Containment Given Steel Flaw The failure probability of the DW walls, head, and torus is assumed to be 1% (compared to 1.1 % in the Calvert Cliffs analysis). | ||
The DW floor failure probability is assumed to be a factor of ten less, 0.1%, (compared to 0.11% in the Calvert Cliffs analysis). | The DW floor failure probability is assumed to be a factor of ten less, 0.1%, (compared to 0.11% in the Calvert Cliffs analysis). | ||
| Line 2,082: | Line 2,082: | ||
===5.0 RESULTS=== | ===5.0 RESULTS=== | ||
The application of the approach based on the guidance contained in EPRI TR-1018243 | The application of the approach based on the guidance contained in EPRI TR-1018243 | ||
[22], EPRI-TR-104285 | [22], EPRI-TR-104285 | ||
[2] and previous risk assessment submittals on this subject [6, 7, 19, 20, 23] have led to the following results. The results are displayed according to the eight accident classes defined in the EPRI report. Table 5.0-1 lists these accident classes. The analysis performed examined Hatch specific accident sequences in which the containment remains intact or the containment is impaired. | [2] and previous risk assessment submittals on this subject [6, 7, 19, 20, 23] have led to the following results. The results are displayed according to the eight accident classes defined in the EPRI report. Table 5.0-1 lists these accident classes. The analysis performed examined Hatch specific accident sequences in which the containment remains intact or the containment is impaired. | ||
Specifically, the break down of the severe accidents contributing to risk were considered in the following manner: | Specifically, the break down of the severe accidents contributing to risk were considered in the following manner: | ||
Revision as of 03:45, 27 April 2019
| ML16188A268 | |
| Person / Time | |
|---|---|
| Site: | Hatch  |
| Issue date: | 07/01/2016 |
| From: | Pierce C R Southern Nuclear Operating Co |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| NL-16-0626 | |
| Download: ML16188A268 (137) | |
Text
Charles R. Pierce Regulatory Affa.irs Director JUL O 1 201& Docket Nos.: 50-321 50-366 Southern Nuclear Operating Company, Inc. 40 Inverness Center Parkway Post Office Box 1295 Birmingham, AL 35242 Tel 205.992.7872 Fax 205.992.7601 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D.C. 20555-0001 Southern Nuclear Operating Company SOUTHERN NUCLEAR A SOUTHERN COMPANY NL-16-0626 Edwin I. Hatch Nuclear Plant Units 1 and 2; License Amendment Request to Revise Technical Specification Section 5.5.12 for Permanent Extension of Type A and Type C Leak Rate Test Frequencies Ladies and Gentlemen:
Pursuant to 1 O CFR 50.90, Southern Nuclear Operating Company (SNC) requests an amendment to the Edwin I. Hatch Nuclear Plant (HNP) Unit 1, Renewed Facility Operating License (DPR-57), and Unit 2, Renewed Facility Operating License (NPF-5), by incorporating the attached proposed change into the Unit 1 and Unit 2 Technical Specifications (TS). Specifically, the proposed change is a request to revise TS 5.5.12 "Primary Containment Leakage Rate Testing Program" to allow the following:
- Increase in the existing Type A integrated leakage rate test (ILRT) program test interval from 1 O years to 15 years in accordance with Nuclear Energy Institute (NEI) Topical Report NEI 94-01, Revision 3-A and the and limitations specified in NEI 94-01, Revision 2-A.
- Adopt an extension of the containment isolation valve (CIV) leakage testing (Type C) frequency from the 60 months currently permitted by 1 O CFR 50, Appendix J, 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.
- Adopt the use of American National Standards Institute/American Nuclear Society (ANSI/ANS) 56.8-2002, Containment System Leakage Testing Requirements.
- Adopt a more conservative grace interval of 9 months, for Type A, Type B and Type C leakage tests in accordance with NEI 94-01, Revision 3-A. The proposed change to the TS contained herein would revise HNP TS 5.5.12, by replacing the references to Regulatory Guide (RG) 1.163, Performance-Based Containment Leak-Test Program and 1 O CFR 50, Appendix J, Option B with a reference to NEI topical report NEI 94-01, Revision 3-A (Reference 2), dated July 2012, and the conditions and limitations specified in NEI 94-01, Revision 2-A U.S. Nuclear Regulatory Commission NL-16-0626 Page 2 dated October 2008, as the documents used by HNP to implement the performance-based leakage testing program in accordance with Option B of 1 O CFR 50, Appendix J. This license amendment request (LAA) also proposes the following administrative changes to TS 5.5.12:
- Deleting the information regarding the performance of the next HNP Unit 1 and Unit 2 Type A test to be performed no later than April 2008 for Unit 1 and no later than November 201 O for Unit 2, as both Type A tests have already occurred.
In addition, the Basis for TS Surveillance Requirement (SR) 3.6.1.1.1 is revised to incorporate the references to the NEI 94-01 documents and ANSI/ANS 56.8-2002, Containment System Leakage Testing Requirements.
The Bases changes are being provided for informational purposes only and will be implemented in accordance with the TS Bases Control Program based upon approval of this LAA. SNC requests approval within 12 months. The proposed changes will be implemented within six months of issuance of the amendment.
Enclosure 1 provides the evaluation of the proposed change and includes attachments with mark-ups and clean copies of the TS pages, mark-ups of TS Bases pages, and the risk assessment supporting the proposed amendment.
This letter contains no NRC commitments.
If you have any questions, please contact Ken McElroy at (205) 992-7369.
Mr. C. R. Pierce states he is the Regulatory Affairs Director for Southern Nuclear Operating Company, is authorized to execute this oath on behalf of Southern Nuclear Operating Company and, to the best of his knowledge and belief, the facts set forth in this letter are true. C. R. Pierce Regulatory Affairs Director crp/efb/lac ex_ subscribed before me this j sf day of :Ji"t ) '1 '2016. My commission expires: /-2 .. Z0/ 11 -. '
U.S. Nuclear Regulatory Commission NL-16-0626 Page 3
Enclosure:
- 1. Evaluation of Proposed Change cc: Southern Nuclear Operating Company Mr. S. E. Kuczynski, Chairman, President
& CEO Mr. D. G. Bost, Executive Vice President
& Chief Nuclear Officer Mr. D. R. Vineyard, Vice President
-Hatch Mr. M. D. Meier, Vice President
-Regulatory Affairs Mr. B. J. Adams, Vice President
-Engineering Mr. Demitrius Davis, Fleet Programs Director Mr. W. David Morrow, Fleet Programs Manager Mr. Mitch Etten-Bohm, Senior Engineer Mr. G. L. Johnson, Regulatory Affairs Manager -Hatch RType: Hatch=CHA02.004 U.S. Nuclear Regulatory Commission Ms. C. Haney, Regional Administrator Mr. M. D. Orenak, NRR Senior Project Manager -Hatch Mr. D. H. Hardage, Senior Resident Inspector
-Hatch Alabama Department of Public Health Dr. T. M. Miller, MD, State Health Officer State of Georgia Mr. J. H. Turner, Director -Environmental Protection Division Southern Nuclear Operating Company Edwin I. Hatch Nuclear Plant Units 1 and 2; License Amendment Request for Changes to License Amendment Request to Revise Technical Specification Section 5.5.12 for Permanent Extension of Type A and Type C Leak Rate Test Frequencies Enclosure 1 Evaluation of Proposed Change EVALUATION OF PROPOSED CHANGE Enclosure Page 1 of 81
SUBJECT:
License Amendment Request -Revise Technical Specification Section 5.5.12 for Permanent Extension of Type A and Type C Leak Rate Test Frequencies 1.0
SUMMARY
DESCRIPTION
2.0 DETAILED
DESCRIPTION
3.0 TECHNICAL
EVALUATION
4.0 REGULATORY EVALUATION
4.1 Applicable
Regulatory Requirements/Criteria
4.2 Precedent
4.3 No Significant Hazards Consideration
4.4 Conclusion
5.0 ENVIRONMENTAL
CONSIDERATION
6.0 REFERENCES
Attachments:
- 1. Technical Specifications Pages Markups 2. Bases Page Markups (For Information Only) 3. Plant Hatch Units 1 & 2 Risk Assessment to Support ILRT (Type A) Interval Extension Request 4. Technical Specifications Pages Clean Copies Hatch Nuclear Plant Units 1 and 2 1.0
SUMMARY
DESCRIPTION Enclosure Page 2 of 81 Pursuant to 10 CFR 50.90, Southern Nuclear Operating Company (SNC) requests an amendment to the Edwin I. Hatch Nuclear Plant (HNP) Unit 1, Renewed Facility Operating License (DPR-57), and Unit 2, Renewed Facility Operating License (NPF-5), by incorporating the attached proposed change into the Unit 1 and Unit 2 Technical Specifications (TS). Specifically, the proposed change is a request to revise TS 5.5.12 "Primary Containment Leakage Rate Testing Program" to allow the following:
- Increase in 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 NEI 94-01, Revision 3-A and the conditions and limitations specified in NEI 94-01, Revision 2-A.
- Adopt an extension of the containment isolation valve (CIV) leakage testing (Type C) frequency from the 60 months currently permitted by 10 CFR 50, Appendix J, 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.
- Adopt the use of American National Standards Institute/American Nuclear Society (ANSI/ANS) 56.8-2002, Containment System Leakage Testing Requirements.
- Adopt a more conservative grace interval of 9 months, for Type A, Type B and Type C leakage tests in accordance with NEI 94-01, Revision 3-A. The proposed change to the TS contained herein would revise HNP TS 5.5.12, by replacing the references to Regulatory Guide (RG) 1.163, Performance-Based Containment Leak-Test Program, (Reference
- 1) and 10 CFR 50, Appendix J, Option B with a reference to NEI topical report NEI 94-01, Revision 3-A (Reference 2), dated July 2012, and the conditions and limitations specified in NEI 94-01, Revision 2-A (Reference 8), dated October 2008, as the documents used by HNP to implement the performance-based leakage testing program in accordance with Option B of 1 O CFR 50, Appendix J. This license amendment request (LAR) also proposes the following administrative changes to TS 5.5.12:
- Deleting the information regarding the performance of the next HNP Unit 1 and Unit 2 Type A test to be performed no later than April 2008 for Unit 1 and no later than November 2010 for Unit 2, as both Type A tests have already occurred.
In addition, the Basis for TS Surveillance Requirement (SR) 3.6.1.1.1 is revised to incorporate the references to the NEI 94-01 documents and ANSI/ANS 56.8-2002, Containment System Leakage Testing Requirements.
The Bases changes are being provided for informational purposes only and will be implemented in accordance with the TS Bases Control Program based upon approval of this LAR.
2.0 DETAILED
DESCRIPTION
2.1 Current
Containment Leakage Rate Testing Program Enclosure Page 3 of 81 HNP, Units 1 and 2 TS 5.5.12, "Primary Containment Leakage Rate Testing Program," currently states, in part: * " A program shall be established to implement the leakage rate testing of the primary containment as required by 10 CFR 50.54(0) 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-Test Program/'
dated September 1995, as modified by the following exception to NEI 94-01, Rev. 0, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J": Unit 1: Unit 2: Section 9.2.3: The first Type A test after the April 1993 Type A test shall be performed no later than April 2008. Section 9.2.3: The first Type A test after the November 2, 1995, Type A test shall be performed no later than November 201 O." 2.2 TS Change Description The proposed changes to HNP, Units 1and2, TS 5.5.12 will remove Unit 1 and Unit 2 TS exceptions, and replace the reference to RG 1.163 with a reference to NEI Topical Report NEI 94-01 Revisions 2-A and 3-A. The proposed change would allow an increase in the Integrated Leak Rate Test (ILRT) test interval from its current 10-year frequency to a maximum of 15 years and the extension of the CIV leakage test (Type C tests) from the current 60-month frequency to 75 months, in accordance with NEI 94-01, Revision 3-A and the conditions and limitations specified in NEI 94-01, Revision 2-A. In addition, this LAR proposes to adopt a more conservative grace interval of 9 months, for Type A, Type B and Type C leakage tests in accordance with NEI 94-01, Revision 3-A, for non-routine, emergent conditions.
This LAR also proposes the following administrative changes to TS 5.5.12:
- Deleting the information regarding the performance of the next HNP Unit 1 Type A test no later than April 2008 and the next HNP Unit 2 Type A test no later than November 2010, as both Type A tests have already occurred.
The proposed change will revise TS 5.5.12 to state, in part: Enclosure Page 4 of 81 "A program shall be established to implement the leakage testing of the containment as required by 10 CFR 50.54(0) 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." Markups of TS 5.5.12 for both HNP Units 1 and 2 are provided in Attachment
- 1. Markups of TS Bases for SR 3.6.1.1 Primary Containment, and SR 3.6.1.1.1 for both HNP Units 1 and 2 are provided in Attachment 2 for informational purposes only. Based upon approval of this LAR, these TS Bases changes will be implemented in accordance with the TS Bases Control Program. Attachment 3 contains the plant specific risk assessment conducted to support this proposed change. This risk assessment followed the guidelines of NRC RG 1.17 4, Revision 2 (Reference
- 3) and NRC RG 1.200, Revision 2 (Reference 4). The risk assessment concluded that increasing the ILRT interval to 15 years is considered to represent an insignificant change in risk for HNP. 3.0 TECHNICAL EVALUATION
3.1 Description
of Primary Containment System The primary containment system houses the reactor pressure vessel, the reactor coolant recirculation system, and other branch connections of the reactor coolant system (RCS). The primary containment consists of the drywell, the suppression chamber that stores a large volume of water, a connecting vent system between the drywell and suppression chamber, isolation valves, a vacuum relief system, containment cooling systems, and other service equipment.
The drywell is a steel pressure vessel in the shape of a light bulb, and the suppression chamber is a torus-shaped steel pressure vessel located below and encircling the drywell. The primary containment system is designed to withstand the pressures resulting from a breach of the nuclear system process piping up to and including an instantaneous circumferential break of the reactor recirculation piping. The primary containment system provides a holdup for the decay of any released radioactive material and stores sufficient water to:
Enclosure Page 5 of 81
- Condense the steam released as a result of a breach in the nuclear system process barrier.
- Supply the emergency core cooling system (ECCS). The primary containment system free volume is filled with a nitrogen atmosphere during normal operation.
The containment atmospheric control system is capaQle of reducing and maintaining the oxygen content of the atmosphere below 4 percent during normal operation.
3.1.1 Drywall
The drywall is a steel pressure vessel with a spherical lower portion 65 feet (ft.) in diameter and a cylindrical upper portion 35 ft. 7 inches (in.) in diameter for Unit 1 and 37 ft 1 in. in diameter for Unit 2. The overall height of the drywall is approximately 111 ft. The design, fabrication, inspection, and testing of the Unit 1 drywall comply with the requirements of the American Society of Mechanical Engineers (ASME) Code, Section Ill, Subsection 8, Requirements for Class 8 Vessels, which pertains to containment vessels for nuclear power stations.
The primary containment is fabricated of SA-516 grade 70 plates. The design, fabrication, inspection, and testing of the Unit 2 drywall vessel comply with requirements of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code, Section Ill, Nuclear Power Plant Components, Subsection NE, Requirements for Class MC Components, 1971 Edition, including 1971 Summer Addenda which pertain to containment vessels for nuclear power plants. The steel head and shell of the drywall are fabricated of SA-516 GR70 steel plate. The Unit 1 drywall is designed for an internal pressure of 56 pounds per square inch gage (psig) coincident with a temperature of 281 degrees Fahrenheit
(°F) for Unit 1 and 340 °F for Unit 2, with applicable dead, live, and seismic loads imposed on the shell. Thermal stresses in the steel shell due to temperature gradients are also incorporated into the design. Thus, in accordance with the ASME Code, Section Ill, the maximum drywall pressure is 62 psig. Charpy V-notch impact tests were performed on specimens of all plate and forged materials.
Plates, forgings, and pipes of the drywall have an initial nil ductility transition temperature (NOTT) of -0°F when tested in accordance with the appropriate code for these materials.
It can be reasonably expected that the drywall is neither pressurized nor subjected to a substantial stress at temperatures below 30°F. The drywall is enclosed in a reinforced concrete structure for shielding purposes.
Resistance to deformation and buckling of the drywall plate is provided in areas where the concrete backs up the steel shell. Above the transition zone, the drywall is separated from the reinforced concrete by an airgap of approximately 2 in. Shielding Enclosure Page 6 of 81 over the top of the drywell is provided by removable, segmented, reinforced concrete shield plugs. 3.1.2 Suppression Chamber The suppression chamber is a steel pressure vessel in the shape of a torus located below and encircling the drywell, with a major diameter of approximately 107 ft. for Unit 1 and 107 ft. 1 in. for Unit 2, a cross-sectional diameter of approximately 28 ft. for Unit 1 and 28 ft. 1 in. for Unit 2. The suppression chamber contains the suppression pool and the air space above the pool. The suppression chamber transmits seismic loading to the reinforced concrete foundation slab of the reactor building.
Space is provided outside the chamber for inspection.
The torus-shaped suppression chamber is designed to the same material and code requirements as the steel drywell vessel. The material has an NOTT ::5 0°F. Modifications were made to the suppression chamber due to hydrodynamic loads identified during the Mark I Containment Long-Term Program. 3.1.3 Vent System Large vent pipes connect the drywell and the suppression chamber. Eight circular vent pipes, each having a diameter of 5 ft. 11 in. for Unit 1 and 6 ft. 3 in. for Unit 2, are provided.
The vent pipes are designed for the same pressure and temperature conditions as the drywell and suppression chamber. Jet deflectors in the drywell at the entrance of each vent pipe prevent possible damage to the vent pipe from jet forces that can accompany a pipe break within the drywell. Modifications were made to the vent system due to hydrodynamic loads identified during the Mark I Containment Long-Term Program. The drywell vents are connected to a 4-ft 6-in. diameter vent header from the torus that is contained within the suppression chamber airspace.
Projecting downward from the header are 80 downcomer pipes that are 24 in. in diameter and terminate 4 ft. 0 in. below the water surface of the suppression pool for Unit 1 and 4 ft. 4 in. for Unit 2. The vent system inside the torus is not pressure tested, although the vent pipes from the drywell to the suppression chamber are tested as part of the primary containment test. The vent system, which is designed for a differential pressure (LiP) of 56 psi between the drywell and suppression chamber, would be subjected to < 35 pounds per square inch differential (psid) during a loss of coolant accident (LOCA). 3.1.4 Suppression Pool The suppression pool contains demineralized water; serves as a heat sink for postulated anticipated operational occurrences (AOOs), accidents, and special events; and is a source of water for the ECCS. Enclosure Page 7 of 81 The suppression pool receives energy in the form of steam and water from either the safety relief valve (SRV) discharge piping or the drywall vent system downcomers that discharge under water. The steam is condensed in the suppression pool. The condensed steam and any water carryover cause an increase in pool volume and temperature.
Energy is removed from the suppression pool when the residual heat removal (RHR) system is operating in the suppression pool cooling mode. 3.1.5 Penetrations 3.1.5.1 Pipe Penetrations Two general types of pipe penetrations are provided:
- Penetrations that must accommodate thermal movement.
- Penetrations that experience relatively little thermal stress. Some piping penetrations, such as those used for the steam lines, have special provisions for thermal movement.
In these penetrations, the process line is enclosed in a guard pipe attached to the main steam line (MSL) through a multiple head fitting. This fitting is a one-piece forging with integral flues and is designed to meet all requirements of the ASME Code, Section Ill, Subsection B. The forging is radiographed and ultrasonically tested as specified by the ASME Code. The guard pipe and flued head are designed to the same pressure requirements as the process line. The process line penetration sleeve is welded to the drywall and extends through the biological shield where it is welded to a two-ply expansion bellows assembly that is welded to the flued-head fitting. The pipe is guided through pipe supports at the end of the penetration assembly to allow steam line movement parallel to the penetration and limit pipe reactions of the penetration to allowable stress levels. Where necessary, the penetration assemblies are anchored outside the containment to limit the movement of the line relative to the containment.
The bellows accommodate the movement between the pipe and the containment shell. The bellows-type expansion joints used in the containment penetrations were designed,
- manufactured, and inspected to ASME Code, Section Ill, in conjunction with Code Cases 1177-7 and 1330-2. These code cases, along with Section Ill, delineate the allowable stress limits for the bellows-type expansion joints and nondestructive examination requirements for bellows used in nuclear service. The cold piping, ventilation duct, and instrument line penetrations are generally welded directly to the sleeves. Double-flued head fittings are used in some cases where stress Enclosure Page 8 of 81 analyses indicate the need. Bellows and guard pipes are not necessary in these designs, since the thermal stresses are small and are accounted for in the design of the weld joint. 3.1.5.2 Electrical Penetrations All penetrations are hermetically sealed with provisions for periodic leak testing at design pressure.
The penetration canisters are factory assembled and tested with the number of field welds held to a minimum. These seals also meet the intent ASME Code, Section Ill, even though the Code has no provisions for qualifying the procedures or performances.
3.1.5.3 Traversing lncore Probe (TIP) Penetrations The TIP guide tubes pass from the reactor building through the primary containment.
The guide tube penetrations through the primary containment are sealed by means of brazing that meets the requirements of the ASME Code,Section VIII. These seals also meet the intent of ASME Code, Section Ill, even though the Code has no provisions for qualifying procedures or performances.
3.1.5.4 Personnel and Equipment Access Locks One personnel access lock provides access to the drywell. The lock has two gasketed doors in series that are designed and constructed to withstand the drywell design pressure.
The doors are mechanically interlocked to ensure that at least one door is locked at times when primary containment is required.
However, in case of a threat to plant personnel safety, breakglass stations are provided inside the drywell, as well as inside the airlock, with a selector switch inside the reactor building to defeat these interlocks.
Breakage of the glass or operation of the selector switch is annunciated in the MCA. The locking mechanisms are designed to maintain a tight seal when the doors are subjected to either internal or external pressure.
The seals on this access opening are capable of being tested for leakage. A bolted-in-place personnel access hatch in the drywell head contains double, testable seals. Two bolted-in-place equipment access hatches contain double, testable seals. Personnel and equipment hatches are sized and located with full consideration of service required, accessibility for maintenance, and periodic testing programs.
A 2-in. minimum gap is maintained around the barrel of the personnel and equipment hatches where they pass through or enter the concrete shield wall. A bolted-in-place control rod drive removal hatch, with double, testable seals permits extensive maintenance of the drive mechanism, if required.
3.1:5.5 Access to Suppression Chamber Enclosure Page 9 of 81 Access to the suppression chamber is provided at two locations via two 4-ft diameter manhole entrances with double-gasketed, bolted covers connected to the chamber by 4-ft diameter steel pipes. These access ports are bolted closed when primary containment is required and are opened only when the primary system temperature is s 212°F and the pressure-suppression system is not required to be operable.
3.1.5.6 Access for Refueling Operations The top portion of the drywell is removed during refueling operations.
The head is held in place by bolts and is sealed with a double seal arrangement.
The head is bolted closed when primary containment is required and is opened only when the primary coolant temperature is < 212°F and the pressure-suppression system is not required to be operable.
The double seal on the head flange provides a method for determining leak tightness after the drywell head has been replaced.
3.1.6 Net Positive Suction Head Analysis for HNP Unit 1 and Unit 2 3.1.6.1 HNP-1 Short-Term Response Calculations performed at 156 °F (Unit 1) 155 °F (Unit 2) suppression pool temperature at a power level of 2804 MWt and reactor operating pressure of 1060 psia demonstrate that containment overpressure is not required for either the RHR or CS pumps during the short-term post-LOCA period. 3.1.6.2. HNP-2 Short-Term Response The LPCI mode of RHR and the CS system are designed to ensure adequate NPSH margin availability under all combinations of foreseeable adverse conditions.
The point of minimum margin for all pumps occurs at the peak suppression pool temperature calculated on the basis of conservative assumptions.
No dependence is placed on positive containment pressure.
The regulatory position given in RG 1.1 (November 1970) is met. 3.1.6.3 HNP-1 Long Term Response Using the results of the long-term analysis and the equation for available NPSH, it was determined that 2.91 psig (6.7 ft.) of containment overpressure is required to ensure adequate NPSH to the RHR pumps, and 2.85 psig (6,6 ft.) of containment overpressure is required to ensure adequate NPSH to the CS pumps at the peak calculated suppression pool temperature of 210°F.
Enclosure Page 10 of 81 Using the calculated suppression pool temperature profile, containment overpressure is required for a period from approximately
2.6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />s
(hrs.) to 18.7 hrs. after LOCA initiation.
To provide sufficient margin for the peak suppression pool temperature of 210 °F, the long-term NPSH evaluation takes credit for a containment overpressure of 4.2 psig (1 Oft.). The overpressure credit is applied for a period of 1.5 to 26.5 hrs. following LOCA initiation.
Any changes resulting in an individual or collective increase of 1 ft. (approximately 0.4 psig) of the containment overpressure margin of 10 ft. (4.2 psig) requires NRC notification.
3.1.6.4 HNP-2 Long-Term Response The long-term containment response analysis demonstrates the RHR and CS pumps have NPSH ma,rgin without taking credit for containment overpressure.
3.2 Justification
for the Technical Specification Change 3.2.1 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. Title 10 CFR 50, Appendix J also ensures that periodic surveillance of reactor containment penetrations and isolation valves is performed so that proper maintenance and repairs are made during the service'life of the containment and the systems 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 design basis accident.
Appendix J identifies three types of required tests: 1) Type A tests, intended to measure the primary containment overall integrated leakage rate; 2) Type B tests, intended to detect local leaks and to measure leakage across pressure-containing or leakage limiting boundaries (other than valves) for primary containment penetrations, and; 3) Type C tests, intended to measure containment isolation valve leakage rates. Types B and C tests identify the vast majority of potential containment leakage paths. Type A tests identify the overall (integrated) containment leakage rate and serve to ensure continued leakage integrity of the containment structure by evaluating those structural parts of the containment not covered by Type B and C testing. In 1995, 10 CFR 50, Appendix J, "Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors," 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 Enclosure Page 11 of 81 failure. The use* of the term "performance-based" in 1 O 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 8. Also in 1995, RG 1.163 (Reference
- 5) with certain modifications and additions.
Option 8, 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 was considered in the establishment of the intervals allowed by RG 1.163 and NEI 94-01, but that this "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 8 to 10 CFR 50, Appendix J, subject to the limitations and conditions noted in Section 4.0 of the NRC Safety Evaluation Report (SER) on NEI 94-01. The NRC SER was included in the front matter of the NEI 94-01, Revision 2-A report. 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 (September 1995). It delineates a performance-based approach for determining Type A, Type 8, 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 8 to 10 CFR 50, Appendix J and includes provisions for extending Type A ILRT intervals to up to 15 years. NEI 94-01 has been endorsed by RG 1.163 and NRC SERs of June 25, 2008 (Reference
- 9) and June 8, 2012 (Reference
- 10) as an acceptable methodology for complying with the provisions of Option 8 to 10 CFR 50. The regulatory positions stated in RG 1.163 as modified by NRC SERs dated June 25, 2008 and June 8, 2012 are incorporated in this document.
It delineates a performance-based approach for determining Type A, Type 8, and Type C containment leakage rate surveillance testing frequencies.
Justification of extending test intervals is based on the performance history and risk insights.
Extensions of Type 8 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 administrative limits. Intervals may be increased from 30 months up to a maximum of 120 months for Type 8 tests (except for containment airlocks) and Enclosure Page 12 of 81 up to a maximum of 75 months for Type G tests. If a licensee considers extended test intervals of greater than 60 months for Type B or Type G 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 NRG has provided the following concerning the use of grace in the deferral of ILRTs beyond the 15-year interval in NEI 94-01, Revision 2-A, NRG SER Section 3.1 .1 .2, which states, in part: " ... Section 9.2.3, NEI TR 94-01, Revision 2, states, "Type A testing shall be performed during a period of reactor shutdown at a frequency of at least once per 15 years based on acceptable performance history." However, Section 9.1 states that the "required surveillance intervals for recommended Type A testing given in this section may be extended by up to 9 months to accommodate unforeseen emergent conditions but should not be used for routine scheduling and planning purposes." The NRC staff believes that extensions of the performance-based Type A test interval beyond the required 15 years should be infrequent and used only for compelling reasons. Therefore, if a licensee wants to use the provisions of Section 9.1 in TR NEI 94-01, Revision 2, the licensee will have to demonstrate to the NRG staff that an unforeseen emergent condition exists." NEI 94-01, Revision 3-A, Section 10.1 concerning the use of grace *in the deferral of Type B and Type C LLRTs past intervals of up to 120 months for the recommended surveillance frequency for Type B testing and up to 75 months for Type C testing, states: "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 MS IVs) or to valves held to the base interval (30 months) due to unsatisfactory LLRT performance." The NRG has also provided the following concerning the extension of ILRT intervals to 15 years in NEI 94-01, Revision 3-A, NRG SER Section 4.0, Condition 2, which states, in part:
Enclosure Page 13 of 81 "The basis for acceptability of extending the ILRT interval out to once per 15 years was the enhanced and robust primary containment inspection program and the local leakage rate testing of penetrations.
Most of the primary containment leakage experienced has been attributed to penetration leakage and penetrations are thought to be the most likely location of most containment leakage at any time." 3.2.2 Current HNP ILRT Requirements 10 CFR 50, Appendix J was revised, effective October 26, 1995, to allow licenses to choose containment leakage testing under either Option A, "Prescriptive Requirements," or Option B, "Performance-Based Requirements." On March 6, 1996 the NRC approved License Amendment No. 200 for HNP, Unit 1 and Amendment 141 for Unit 2 (Reference
- 19) authorizing the implementation of 10 CFR 50, Appendix J, Option B for Type A, B and C tests. Current TS 5.5.12 requires that a program be established to comply with the containment leakage rate testing requirements of 10 CFR 50.54(0) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions.
The program is required to be in accordance with the guidelines contained in RG 1.163. RG 1.163 endorses, with certain exceptions, NEI 94-01, Revision 0, as an acceptable method for complying with the provisions of Appendix J, Option 8. RG 1.163, Section C.1 states that licensees intending to comply with 10 CFR 50, Appendix J, Option B, should establish test intervals based upon the criteria in Section 11.0 of NEI 94-01 (Reference
- 5) rather than using test intervals specified in ANSI/ANS 56.8-1994.
NEI 94-01, Section 11.0 refers to Section 9, which states that Type A testing shall be performed during a period of reactor shutdown at a frequency of at least once per ten years based on acceptable performance history. Acceptable performance history is defined as completion of two consecutive periodic Type A tests where the calculated performance leakage was less than 1.0la (where La is the maximum allowable leakage rate at design pressure).
Elapsed time between the first and last tests in a series of consecutive satisfactory tests used to determine performance shall be at least 24 months. Adoption of the Option B performance based containment leakage rate testing program altered the frequency of measuring primary containment leakage in Types A, 8, 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 11 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 types of containment types, including a post tensioned, shallow domed concrete containment similar to HNP's containment structures.
NUREG-1493 concluded in Section 10.1.2 that reducing the frequency of Type A tests (ILRT} from the original three (3) tests per Enclosure Page 14 of 81 10 years to one (1) test per 20 years was found to lead to an imperceptible increase in risk. The estimated increase in risk is very small because ILRTs identify only a few potential containment leakage paths that cannot be identified by Types B and C testing, and the leaks that have been found by Type A tests have been only marginally above existing requirements.
Given the insensitivity of risk to containment leakage rate and the small fraction of leakage paths detected solely by Type A testing, NUREG-1493 concluded that increasing the interval between ILRTs is possible with minimal impact on public risk. 3.2.3 HNP 10 CFR 50, Appendix J, Option B Licensing History March 6, 1996 The Commission issued on March 6, 1996 Amendments Nos. 200 and 141 to Facility Operating License Nos. DPR-57 and NFP-5 for the HNP, Units 1 and 2, respectively (Reference 19). The amendments revised the TS for containment systems to reflect the adoption of the requirements of 10 CFR 50, Appendix J, Option B, and the implementation of a performance-based containment leak-rate testing program at the HNP, Units 1 and 2. February 20, 2002 The Commission issued Amendment No. 226 to Facility Operating License No. DPR-57 for HNP, Unit 1 (Reference
- 14) on February 20, 2002. This amendment revised TS 5.5.12, Primary Containment Leakage Rate testing Program, to allow a one-time deferral of the Type A Containment ILRT based on the risk-informed guidance in RG 1.174. Specifically, the proposed TS says that the first Type A test performed after the April 1993 Type A test shall be performed no later than April 2008. May 28, 2004 The Commission issued on May 28, 2004 Amendment No. 241 to Renewed Facility Operating License DPR-57 and Amendment No. 184 to Renewed Facility Operating License NPF-5 for HNP, Units 1 and 2, respectively (Reference 16). This amendment changed the peak calculated post-accident primary containment internal pressure values, Pa, in TS 5.5.12, "Primary Containment Leakage Rate Testing Program," for Units 1 and Unit 2. The proposed change supported a 10-psi increase in the nominal reactor steam dome operating pressure at each unit. The purpose of the pressure increase in the nominal reactor steam dome pressure is to allow'for additional flow control margin for the high-pressure turbine. This flow margin is needed to operate the plants at 100 percent of the increased (Reference
- 13) rated thermal power level of 2804 MW (t).
February 1, 2005 Enclosure Page 15 of 81. The Commission issued on February 1, 2005 Amendment No. 187 to Renewed Facility Operating License No. NPF-5 for HNP, Unit 2 (Reference 15). This amendment modified TS 5.5.12, Primary Containment Leakage Rate testing Program. The change would allow a one-time change in the Appendix J, Type A test (containment ILRT) interval from the required 10 years to a test interval of 15 years. Specifically, the exception states that the first Type A test performed after the November 2, 1995, Type A test shall be performed no later than November 2010. August 28, 2008 The Commission issued on August 28, 2008 Amendment No. 256 to Renewed Facility Operating License DPR-57 and Amendment No. 200 to Renewed Facility Operating License NPF-5 for HNP Units 1 and 2, respectively (Reference 17). The amendments revised the licensing basis with a full scope implementation of an alternative source term (AST) for HNP. TS 3.6.1.3 Primary Containment Isolation Valves The proposed license amendment revised the following TS that are associated with the analyses performed to support the AST. The proposed change for Unit 1, added a new SR 3.6.1 .3.13, which establishes a maximum combined leakage rate for all secondary containment bypass leakage paths of 0.02La. The proposed change for Unit 2, revised SR 3.6.1 .3.10 to increase the maximum combined leakage rate for all secondary containment bypass leakage paths from O.OQ9La to 0.02La. La is defined in 10 CFR 50, Appendix J. The secondary containment bypass leakage rate assumptions in the radiological dose consequences analysis for the LOCA form the basis for the revised TS limits. The increase in bypass leakage is necessary to allow for newly identified bypass leakage paths. The addition of this TS SR to Unit 1 reflects a required RG 1 .183 assumption in the accident analyses and standardizes the TS between units. The NRG staff's assessment found these changes acceptable since the proposed secondary bypass leakage rate limit of 0.02La was assumed in the accident analysis and regulatory criteria have been met. Another proposed change was to eliminate the per line main steam isolation valve (MSIV) leakage rate limits from the TS SR for both units (SR 3.6.1.3.10 and SR 3.6.1.3.11, respectively).
Specifically, for Unit 1, the licensee proposed to establish a combined maximum leakage rate of 100 standard cubic feet per hour (scfh) when tested at > 28.0 psig and < 50.8 psig and for Unit 2, a combined maximum leakage rate is reduced from 250 scfh to 100 scfh when tested at> 28.8 psig and < 47.3 psig. The licensee indicated that the pressure values of 50.8 psig and 47.3 psig represent Enclosure Page 16 of 81 calculated peak drywell pressures for Unit 1 and Unit 2, respectively, in the event of a LOCA. The revised proposed values for MSIV combined maximum leakage rates are used in the radiological dose consequences analysis for the LOCA. The contribution to total combined leakage from any individual MSIV is not considered in the analysis.
The analysis assumes that the maximum allowed combined leakage rate is entirely through one MSIV. The NRC staff found this change acceptable since this value was assumed in the revised accident analysis, and calculated doses are below the regulatory criteria of 10 CFR 50.67. A second test pressure range, with a corresponding leakage rate criterion, was proposed for both units when test pressure exceeds the peak calculated drywell pressure during a LOCA. This is in addition to the 100 scfh combined maximum leakage rate specification when tested within the specified test pressure range that is below the calculated peak drywell pressure.
For Unit 1, a combined maximum leakage rate of 144 scfh is established when tested at > 50.8 psig. For Unit 2, a combined maximum leakage rate of 144 scfh is established when tested at> 47.3 psig. The addition of a second MSIV leakage rate criterion for testing at or above calculated peak drywell pressure provides a more accurate leakage rate acceptance criterion for test pressures that are higher than calculated post-LOCA peak drywell pressures.
This facilitates testing the MSIVs in the accident direction at peak accident drywell pressure as preferred by 10 CFR 50 Appendix J, as opposed to testing the MS IVs in the reverse direction at a lower test pressure as allowed by existing HNP Appendix J exemptions.
A higher pressure would result in a higher mass flow rate through a given leakage area. The higher leakage rate (mass flow rate) acceptance criterion is based on a pressure and mass flow rate analysis.
This allows for the use of a different MSIV Appendix J test configuration as dictated by plant configuration during the outage, while also ensuring that the appropriate acceptance criterion exists for the actual test pressure used. For Unit 2, the requirement to restore MSIV leakage to 11.5 scfh upon discovery of leakage not meeting the 100 scfh leakage rate limit was proposed to be eliminated.
The NRC staff found this change to be acceptable since it is not an input or assumption in the radiological dose consequence analysis.
3.2.4 ILRT History As noted previously, HNP 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 Option B. Since the adoption of Option B, the performance leakage rates are calculated in accordance with NEI 94-01, Section 9.1.1 for Type A testing. Tables 3.2.4-1 and 3.2.4-2 list the past Periodic Type A ILRT results for Units 1 and 2, respectively.
Enclosure Page 17 of 81 Table 3.2.4-1, Unit 1 Type A ILRT History Test Date June 1978 February 1983 April 1986 November 1988 April 1993 March 2008 Leakage Rate (1) (Containment air weight %/day) 0.456 0.442 0.428 0.4968 0.3488 0.3485 (1) The Commission issued on May 28, 2004 Amendment No. 241 to Renewed Facility Operating License DPR-57 for HNP, Unit 1 (Reference 16). This amendment changed the peak calculated post-accident primary containment internal pressure values, Pa, in TS Section 5.5.12. The peak calculated primary containment internal pressure for the design basis LOCA, Pa, was increased to 50.8 psig. Table 3.2.4-2, Unit 2 Type A ILRT History Test Date May 1982 January 1986 November 1989 November 1992 November 1995 March 2009 Leakage Rate (1 ), (Containment air weight %/day) 0.7890 0.5870 0.8000 0.8839 0.3175 0.5422 (1) The Commission issued on May 28, 2004 Amendment 184 to Renewed Facility Operating License NPF-5 for HNP, Unit 2 (Reference 16). This amendment changed the peak calculated post-accident primary containment internal pressure values, Pa, in TS Section 5.5.12. The peak calculated primary containment internal pressure for the design basis LOCA, Pa, was increased to 47.3 psig. The results of the last two Type A ILRTs for both HNP, Units 1 and 2 are less than the maximum allowable containment leakage rate of 1.2 wt%/day. As a result, since both tests for both units were successful, both units have been placed on extended ILRT frequencies.
The current ILRT interval frequency for HNP Units 1 and 2 is 10 years. 3.3 Plant Specific Confirmatory Analysis 3.3.1 Methodology Enclosure Page 18 of 81 An evaluation has been performed to assess the risk impact of extending the currently allowed containment Type A integrated leak rate test (ILRT) interval to a permanent 15 years for HNP Units 1 and 2. The extension would allow for substantial cost savings as the ILRT could be deferred for additional scheduled refueling outages. The risk assessment follows the guidelines from the following:
e NEI 94-01 Revision 3-A (Reference 2),
- The methodology used in EPRI TR-104285 (Reference 7),
- The NEI "Interim Guidance for Performing Risk Impact Assessments In Support of One-Time Extensions for Containment Integrated Leakage Rate Test Surveillance Intervals" (References 33, 37),
- The NRC regulatory guidance on the use of PAA as stated in RG 1.200 (Reference
- 4) as applied to ILRT interval extensions, and risk insights in support of a request for a change in the plant's licensing basis as outlined in RG 1.174 (Reference 3),
- The methodology used for Calvert Cliffs to estimate the likelihood and risk implications of corrosion-induced leakage of steel liners going undetected during the extended test interval (Reference 32),
- The methodology used in EPRI TR-1009325, Revision 2-A (Reference
- 20) for performing a risk impact assessment of extended ILRT intervals.
- The EPRI TR-1009325 Revision 2-A methodology incorporates the specific limitations
- and conditions outlined in the NRC acceptance of the EPRI TR-1009325 Revision 2 methodology documented in the NRC Final Safety Evaluation (Reference 9). The format of this document is consistent with the intent of the Risk Impact Assessment Template for evaluating extended ILRT intervals provided in Appendix Hof the EPRI TR methodology report (Reference 20). The NRG report on performance-based leak testing, NUREG-1493, analyzed the effects of containment leakage on the health and safety of the public and the benefits realized from the containment leak rate testing. In that analysis, it was determined that for a representative PWR plant, (i.e., Surry) containment isolation failures contribute less than 0.1 percent to the latent risks from reactor accidents.
Consequently, it is desirable to show that extending the ILRT interval will not lead to a substantial increase in risk from containment isolation failures for HNP. Earlier ILRT frequency extension submittals have used the EPRI TR-104285 (Reference
- 7) methodology to perform the risk assessment.
In October 2008, EPRI TR-1018243 (Reference 20} was issued to update the generic methodology for ILRT extensions to 15 years using current performance data and to incorporate the specific limitations and conditions outlined by the NRC in the final safety evaluation of the methodology (Reference 9). This more recent EPRI document considers additional risk metrics and criteria including the change in population dose, large early release Enclosure Page 19 of 81 frequency (LERF), and conditional containment failure probability (CCFP), whereas EPRI TR-104285 considered only the change in population dose. In the SER 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 extend the ILRT surveillance interval to 15 years, subject to the limitations and conditions noted in Section 4.0 of the Safety Evaluation (SE). Table 3.3.1-1 addresses each of the four limitations and conditions for the use of EPRI 1009325, Revision 2. Table 3.3.1-1, EPRI Report No. 1009325 Revision 2 Limitations and Conditions Limitation/Condition lFrom Section 4.2 of SE) HNP Resoonse 1. The licensee submits documentation HNP PRA technical adequacy is addressed in indicating that the technical adequacy of Section 3.3.2 of this LAR and Attachment 3, their PRA is consistent with the "Plant Hatch Units 1 & 2 Risk Assessment to requirements of RG 1.200 relevant to the Support ILRT (Type A) Interval Extension I LRT extension.
Request," Appendix B, "Hatch PRA Technical Adequacy Evaluation In Support of ILRT Interval Extension Risk Assessment." 2.a The licensee submits documentation Because the ILRT does not impact core indicating that the estimated risk increase damage frequency (CDF), the relevant associated with permanently extending the criterion is LEAF. The increase in internal ILRT surveillance interval to 15 years is events LEAF resulting from a change in the small, and consistent with the clarification Type A ILRT test frequency from three in ten provided in Section 3.2.4.5 of this SE. years to one in fifteen years is conservatively estimated as 6.39E-08/yr using the EPRI guidance as written and including potential corrosion impacts. The LEAF increase using the EPRI Expert Elicitation values is substantially less (i.e., 7.52E-09/yr).
Using both approaches, the estimated change in LEAF is determined to be very small" using the acceptance guidelines of RG 1.17 4.
Limitation/Condition
<From Section 4.2 of SE) 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.
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. 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 La instead of 35 La. Enclosure Page 20 of 81 HNP Resoonse The change in Type A test frequency from three in ten years to one in fifteen years, measured as an increase in the total integrated plant dose risk for those accident sequences influenced by Type A testing, is 9.90E-03 person-rem/yr using the EPRI guidance values, and drops to 1.96E-03 person-rem/yr using the EPRI Expert Elicitation values. The EPRI guidance states that a very small population dose is defined as an increase of <1 .0 person-rem/yr or <1 % of the total population dose, whichever is less restrictive for the risk impact assessment of the extended I LRT intervals.
The Hatch dose increase results are significantly less than 1.0 person-rem/yr.
Moreover, the risk impact when compared to other severe accident risks is negligible.
The increase in CCFP when comparing the three in ten-year frequency to one in fifteen-year frequency is about 0.84% using the EPRI guidance values, and drops to about 0.10% using the EPRI Expert Elicitation values. The EPRI guidance states that increases in CCFP < 1.5 percentage points are very small. Therefore the increase for Hatch is determined to be very small. The representative containment leakage for Class 3b sequences used by HNP is 100 La, 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 La for the Class 3b sequences.
Limitation/Condition (From Section 4.2 of SEl 4. A licensee amendment request (LAR) is required in instances where containment over-pressure is relied upon for ECCS performance.
3.3.2 Technical
Adequacy of the PAA Enclosure Page 21 of 81 HNP Resoonse For HNP Unit 1 containment overpressure is not required for either the RHR or CS pumps during the short-term post-LOCA period. For HNP Unit 1 containment overpressure is required for a period from approximately 2.6 hr. to 18.7 hr. after LOCA initiation.
To provide sufficient margin for the peak suppression pool temperature of 210 °F, the long-term NPSH evaluation takes credit for a containment overpressure of 4.2 psig (1 Oft.). The overpressure credit is applied for a period of 1.5 to 26.5 hrs. following LOCA initiation.
Any changes resulting in an individual or collective increase of 1 ft. (approximately 0.4 psig) of the containment overpressure margin of 1 O ft. ( 4.2 psig) requires NRG notification.
For HNP Unit 2 the short term and long-term containment response analysis demonstrates the RHR and CS pumps have NPSH margin without taking credit for containment overpressure.
An additional amendment request is not required in this instance, as the over-pressure requirement has previously been incorporated in the HNP-2 operating license as documented in the FSAR. Technical adequacy is presented in Appendix B, "Hatch PRA Technical Adequacy in Support of ILRT Interval Extension Risk Assessment," of Attachment 3 of this submittal.
A PRA technical adequacy evaluation was performed consistent with the requirements of RG-1.200, Revision 2 (Reference 4). 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 HNP Units 1 and 2 to fifteen years on a permanent basis satisfies the risk acceptance guidelines in RG 1.174.
3.3.2.1 Demonstrate the Technical Adequacy of the PAA Enclosure Page 22 of 81 The guidance provided in RG 1.200, 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:
- Identification of permanent plant changes (such as design or operational practices) that have an impact on the PRA but have not been incorporated in the PAA.
- The parts of the PAA used to produce the results are performed consistently with the PAA Standard as endorsed by RG 1 .200.
- A summary of the risk assessment methodology used to assess the risk of the application, including how the PAA model was modified to appropriately model the risk impact of the application.
- Identification of key assumptions and approximations in the PRA relevant to the results used in the decision making process.
- A discussion of the resolution of peer review or self-assessment findings and observations (F&Os) that are applicable to the parts of the PAA required for the application.
- Identification of parts of the PAA used in the analysis that were assessed to have capability categories less than that required for the application.
3.3.2.2 Technical Adequacy of the PAA Model The PAA model version used for the ILRT extension assessment is the Hatch Unit 1 Internal Events PRA model version 4.1 , change notice PRA-CN-H-13-003, which was completed in October 2013, updated with the Level 2 model documented in SNC calculation H-RIE-IEIF-U01-010.
This is a maintenance update of the HNP Unit 1 Internal Events PAA, Revision 4, which incorporated the resolution of F&Os associated with the November 2009 Peer Review of the HNP Unit 1 Internal Events PAA model. Revision 4.1 of the HNP PAA model is the most recent evaluation of the risk profile at HNP for internal event challenges.
The PAA 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 HNP PAA is based on the event tree I fault tree methodology, which is a well-known methodology in the industry.
The HNP PRA model is controlled in accordance with SNC procedure RIE-001, "Generation and Maintenance of Probabilistic Risk Assessment Models and Associated Enclosure Page 23 of 81 Updates," and associated guidelines.
This procedure defines the process for implementing regularly scheduled and interim PRA model updates, for tracking issues identified as potentially affecting the PRA models (e.g., due to changes in the plant, errors or limitations identified in the model, industry operating experience, etc.), and for controlling the model and associated computer files. To ensure that the current PRA model remains an accurate reflection of the as-built, as-operated plants, RIE-001 requires that following activities outlined in the procedure are routinely performed:
- Design changes and procedure changes are reviewed for their impact on the PRA model on an on-going basis.
- Reliability data, unavailability data, initiating events frequency data, human reliability data, and other such PRA inputs shall be reviewed approximately every two fuel cycles and updated as necessary to maintain the PRA consistent with the as-operated plant. As indicated previously, RG 1.200 also requires that additional information be provided as part of the submittal to demonstrate the technical adequacy of the PRA model used for the risk assessment.
Each of these items are addressed in the following sections.
3.3.2.3 Plant Changes Not Yet Incorporated into the PRA Model As part of PRA model configuration control, SNC maintains a PRA model maintenance database that tracks all issues that have been identified that could impact the Hatch PRA model. Per SNC procedure RIE-001 the significance of the pending items in the database is evaluated to determine the impact on model results. Each pending item is prioritized for future model updates according to its significance to model results. A review of the current open items in the database for HNP identified no permanent plant design or operational changes that would significantly impact the results of the risk assessment performed for the ILRT interval extension evaluation.
3.3.2.4 Previous Peer Review and Self Assessment of the HNP PRA Model The HNP PRA model was reviewed extensively during development and undergoes independent internal review during each update. The Hatch PRA was reviewed twice prior to issuance of the ASME PRA Standard for peer review. The initial peer review was conducted by the BWR Owners Group (BWROG) in April 2001. The review team used Revision A-3 NEI draft "Probabilistic Risk Assessment (PRA) *Peer Review Process Guidance" dated June 2, 2000 as the basis for review. This review was observed by a team from the NRC. In 2006, a gap analysis was performed against the available versions of the ASME PRA Standard and RG 1.200, Revision 0 (2003 trial version).
Enclosure Page 24 of 81 3.3.2.5 RG 1.200 PRA Review of the HNP PRA Model against the ASME PRA Standard Requirements A PRA Peer Review of all elements of the HNP Internal Events PRA PRA model including Internal Flooding against RG 1.200, Revision 2 clarifications, the ASME/ANS PRA Standard (Reference 30), and NEI 05-04 was performed in November 2009. A summary of the results of the PRA Peer Review (Reference
- 21) previously provided to the NRC as part of the NEI Risk Informed Technical Specification (RITS) Initiative 5b LAR submittal (ML 103140510) for which SNC received a NRC SER as discussed in Attachment 3, Appendix B, section B.2.7 of this submittal, is shown below. Based on the results of the Peer Review, 95% of the SRs evaluated met Category II or better. There were 10 supporting requirements that were noted as "Not Met" and 5 that were noted "Met" at Category I only. All of the "Not Met" findings were resolved as part of the update of the Hatch Internal Events PRA Model, Revision 4.0, to Revision 4.1 as noted in Attachment 3, Appendix B, Tables B.2-1 and B.2-2 of this submittal.
3.3.2.6 PRA Portions With Inadequate Technical Adequacy As previously noted, the NRC safety evaluation (Reference
- 9) of the EPRI ILRT methodology specifies that Capability Category I is appropriate for the applicable PRA Standard supporting requirements.
Based on the update to the HNP Internal Events PRA model to Revision 4.1, following the 2009 PRA Peer Review, all PRA Standard supporting requirements are met at Capability Category 11 or higher, as applicable.
3.3.2.7 NRC SER for HNP Units 1 and 2 NEI Risk-Informed Technical Specification (RITS) 5b Submittal SNC submitted a LAR and received an SER for NEI RITS Initiative 5b to implement the Surveillance Frequency Control Program (SFCP) at Hatch. The NEI RITS Initiative 5b application is similar to this ILRT interval extension submittal in that they both deal with surveillance frequency extensions.
Excerpts from the NRC SER for HNP pertaining to the HNP PRA quality are provided in Attachment 3, Appendix B, section B.4 of this submittal, and the overall conclusions are considered applicable to this submittal.
3.3.2.8 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 of the ILRT interval for HNP, Units 1 and 2, to fifteen (15) years on a permanent basis satisfies the risk acceptance guidelines in RG 1.174.
3.3.3 Summary
of Plant-Specific Risk Assessment Results Enclosure Page 25 of 81 The findings of the HNP, Units 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 very small. The HNP plant-specific results for extending ILRT interval from the current 10 years to 15 years are summarized below: Based on the results from Attachment 3, Section 7.0, "Conclusions," and the sensitivity calculations presented in Section 6.0 "Sensitivities," the following conclusions regarding the assessment of the plant risk associated with permanently extending the Type A ILRT test frequency to 15 years:
- RG 1.174 (Reference
- 3) provides guidance for determining the risk impact of plant-specific changes to the licensing basis. RG 1.17 4 defines "very small" changes in risk as resulting in increases of CDF below 1 o-6/yr and increases in LERF below 1 o-7/yr. Because the ILRT does not impact CDF, the relevant criterion is LERF. The increase in internal events LERF resulting from a change in the Type A ILRT test frequency from three in ten years to one in fifteen years is conservatively estimated as 6.39E-08/yr using the EPRI guidance as written and including potential corrosion impacts. The LERF increase using the EPRI Expert Elicitation values is substantially less (i.e., 7.52E-09/yr).
Using both approaches, the estimated change in LERF is determined to be "very small" using the acceptance guidelines of RG 1.17 4.
- The change in Type A test frequency from three in ten years to one in fifteen years, measured as an increase in the total integrated plant dose risk for those accident sequences influenced by Type A testing, is 9.90E-03 person-rem/yr using the EPRI guidance values, and drops to 1.96E-03 person-rem/yr using the EPRI Expert Elicitation values. The EPRI guidance states that a very small population dose is defined as an increase of <1.0 person-rem/yr or <1 % of the total population dose, whichever is less restrictive for the risk impact assessment of the extended ILRT intervals.
The Hatch dose increase results are significantly less than 1.0 person-rem/yr.
Moreover, the risk impact when compared to other severe accident risks is negligible.
- The increase in the CCFP when comparing the three in ten-year frequency to one in fifteen-year frequency is about 0.84% using the EPRI guidance values, and drops to about 0.10% using the EPRI Expert Elicitation values. The EPRI guidance states that increases in CCFP < 1 .5 percentage points are very small. Therefore, the increase for Hatch is determined to be very small.
- The potential impact on LERF from external events was quantitatively assessed utilizing information from the Individual Plant Examination of External Events (IPEEE). The total increase in LERF due to internal and external events using Enclosure Page 26 of 81 the EPRI guidance values is estimated to be 9.SE-8/yr, which remains in the "very small" change region (i.e., < 1 E-7/yr) of the RG 1.174 acceptance guidelines.
Therefore, increasing the ILRT interval to 15 years is considered to represent an insignificant change in risk for HNP. 3.3.4 Previous Assessments The NRG in NUREG-1493 (Reference
- 6) has previously concluded that:
- Reducing the frequency of Type A tests (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 Type B and C testing, and the leaks that have been found by Type A tests have been only marginally above existing requirements.
- Given the insensitivity of risk to containment leakage rate and the small fraction of leakage paths detected solely by Type A testing, increasing the interval between integrated leakage-rate tests is possible with minimal impact on public risk. The impact of relaxing the ILRT frequency beyond 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 HNP confirm these general findings on a plant specific basis considering the severe accidents evaluated for HNP, the HNP containment failure modes, and the local population surrounding HNP. Details of the HNP, Units 1 and 2, risk assessment are contained in Attachment 3 of this submittal.
3.4 Non-Risk Based Assessment Consistent with the defense-in-depth philosophy discussed in RG 1.17 4, HNP has assessed other non-risk based considerations relevant to the proposed amendment.
HNP has multiple inspections and testing programs that ensure the containment structure remains capable of meeting its design functions and that are designed to identify any degrading conditions that might affect that capability.
These programs are discussed below. 3.4.1 Protective Coatings Program (PCP) The Plant Hatch PCP provides a means of preventing or minimizing loss of material that would otherwise result from contact of the base material with a corrosive environment.
Enclosure Page 27 of 81 The PCP is a mitigation and condition monitoring program designed to provide base metal aging management through surface application, maintenance, and inspection of protective coatings on selected components and structures.
Coating Service Level I are those coating systems applied inside the primary containment where coating failure could adversely affect the operation of post-accident fluid systems and, thereby, impair safe shutdown of the plant. Program Scope . The PCP provides specifications for coatings applied to structures and components within the scope of license renewal. The PCP includes specific inspection techniques and frequencies for Service Level I coatings (which include non-immersion coatings applied to the suppression chamber and drywall airspace and immersion coatings applied to the suppression chamber interior below the normal water level). The current term PCP has been enhanced for the renewal term to provide inspection techniques and frequencies for certain accessible non-service level I coatings.
These requirements apply to external surfaces of carbon steel commodities outside of primary containment and within the scope of license renewal that are expected to experience significant atmospheric corrosion.
The PCP has also been enhanced to provide for inspection and documentation of the condition of normally inaccessible (underground or embedded) carbon steel components within the scope of license renewal, whenever these components are exposed or uncovered.
Parameters Inspected or Monitored Periodic inspection of components is conducted in order to identify areas of degraded coatings and associated corrosion of base metals, which may indicate a loss of material.
Detection of Aging Effects Detection of degraded coatings and associated corrosion of base metals is accomplished primarily through visual inspection techniques.
For surfaces determined to be suspect, dry film thickness, adhesion, and continuity tests may also be performed.
Monitoring and Trending Service level I coatings are inspected at set intervals.
A baseline inspection of service level I coated components within the scope of license renewal will be performed.
Coated components are monitored for changes in previously identified findings and for newly developed conditions.
Trending of such findings is performed to predict degrading conditions and to determine the potential long-term impact of the finding. Inspection results are maintained in plant records. Engineering personnel track and trend results in accordance with site procedures.
Acceptance Criteria Enclosure Page 28 of 81 Any significant degradation of structural components that is observed during the visual inspection activities are noted and corrective actions implemented in accordance with the corrective actions program. Acceptance criteria are specifically stated in the PCP and the implementing procedures.
Torus Coatings A visual inspection is performed during each refueling outage of the torus coating in the area above and below the water line to the extent it is visible from the surface. It is expected that if corrosion effects or loss of coating from peeling occurs, the most likely place would be in the area of the water line. If during the visual inspection significant corrosion is indicated, an ultrasonic inspection of this area is performed to determine if the thickness of the torus wall meets the minimum wall thickness required.
If it is observed during the surveillance program that excessive coating loss has occurred, the latest developments in the industry are surveyed and will be considered in applying a replacement coating. Containment
-Non-Immersion Coatings General walk-down of the Drywall is performed every refueling outage. Unqualified/Degraded Coatings in Containment The limitation on the quantity of non-acceptable coatings assumed in various calculations, such as ECCS sump/strainer blockage, is 3, 150 ft 2 in either unit. The total amount of unqualified coatings in each containment as documented in most recent inspections is as follows:
- Unit 1 total square footage of non-acceptable coatings is 426.2 ft 2.
- Unit 2 total square footage of non-acceptable coatings is 87.9 ft 2. 3.4.2 lnservice Inspection Program (ISi) Class MC Components Inspection Plan This inspection plan provides a summary of the examinations and tests applicable to components treated as Class MC for ISi. This plan was developed utilizing the ASME Section XI Code, 2007 Edition through the 2008 Addenda, Subsection IWE. ASME Class MC components include: the drywall, the suppression pool (torus), the verit headers, penetrations, airlocks and manways. This plan includes examinations required by ASME XI Subsection IWE as modified by 10 CFR 50.55a(b)(2)(ix)(A), (B), (F), (G), (H), and (I) and any applicable relief requests, exemptions or alternatives.
A listing of applicable sections of 10 CFR 50.55a and Code Cases as well as relief requests, Enclosure Page 29 of 81 exemptions, and alternatives can be found in Volume 1 of the ISi Plan. This plan also includes examinations not required by Subsection IWE that SNC has elected to perform due to specific industry concerns.
Relief Request By letter dated July 16, 2015, as supplemented by letter dated December 16, 2015, SNC submitted a request to the NRC for relief from the requirements of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code (B&PV Code) at HNP, Units 1 and 2. SNC requested to use the current ASME B&PV code of record, the 2001 edition through the 2003 addenda, in combination with the 2007 edition through the 2008 addenda for certain inservice inspection and containment inservice inspection activities from January 1, 2016, through November 30, 2017. The NRG staff reviewed the subject request and concludes, as set forth in the enclosed safety evaluation, that the licensee has adequately addressed all of the regulatory requirements set forth in 10 CFR 50.55a(z)(1
). Therefore, the NRC staff authorized the use of Relief Request HNP-ISl-AL T-5-01 at HNP, Units 1 and .2, from January 1, 2016, to November 30, 2017. (Reference
- 35) The application of Relief Request HNP-ISl-AL T-5-01 as applicable to Sub-section IWE is displayed in the following table: Table 3.4.2-1, Proposed ASME Section XI, Sub-section IWE, Code Of Record For HNP ASME Section XI Code Provision ASME Section XI Code Edition/ Addenda 1 Sub-section Article 2001 Edition/ 2001 Edition/ 2007 Edition/ No Addenda 2003 2008 Addenda Addenda IWE Requirements IWE-1000 x2 for Class MC IWE-2000 x2 Components IWE-3000 x IWE-5000 x 1 SNC will also comply with all NRG conditions, limitations, and restrictions specified in 10 CFR 50.55a as they apply to the specific edition and addenda referenced.
2 The selection, planning, and scheduling of ISi examinations/tests will comply with these ASME Section XI articles (e.g. IWB-1000 and 2000) from the 2007 Edition/2008 Addenda or applicable NRG approved alternatives that are specified in the HNP ISl/Cll Program Plans. Implementation Schedule The current 10-year inspection interval began January 1, 2016 and goes through December 31, 2025. All inspections required during the previous containment inspection Enclosure Page 30 of 81 interval were completed during the previous interval.
Exams required to be performed on an interval frequency will be performed at the same point in time as would be required if the containment inspection interval had not changed. All other code required exams are required on a period basis. The change of inspection interval will have no impact on the scheduling of these exams. The ISi inspection interval is broken into three periods. The period durations, in order, are 3-years, 4-years, and 3-years. Inspection period dates for the 5th ISi inspection interval is displayed in Tables 3.4.2-1 and 3.4.2-2. Table 3.4.2-2, HNP Unit 1 IWE Examination Schedule 5th Interval (ll 1/1/16 through 12/31/18 1st Period 1 R27-2016 1R28 -2018 5th Interval (ll 1/1/19 through 12/31/23 2nd Period 1 R29 -2020 1 R30 -2022 5th Interval (ll 1/1/24 through 12/31/26 3rd Period 1R31 -2024 1R32-2026 (1) Intervals and Periods are being extended in accordance with IWA-2430.
Table 3.4.2-3, HNP Unit 2 IWE Examination Schedule 5th Interval (1 l 1/1/16 through 12/31/19 1st Period 2R24-2017 2R25 -2019 5th Interval (1 l 1/1/16 through 12/31/23 2nd Period 2R26-2021 2R27-2023 5th Interval (1 l 1/1/24 through 12/31/27 3rd Period 2R28-2025 2R29 -2027 (1) Intervals and Periods are being extended in accordance with IWA-2430.
Program In order to minimize duplication of efforts to the maximum extent practical, the Containment Inspection Program at Plant Hatch is mainly comprised of existing plant programs and procedures that have been appropriately modified and drawn together, under the overall direction of the Containment Inspection Program Responsible Engineer (CIPRE), to provide a complete and comprehensive program for examination Enclosure Page 31 of 81 of the pressure retaining surfaces of containment, structures that are part of reinforcement, and any associated permanent attachments.
Beginning with this lnservice Inspection Plan at the programmatic level and moving to the implementation level, the program is largely made up of the following documents:
- Fifth Ten-Year Examination Plan (ISi Plan) This inspection plan provides a summary of the examinations and tests applicable to components treated as Class MC for the purposes of ISi. It provides a list of the examinations and tests to be performed during the Fifth ten-year interval and the appropriate schedule, by period, for implementation of each.
- SNC lnservice Inspection Engineering Program This administrative control procedure establishes provisions for the implementation of a program which satisfies the requirements of the ASME Section XI Code as required by Technical Requirements Manual Unit 2, Section T3.4.2.1.
In particular, this procedure applies to the implementation of the ISi Program (including containment inspection) and the Repair/Replacement Program.
- IWE/IWL Roles and Responsibilities This administrative control procedure establishes the roles and responsibilities of the individuals within the IWE program.
- IWE Implementation This Nuclear Management Instruction (NMI) provides the general instructions applicable to the implementation and management of the ASME Boiler and Pressure Vessel Code,Section XI, Subsection IWE requirements, as supplemented by 10 CFR 50.55a.
- Visual Examination of the Drywall Air Gap and Sand Cushion Drain Lines This procedure is intended to address examinations that are associated with the Containment Inspection Program but which are not required by the ASME Code,Section XI. Those examinations have been included in the plan document as a convenience.
This procedure defines the requirements for the visual examination of the drywall air gap and sand cushion drain lines, including providing instruction for their examination.
These examinations are performed in order to detect conditions that are indicative of degradation or problems with functionality and include direct and remote visual examination techniques.
- Orywell Surfaces Visual Inspection Enclosure Page 32 of 81 This procedure provides instructions for performing the inspection of the interior Orywell surfaces and interior and exterior Orywell Head surfaces to satisfy the requirements of TS SR 3.6.1.1.1 and also provides instructions for performing the inspection as required by the ISi Plan.
- Venting Assembly and Suppression Chamber Surfaces Visual Inspection This procedure provides instructions for performing the inspection of the interior (vapor phase) and exterior surfaces of the Suppression Chamber to satisfy the requirements of TS SR 3.6.1 .1.1 and also provides instruction for performing the inspection as required by the ISi Plan.
- Nuclear Coatings Program This procedure establishes the responsibilities for implementing, maintaining, and periodically assessing the effectiveness of the Nuclear Coatings Program and comprises all those systematic and planned actions necessary to ensure that safety and non-safety related coatings activities satisfy the applicable requirements.
- Procedure for Condition Assessments This procedure provides instructions for performing surveillance inspection and monitoring of all coatings systems that are classified as safety related and reporting inspection results. Periodic completion of a portion of the total scope of inspections described in this procedure also satisfies the ASME Code,Section XI, Subsection IWE visual examination (VT -3) requirement for the submerged surfaces of the containment pressure retaining boundary.
- Primary Containment Integrated Leakage Rate Test This procedure establishes the criteria and detailed procedure to demonstrate that containment leakage at design basis accident pressure does not exceed the acceptance limit specified in TS SR 3.6.1.1.1.
This procedure also provides for containment structural inspection prior to each Type A test and at a periodic interval between tests based on performance of the containment system. General Visual Examination (GVE) This examination is considered to be an increased level, controlled, surveillance activity and not a formalized nondestructive examination (NOE) method in the true sense of recognized, established NOE methods. This position is based on the following considerations:
Enclosure Page 33 of 81
- GVE is not addressed in ASME Section XI, Subsection IWA, and since it is not included in the scope of NOE, the provisions of Subsection IWA are not applicable.
GVE is addressed only in Subsection IWE, paragraph IWE-3510.1.
- The requirements of ASME Section XI, Subsection IWA, paragraph IWA-2240 do not apply since GVE is the examination specified and not a proposed alternative method.
- The personnel qualification requirements of SNT-TC-1A do not apply and, as described in IWE-3510, are the responsibility of the Owner, under the direction of a qualified, responsible individual "knowledgeable in the requirements for design, inservice inspection, and testing of Class MC components.
11
- Per 10 CFR 50.55a(b)(2)(ix)(B), minimum illumination, maximum distance, and resolution requirements have not been defined for GVE and are left to the judgment of trained, knowledgeable, and experienced individuals, selected at the discretion of, and under the direction of a qualified, responsible individual 11 knowledgeable in the requirements for design, inservice inspection and testing of Class MC components" provided that conditions or indications for which the visual examination is performed can be detected at the chosen distance or illumination.
For the purposes of General Visual Examination, ASME Section XI surface areas of Class MC containment vessels, parts, appurtenances may be considered inaccessible if visual access by line of sight with adequate lighting from permanent vantage points is obstructed by permanent plant structures, equipment, or components, provided these surface areas do not require examination in accordance with the inspection plan or IWE-1240." (i.e., surface areas requiring augmented examination).
This defines inaccessible as defined in this examination plan. Containment Visual (VT-3) 10 CFR 50.55a(b)(2)(ix)(G) requires that a VT-3 be performed on wetted surfaces of submerged areas (i.e., submerged areas of the torus) and accessible surface areas of the vent system for Item E1 .12 and E1 .20 of ASME Section XI Table IWE-2500-1.
Pressure retaining bolted connections also require a VT-3 examination.
ISl-EX-01 allows the performance of a General Visual in lieu of the VT -3 for non-submerged accessible surface areas of the vent system.
- Submerged Surfaces of the Torus Plant Hatch has implemented a torus submerged surfaces examination and coatings repair program since the late 1980s. A coatings contractor performs visual examinations and spot coatings repairs using underwater divers. This Enclosure Page 34 of 81 same contractor provides VT-3 certified personnel to perform the Subsection IWE required VT-3 examinations and provides the results to SNC for evaluation and resolution of any deficient conditions, as appropriate.
SNC decided to perform the initial Subsection IWE, VT-3 visual examination of the torus submerged surfaces prior to the Code required schedule date. The initial VT-3 was performed on Unit 1 in 1999 (1 R18) and on Unit 2 in 1998 (2R14). Subsequent VT-3 examination of the torus submerged surfaces will be performed in accordance with the Code required schedule or more frequently if deemed appropriate by the CIPRE or personnel responsible for the Plant Hatch safety related coatings program. Repair and Replacement Activities All containment pressure retaining component repairs, modifications, or replacements that affect the containment leakage boundary shall be tested in accordance with 10 CFR 50 Appendix J. General Discussion for Category E-A Drvwell Shell The exterior surface of the drywell shell, with the exception of the drywell head, is exempt from examination per IWE-1220(b) and IWE-1232(a).
The exterior surface is inaccessible due to the concrete shield wall and the 2" air gap. All shell welds were solution film tested at 56 psig after completion of construction which met the construction code requirements and IWE-1232(a)(2) for Unit 1 and Unit 2. The interior and exterior embedded portions of the drywell shell (i.e., below the 114 foot elevation) are exempt from examination per IWE-1220(b) and IWE-1232(a).
Shell welds below the 114 1 -8" elevation were examined per the ASME Section 111 Code (1968 Edition and Addenda in effect through June 30, 1968, FSAR K.2.2.), paragraphs N-1410 and N-1411 (gas medium test) and all shell welds were solution film tested at 56 psig after completion of construction which met the construction code requirements and thus the requirements of IWE-1232(a)(2).
The interior surfaces of the drywell shell are generally accessible for visual examination.
1 OCFR 50.55a(b)(2)(ix)(B) allows for relaxation of the distance and lighting requirements when performing remote visual examination provided that the conditions or indications for which the visual examination is performed can be detected at the chosen distance and illumination.
Visual examination from the 114 1 -0" floor elevation, various catwalks and ladders, and access provided from piping and components should provide adequate access to perform the general visual and VT-3 in order to assess the condition of the interior drywell surfaces.
Enclosure Page 35 of 81 The provisions of IWE-1220(c), IWE-1231 (a), IWE-1231 (b) and IWE-1232, which require that containment surfaces remain accessible, must be complied with for any repairs, replacements, or modifications to the drywell. Suppression Pool Exterior Surfaces The outside surfaces of the suppression pool are generally accessible for visual examination.
10 CFR 50.55a(b){2)(ix)(B) allows for relaxation of the distance and lighting requirements when performing remote visual examination provided that the conditions or indications for which the visual examination is performed can be detected at the chosen distance and illumination.
Therefore, the visual examination of virtually 100% (easily> 80%) of the exterior suppression pool surface can be performed for the 87' -0 11 floor elevation, the 114' -0 11 elevation inner and outer circumference catwalks, and the top of the suppression pool with adequate resolution to detect any degradation of the surfaces.
Suppression Pool Interior Surfaces Virtually 100% of the interior non-submerged (vapor space) suppression pool surfaces are accessible for visual examination from the 114' -0 11 interior catwalk, or from the top of the vent header if the provisions of 10 CFR 50.55a(b )(2)(ix)(B) are applied. Visual examination from these vantage points should provide adequate access to perform visual examination of these surfaces.
Visual examination of this suppression pool vapor space is performed by QC personnel each inspection period. The results of these examinations indicate only minor coating loss, and virtually no degradation of the shell material.
Therefore, classification of this area as IWE, Category E-A is warranted.
Suppression Pool Interior Submerged Surfaces The submerged surfaces of the suppression pool are only accessible for visual examination using underwater divers or by draining the pool. Draining the pool is not an attractive option due to the time and expenses involved.
Divers beginning with the spring 1990 refueling outage have performed visual examinations of these surfaces for Unit 1 and the spring 1991 refueling outage for Unit 2. An extensive de-sludging, visual examination, and patch coating repair program was initiated beginning in 1991. These activities have continued and a long-range suppression pool maintenance program is in place at HNP. Examination Results HNP Unit 1: The results of these examinations indicated that there was some coating degradation and shell pit measurements were taken to determine the maximum degradation and the Enclosure Page 36 of 81 rate of degradation.
Subsequent review and evaluation in 1996 revealed a maximum pit depth of approximately 0.030" with a corrosion rate of 0.15 mils (0.00015")
per year. The nominal thickness of the submerged area is 0.594" with a minimum design thickness of 0.440". Ultrasonic thickness measurements in 1997 of an 18" X 36" grid in Bay 14 revealed an actual average shell thickness of 0.680" with a minimum thickness of 0.643" and a maximum thickness of 0.729". Therefore, since this area was recoated in 1981 there has been no significant degradation of the submerged area of the suppression pool shell and the current degradation rate is very slow (0.00015 inches/year).
HNP Unit 2: The results of these examinations indicated that there was some coating degradation and shell pit measurements were taken to determine the maximum degradation and the rate of degradation.
Subsequent review and evaluation in 1997 revealed a maximum pit depth of approximately 0.040" with a corrosion rate of 1.74 mils (0.00174")
per year. The nominal thickness of the submerged area is 0.594" with a minimum design thickness of 0.440". There has been no significant degradation of the submerged area of the suppression pool shell and the current degradation rate is very slow (0.00174 inches/year).
Since HNP plans to continue de-sludging, examination, and spot coating repair as necessary, there is no justification to classify the submerged areas as IWE, Category EC, which would require VT -1 and ultrasonic thickness measurements.
Classification of the HNP Unit 1 submerged surfaces as IWE, Category E-A is warranted at the present time. The results of these examinations for HNP Unit 2 indicated that there was some coating degradation and shell pit measurements were taken to determine the maximum degradation and the rate of degradation.
Subsequent review and evaluation in 1997 revealed a maximum pit depth of approximately 0.040" with a corrosion rate of 1.74 mils (0.00174")
per year. The nominal thickness of the submerged area is 0.594" with a minimum design thickness of 0.440". There has been no significant degradation of the submerged area of the suppression pool shell and the current degradation rate is very slow (0.00174 inches/year).
Since HNP plans to continue de-sludging, examination, and spot coating repair as necessary, there is no justification to classify the submerged areas as IWE, Category E-C, which would require VT-1 and ultrasonic thickness measurements.
Classification of the HNP Unit 2 submerged surfaces as IWE, Category E-A is warranted at the present time. Vent System Examination Position The results of visual examinations performed on the vent system, located inside the suppression pool, in conjunction with the suppression pool vapor space examination indicate only minor coating loss, and virtually no degradation of the shell material.
Therefore, classification of this area as IWE, Category E-A is warranted.
Enclosure Page 37 of 81 Virtually 100% of the exterior vent system (located inside the suppression pool) surfaces are accessible for visual examination from the 114' -0" interior catwalk, or from the top of the vent header if the provisions of 10 CFR 50.55a(b)(2)(ix)(B) are applied. Visual examination of the exterior vent system surfaces located outside the suppression pool are accessible from the inner circumference catwalk, the top of the vent pipe and the 87' -0" floor elevation if the provisions of 10 CFR 50.55a(b)(2)(ix)(B) are applied. Visual examination of the interior vent system is accessible from the drywell. Visual examination of the vent system from these vantage points should provide adequate access to perform visual examination of these surfaces.
There have been no reports of significant degradation of the exterior or interior surfaces of the vent system during examination and classification as IWE, Category E-A is warranted at the present time. Category E-A Specific Evaluation and Examination Position Item E1.10 Evaluation Item E1.10 includes the containment vessel pressure retaining boundary and the examinations listed in items E1.11 and E1.12. The examinations described in E1.11 and E1 .12 are applicable as described in the appropriate sections below. Item E1 .11 Evaluation (General Visual Examination)
Table IWE-2500-1, Item E1 .11 references the below listed footnotes relative to containment surface examination requirements.
- 1. Examinations shall include all accessible interior and exterior surfaces of Class MC components, parts, and appurtenances, and metallic shell and penetration liners of Class CC components.
The following items shall be considered for examination: (a) integral attachments and structures are parts of reinforcing structure, such as stiffening rings, manhole frames, and reinforcement around openings. (b) surfaces of attachment welds between structural attachments and the pressure retaining boundary or reinforcing structure, except for nonstructural or temporary attachments as defined in NE-4435 and minor permanent attachments as defined in CC-4543.4. (c) surfaces of containment structural and pressure boundary welds, including longitudinal welds (Category A), circumferential welds (Category B), flange welds (Category C), and nozzle-to-shell welds (Category D) as defined in NE-3351 for Class MC; and surfaces of Flued Head and Bellows Seal Circumferential Welds joined to the Penetration.
Enclosure Page 38 of 81 (d} pressure-retaining bolted connections, including bolts, studs, nuts, bushings, washers, and threads in base material and flange ligaments between fastener holes. Bolted connections need not be disassembled for performance of examinations, and bolting may remain in place under tension. Table IWE-2500-1 requires the General Visual Examination prior to each inspection period. 10 CFR 50 Appendix J requires the exam prior to each Type A test. Item E1 .11 Examination Position A General Visual Examination of the accessible containment surfaces is required once each inspection period and prior to each Type A test. The General Visual Examination includes the following areas.
- Accessible surfaces of the interior of the drywell shell above the 114-foot floor elevation.
- Interior and exterior surfaces of the drywall head.
- Accessible interior and exterior surfaces of drywell penetrations.
- Accessible interior and exterior surfaces of the drywall to torus vent lines.
- Accessible interior and exterior surfaces of the torus vent header and downcomers.
- Accessible exterior surfaces of the torus shell and torus supports.
- Accessible interior surfaces of the torus shell above the water level. The exterior drywell shell surface is exempt from examination per IWE-1220(b) and IWE-1232(a).
The requirements of IWE-1231 (a}(3) are satisfied (i.e., at least 80% of the accessible surface area can be examined either directly or remotely}
by performing examination from existing catwalks, walkways, ladders, floor elevations and adjacent structures of the drywell shell, drywell head, drywell to torus vent lines, vent header and downcomers, containment penetrations, the interior torus shell above the water level, and the torus exterior shell surfaces.
Item E1 .11 Evaluation (Bolting VT-3) 10 CFR 50.55a(b)(2)(ix)(G) and Item E1 .11 (Bolting) applies to the examination/testing of pressure retaining bolted connections where the pressure retaining function is considered to apply to bolting which is in tension during the accident.
Item E1 .11 requires a general visual examination of all pressure retaining bolted connections which are part of the Class MC containment structure once each 10-year inspection interval.
10 CFR 50.55a(b)(2}(ix}(G}
requires a VT-3 exam. 10 CFR 50.55a(b)(2)(ix)(H) requires that the VT-3 be performed each inspection interval.
Flaws or degradation identified during the performance of the VT-3 examination must be examined in accordance with the VT-1 examination method. The criteria in the material specification or IWB-3517 .1 Enclosure Page 39 of 81 must be used to evaluate containment bolting flaws or degradation.
While disassembly is not required to support the examination, examination is required for any appropriate bolted connections that are disassembled.
Bolting may be examined in place under tension when disassembly is not otherwise required during the inspection interval.
Item E 1.11 Examination (Bolting VT-3) Position All Class MC pressure retaining bolted connections are listed in the examination plan and will be VT-3 examined in accordance with IWE as amended by 10 CFR 50.55a at least once each inspection interval if disassembled.
Any connections that are not disassembled during normal outage activities will be examined with the bolting in place. Flaws or degradation identified during the performance of the VT-3 examination will be examined in accordance with the VT-1 examination method. All bolted Class MC connections, except Penetration X-218B, are normally disassembled during the interval.
Electrical penetrations used at Plant Hatch are weld-in design, do not utilize pressure retaining bolting, and are not specifically listed in the examination tables. These penetrations are part of the general visual examinations performed on a periodic basis. All bolted connections are also included in the Appendix J leakrate testing program. Appendix J leakrate testing is required anytime the connection is disassembled, and at least every 10 years if not disassembled, which confirms containment leak tight integrity.
Item E 1.12 Evaluation (VT-3 Visual Examination)
Table IWE-2500-1, Item E1 .12 references the below listed footnotes relative to containment surface examination requirements.
- 1. Examinations shall include all accessible interior and exterior surfaces of Class MC components, parts, and appurtenances, and metallic shell and penetration liners of Class CC components.
The following items shall be considered for examination: (a) integral attachments and structures are parts of reinforcing structure, such as stiffening rings, manhole frames, and reinforcement around openings. (b) surfaces of attachment welds between structural attachments and the pressure retaining boundary or reinforcing structure, except for nonstructural or temporary attachments as defined in NE-4435 and minor permanent attachments as defined in CC-4543.4.
Examination shall include the weld metal and the base metal for 1/2 in. beyond the edge of the weld. (c) surfaces of containment structural and pressure boundary welds, including longitudinal welds (Category A), circumferential welds (Category B), flange welds (Category C), and nozzle-to-shell welds (Category D) as defined in NE-3351 for Class MC; and surfaces of Flued Head and Bellows Seal Circumferential Welds joined to the Penetration.
Enclosure Page 40 of 81 (d) pressure-retaining bolted connections, including bolts, studs, nuts, bushings, washers, and threads in base material and flange ligaments between fastener holes. Bolted connections need not be disassembled for performance of examinations, and bolting may remain in place under tension. 10 CFR 50.55a(b)(2)(ix)(G) requires VT-3 Visual Examination of 100% of the accessible containment surfaces once each inspection interval.
Item E 1.12 Examination Position A VT-3 Visual Examination of the wetted surfaces of submerged areas is required once each inspection interval.
A VT-3 visual examination will be performed each interval on the following submerged, accessible, pressure boundary surfaces of the Drywell, Torus, and Vent System: 1) Accessible interior surfaces of the torus shell which are submerged (utilizing divers). 2) Accessible submerged surfaces of the vent header downcomers, vent header supports, and interior submerged attachments welded to the torus shell (utilizing divers). Item E1 .20 Evaluation (General Visual Examination)
Table IWE-2500-1, Item E1 .20 references the below listed footnotes relative to containment vent system surface examination requirements. 1 . Examinations shall include all accessible interior and exterior surfaces of Class MC components, parts, and appurtenances, and metallic shell and penetration liners of Class CC components.
The following items shall be considered for examination: (a) integral attachments and structures are parts of reinforcing structure, such as stiffening rings, manhole frames, and reinforcement around openings. (b) surfaces of attachment welds between structural attachments and the pressure retaining boundary or reinforcing structure, except for nonstructural or temporary attachments as defined in NE-4435 and minor permanent attachments as defined in CC-4543.4.
Examination shall include the weld metal and the base metal for 1/2 in. beyond the edge of the weld. (c) surfaces of containment structural and pressure boundary welds, including longitudinal welds (Category A), circumferential welds (Category B), flange welds (Category C), and nozzle-to-shell welds (Category D) as defined in NE-Enclosure Page 41 of 81 3351 for Class MC; and surfaces of Flued Head and Bellows Seal Circumferential Welds joined to the Penetration. (d) pressure-retaining bolted connections, including bolts, studs, nuts, bushings, washers, and threads in base material and flange ligaments between fastener holes. Bolted connections need not be disassembled for performance of examinations, and bolting may remain in place under tension. 2. Includes flow-channeling devices within containment vessels. 10 CFR 50.55a(b)(2)(ix)(G) requires a VT-3 visual examination of 100% of the accessible containment vent system surfaces once each inspection interval.
Exemption Request ISl-EX-01 allows the use of a general visual type inspection in lieu of performing the VT-3. Item E1 .20 Examination Position A General Visual Type Examination of the accessible containment vent system surfaces is required once each inspection interval per exemption request ISl-EX-01.
A VT-3 Visual Examination will be performed on the submerged, accessible; pressure boundary surfaces of the Vent System in accordance with item E1 .12. The containment vent system is comprised of the drywall to torus vent lines, the vent header and associated downcomers.
The vent header and downcomers are located inside the torus. A General Visual Type Examination will be performed in the following areas, which are included within the scope of the E1 .20 examinations described above. 1) Accessible (virtually 100%) interior surfaces of the drywall to torus vent lines. 2) Accessible exterior surfaces of the drywell to torus vent lines (portions visible from the exterior torus catwalk, and from the interior torus catwalk 3) Accessible (virtually 100%) interior surfaces of the torus vent header. 4) Accessible (approx. 50%) exterior surfaces of the torus vent header. 5) Accessible (approx. 50%) exterior surfaces of the vent header downcomers.
Examination shall include the inside and outside of the vent system shell per Table IWE-2500-1, Category E-A, Footnote 1. The requirements of IWE-1231 (a)(3) are satisfied (i.e., at least 80% of the accessible surface area can be examined either directly or remotely) from the interior/exterior of the vent lines and vent header, existing torus catwalks and walkways, ladders, adjacent structures.
The requirements of IWE-1232(a) were satisfied during construction.
Item E1 .30 Evaluation (General Visual Examination)
Enclosure Page 42 of 81 Item E 1 .30 requires general visual examination of containment moisture barrier materials at concrete-to-metal interfaces.
HNP has only one such moisture barrier that i$ located inside the drywall at the 114-foot concrete floor elevation to drywall shell interface.
This moisture barrier provides a seal to prevent seepage of water that might accumulate on this floor elevation, into the space between the concrete and the drywall shell. SCS evaluated the potential for shell degradation below the 114-foot elevation should water accumulate in this region. Their evaluation indicated that due to the concrete and water interaction in this area, the pH of the resulting environment was not conducive to shell degradation.
Item E1 .30 Position HNP will implement a general visual examination of the moisture barrier located at the 114-foot floor elevation inside the drywall. The moisture barrier will be examined at least once each inspection period. SNC Engineering Department (Civil) evaluation of the examination results is anticipated to support acceptance or recommendation for corrective action, as required.
CATEGORY E-C Category E-C applies to containment surfaces requiring augmented examinations.
Surfaces that should be evaluated as requiring augmented examinations are defined by IWE-1240.
The basic premise of IWE-1240 is: (a) containment surfaces that are subject to accelerated corrosion with no or minimal corrosion allowance or areas where the absence or repeated loss of protective coatings has resulted in substantial corrosion and pitting, and (b) containment surfaces subjected to excessive wear from abrasion or erosion that causes a loss of protective coatings, deformation, or material loss. The areas described in IWE-1240 were considered for their applicability at HNP and a discussion of each area is provided below. Interior Submerged Surfaces of Suppression Pool (Torus) (See General Discussion for Category E-A) The torus design accounted for maintenance of a specific water level during all modes of plant operation and post accident.
The interior and exterior surfaces were initially provided with protective coatings, which have been inspected and patch coated as needed since commercial operation of the plant. HNP implements periodic VT-3 visual examination, utilizing underwater divers, of the submerged surfaces to determine any areas of coating or shell degradation.
A recoating process has been implemented for any areas that indicated coating degradation.
Pitting depth measurements were taken in conjunction with these examinations to determine torus shell corrosion rates. Test specimens have also been placed inside the torus, Enclosure Page 43 of 81 below the water level, to provide additional information relative to coating degradation and potential shell corrosion rates. Evaluation of the HNP Unit 1 and Unit 2 examination results to date does not indicate that the submerged areas of the torus have experienced any significant degradation that presently warrants classification as IWE Category E-C. The interior submerged surfaces of the torus have been included in the examination plan as IWE Category E-A subject to VT-3 visual examination.
The results of future VT -3 examinations, performed by underwater divers, will be evaluated to determine if these areas should be categorized.
Interior Torus Surfaces Exposed to Periodic Wetting and Drying The containment spray mode of RHR system operation is only used infrequently to control suppression pool pressure.
This has resulted in discoloration of the protective coating on the areas adjacent to the spray nozzles. However, periodic examination of the interior torus surfaces has not indicated any significant degradation of the protective coating or the shell surface. Some minor areas of the coating have been cleaned and recoated, but no significa,nt shell degradation has been identified.
These surfaces are visually examined in accordance with Category E-A, and the performance of augmented examinations per Category E-C is not presently warranted for these surface areas. Bottom Interior of Torus Adjacent to SRV Discharge Lines The SRV discharge lines at Plant Hatch were modified in the early 1980s incorporating a "T-quencher" design, which evenly distributes the discharged steam and prevents steam-jets that could damage the protective coating or the shell surface. Periodic VT-3 visual examination by underwater divers has not indicated any significant coating degradation, which would indicate potential shell degradation.
These surfaces are included within the scope of the Category E-A examinations and are periodically inspected by underwater divers. Therefore, the performance of augmented examinations per Category E-C is not presently warranted for these surface areas. Torus Seismic Restraints (Earthquake Ties-4) The torus is provided with 4 seismic restraints to account for the possibility of any seismic loads that could be experienced.
These restraints are located at the 87-foot floor elevation in the torus room and are accessible during the general examinations (Category E-A) of the containment surfaces.
The torus room is not a harsh environment and HNP has not been subjected to any seismic events that would affect the torus or the restraints.
These seismic restraints are included within the scope of the Category A examinations and performance of augmented examinations per Category E-C is not presently warranted for these restraint areas.
Exterior Drvwell Shell Below the 114-Foot Floor Elevation Enclosure Page 44 of 81 The exterior of the drywell shell at and below the 114-foot elevation was considered as possibly subject to accelerated degradation due to problems reported at Oyster Creek. This area at Oyster Creek was found to be severely corroded due to exposure to water and corrosive chemicals that had accumulated in the air gap region because of a leak in the refueling bellows, chemicals in the gap forming material (that was left in place), and drain lines that were not functional.
The refueling bellows at HNP is of a different design than that at Oyster Creek and virtually all of the gap forming material was removed during construction.
The sand cushion drain lines have been modified at HNP (discharge elbows removed) to facilitate visual examination.
The air gap drain lines and the sand cushion drain lines have been , examined using a video probe to assure that they are functional and that any water that might leak into the drywell air gap region would be discharged from the area. These visual examinations did not indicate the present or past existence of moisture in these areas. The discharge of each drain is also examined for evidence of moisture during each refueling outage, while the reactor cavity is flooded, to assure that no water is present in this area. Therefore, the performance of augmented examinations per Category E-C is not presently warranted for these surface areas. Drvwell Equipment Hatches and Personnel Air Lock The equipment hatches and personnel air lock are used as entry/exit openings during refueling outages for equipment and personnel.
The air lock is provided with floor grating which prevents abrasion of the lower portion of the shell. Wooden platforms are constructed in the equipment hatches to prevent abrasion of the shell. Therefore, there is no reason to expect accelerated degradation in these areas and the general visual examination requirements of Category E-A are adequate to monitor the structural integrity.
Category E-C Position Based on a review of IWE-1240 relative to the containment design at HNP and the results of previous HNP Unit 1 and Unit 2 examinations related to the integrity of the containment, there are no areas that should be designated for augmented examination per Category E-C at the present time. The results of future containment examinations, related to IWE, Appendix J, and the Maintenance Rule, will be evaluated to determine if any areas are experiencing degradation that would result in the need to implement augmented examinations.
Torus Inspection Program The suppression pool, or torus, is made up of sixteen cylindrical sections or bays, that are "mitered" to form a large "donut" with a diameter from center line to center line of approximately 107', and a cross-sectional inside diameter of approximately 28'. The Enclosure Page 45 of 81 normal water depth is approximately 12.5'. At the centerline, each bay is approximately 21 '-3" long. A ring girder, which is part of the attachment and support structure of the torus, is located at the joint between each bay and provides some separation between each bay. In 1990, several inspection grids (approximately 12" square) were established in the Unit 1 torus and de-sludging was performed.
The inspection grids were then utilized to monitor loss of wall thickness at pit locations, and de-sludging was performed to minimize the possibility of ECCS strainer blockage.
In 1991, inspection grids were similarly established in the Unit 2 torus and de-sludging was performed.
During these 1990/1991 refueling outages, a visual inspection was performed by divers in the submerged areas and by plant/SGS personnel in the vapor area. Local repairs were performed whenever general corrosion exceeded established acceptance criteria.
In no case have we observed any degradation, which infringed upon the minimum wall thickness requirements of the torus. The inspections, de-sludging, and repairs have been performed as necessary since their inception in 1990. De-sludging This activity is performed in the submerged area by divers using a vacuum system. The vacuum system pulls the sludge into filter banks. The filter banks are stationed with pumps to continuously filter the water removing most of the suspended particles.
This activity requires approximately one week from set up to removal of filters. SNC has found the pitting degradation to decrease as the frequency of de-sludging is increased.
SNC has de-sludged each unit as necessary since 1993. This activity is considered as normal maintenance and therefore is not considered to be part of the ASME Section XI IWE Program requirements.
Spot Coating Repair of Submerged Areas The need for spot coating will continue to be evaluated following each inspection, and any repairs made will be in accordance with the plant's ASME Section XI Repair/Replacement Program. , Visual Inspection of Vapor Area All visual inspections of the torus vapor phase will be conducted in accordance with ASME Section XI, Subsection IWE requirements.
Spot Coating Repair of Vapor Area SNC plans to spot repair the coating on HNP Unit 1 and Unit 2 as necessary.
All spot repairs of the torus vapor phase will be conducted in accordance with ASME Section XI, Subsection IWE repair/replacement requirements.
Ultrasonic Testing (UT) Enclosure Page 46 of 81 SNC has included supplemental provisions in the IWE program to check and monitor wall degradation of both Units 1 and 2 torus surfaces.
Beginning with Unit 2 in 1998 and Unit 1 in 1999, SNC will perform ultrasonic (UT) thickness measurements in each torus bay of both Units 1 and 2. These measurements include selection of one grid location near the bottom in each torus bay. After the initial inspections, SNC will repeat the inspections every other outage to monitor degradation rates and their impact on Code minimum thickness.
Conclusion The above plan, in conjunction with the ASME Section XI, Subsection IWE Program, is intended to assure the integrity of the torus. Based on evaluation of the results from all previous examinations, there is currently no indication that there are any degradation concerns which impact the wall thickness or structural integrity of the torus. 3.4.3 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" The following HNP procedures provide instructions for performing inspections to satisfy the requirements of Unit 1 and Unit 2 TS SR 3.6.1 .1 .1:
- Drywell Surfaces Visual Inspection This procedure provides instructions for performing the inspection of the interior and exterior Drywell and Drywell Head surfaces to satisfy the requirements of Unit 1 and Unit 2 TS SR 3.6.1.1.1.
This procedure also provides instructions for performing the inspection of the drywell shell and head as required by the ISi Plans.
Enclosure Page 47 of 81 This procedure applies to Unit 1 and Unit 2 drywalls and drywall heads and shall be performed at least once each ISi Period and prior to each 1 O CFR 50 Appendix J ILRT.
- Venting Assembly and Suppression Chamber Surfaces Visual Inspection
- This procedure provides instructions for performing the suppression chamber (Torus) interior (vapor phase) and exterior surface inspection to satisfy the requirements of Unit 1 and Unit 2 TS, Section SR 3.6.1.1.1.
This procedure also provides instructions for performing the inspection of the torus as required by the ISi Plans. This procedure applies to Unit 1 and Unit 2 suppression chambers (T23) and shall be performed at least once each ISi Period and prior to each 10 CFR 50 Appendix J ILRT. For HNP, no additional inspections are required.
3.4.4 Primary
Containment Leakage Rate Testing Program -Type Band Type G Testing Program HNP 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 maintenance and repairs are made on these components
- throughout their service life. The Types B and C testing program provides a means to protect the health and safety of plant personnel and the public by maintaining leakage from these components below appropriate limits. In accordance with TS 5.5.12, the allowable maximum pathway total Types Band C leakage is 0.6 La where La equals approximately 272,320 standard cubic centimeters per minute (seem) (61, 102 actual cubic centimeters per minute (accm)) for Unit 1 and 254,937 seem (60,432 accm) for Unit 2. As discussed in NUREG-1493 (Reference 6), Type Band Type G 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 Type B and Type G test results from 2006 through the Spring of 2014 for HNP, Unit 1 and from 2007 through the Spring of 2015 for HNP, Unit 2 has shown margin between the actual As-Found (AF) and As-Left (AL) outage summations and the regulatory requirements as described below:
- The As-Found minimum pathway leak rate average for HNP, Unit 1 shows an average of 18.1 % of La with a high of 43.74% La.
Enclosure Page 48 of 81
- The As-Left maximum pathway leak rate average for HNP, Unit 1 shows an average of 12.2% of La with a high of 15.97% La.
- The As-Found minimum pathway leak rate average for HNP, Unit 2 shows an average of 52.3% of La with a high of greater than La.
- The As-Left maximum pathway leak rate average for HNP, Unit 2 shows an average of 25.3% of Li'i with a high of 50.43% La. Tables 3.4.4-1 and 3.4.4-2 provide local leak rate test (LLRT) data trend summaries for HNP Unit 1 and Unit 2 Inclusive of the Unit 1, 2008 ILRT and the Unit 2, 2009 ILRT. Table 3.4.4-1, Unit 1 Type 8 and C LLRT Combined As-Found/As-Left Trend Summary RFO 2008 2010 2012 2014 2016 1RF23 1RF24 1RF25 1RF26 1R27 AF Min Path 26724 8533 33435 28539 27,598 acem accm seem seem seem Fraction of 43.74 13.96 12.28 10.48 10.13 La AL Max Path 7640 8635 28370 26982 38, 162 accm accm seem seem seem Fraction of 12.50 14.13 . 10.42 9.91 14.0 La Table 3.4.4-2, Unit 2 Type 8 and C LLRT Combined As-Found/As-Left Trend Summary RFO 2007 2009 2011 2013 2015 2RF19 2RF20 2RF21 2RF22 2RF23 AF Min Path 32649 25414 Fail AF 132174 34458 aecm accm (1) seem seem Enclosure Page 49 of 81 Table 3.4.4-2, Unit 2 Type Band C LLRT Combined As-Found/As-Left Trend Summary RFO 2007 2009 2011 2013 2015 2RF19 2RF20 2RF21 2RF22 2RF23 Fraction of 54.03 42.05 Fail AF 51.84 13.52 La (1) AL Max Path 14166 12527 30479 43010 38794 accm accm accm seem seem Fraction of 23.44 20.73 50.43 16.87 15.22 La (1) During as-found LLRT testing of 2T48-F309 (CR 2011104286) and 2T48-F324 (CR 2011105199) each of these valves would not hold test pressure indicating gross leakage through the valve. These valves comprise a primary containment barrier. Given gross leakage the technical specification limit for leakage out of primary containment was exceeded.
This was reported under LEA 2011-001-1 (Reference 34). 3.4.5 Type Band Type C Local Leak Rate Testing Program Implementation Review The following Tables 3.4.5-1 and 3.4.5-2 identify the components that were on extended intervals and have not demonstrated acceptable performance during the previous two . outages for HNP, Units 1 and 2 respectively:
Table 3.4.5-1, Unit 1 Type B and C LLRT Program Implementation Review 1RF26 -2014 Component As-Admin As-left Cause of Corrective Scheduled found Limit SCCM Failure Action Interval SCCM SCCM 1 E41-F111 185,244 275 867 Seat Valve was 30 months Pen 221A (1) leakage, refurbished.
MNPLR Broken Acceptance of 64 wedge refurbished (1) valve As-left leakage by evaluation Enclosure Page 50 of 81 Table 3.4.5-1, Unit 1 Type B and C LLRT Program Implementation Review 1RF26 -2014 Component As-Admin As-left Cause of Corrective Scheduled found Limit SCCM Failure Action Interval SCCM SCCM 1T48-F335B 00 575 0 Seat Valve and valve 30 months Pen 26 (2) leakage operator MNPLR (2) refurbished 110 1RF27-2016 Component As-Admin As-left Cause Corrective Scheduled found Limit SCCM of Action Interval SCCM SCCM Failure H48-F334A 700 575 700 Not Acceptance of 30 months Pen 26 MNPLR identified valve As-left 53 leakage by evaluation.
(1) 1 E41-F111 failed as-found testing with an identified leakage rate of 185244 seem. It was discovered during performance of 42SV-TET-001-1 that 1 E41 F111 could not be brought to test pressure due to leakage through seat of this valve. Per engineering request, a set of data was recorded at less than prescribed test pressure.
At 47.5 psig measured leakage was 185,244 seem. The minimum pathway leakage rate for Penetration 221A was 64 seem. Excessive seat leakage was due to stellite breaking off the wedge on the downstream side. (2) 1T48-F111 failed as-found testing with a leakage rate of that could not be quantified.
Diagnostics indicate that there was leakage through 1T48-F335B.
The minimum pathway leakage rate for Penetration 26 was 110 seem. The valve and valve actuator were both refurbished.
Table 3.4.5-2, Unit 2 Type B and C LLRT Program Implementation Review 2RF22-2013 Component As-Admin As-left Cause of Corrective Scheduled found Limit SCCM Failure Action Interval SCCM SCCM 2B31-F019 280 150 2 Seat leakage Refurbished 30 months Pen 41 (1) valve 2T48-F319
& 76,220 4850 0 Seat leakage Refurbished 30 months F320 MNPLR (2) valve 2T48-Pen 26 0 F319 2RF23-2015 Component As-Admin found Limit SCCM SCCM 2T48-342D 00 250 Pen 225K MNPLR 0 As-left Cause of SCCM Failure 30 Leaking hose (3) Enclosure Page 51 of 81 Corrective Scheduled Action Interval Replaced hose 30 months (3) (1) 2B31-F019 failed as-found testing with an identified leakage rate of 280 seem. Diagnostic testing was performed and determined that leakage is through the seat. (2) 2T 48-F319 failed as-found testing with an identified leakage rate of 76220 seem. When the 2T 48-F319 and 2T 48-F320 were tested, the leakage was greater than test equipment upper measurable limit and test pressure could not be attained.
Diagnostic investigation determined that most of the leakage was attributable to the 2T48F319 valve. The minimum pathway leakage rate attributed to 2T48-F320 for Penetration 26 was 0 seem. (3) 2T48-342D failed as-found testing with a leakage rate of that could not be quantified.
The minimum pathway leakage rate for Penetration 225K was 0 seem. Failure was due to leaking hose outside of containment.
Hose was replaced.
No work performed inside containment.
3.4.6 Plant
Operational Performance During power operation the primary containment atmosphere is inerted with nitrogen to ensure that no external sources of oxygen are introduced into containment.
The containment inerting system is used during the initial purging of the primary containment prior to power operation and provides a supply of makeup nitrogen to maintain primary containment oxygen concentration within TS limits. As a result, the primary containment is maintained at a slightly positive pressure during power operation.
Primary containment pressure is continuously recorded and verified by TS surveillance on a frequency of every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> from the MCR. Although this feature, that is inherent to the HNP BWR containment design, does not challenge the structural and leak tight integrity of the containment system at post-accident pressure, the fact that the containment is continuously pressurized by the containment inerting system, and is periodically monitored, provides assurance that gross containment leakage that may develop during power operation will be detected.
3.5 Operating
Experience Enclosure Page 52 of 81 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 HNP Primary Containments, the following site specific and industry events have been evaluated for impact on the HNP Primary Containments:
- GL 87-05, Request for Additional Information Assessment of Licensee Measures to Mitigate and/or Identify Potential Degradation of Mark I Drywalls
- IN 1992-20, Inadequate Local Leak Rate Testing
- IN 2004-09, Corrosion of Steel Containment and Containment Liner
- IN 2010-12, Containment Liner Corrosion
- IN 2014-07, Degradation of Leak-Chase Channel Systems for Floor Welds of Metal Containment Shell and Concrete Containment Metallic Liner Each of these areas is discussed in detail in Sections 3.5.1 through 3.5.6, respectively.
3.5.1 NRC Generic Letter (GL) 87-05, Request for Additional Information Assessment of Licensee Measures to Mitigate and/or Identify Potential Degradation of Mark I Drywalls The NRC issued GL 87-05 (March 12, 1987) after reviewing reports of degraded containment (drywall) shell at Oyster Creek Nuclear Power Plant. In this GL, the NRC requested utilities to provide information relative to: (1) drainage of the sand cushion, (2) preventative maintenance and inspection activities to minimize any possible leakage from the refueling pool, (3) plans for ultrasonic thickness measurements for those drywall shells with open sand cushions, and (4) confirmation of information as listed in GL 87-05. The Oyster Creek Drywall was constructed leaving the air gap forming material in place. The refueling bellows design also incorporated a mechanical joint, which was subject to degradation and leakage when the reactor cavity was flooded and thus allowed water to leak into the air gap region. The sand cushion at Oyster Creek was constructed without a seal plate between the sand cushion and the air gap region. Oyster Creek discovered that their sand pocket and air gap drain lines were not functional and thus leakage from Enclosure Page 53 of 81 a degraded refueling bellows mechanical joint collected in the air gap and remained for a significant time period. After evaluation of the corrosion mechanisms, Oyster Creek determined that the moisture had reacted with chemicals in the sand cushion and gap forming material resulting in a corrosive environment, which led to the degradation of the carbon steel shell. Georgia Power Company, the original licensee of HNP and Sister Company of the current licensee, SNC, performed a review of GL 87-05 as applicable to HNP and responded to the NRC on May 11, 1987 (SL-2429).
The evaluation and resultant response indicated that HNP was not subject to the same conditions, which caused the drywell shell corrosion problem at Oyster Creek. Construction drawings indicated that the gap forming material was removed at Plant Hatch except for narrow rings at the elevation of each concrete pour. The refueling bellows do not contain any mechanical joints subject to degradation and subsequent leakage. The air gap drain lines were inspected utilizing a video probe an_d were all found to be functional.
Video inspection of the air gap drains did not reveal any evidence of moisture or collection of water. The sand cushion at Hatch was constructed with a metal seal plate, which would have directed any water into the air gap drain lines and prevented collection in the sand cushion. At HNP, supplemental visual exams are performed each outage for the Air Gap and Sand Cushion drain lines to ensure that the lines are functional and no corrosion mechanisms exist. These inspections are performed each refueling outage when the reactor cavity is flooded. 3.5.2 IN 88-82, Torus Shells with Corrosion and Degraded Coatings in BWR Containments The NRC issued IN 88-82 (October 14, 1988) after discovery of a degraded suppression pool (torus) shell at Nine Mile Point Nuclear Plant, Unit 1. The Nine Mile Point Unit 1 torus shell was constructed without any protective coatings and included a 1/16" corrosion allowance.
Inspection of the torus shell indicated that excessive corrosion was occurring and that the integrity of the suppression pool shell was in jeopardy.
The suppression pool at HNP was initially constructed with a protective coating on both the interior and exterior surfaces.
Both surfaces were partially re-painted in the early 1980s after completion of suppression pool modifications.
HNP has also implemented suppression pool de-sludging and visual inspection, which has resulted in some Enclosure Page 54 of 81 localized repairs, but the amount of shell degradation has been minimal. This inspection program will continue with periodic visual inspection, de-sludging, and localized repair as needed with a frequency of inspection based on the history of past inspections.
Per requests of HNP Nuclear Maintenance Support, SNC developed an augmented inspection program on the drywell shell and the torus. This program consists of taking UT measurements on 1' x 1' grids at the seven ring locations of the drywell. These grids are located at approximately the 0°, 90°, 180°, and 270° locations (28 total grids). UT , measurements are taken at a 10-year frequency since no significant degradation has been found. In addition to the drywell measurements, SNC will take UT measurements on 1' x 1' grids on all 16 bays of the torus. These measurements are taken every other outage since some degradation has occurred in the past. Measurements at exact locations are not required for the drywell and torus UT' s since these are used only to determine general corrosion rates. These measurements have shown that degradation rates for the drywell shell and torus have been minimal. 3.5.3 IN-92-20, Inadequate Local Leak Rate Testing The issue discussed in IN-92-20, 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 Integrated Leak Rate Test (ILRT) tests in the first three cases. In the event at Quad Cities the two-ply bellows design was not properly subjected to Local Leak Rate Test (LLRT) pressure and the conclusion of the utility was that the ply bellows design could not be Type B LLRT tested as configured.
In the events at both Dresden and Perry was that flanges were not considered a leakage path when the Type C LLRT test was designed.
This omission led to a leakage path that was not discovered until the plant performed an ILRT test. In the event at Clinton relief valve discharge lines that were assumed to terminate below the suppression pool minimum drawdown level were discovered to terminate at a level above that datum. These lines needed to be reconfigured and the valves should have been Type C LLRT tested. The applicability review performed at HNP indicated that only the bellows LLRT issues were found at Plant Hatch. The other issues identified in the IN were not a problem at HNP due to system configuration or the current LLRT program. The bellows issue was carefully considered and a number of actions taken to prevent the bellows installed at HNP from becoming a cause of ILRT test failure. Several bellows were tested by welding a plate inside containment so that the bellows could be tested properly.
The Enclosure Page 55 of 81 LLRT test method for bellows was revised. The ILRT procedure was revised to incorporate methodical leak detection walk down section. Mechanical Bellows Consistently Exceeding the Administrative Limit of 500 seem The following Table 3.5.3-1, Significant Leaking Bellows identifies all of the HNP Unit 1 and Unit 2 Mechanical Bellows, which have identified leakage rates in excess of the 500 seem administrative limit and are also tested each refueling outage: Table 3.5.3-1, Significant Leaking Bellows Penetration Exceeded Range-seem Projected End Current No. Admin Short Term of Life Guidance Mechanical Limit-year Trend Leakage-Bellows seem Last LLRT-seem (Average Outage/Date Change per RFO) 936-6216 1T23-X7A 2002 Increasing 9000 Track and Main Steam (660) Trend Line 6216 1 RF27/2016 656-1332 Track and 1T23-X8 2004 Increasing 2500 Trend Condensate (97) Drain 1332 1 RF27/2016 5629-7594 2T23-X8 1997 Decreasing 3500 Track and Condensate (179) Trend Drain 5629 2RF23/2015 625-716 2T23-X10 1997 Steady 750 Track and RCIC Steam (8) Trend 716 2RF23/2015 3236-5790 2T23-X11 1997 Increasing 5900 Track and HPCrSteam (232) Trend 4676 2RF23/2015 Table 3.5.3-1, Significant Leaking Bellows Enclosure Page 56 of 81 Penetration Exceeded Range-seem Projected End Current No. Admin Short Term of Life Guidance Mechanical Limit-year Trend Leakage-Bellows seem Last LLRT-seem (Average Outage/Date Change per RFO) 511 -771 2T23-X12 1997 Increasing 825 Track and RHR Suction (24) Trend 771 2RF23/2015 5430-7324 2T23-X42 1997 Increasing 7900 Track and Standby Liquid (172) Trend Control 6280 2RF23/2015 Current Procedural Guidance
- LLRT Engineer to continue trending for degradation.
- IF trend indicates penetration will exceed 5% of La prior to end of plant license, THEN repair prior to exceeding 5% level (currently no bellows predicted to exceed 5%).
- IF tested leakage of any Type B penetration unexpectedly exceeds 5% of La, THEN repair penetration the next refuel outage provided analysis supports an additional fuel cycle. IF analysis does not support an additional cycle, THEN repair immediately.
3.5.4 IN 2004-09, Corrosion of Steel Containment and Containment Liner The NRC issued this information notice to alert addressees to recent occurrences of corrosion in freestanding metallic containments and in liner plates of reinforced and stressed concrete containments.
Any corrosion (metal thinning) of the liner plate or freestanding metallic containment could change the failure threshold of the containment under a challenging environmental or accident condition.
Thinning changes, the geometry of the containment shell or liner plate, which may reduce the design margin of safety against postulated accident and environmental loads. Recent experience has Enclosure Page 57 of 81 shown that the integrity of the moisture barrier seal at the floor-to-liner or containment junction is important in avoiding conditions favorable to corrosion and thinning of the containment liner plate material.
Inspections of containment at the floor level, as well as at higher elevations, have identified various degrees of corrosion and containment plate thinning.
The containment structure at Plant Hatch is steel and is inspected under the plant's ISi plan. The inspections are accomplished by procedures 42SV* T23*003-0, Drywall Surfaces Visual Inspection; and 42SV-SUV-047-0, Venting Assembly and Suppression Chamber Surfaces Visual Inspection.
These procedures address examinations to be performed which are associated with the Containment Inspection Program. The procedures define the requirements for visual examination on the drywall shell, associated drain lines and the suppression pool interior and exterior surfaces.
Both coated and uncoated surfaces in the drywall and torus are monitored.
Additionally, the Drywall wall does not stop at the floor level, but progresses as one continuous piece under the drywall floor area. Inside the Drywall at the intersection of the Drywall shell and concrete floor, plant design requires a joint (mastic) sealing compound around the entire circumference of the Drywall. Areas under the mastic seal, on the Drywall surface, have previously been inspected for corrosion during repairs to the mastic seal. When inspected by representatives of the SNC Materials and Inspection Services Group and plant site personnel (using ultrasonic readings), some areas located under the mastic compound were found to be pitted. The steel thickness of the Drywall wall was evaluated and found to meet minimum thickness requirements.
The areas of pitting were coated prior to reinstallation of the new mastic seal. The results of a review of the data packages for Containment ISi of Unit 1, per T23-003-0S (Drywall Surfaces Visual Inspection, currently version 1.7), performed during the 2016 refueling outage and Unit 2 during the 2014 refueling outage, revealed that there were no reportable indications.
Therefore, there were no indications of significant corrosion of the Drywall shells. The Nitrogen lnerting System (NIS) must also be evaluated to determine its impact (if any) on moisture content (and subsequent corrosion) of the drywall environment.
Per 5.2.2.9 of the Unit 1 FSAR, the NIS system is "capable of reducing the oxygen content of the primary containment atmosphere to less than 4% by volume. The system is also capable of maintaining the oxygen content of the primary containment to less than 4% by volume during normal plant operation and following a Design Basis Accident." Therefore, there is normally a very small amount of oxygen within the drywall area. This being the case, at any time, only a small amount of corrosion could be supported in the drywall area, if all other required parameters were met. Based on the existence, continuance, and results of those monitoring programs, no additional actions in response to IN 2004-09 were deemed necessary.
3.5.5 IN 2010-12, Containment Liner Corrosion Enclosure Page 58 of 81 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 had been 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 form when the wall was poured. But the result in both cases was that the material trapped against the steel liner plate leading to corrosion.
In the third case, Salem, an insulating material placed between the concrete floor and the steel liner plate adsorbed moisture and led to corrosion of the liner plate. All three events reported issues with water trapped on the exterior side of the containment.
This event should not occur in HNP because HNP proactively examines for any adverse trending by performing the air gap and sand cushion inspections for evidence of water each refueling outage and have been doing so for many years. The situation that occurred in Salem is likely to take place at HNP if a 100% inspection of the moisture barrier and above surfaces is not completed.
HNP should not experience the event that took place in Beaver Valley and Brunswick, given that efforts were taken to remove any forming material.
Below is a section taken from the ISi Plan Volume 5, which describes other actions taken in the past that ensures that this event does not take place in Plant Hatch:
- Construction drawings indicated that the gap forming material was removed at Plant Hatch except for narrow rings at the elevation of each concrete pour.
- The ai,r gap drain lines were inspected utilizing a video probe and were all found to be functional.
Video inspection of the air gap drains did not reveal any evidence of moisture or collection of water.
- The sand cushion at Hatch was constructed with a metal seal plate, which would have directed any water into the air gap drain lines and prevented collection in the sand cushion. Since March 12, 1987 the NRC has taken interest on how operating nuclear plants assure that the integrity of the primary containment is not compromised.
Because of this interest from the NRC and the importance of the integrity of our Primary Containment, HNP designed the "Containment Inspection Program".
This program is comprised of existing plant programs and procedures in order to provide a complete and comprehensive program for examination of the pressure retaining surfaces of containment, structures that are part of reinforcement and any associated permanent attachment.
Enclosure Page 59 of 81 The following documents provide assurance and instruction on how to do the necessary task to maintain the integrity of the containment.
- Fifth Ten-Year Examination Plan (ISi Plan) This plan provides a summary of all the examinations and tests applicable to components treated as Class MC. It provides the appropriate schedule, period for implementing each exam/test.
- SNC In-Service Inspection Engineering Program This is an administrative control procedure, which establishes provisions for the implementation of a program, which satisfies the requirements of the ASME Section XI Code as required by TRM Section T3.4.2.1 (Structural Integrity).
In particular, this procedure applies to the implementation of the In-Service Inspection Program, in which containment inspection is a part of, and the Repair Replacement (R&R) program.
- Drywall Surfaces Visual Inspection This procedure provides instruction on how to perform the inspection of the interior Drywall surfaces and Interior and Exterior Drywall Head surfaces in order to satisfy TS SR 3.6.1.1.1:
11 Perform required visual examinations and leakage rate testing, except for primary containment air lock testing, in accordance with the primary Containment Leakage Rate Testing Program.11 It also provides instruction for performing the inspection per the ISi Plan requirements.
This is done every outage by the QC personnel.
After the inspection they submit the findings to the engineer, who will evaluate condition and decide if conditions identified are acceptable or not.
- Venting Assembly and Suppression Chamber Surfaces Visual Inspection This procedure provides instruction on how to perform the inspection of the interior (vapor phase) and exterior surfaces of the Suppression Chamber to satisfy requirements specified in TS Section SR 3.6.1.1.1.
It also provides instruction for performing the inspection per the ISi Plan requirements.
This is done every outage by the QC personnel who go out and inspect the respective areas. After inspection is done, QC will submit the findings to the responsible engineer, who will evaluate and decide if any further action is needed.
- Nuclear Coatings Program Enclosure Page 60 of 81 This procedure establishes the responsibilities for implementing and maintaining and periodically assessing the effectiveness of the Protective Coatings Program.
- Procedure for Coating Condition Assessments This procedure provides the method for performing condition assessments of Service Level I coatings used by SNC. This may also be used for performing condition assessments on non-safety related coatings and Service Level II and Ill coatings.
This addresses frequency, documentation and corrective action to be performed.
- Primary Containment Integrated Leakage Rate Testing This procedure establishes the criteria and detailed procedure to demonstrate that containment leakage at a design basis accident pressure does not exceed the acceptance limit specified in the TS SR 3.6.1.1.1.
This procedure also provides for containment structural inspection prior to each Type A Test and at a periodic interval between tests based on performance of the containment system.
- Visual Examination of the Drywell Air Gap and Sand Cushion Drain Lines This procedure addresses examinations, which are associated with the Containment Inspection Program but not required by the ASME Code,Section XI; however, they have been included in the Fifth Ten-Year Examination Plan Edwin I. Hatch Nuclear Plant. This inspection is done every outage. The engineer goes out and examines the discharge end of each sand cushion drain line as well as the air gap drain line for evidence of water each refueling outage while the reactor cavity is flooded. One reason for this test is to address the integrity of the refueling bellows. If a small quantity of water is observed in these areas, the situation can be addressed to minimize the water trapped in the sand cushion. If this situation is not addressed and a large amount of water is trapped in the cushion, the water could rust the outer wall of the drywell, thus compromising the integrity of our primary containment.
As a final point, the structural integrity of the HNP primary containment is vital for the generation of electricity as well as for the safety of plant personnel and the public. It is for this reason that this compendium of programs and procedures provide the guidance to ensure that the Primary Containment will not be compromised.
3.5.6 IN 2014-07, Degradation of Leak-Chase Channel Systems for Floor Welds of Metal Containment Shell and Concrete Containment Metallic Liner Enclosure Page 61 of 81 The containment basemat metallic shell and liner plate seam welds of pressurized water reactors 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 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 Gunction) 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. Plant Hatch does not have leak chase channels attached to its containment vessel, thus they would not have these leak chase test connections.
Subsequently no other known penetrations are known to exist to have contact with the inaccessible portions of the containment liner. 3.5.7 Results of recent Inspections Drvwell Air Gap Drain Lines and Drywell Sand Pocket Drain Lines 2016 Outage (1 R27) and 2015 Outage (2R23) All four drywell air gap drain lines and all four drywell sand pocket drain lines were visually examined to determine the existence or evidence of moisture and/or leakage. No moisture or leakage was observed at any drain line. There was no evidence of leakage identified.
Drvwell Ultrasonic Thickness Measurements 2014 Outage (1 R26) Examination Description Eight (8) drywell shell rings were examined in accordance with the Hatch Unit 1 Class MC Component Surveillance Schedule listed in the Fourth Ten-Year lnservice Inspection Plan. These exams were conducted to determine the relative condition of the Enclosure Page 62 of 81 primary containment shell. An ultrasonic test to obtain wall thickness measurements was performed on each of the eight (8) shell rings at the 0, 90, 180, and 270 degree azimuths using a 12" x 12" grid. Examination Results Based on the wall thickness measurements that were taken for each the eight (8) shell rings, there has been no significant change in the relative condition of the drywell since the drywell shell wall thickness measurements were taken during Outage 1 R21 in 2004. The minimum and maximum wall thickness values from the 2014 outage were compared against those taken during the 2004 outage. The minimum wall thickness values were compared to the nominal ring thicknesses, and there is presently no indication that the drywell shell wall thickness of the shell rings has degraded such that it is less than the nominal wall thickness.
2015 Outage (2R23) Examination Description Seven (7) drywell shell rings were examined in accordance with the Hatch Unit 2 Class MC Component Surveillance Schedule listed in the Fourth Ten-Year lnservice Inspection Plan. These exams were conducted to determine the relative condition of the primary containment shell. An ultrasonic test to obtain wall thickness measurements was performed on each of the seven (7) shell rings at the 0, 90, 180, and 270 degree azimuths using a 12" x 12" grid. Examination Results Based on the wall thickness measurements that were taken for each the seven (7) shell rings, there has been no significant change in the relative condition of the drywell since the drywell shell wall thickness measurements were taken during Outage 2R18 in 2005. The minimum and maximum wall thickness values from the 2015 outage were compared against those taken during the 2005 outage. The minimum wall thickness values were compared to the nominal ring thicknesses, and there is presently no indication that the drywell shell wall thickness of the shell rings has degraded such that it is less than the nominal wall thickness.
Torus Ultrasonic Thickness Measurements 2014 Outage (1 R26) Examination Description The submerged portion of the torus shell at each of the sixteen (16) torus bays was examined in accordance with HNP-1 Fourth Ten-Year Interval lnservice Inspection Plan, Volume 5 (IWE), Version 6. Wall thickness measurements were taken on the submerged portion of the torus shell at each of the sixteen torus bays and were recorded on an Ultrasonic Thickness Report. These examinations for wall thickness Enclosure Page 63 of 81 were conducted in order to determine the relative condition of the torus shell. Each bay was tested using a 12" x 12" grid located on each torus bay. Examination Results Based on the wall thickness measurements that were taken for each of the sixteen torus bays, there has been no significant change in the relative condition of the torus since torus shell wall thickness measurements were taken during Outage 1 R24 in 2010. The minimum and maximum wall thickness values from the 2014 outage were compared against those taken during the 2010 outage. The minimum wall thickness values were compared to the torus nominal thickness value (0.594"), and there is presently no indication that the wall thickness of the torus bays has degraded such that they are less than the nominal wall thickness.
Comparison of the 2010 and 2014 wall thickness measurements demonstrated continued adequacy of the current torus shell wall thickness condition.
2013 Outage (2R22) Examination Description On February 7,2013, the submerged portion of the torus shell at each of the sixteen (16) torus bays was examined in accordance with the HNP-2 Fourth Ten-Year Interval lnservice Inspection Plan, Volume 5 (IWE), Version 4.0. Wall thickness measurements were taken of the submerged portion of the torus shell at each of the sixteen torus bays. Each bay was examined using a 12" x 12" grid located on each torus bay. Examination Results Based on the wall thickness measurements that were taken for each of the sixteen torus bays, there has been no significant change in the relative condition of the torus since torus shell wall thickness measurements were last taken during Outage 2R20 in 2009. The minimum wall thickness values from the 2013 outage were compared against those taken during the 2009 outage. No maximum wall thickness measurements were identified for the examinations conducted in 2009. The minimum wall thickness values from the 2009 and 2013 outages were compared to the torus shell nominal wall thickness of 0.594 inches. There is presently no indication that the torus shell wall thickness of the torus bays has degraded such that they are less than the nominal wall thickness of 0.594 inches. Drvwell Surfaces Visual Inspection 2016 Outage (1 R27) Examination Description Interior and Exterior Surfaces (including personnel air lock and equipment hatches) of Drywell, as well as performing a general visual exam of the Mastic Seal, Interior and Exterior Surfaces of Drywell Head, Venting Assembly, Torus Interior, Torus Exterior and Support Inspection.
Examination Results Inspection findings were characterized as follows: Enclosure Page 64 of 81
- Exterior surface of the Torus -Areas of missing paint, flaking paint, unqualified coatings and delaminated coatings on torus shell. Areas of corrosion, rusting on torus shell.
- Interior surface of the Torus -Areas of corrosion on torus shell.
- Interior Surface of the Vent Pipe, Vent Header and Downcomers
-Areas of flaking paint, unqualified coatings and delaminated coatings.
- Interior surface of the Drywell -Areas of flaking paint, blistering and missing paint. Two 6 inch areas where the mastic has separated from the edge of the edge of the floor. None of the items identified were determined to need immediate repair. 2011 Outage (2R21) Examination Description Interior and Exterior Surfaces (including personnel air lock and equipment hatches) of Drywell, as well as performing a general visual exam of the Mastic Seal, Interior and Exterior Surfaces of Drywell Head, Venting Assembly, Torus Interior, Torus Exterior and Support Inspection.
Examination Results Inspection findings were characterized as follows:
- Mastic seal -Unknown chemical reacted with existing mastic seal causing it to become unstable.
Repair completed.4/23/2011.
Areas in which corrosion was noted were identified as areas to be monitored.
CRs as well as degraded coatings were logged and the respective were created to fix the condition.
3.6 License
Renewal Aging Management The renewed operating licenses for HNP Unit 1 and Unit 2 were issued on January 15, 2002, after NRC review of the license renewal applications submitted in February 2000. As such, the original licensed term of operation of 40 years was extended to 60 years, with the renewal term for HNP Unit 1 ending August 6, 2034, and for HNP Unit 2 on June 13, 2038.
Enclosure Page 65 of 81 As part of the process of obtaining renewed operating licenses, SNC was required to demonstrate that certain aging effects would be adequately managed for the term of the renewed operating licenses.
The process used to demonstrate adequate aging management to the NRC included the grouping of various aging management activities into 31 aging management programs.
The license renewal rule, 10 CFR 54, requires that a description of these aging management programs become part of the FSAR. As such, sections 18.2 through 18.6 are incorporated into the FSAR as approved by the NRC during the license renewal process. The program and activity descriptions in FSAR sections 18.2 through 18.6 represent the HNP Unit 1 and Unit 2 commitments for managing aging of the in-scope systems, structures, and components during the period of extended operation.
The following Programs, which are part of the supporting basis for this LAR, are also Aging Management Programs for HNP Unit 1 and Unit 2:
- Protective Coatings Program (PCP) The PCP provides a means of preventing or minimizing loss of material that would otherwise result from contact of the base material with a corrosive environment.
The PCP is a mitigation and condition monitoring program designed to provide base metal aging management through surface application, maintenance, and inspection of protective coatings on selected components and structures.
- Primary Containment Leakage Rate Testing Program (PCLRTP) The PCLRTP satisfies the requirements that primary containment meets the leakage-rate test requirements in either option A or B of 10 CFR 50, Appendix J. HNP has opted for option B which identifies the performance-based requirements and criteria for preoperational and subsequent periodic leakage-rate testing. This program is designed to ensure that (a) leakage through the primary containment or systems and components penetrating the primary containment does not exceed allowable leakage rates specified in the Technical Specifications and (b) integrity of the containment structure is maintained during its service life. The PCLRTP manages the aging effect of loss of material.
- lnservice Inspection Program (ISi) The ISi program is a condition monitoring program that provides for the implementation of ASME Section XI in accordance with the provisions of 10 CFR 50.55a. The ISi program also includes augmented examinations required to satisfy commitments made by SNC. The 10-year examination plan provides a systematic guide for performing required examinations.
The period of extended operation will include the fifth and sixth ISi intervals.
Only a portion of the ISi program is credited for license renewal. 3.7 NRC SER Limitations and Conditions Enclosure Page 66 of 81 3.7.1 Limitations and Conditions Applicable to NEI 94-01 Revision 2-A The NRC staff found that the use of NEI TR 94-01, Revision 2, was acceptable for referencing by licensees proposing to amend their TSs to permanently extend the ILRT surveillance interval to 15 years, provided the following conditions as listed in Table 3.7.1-1 were satisfied:
Table 3.7.1-1: NEI 94-01, Revision 2-A, Limitations and Conditions Limitation/Condition (From Section 4.0 of SE) HNP Resoonse For calculating the Type A leakage rate, the HNP will utilize the definition in NEI 94-01 licensee should use the definition in the NEI Revision 3-A, Section 5.0. This definition has TR 94-01, Revision 2, in lieu of that in remained unchanged from Revision 2-A to ANSl/ANS-56.8-2002. (Refer to SE Revision 3-A of NEI 94-01. Section 3.1.1.1.)
The licensee submits a schedule of Reference Tables 3.4.2-2 and 3.4.2-3 of this containment inspections to be performed submittal.
prior to and between Type A tests. (Refer to SE Section 3.1.1.3.)
The licensee addresses the areas of the Reference Sections 3.4.2 and 3.5 of this containment structure potentially subjected to submittal.
degradation. (Refer to SE Section 3.1.3.) The licensee addresses any tests and There are no major modifications planned. inspections performed following major modifications to the containment structure, as applicable. (Refer to SE Section 3.1.4.) The normal Type A test interval should be HNP will follow the requirements of NEI 94-01 less than 15 years. If a licensee has to utilize Revision 3-A, Section 9.1, This requirement the provision of Section 9.1 of NEI TR 94-01, has remained unchanged from Revision 2-A Revision 2, related to extending the ILRT to Revision 3-A of NEI 94-01. interval beyond 15 years, the licensee must demonstrate to the NRG staff that it is an In accordance with the requirements of 94-01 unforeseen emergent condition. (Refer to SE Revision 2-A, SER Section 3.1.1.2, HNP will Section 3.1.1.2.)
also demonstrate to the NRG staff that an unforeseen emergent condition exists in the event an extension beyond the 15-year interval is required.
Enclosure Page 67 of 81 Table 3.7.1-1: NEI 94-01, Revision 2-A, Limitations and Conditions Limitation/Condition (From Section 4.0 of SEl HNP Resoonse For plants licensed under 1 O CFR Part 52, Not applicable.
HNP was not licensed under applications requesting a permanent 1 O CFR Part 52. 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. 3.7.2 Limitations and Conditions Applicable to NEI 94-01 Revision 3-A The NRC staff found that the guidance in NEI TR 94-01, Revision 3, was acceptable for referencing by licensees in the implementation for the optional performance-based requirements of Option 8 to 10 CFR 50, Appendix J. However, the NRC staff identified two conditions on the use of NEI TR 94-01, Revision 3 (Reference NEI 94-01 Revision*
3-A, NRC SER 4.0, Limitations and Conditions):
Topical Report Condition 1 NEI TR 94-01, Revision 3, is requesting that the allowable extended interval for Type C LLRTs be increased to 75 months, with a permissible extension (for non-routine emergent conditions) of nine months (84 months total). The staff is allowing the extended interval for Type C LLRTs be increased to 75 months with the requirement that a licensee's post-outage report include the margin between the Type 8 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 Enclosure Page 68 of 81 Condition 1 presents three (3) separate issues that are required to be addressed.
They are as follows:
- ISSUE 1 -The allowance of an extended interval for Type C LLRTs of 75 months carries the requirement that a licensee's post-outage report include the margin between the Type B and Type C leakage rate summation and its regulatory limit.
- 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.
Response to Condition 1, ISSUE 1 The post-outage report shall include the margin between the Type B and Type C Minimum Pathway Leak Rate (MNPLR) summation value, as adjusted to include the estimate of applicable Type C leakage understatement, and its regulatory limit of 0.60 La. Response to Condition 1, ISSUE 2 When the potential leakage understatement adjusted Type Band C MNPLR total is greater than the HNP leakage summation limit of 0.50 La, but less than the regulatory limit of 0.6 La, then an analysis and determination of a corrective action plan shall be prepared to restore the leakage summation margin to less than the HNP 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 HNP will apply the 9-month grace 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 Enclosure Page 69 of 81 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 c.ontainment leakage potential, the as-found minimum pathway leakage rates for the just tested penetrations are summed with the as-left minimum pathway leakage rates for penetrations tested during the previous 1 or 2 or even 3 refueling outages. Type C tests involve valves, which in the aggregate, will show increasing leakage potential due to normal wear and tear, some predictable and some not so predictable.
Routine and appropriate maintenance may extend this increasing leakage potential.
Allowing for longer intervals between LLRTs means that more leakage rate test results from farther back in time are summed with fewer just tested penetrations and that total used to assess the current containment leakage potential.
This leads to the possibility that the LLRT totals calculated understate the actual leakage potential of the penetrations.
Given the required margin included with the performance criterion and the considerable extra margin most plants consistently show with their testing, any understatement of the LLRT total using a 5-year test frequency is thought to be conservatively accounted for. Extending the LLRT intervals beyond 5 years to a 75-month interval should be similarly conservative provided an estimate is made of the potential understatement and its acceptability determined as part of the trending specified in NEI 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 Type B and C total leakage, and must be included in a licensee's post-outage report. The report must include the reasoning and determination of the acceptability of the extension, demonstrating that the LLRT totals calculated represent the actual leakage potential of the penetrations.
Response to Condition 2 Condition 2 presents two (2) separate issues that are required to be addressed.
They are as follows:
- ISSUE 1 -Extending the LLRT intervals beyond 5 years to a 75-month interval should be similarly conservative provided an estimate is made of the potential understatement and its acceptability determined as part of the trending specified in NEI TR 94-01, Revision 3, Section 12.1.
- ISSUE 2 -When routinely scheduling any LLRT valve interval beyond 60-months and up to 75-months, the primary containment leakage rate testing program trending or monitoring must include an estimate of the amount of understatement in the Types B and C total, and must be included in a licensee's post-outage report. The report must include the reasoning and determination of the Enclosure Page 70 of 81 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, HNP 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 LLRT's being "carried forward" and will be included whenever the total leakage summation is required to be updated (either while on line or following an outage). When the potential leakage understatement adjusted leak rate total for those Type C components being tested on greater than a 60-month test interval up to the 75-month extended test interval is summed with the non-adjusted total of those Type C components being tested at less than or equal to a 60-month test interval, and the total of the Type B tested components, if the MNPLR is greater than the leakage summation limit of 0.50 La, but less than the regulatory limit of 0.6 La, then an analysis and corrective action plan shall be prepared to restore the leakage summation value to less than the HNP 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. Response to Condition 2, ISSUE 2 If the potential leakage understatement adjusted leak rate MNPLR is less than the HNP leakage summation limit of 0.50 La, then the acceptability of the greater than a 60-month test interval up to the 75-month LLRT extension for all affected Type C components has been adequately demonstrated and the calculated local leak rate total represents the actual leakage potential of the penetrations.
In addition to Condition 1, ISSUES 1 and 2, which deal with the MNPLR Type 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 ANSl/ANS-56.8-2002 and shall be available on-site for NRC review. The report shall show that the Enclosure Page 71 of 81 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 HNP, in the event an adverse trend in the aforementioned potential leakage understatement adjusted Type Band 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 HNP an adverse trend is defined as three (3) consecutive increases in the final RCS Mode Change Type Band C MNPLR leakage summation values, as adjusted to include the estimate of applicable Type C leakage understatement, as expressed in terms of La. 3.8 Conclusion NEI 94-01, Revision 3-A, dated July 2012, and the conditions and limitations specified in NEI 94-01, Revision 2-A, dated October 2008, describe an NRG-accepted approach for implementing the performance-based requirements of 10 CFR 50, Appendix J, Option B. It incorporates the regulatory positions stated in RG 1.163 and includes provisions for extending Type A intervals to 15 years and Type C test intervals to 75 months. NEI 94-01, Revision 3-A delineates a performance-based approach for determining Type A, Type B, and Type C containment leakage rate surveillance test frequencies.
HNP is adopting the guidance of NEI 94-01, Revision 3-A, and the conditions and limitations specified in NEI 94-01, Revision 2-A, for the HNP, Units 1 and 2, 10 CFR 50, Appendix J testing program plan. Based on the previous ILRTs conducted at HNP, 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 and the overlapping inspection activities performed as part of the following HNP, Units 1 and 2 inspection programs:
- Containment Inspection Program (Class MC/IWE)
- Containment Inspections per TS SR 3.6.1 .1.1
- Protective Coatings Program Enclosure Page 72 of 81 This experience is supplemented by risk analysis studies, including the HNP, Units 1 and 2 risk analysis provided in Attachment
- 3. The risk assessment concluded that increasing the ILRT interval to 15 years is considered to represent an insignificant change in risk for HNP.
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(0) 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, 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 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) indicates that, in general, the risk impact associated with ILRT interval extensions for intervals up to 15 years is small. However, plant-specific confirmatory analyses are required.
The NRC staff reviewed NEI TR 94-01, Revision 2, and EPRI Report No. 1009325, Revision 2. For NEI TR 94-01, Revision 2, the NRC staff determined that it described an acceptable approach for implementing the optional performance-based requirements Enclosure Page 73 of 81 of Option B to 1 O CFR 50, Appendix J. This guidance includes provisions for extending Type A ILRT intervals to up to 15 years and incorporates the regulatory positions stated in RG 1.163. The NRC staff finds that the Type A testing methodology as described in ANSl/ANS-56.8-2002, and the modified testing frequencies recommended by NEI TR 94-01, Revision 2, serves 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 Band Type C leakage rates support the leakage tightness of primary containment by minimizing potential leakage paths. For EPRI Report No. 1009325, Revision 2, a risk-informed methodology using specific risk insights and industry ILRT performance data to revise ILRT surveillance frequencies, the NRC staff finds that the proposed methodology satisfies the key principles of risk-informed decision making applied to changes to TSs as delineated in RG 1.177 and RG 1.174. The NRC staff, therefore, found that this guidance was acceptable for referencing by licensees proposing to amend their TS in regards to containment leakage rate testing, subject to the limitations and conditions noted in Section 4.2 of the Safety Evaluation Report (SER). The NRC staff reviewed NEI TR 94-01, Revision 3, and determined that it described an acceptable approach for implementing the optional performance-based requirements of Option B to 10 CFR 50, Appendix J, as modified by the conditions and limitations summarized in Section 4.0 of the associated Safety Evaluation.
This guidance included provisions for extending Type C LLRT intervals up to 75 months. Type C testing ensures that individual containment isolation valves are essentially leak tight. In addition, aggregate Type C leakage rates support the leakage tightness of primary containment by minimizing potential leakage paths. The NRC staff, therefore, found that this guidance, as modified to include two limitations and conditions, was acceptable for referencing by licensees proposing to amend their TS in regards to containment leakage rate testing. Any applicant may reference NEI TR 94-01, Revision 3, as modified by the associated SER and approved by the NRC, and the conditions and limitations 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)
Enclosure Page 74 of 81
- Comanche Peak Nuclear Power Plant, Units 1 and 2 (Reference
- 36) 4.3 No Significant Hazards Consideration Southern Nuclear Operating Company (SNC) has evaluated whether or not a significant hazards consideration is involved with the proposed amendment by focusing on the .three standards set forth in 10 CFR 50.92, "Issuance of amendment," as discussed below: 1. Does the proposed amendment involve a significant increase in the probability or consequences of an accident previously evaluated?
Response:
No. The proposed amendment to the Technical Specifications (TS) involves the extension of the Edwin I. Hatch Nuclear Plant (HNP), 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 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 current Type C test interval of 60 months for selected components would be extended on a performance basis to no longer than 75 months. Extensions of up to nine months (total maximum interval of 84 months for Type C tests) are permissible only for non-routine emergent conditions.
The proposed 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 Type A test frequency from three in ten years to one in fifteen years, measured as an increase in the total integrated plant dose risk for those accident sequences influenced by Type A testing, is 9.90E-03 person-rem/yr using the Electric Power Research Institute (EPRI) guidance values, and drops to 1.96E-03 person-rem/yr using the EPRI Expert Elicitation values. Therefore, this proposed extension does not involve a significant increase in the probability of an accident previously evaluated.
In addition, as documented in NUREG-1493, "Performance-Based Containment Leak-Test Program," Types Band 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 HNP, Units 1 and 2 Type A test history supports this conclusion.
Enclosure Page 75 of 81 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 leakage rate test (LLRT) requirements and administrative controls such as configuration management and procedural requirements for system restoration ensure that containment integrity is not degraded by plant modifications or maintenance activities.
The design and construction requirements of the containment 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 extensions do not significantly increase the consequences of an accident previously evaluated.
The proposed amendment also deletes exceptions previously granted to allow time extensions of the ILRT test frequency for both Units 1 and 2. These exceptions were for activities that have already taken place; therefore, their deletion is solely an administrative action that has no effect on any component and no physical impact on how the units are operated.
Therefore, the proposed change does not result in a significant increase in the probability or consequences of an accident previously evaluated.
- 2. Does the proposed change create the possibility of a new or different kind of accident from any accident previously evaluated?
Response:
No. The proposed amendment to the TS involves the extension of the HNP, Unit 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 change to the plant (i.e., no new or different type of equipment will be installed) nor does it alter the design, configuration, or change the manner in which the plant is operated or controlled beyond the standard functional capabilities of the equipment.
The proposed amendment also deletes exceptions previously granted to allow time extensions of the ILRT test frequency for both Units 1 and 2. These exceptions were for activities that would have already taken place by the time this amendment is approved; therefore, their deletion is solely an administrative action that does not result in any change in how the units are operated.
Enclosure Page 76 of 81 Therefore, the proposed change does not create the possibility of a new or different kind of accident from any 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 HNP, 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 only the extension of the interval between Type A containment leak rate tests and Type C tests for HNP, 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, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J," Revision 3-A. Industry experience supports the conclusion that Type 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 XI, 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 Type A, 8, 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 both HNP Units 1 and 2. These exceptions were for activities that have taken place; therefore, their deletion is solely an administrative action and does not change how the units are 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.
Enclosure Page 77 of 81 Based on the above, SNC concludes that the proposed amendment does not involve a significant hazards consideration under the standards set forth in 10 CFR 50.92(c), and, accordingly, a finding of no significant hazards consideration is justified.
4.4 Conclusion
In conclusion, based on the considerations discussed above, (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) such activities will be conducted in compliance with the Commission's regulations, and (3) the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public. 5.0 ENVIRONMENTAL CONSIDERATION A review has determined that the proposed amendment would change a requirement with respect to installation or use of a facility component located within the restricted area, as defined in 10 CFR 20, or would change an inspection or surveillance requirement.
However, the proposed amendment does not involve (i) a significant hazards consideration, (ii) a significant change in the types or significant increase in the amounts of any effluent that may be released offsite, or (iii) a significant increase in individual or cumulative occupational radiation exposure.
Accordingly, the proposed amendment meets the eligibility criterion for categorical exclusion set forth in 10 CFR 51.22(c)(9).
Therefore, pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the proposed amendment.
6.0 REFERENCES
- 1. Regulatory Guide 1.163, Performance-Based Containment Leak-Test Program, September 1995 2. NEI 94-01, Revision 3-A, Industry Guideline for Implementing Based Option of 10 CFR 50, Appendix J, 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, 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, March 2009 Enclosure Page 78 of 81 5. NEI 94-01, Revision 0, Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J, July 1995 6. NUREG-1493, Performance-Based Containment Leak-Test Program, January 1995 7. EPRI TR-104285, Risk Impact Assessment of Revised Containment Leak Rate Testing Intervals, August 1994 8. NEI 94-01, Revision 2-A, Industry Guideline for Implementing Based Option of 10 CFR 50, Appendix J, October 2008 9. Letter from M. J. Maxin (NRC) to J. C. Butler (NEI), dated June 25, 2008, 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) 10. Letter from S. Bahadur (NRC) to B. Bradley (NEI), dated June 8, 2012, Final Safety Evaluation of Nuclear Energy Institute (NEI) Report 94-01, Revision 3, Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, AppendixJ (TAC No. ME2164) 11. Boiling Water Reactors Owners' Group, BWROG PSA Peer Review Certification Implementation Guidelines, Revision 3, January 1997 12. Draft Regulatory Guide DG-1122, An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities, November 2002 13. Letter from S. Bloom (NRC) to H. Sumner (SNC), dated September 23, 2003, Edwin I. Hatch Nuclear Plant, Unit 1 and 2 -Issuance of Amendments Regarding Appendix K Measurement Uncertainty Recovery, (ML032590944)
- 14. Letter from L. Olshan (NRC) to H. Sumner (SNC), dated February 20, 2002, Edwin I. Hatch Nuclear Plant, Unit 1-Issuance of Amendment Re: Amendment Revises TS 5.5.12 to Allow a One-Time Deferral of the Type A Containment Integrated Leak Rate Test Based on the Risk-Informed Guidance in Regulatory Guide 1.174. (TAC No. MB2842) 15. Letter from C. Gratton (NRC) to H. Sumner (SNC), dated February 1, 2005, Edwin I. Hatch Nuclear Plant, Unit 2 Re: Issuance of Amendment Revising the Enclosure Page 79 of 81 Technical Specifications for the Primary Containment Leakage Rate Testing Program (TAC No. MC2761) 16. Letter from C. Gratton (NRG) to H. Sumner (SNC), dated May 28, 2004, Edwin I. Hatch Nuclear Plant, Units 1 and 2 Re: Issuance of Amendments Revising the Technical Specifications for the Primary Containment Leakage Rate Testing Program (TAC Nos. MC1432 and MC1433) 17. Letter from R. Martin (NRG) to D. Madison (SNC), dated August 28, 2008, Edwin I. Hatch Nuclear Plant, Unit NOS. 1 AND 2, Issuance of Amendments Regarding Alternate Source Term (TAC Nos. MD2934 and MD2935) 18. Letter from R. Ennis (NRG) to M. Pacilio (Exelon), dated August 25, 2014, Peach Bottom Atomic Power Station, Units 1 and 2 -Issuance of Amendments Re: Extended Power Uprate (TAC Nos. ME9631 and ME9632) 19. Letter from K. Jabbour (NRG) to J. Beckham Jr. (Georgia Power), dated March 6, 1996, Edwin I. Hatch Nuclear Plant, Units 1 and 2 -Issuance of Amendment Regarding the Adoption of the Requirements of 10 CFR 50, Appendix J, Option B, and the Implementation of a Performance-based Containment Leak-rate Testing Program. (TAC NOS. M94046 and M94047) 20. Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals:
Revision 2-A of 1009325. EPRI, Palo Alto, CA: October 2008. 1018243 21. Hatch Unit 1 Peer Review Report (2009), February 2010 22. Regulatory Guide 1.147, Revision 16, lnservice Inspection Code Case Acceptability, ASME Section XI, Division 1, October 2010 23. NUREG-1769, Safety Evaluation Report Related to the License Renewal of Peach Bottom Atomic Power Station, Units 1 and 2, March 2003 24. ML 14148A235, Letter to D. Heacock from S. Williams (NRG) dated July 3, 2014. Surry Power Station, Units 1 And 2 -Issuance of Amendment Regarding the Containment Type A and Type C Leak Rate Tests 25. ML15072A264, Letter to L. Weber from A. Dietrich (NRG) dated March 30, 2015. Donald C. Cook Nuclear Plant, Units 1 and 2 -Issuance of Amendments Re: Containment Leakage Rate Testing Program 26. ML15078A058, Letter to E. Larson from T. Lamb (NRG) dated April 8, 2015. Beaver Valley Power Station, Unit Nos. 1 And 2 -Issuance of Amendment Re: License Amendment Request to Extend Containment Leakage Rate Test Frequency Enclosure Page 80 of 81 27. ML 15154A661, Letter to G. Gellrich from A. Chereskin (NRG) dated July 16, 2015. Calvert Cliffs Nuclear Power Plant, Unit Nos. 1 and 2 -Issuance of Amendments Re: Extension of Containment Leakage Rate Testing Frequency
- 28. ML 15196A559, Letter to B. Hanson from R. Ennis (NRG) dated September 8, 2015. 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) 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, March 2009 31. Letter from A. Pietrangelo (NEI) to NEI Administrative Points of Contact, Time Extension of Containment Integrated Leak Rate Test Interval -Additional Information, November 30, 2001 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, Accession Number ML020920100, March 27, 2002 33. Letter from A. Pietrangelo (NEI) to NEI Administrative Points of Contact, Interim Guidance for Performing Risk Impact Assessments in Support of One-Time Extensions for Containment Integrated Leak Rate Test Surveillance Intervals, November 13, 2001 34. ML11347A198, Edwin I. Hatch Nuclear Plant -Unit 2, Licensee Event report 2011-001-01, Revision 1, Primary Containment Isolation Penetration Exceeded Overall Allowable Technical Specification Leakage Limits, December 9, 2011 35. ML 15352A294, Letter from M. Marley (NRG) to C. Pierce (SNC), Relief from the Requirements of the ASME Code (CAC Nos. MF6494 and MF6495), December 28,2015 36. ML 15309A073, Letter to R. Flores (Luminant) from B. Singal (NRG) dated December 30, 2015. 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)
Enclosure Page 81 of 81 37. Letter from A. Pietrangelo (NEI) to NEI Administrative Points of Contact, Time Extension of Containment Integrated Leak Rate Test Interval -Additional Information, November 30, 2001.
ATTACHMENT 1 Markup of Technical Specification Pages 5.0-16 TS 5.5.12 Programs and Manuals 5.5 5.5 P r ograms and Manuals (continued) 5.5.12 Primarv Containment Lea k age Rate Testing Program A prog r am shall be established to imp l ement the leakage rate testing of the primary containment as required by 10 CFR 50.54(0) 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 Test Program ," dated September 1996, as modified by the following exception to NEI 94 01, Rev. 0 , "Industry Guideline for I mp l ementing Performance Based Option of 10 CFR 60 , Appendix J": Section 9.2.3: The first Type A test after the April 1993 Type A test shall be performed no later than April 2008. The peak calculated primary containment internal pressure for the design basis loss of coolant accident, Pa. is 50.8 psig. The maximum allowable primary containment leakage rate , La. at Pa is 1.2% of primary containment air weight per day. Leakage rate acceptance criteria are: a. Primary containment overall leakage rate acceptance criterion is s 1.0 La. During the first unit startup following testing in accordance with this program, the leakage rate acceptance criteria are s 0.60 La for the combined Type Band Type C tests , and s 0.75 La for Type A tests; b. Air lock testing acceptance criteria are: 1) Overall air lock leakage rate is s 0.05 La when tested Pa. 2) For each door, leakage rate is s 0.01 La when the gap between the door seals is pressurized to 10 psig for at least 15 minutes. The provisions of SR 3.0.2 do not apply to the test frequencies specified in the Primary Containment Leakage Rate Testing Program. NEI 94-01 , "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 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." (continued)
HATCH UNIT 1 5.0-16 Amendment No. 244 Programs and Manuals 5.5 5.5 Programs and Manuals (continued) 5.5.12 Primary Containment Leakage Rate Testing Program A program shall be established to implement the leakage rate testing of the primary containment as required by 10 CFR 50.54(0) 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 , " Perfermanoe Based Containment Leak Test Program ," dated September 1995 , as modified by the following exeeption to NEI 94 01 , Rev. 0 , " Industry Guideline for Implementing Perfermanoe Based Option of 10 CFR 50 , Appendix J": Seetion 9.2.3: The first Type A test after the November 2 , 1995 , Type A test shall be performed no later than November 2010. The peak calculated primary containment internal pressure for the design basis loss of coolant accident , Pa. is 47.3 psig. The maximum allowable primary containment leakage rate, La. at Pa is 1.2% of primary containment air weight per day. Leakage rate acceptance criteria are: a. Primary containment overall leakage rate acceptance criterion is s 1.0 La. During the first unit startup following testing in accordance with this program, the leakage rate acceptance criteria are s 0.60 La for the combined Type Band Type C tests, and s 0.75 L a for Type A tests; b. Air lock testing acceptance criteria are: 1) Overall air lock leakage rate is s 0.05 La when tested at s Pa. 2) For each door, leakage rate is s 0.01 La when the gap between the door seals is pressurized 10 psig for at least 15 minutes. The provisions of SR 3.0.2 do not apply to the test frequencies specified in the Primary Conta i nment Leakage Rate Testing Program. NEI 94-01, "Industry Guideline for Implementing Based Option of 10 CFR Part 50, Appendix J," Revision 3-A , dated July 2012, and the conditions and limitations specified iri NEI 94-01, Revision 2-A , dated October 2008." (continued}
HATCH UNIT2 5.0-16 Amendment No. 487 ATTACHMENT 2 Markup of Technical Specification Bases Pages B 3.6-4, B 3.6-5 (Unit 1) B 3.6-3 thru B 3.6-5 (Unit 2) B 3.6.1.1.1.
For Information Only BASES (continued)
ACTIONS SURVEILLANCE REQUIREMENTS NEI 94-01 Revision 3-A (Ref. 7), the Limitations and Conditions of NEI 94-01 Revision 2-A (Ref.6), and ANSI/ ANS 56.8-2002 HATCH UNIT 1 Primary Containment B 3.6.1.1 In the event primary containment is inoperable, primary containment must be restored to OPERABLE status within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Completion Time provides a period of time to correct the problem commensurate with the importance of maintaining primary containment OPERABILITY during MODES 1 , 2, and 3. This time period also ensures that the probability of an accident (requiring primary containment OPERABILITY) occurring during periods where primary containment is inoperable is minimal. 8.1 and 8.2 If primary containment cannot be restored to OPERABLE status w i thin the required Completion Time , the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and to MODE 4 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The allowed Completion Times are reasonable , based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. SR 3.6.1.1.1 Maintaining the primary containment OPERABLE requires compliance with the visual examinations and leakage rate test requirements of the Primary Containment Leakage Rate Testing Program. Failure to meet air lock leakage testing (SR 3.6.1.2.1 ), or main steam isolation valve leakage (SR 3.6.1.3.10), does not necessarily result in a failure of this SR. The impact of the failure to meet these SRs must be evaluated against the Type A , B, and C acceptance criteria of the Primary Containment Leakage Rate Testing Program. The Primary Containment Leakage Rate Testing Program is based on the guidelines in Regulatory Guide 1.168 (Ref. 6), NEI 94 01 (Ref. 7), and ANSI/ANS §6.8 1994 (Ref. 8). Specific acceptance criteria for as found and as left leakage rates , as well as the methods of defining the leakage rates, are contained in the Primary Containment Leakage Rate Testing Program. At all other times between required leakage rate tests, the acceptance criteria are based on an overall Type A leakage limit of 1.0 La. At 1.0 La. the offsite dose consequences are bounded by the a ssumptions of t he safety analysis.
The Frequency is required by the Primary Containment Leak Rate Testing Program. (continued)
B 3.6-3 REVISION§ BASES SURVEILLANCE REQUIREMENTS (continued}
REFERENCES Primary Containment B3.6.1.1 SR 3.6.1.1.2 Maintaining the pressure suppression function of primary containment requires limiting the leakage from the drywell to the suppression chamber. Thus, if an event were to occur that pressurized the drywell, the steam would be directed through the downcomers into the suppression pool. This SR measures drywell to suppression chamber differential pressure during a 10 minute period to ensure that the leakage paths that would bypass the suppression pool are within allowable limits. Satisfactory performance of this SR can be achieved by establishing a known differential pressure between the drywall and the suppression chamber and verifying that the pressure in either the suppression chamber or the drywell does not change by more than 0.25 inch of water per minute over a 10 minute period. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. 1. 2. 3. 4. 5. 6. ) 7. FSAR, Section 5.2. FSAR , Section 14.4.3. 10 CFR 50 , Appendix J , Option B. NRC No.93-102 , "Final Policy Statement on Technical Specification Improvements
," July 23 , 1993. Primary Containment Leakage Rate Testing Program. Regulatory Guide 1.163 , " Perf-Ormanee Ba s ed Conta i nment Leak Test Program ," September 1995. NEI 94-01 , *industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J ," Revision 9,-JtlJy 26 , 1995. 3-A , July 2012 NEI 94-0 1, " Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50 , Appendix J ," Revision 2-A , October 2008. (continued)
HATCH UNIT 1 B 3.6-4 REVISION 69 BASES Primary Containment B 3.6.
1.1 REFERENCES
(continued)
HATCH UNIT 1 8. ANSI/ANS 56.8 1994 , " American National Standard for Containment System t akage Testing Requirements," 1994. Ame r ican Nuclear Society , " Conta i nmen t System Leakage Test ing Requ i rements ," ANSI/ANS 56.8-2002. B 3.6-5 REVISION 69 BASES (cont i nued) ACTIONS SURVEILLANCE REQUIREMENTS Primary Conta i nment B 3.6.1.1 In the event primary containment is inoperable , p r imary conta i nment must be restored to OPERABLE status wi t hin 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Completion Time provides a period of time to correct the problem commensurate with the importance of maintaining primary containment OPERABILITY during MODES 1 , 2 , and 3. This time period also ensures that the probabi l ity of an accident (requiring primary containment OPERABILITY) occurring during periods where primary containment is inoperable is minima l. B.1 and B.2 If primary containment cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To ach i eve this status , the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and to MODE 4 with i n 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The allowed Comp l etion Times are reasonab l e , based on operating experience , to reach the required plant conditions from full power cond i tions in an orderly manner and without challenging plant systems. SR 3.6.1.1.1 Mainta i ning the primary containment OPERABLE requires compliance with the visual examinations and l eakage rate test requirements of the Primary Containment Leakage Rate Testing Program. Failu r e to meet air lock leakage test i ng (SR 3.6.1.2.1 ), secondary containment bypass leakage (SR 3.6.1.3.10), or main steam isolation valve leakage (SR 3.6.1.3.11) does not necessarily result in a failure of this SR. The impact of the failure to meet these SRs must be evaluated against the Type A , B , and C acceptance c r iteria of the Primary Conta in ment Leakage Rate Testing Program. The Primary Containment Leakage Rate Testing Program is based on the guidelines in Regulatory Gu i ao 1.163 (Ref. 6), NEI 94 01 (Ref. 7), ane 56.8 1994 (Ref. 8). Specific acceptance criteria for as found and as left leakage rates , as well as the methods of defining t h e leakage rates , are contained in the Primary Containment Leakage Rate Testing Program. At all other times between requi r ed leakage rate te s ts , the acceptance criteria are based on an overall Type A leakage l imit of 1.0 L a. At 1.0 L a. the o ff site dose consequences are bounded by the assumptions of the safety analysis. The Frequency is required by the Primary Containment Leakage Rate Tes ti ng Program. NEI 94-01 Revision 3-A (Ref. 7), the Limitations and Conditions of NEI 94-01 Revision 2-A (Ref.6), and ANSI/ _ANS 56.8-2002 HATCH UNIT 2 (continued) B 3.6-3 REVISION 7-BASES SURVEILLANCE REQUIREMENTS (continued)
REFERENCES SR 3.6.1.1.2 Primary Containment B 3.6.1.1 Maintaining the pressure suppression function of primary containment requires limiting the leakage from the drywall to the suppression chamber. Thus, if an event were to occur that pressurized the drywell, the steam would be directed through the downcomers into the suppression poo l. This SR measures drywell to suppression chamber differential pressure during a 10 minute period to ensure that the leakage paths that would bypass the suppression pool are within allowab l e limits. Satisfactory performance of this SR can be achieved by establishing a known differential pressure between the drywall and the suppression chamber and verifying that the pressure in either the suppression chamber or the drywell does not change by more than 0.25 inch of water per minute over a 10 minute period. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. 1. FSAR, Section 6.2. 2. FSAR, Section 15.1.39. 3. 10 CFR 50 , Appendix J , Option 8. 4. NRC No.93-102 , "Final Policy Statement on Technica l Specification Improvements
," July 23 , 1993. 5. Primary Containment Leakage Rate Testing Program. _____ 6_')_ -Regulatory Guide 1.16a , " Performance Based Containment Leak Test Program ," September 1996. 7. NEI 94-01, "Industry Guide l ine for Implementing Perfonnance-Based Option of 10 CFR Part 50 , Appendix J," Revision G,Jt:ffy26 , 1995. ...,....,3-
-A-, -Ju-ly_2_0-12-NEI 94-01, "Industry Guideline for Implementing Based Option of 10 CFR Part 50, Appendix J ," Revision 2-A, October 2008. (continued)
HATCH UNIT2 B 3.6-4 REVISION 7Q BASES REFE:RENCES (cont i nued} HATCH UNIT2 8. Primary Containment B 3.6.1.1 ANSl!ANS 66.8 1994 , " American Nationa l Standard for Con t ainment System Leakage Testing Requirements
," 1994. I\ American Nuclear Soc i ety , " Conta i nment System L eakage Testing Requ i rements ," ANSI/ANS 56.8-2002. B 3.6-5 REVISION 71iJ ATTACHMENT 3 Plant Hatch Units 1 & 2 Risk Assessment to Support ILRT (Type A) Interval Extension Request Plant Hatch Units 1 & 2 Risk Assessment to Support ILRT (Type A) Interval Extension Request TABLE OF CONTENTS Section Page 1.0 PURPOSE OF ANALYSIS .................................................................................
1-1 1.1 PURPOSE ..........................................................................................
1-1
1.2 BACKGROUND
...................................................................................
1-1 1.3 ACCEPTANCE CRITERIA .......................................................................
1-3 2.0 METHODOLOGY
............................................................................................
2-1 3.0 GROUND RULES ...........................................................................................
3-1 4.0 INPUTS .......................................................................................................
4-1 4.1 GENERAL RESOURCES AVAILABLE
.......................................................
.4-1 4.2 PLANT-SPECIFIC INPUTS .....................................................................
4-6 4.3 IMPACT OF EXTENSION ON DETECTION OF COMPONENT FAILURES THAT LEAD TO LEAKAGE (SMALL AND LARGE) ..............................................
4-17 4.4 IMPACT OF EXTENSION ON DETECTION OF STEEL CORROSION THAT LEADS TO LEAKAGE ....................................................................................
4-19 5.0 RESULTS .....................................................................................................
5-1 5.1 STEP 1 -QUANTIFY THE BASE-LINE RISK IN TERMS OF FREQUENCY PER REACTOR YEAR ..................................................................................
5-3 5.2 STEP 2 -DEVELOP PLANT-SPECIFIC PERSON-REM DOSE (POPULATION DOSE) PER REACTOR YEAR ..................................................................
5-9 5.3 STEP 3 -EVALUATE RISK IMPACT OF EXTENDING TYPE A TEST INTERVAL FROM 10-T0-15 YEARS ....................................................................
5-12 5.4 STEP 4 -DETERMINE THE CHANGE IN RISK IN TERMS OF LARGE EARLY RELEASE FREQUENCY
.......................................................................
5-16 5.5 STEP 5 -DETERMINE THE IMPACT ON THE CONDITIONAL CONTAINMENT FAILURE PROBABILITY
......................................................................
5-17 5.6 STEP 6 -DETERMINE THE IMPACT ON THE POPULATION DOSE RISK ...... 5-18 5.7
SUMMARY
OF INTERNAL EVENTS RESULTS ..........................................
5-18 5.8 EXTERNAL EVENTS CONTRIBUTION
....................................................
5-20 6.0 SENSITIVITIES
............................................................................................
6-1 6.1 SENSITIVITY TO CORROSION IMPACT ASSUMPTIONS
.............................
6-1 6.2 EPRI EXPERT ELICITATION SENSITIVITY
...............................................
6-3 6.3 NON-EARLY RELEASE SENSITIVITY
.......................................................
6-6 6.4 ILRT EXTENSION RISK BENEFIT ...........................................................
6-8
7.0 CONCLUSION
S
.............................................................................................
7-1
8.0 REFERENCES
...............................................................................................
8-1 APPENDIX A NUREG/CR-4551 PEACH BOTTOM POPULATION ESTIMATE .......................
A-1
1.0 PURPOSE
OF ANALYSIS 1.1 PURPOSE The purpose of this analysis is to provide an assessment of the risk associated with extending , the currently allowed containment Type A integrated leak rate test (ILRT) interval to a permanent fifteen yearsC 1 l for Hatch Units 1 & 2. The extension would allow for substantial cost savings as the ILRT could be deferred for additional scheduled refueling outages. The risk assessment follows the guidelines from NEI 94-01 [1], the methodology used in EPRI TR-104285 [2], the NE! "Interim Guidance for Performing Risk Impact Assessments In Support of One-Time Extensions for Containment Integrated Leakage Rate Test Surveillance Intervals" [3, 21], the NRC regulatory guidance on the use of Probabilistic Risk Assessment (PRA) as stated in Regulatory Guide 1.200 [28] as applied to ILRT interval extensions, and risk insights in support of a request for a plant's licensing basis as outlined in Regulatory Guide (RG) 1.174 [4], the methodology used for Calvert Cliffs to estimate the likelihood and risk implications of corrosion-induced leakage of steel liners going undetected during the extended test interval [19], and the methodology used in EPRI TR-1009325, Revision 2-A [22] for performing a risk impact assessment of extended integrated leak rate testing intervals.
The EPRI TR-1009325 Revision 2-A methodology incorporates the specific limitations and conditions outlined in the NRC acceptance of the EPRI TR-1009325 Revision 2 methodology documented in the NRC Final Safety Evaluation
[32]. The format of this document is consistent with the intent of the Risk Impact Assessment Template for evaluating extended integrated leak rate testing intervals provided in Appendix H of the EPRI methodology report [22].
1.2 BACKGROUND
Revisions to lOCFRSO, Appendix J (Option B) allow individual plants to extend the Integrated Leak Rate Test (ILRT) Type A surveillance testing frequency requirements from three-in-ten years to at least once in ten years. The revised Type A frequency is based on an acceptable performance history defined as two consecutive periodic Type A tests at least 24 months apart in which the calculated performance leakage was less than limiting containment leakage rate of 1.0La (allowable leakage).
Cll The ILRT risk assessment is to be used to support a request to a 1 in 15 year ILRT test frequency on a permanent basis. The risk assessment methodology and results equally support a request to extend the ILRT test frequency to 1 in 15 years on a one time basis, as has been performed by many utilities.
1-1 The basis for a 10-year test interval is provided in Section 11.0 of NEI 94-01, Revision O, and was established in 1995 during development of the performance-based Option B to Appendix J. Section 11.0 of NEI 94-01 states that NUREG-1493
[5], "Performance-Based Containment Leak Test Program," September 1995, provides the technical basis to support rulemaking to revise leakage rate testing requirements contained in Option B to Appendix J. The basis consisted of qualitative and quantitative assessments of the risk impact (in terms of increased public dose) associated with a range of extended leakage rate test intervals.
To supplement the NRC's rulemaking basis, NEI undertook a similar study. The results of that study are documented in Electric Power Research Institute (EPRI) Research Project Report TR-104285
[2]. The NRC report on performance-based leak testing, NUREG-1493, analyzed the effects of containment leakage on the health and safety of the public and the benefits realized from the containment leak rate testing. In that analysis, it was determined that for a representative PWR plant (i.e., Surry) containment isolation failures contribute less than 0.1 percent to the latent risks from reactor accidents.
Consequently, it is desirable to show that extending the ILRT interval will not lead to a substantial increase in risk from containment isolation failures for the Hatch plants. Earlier ILRT frequency extension submittals have used the EPRI TR-104285
[2] methodology to perform the risk assessment.
In October 2008, EPRI TR-1018243
[22] was issued to update the generic methodology for ILRT extensions to 15 years using current performance data and to incorporate the specific limitations and conditions outlined by the NRC in the final safety evaluation of the methodology
[32]. This more recent EPRI document considers additional risk metric? an_d criteria including 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 population dose. Hatch requested a one-time extension of the ILRT test frequency from 1 in 10 years to 1 in 15 years for Unit 1 [23] and Unit 2 [24]. The NRC approved the one-time extensions for both Unit 1 [33] and Unit 2 [34]. It should be noted that containment leak-tight integrity is also verified through periodic inservice inspections conducted in accordance with the requirements of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code Section XI. More specifically, 1-2 Subsection IWE provides the rules and requirements for inservice inspection of Class MC pressure-retaining components and their integral attachments, and of metallic shell and penetration liners of Class CC pressure-retaining components and their integral attachments in light-water cooled plants. Furthermore, NRC regulations 10 CFR 50.55a(b)(2)(ix)(E) require licensees to conduct visual inspections of the accessible areas of the interior of the containment.
In addition, Appendix J, Type B local leak tests performed to verify the leak-tight integrity of containment penetration bellows, airlocks, seals, and gaskets are also not affected by the change to the Type A test frequency.
1.3 ACCEPTANCE
CRITERIA The acceptance guidelines in RG 1.174 -are used to assess the acceptability of this permanent extension of the Type A test interval beyond that established during the Option B rulemaking of Appendix J. RG 1.174 defines very small changes in the risk-acceptance guidelines as increases in core damage frequency (CDF) less than 10-6 per reactor year and increases in large early release frequency (LERF) less than 10-7 per reactor year. Because the Type A test does not impact CDF for Hatch, the relevant criterion is the change in LERF. RG 1.174 also defines small changes in LERF as below 10-6 per reactor year provided that the total from all contributors (including external events) can be reasonably shown to be less than 10-5 per reactor year. RG 1.174 discusses defense-in-depth and encourages the use of risk analysis techniques to help ensure and show that key principles, such as the defense-in-depth philosophy, are met. Therefore, the increase in the conditional containment failure probability (CCFP) that helps to ensure that the defense-in-depth philosophy is maintained is also calculated.
Regarding CCFP, changes of up to 1.1% have been accepted by the NRC for the one-time requests for extension of ILRT intervals.
In context, it is noted that a CCFP of 1/10 (10%) has been approved for application to evolutionary light water designs. Given these perspectives, a change in the CCFP of up to 1.5% (percentage point) is assumed to be small. This criterion is articulated in the NRC Final Safety Evaluation Report [32] associated with NEI 94-01 and the EPRI ILRT methodology.
1-3 In addition, the total annual risk (person rem/yr population dose) is examined to demonstrate both the relative change and absolute change in this parameter.
Examinations of NUREG-1493 and Safety Evaluation Reports (SER) for one-time interval extensions (summarized in Appendix G of EPRI 1018243 [22]) indicate a range of incremental increases in population dose that have been accepted by the NRcC 1>. The range of incremental population dose increases is from <= 0.01 to 0.2 person-rem/yr and/or 0.002 to 0.46% of the total accident dose. The total doses for the spectrum of all accidents (NUREG-1493
[5], Figure 7-2) result in health effects that are at least two orders of magnitude less than the NRC Safety Goal risk. Given these perspectives, a very small population dose is defined as an increase from the baseline interval (3 tests per 10 years) dose of <= 1.0 person-rem/yr or 1 % of the total baseline dose, whichever is less restrictive for the risk impact assessment of the proposed extended ILRT interval.
This criterion is articulated in the NRC Final Safety Evaluation Report [32] associated with NEI 94-01 and the EPRI ILRT methodology.
Cl) The methodology used in the one-time ILRT interval extension requests assumed a large leak magnitude (EPRI class 3b) of 35La, whereas the methodology in this document uses 100La. The dose risk is impacted by this change and will be larger than those of previous submittals.
1-4
2.0 METHODOLOGY
A simplified bounding analysis approach consistent with the latest EPRI approach [22] as accepted by the NRC [32] is used for evaluating the change in risk associated with increasing the test interval to fifteen years. The approach is consistent with that presented in EPRI TR-1018243
[22], NUREG-1493
[5] and the Calvert Cliffs liner corrosion analysis [19]. The analysis uses results from a Level 2 analysis of core damage scenarios from the current Hatch Unit 1 PRA model and the subsequent containment responses for the various fission product release categories (including containment intact release).
This risk assessment is applicable to Hatch Units 1 & 2 because Unit 2 can be adequately represented by Unit 1 PRA results (see Section 4.2). The six general steps of this assessment are as follows: 1. Quantify the baseline risk in terms of the frequency of events (per reactor year) for each of the eight containment release scenario types identified in the EPRI report. 2. Develop plant-specific person-rem (population dose) per reactor year for each of the eight containment release scenario types from plant specific consequence analyses.
- 3. Evaluate the risk impact (i.e. the change in containment release scenario type frequency and population dose) of extending the ILRT interval to fifteen years. 4. Determine the change in risk in terms of Large Early Release Frequency (LERF) in accordance with RG 1.174 [4] and compare this change with the acceptance guidelines of RG 1.174. 5. Determine the impact on the Conditional Containment Failure Probability (CCFP) 6. Evaluate the sensitivity of the results to assumptions in the corrosion analysis, external events, and to the probability of undetected leaks from containment (due to corrosion breach) to LERF. This approach is based on the information and approaches contained in the previously mentioned studies. Furthermore,
- Consistent with the other industry containment leak risk assessments, the Hatch assessment uses LERF and delta LERF in accordance with the risk acceptance guidance of RG 1.174. Changes in population dose and conditional containment failure probability (CCFP) are also considered to show that defense-in-depth and the balance of prevention and mitigation is preserved.
- This evaluation uses ground rules and methods to calculate changes in risk metrics that are consistent with those in the EPRI methodology
[22]. 2-1
- The EPRI methodology
[22] specifies that emergency core cooling system (ECCS) net positive suction head (NPSH) requirements be assessed regarding whether containment over pressure is credited in the design basis ECCS analysis, and if containment over pressure is credited, the potential impacts on the core damage frequency (CDF). As documented in Section 6.3.3.9 of the Hatch FSAR [36], containment over pressure is not required or credited for Unit 2 for either short term (i.e., < 10 minutes following LOCA initiation) or long term Residual Heat Removal (RHR) pump or Core Spray (CS) pump operation.
For Unit 1, the design basis calcu.lations indicate that 3.24 psig (7.5 ft) of containment over pressure is required to ensure adequate NPSH to the RHR pumps, and 3.2 psig (7.4 ft) of containment over pressure is required to ensure adequate NPSH to the CS pumps (at the peak calculated suppression pool temperature of 211.3 °F) for a period from about 2.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> to 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br /> after LOCA initiation.
These design basis calculations utilize conservative inputs (e.g., reactor operation at 100.5%) and one RHR heat exchanger.
To provide sufficient margin, the long term NPSH evaluation takes credit for 4.2 psig (10 ft) of containment over pressure for the period of 1.5 to 26.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> following LOCA initiation.
No over pressure credit is required for Unit 1 for the short term response (i.e., < 10 minutes following LOCA initiation).
MAAP runs in support of the Hatch PRA demonstrate that if RHR containment heat removal is available, the suppression pool water temperature stays well below 211 °F in the long term for a large LOCA and loss of ECCS NPSH is not a concern. Table 2.0-1 presents the results from four MAAP sensitivity cases performed in support of the ILRT analysis.
The MAAP cases model a large break LOCA (i.e., 28" diameter recirculation line break), core injection via core spray, one train of RHR for containment heat removal, with varied containment leakage values. MAAP Case 516Dl serves as the base case and models maximum allowed Technical Specification containment leakage (i.e., 1 La). The other three cases model increased containment leakage areas to estimate leakage for approximately lOOLa, 200La, and 400La. The general EPRI methodology is based on assuming a lOOL.13 leakage rate. Consistent with the design basis calculations, these MAAP cases utilize an initial torus water temperature of 100 °F and drywell temperature of 150 °F. The MAAP cases demonstrate that a single train of RHR containment heat removal is adequate to keep the suppression pool temperature approximately 181 °F or lower up to a leakage of 400La. With the suppression pool temperature well below 211 °F, loss of ECCS NPSH is not a concern for sequences where one or more trains of RHR containment heat removal operate. In the event that containment heat removal (i.e., RHR and containment vent) is unavailable, containment pressure will increase to the point of containment failure due to over pressure.
In the Hatch PRA, containment failure is assumed to result in a loss of ECCS core injection due to the potential for disruption of injection lines and degraded environmental conditions in plant areas housing injection equipment.
While the potential exists for a pre-existing containment failure (as might be detected by the Type A ILRT) to preclude the containment pressure from reaching the point of containment over pressure failure and instead result in loss of adequate NPSH to the ECCS pumps taking suction from the suppression 2-2 pool, the end result would be the same, i.e., loss of ECCS injection leading to core damage. Therefore, there is no change in CDF associated with loss of containment heat removal sequences.
Regarding the consideration of successful containment vent or other containment isolation failures (e.g., random containment isolation valve failures), the CDF associated with such accident sequences is not impacted by the ILRT frequency.
The ILRT frequency only impacts risk (i.e., CDF or LERF) associated intact containment configurations, (i.e., as characterized by EPRI Classes 1, 3a, and 3b in the EPRI methodology).
Containment configurations which are not intact (e.g., EPRI Class 2 for large containment isolation failures) are not impacted by the ILRT frequency because containment integrity is failed independent of the containment failure mechanisms evaluated by an ILRT. Based on the above discussion, there is no meaningful change in the CDF associated with the ILRT interval pertaining to the long term containment over pressure credit for Unit 1 ECCS NPSH. Therefore CDF is not quantitatively evaluated in this ILRT risk assessment as a figure of merit. It is additionally noted that design basis NPSH calculations include a level of conservatism.
For instance, the manufacturer recommended NPSH limit includes an operational design margin. The amount of margin depends on the specific pump design and the operating condition of the pump. Plant tests at TVA (Browns Ferry) [37] and Monticello have shown that substantial margin exists for ECCS pumps of BWR/3 and BWR/4 plants. Thus, the best estimate NPSH requirements for Hatch ECCS pump successful operation would be expected to be less than either that credited or that calculated by the design basis analysis.
2-3 Table 2.0-1 HATCH MAAP CONTAINMENT OVER PRESSURE SENSITIVITY CASEsC 1> MAAP CASE CONTAINMENT MAXIMUM TORUS TIME AT MAXIMUM ID LEAKAGE SIZE TEMP (F) TORUS TEMP 51601 5E-5 ft"2 181 6.5 to 8.5 hrs (1 La) 51602 5E-3 ft"2 181 6.9 to 8.0 hrs ("'100 La) 51603 1E-2 Ft"2 180 5.5 to 9.8 hrs ("'200 La) 51604 2E-2 ft"2 180 5.5 to 9.8 hrs ("'400 La) C 1> Cases model LLOCA, core injection via core spray, one train of RHR for containment heat removal, and varied containment leakage sizes. 2-4
3.0 GROUND
RULES The following ground rules are used in the analysis:
- The technical adequacy of the Hatch Unit 1 PRA is consistent with the requirements of Regulatory Guide 1.200 [28] as is relevant to this ILRT interval extension.
The PRA technical adequacy is documented separately.
- The Hatch Unit 1 Level 1 and Level 2 internal events PRA models provide representative results. (A Unit 2 PRA model is available and the CDF and LERF results are essentially the same as the Unit 1 results. It is judged that the Unit 2 model will not provide any unique or additional insights compared to the results from the Unit 1 model.)
- It is appropriate to use the Hatch Unit 1 internal events PRA model as a gauge to effectively describe the risk change attributable to the ILRT extension.
It is reasonable to assume that the impact from the ILRT extension (with respect to percent increases in population dose) will not substantially differ if fire and seismic events were to be included in the calculations; nevertheless fire and seismic events have been accounted for in the analysis based on the available information from the Hatch IPEEE [18] as described in Section 5.8.
- Dose results for the containment failures modeled in the PRA can be characterized by information provided in the Hatch Severe Accident Mitigation Alternatives (SAMA) analysis and associated responses to Requests for Additional Information (RAis) [9, 29, 30]. Hatch SAMA dose results all represent high magnitude releases.
These dose results can be applied to containment failure releases that are lower in magnitude (i.e., non-high releases).
- Plant specific dose calculations for containment intact cases are not available from the Hatch SAMA analysis.
NUREG-1150 results for such cases are adequately representative for use in the Hatch analysis based on scaling the NUREG-1150 results to account for differences in regional population, power level, and allowed technical specification leakage.
- Accident classes describing radionuclide release end states are defined consistent with the EPRI methodology
[22], as summarized in Section 4.2.
- The representative containment leakage for Class 1 sequences is 1La. Class 3 accounts for increased leakage due to Type A inspection failures.
- The representative containment leakage for Class 3a sequences is 10La, based on the previously approved methodology performed for Indian Point Unit 3 [6, 7].
- The representative containment leakage for Class 3b sequences is 100La, based on the NRC SER [32] and incorporated in the latest EPRI report [22]. Note that most of the previous one-time ILRT extension requests utilized 35La. 3-1
- The Class 3b can be very conservatively categorized as LERF based on the previously approved methodology
[6, 7]. The Class 3b category increase is used as a surrogate for LERF in this application even though the releases associated with a 100La release would not necessarily be consistent with a "Large" release for Hatch. * * *
- The impact on population doses from containment bypass scenarios is not altered by the proposed ILRT extension.
Rather it is accounted for in the EPRI methodology as a separate entry for comparison purposes, as accepted in the NRC SER [32]. Because the containment bypass contribution to population dose is fixed, no changes to the conclusions from this analysis will result from this separate categorization.
The reduction in ILRT frequency does not impact the reliability of containment isolation valves to close in response to a containment isolation signal. Consideration of the risk impact of the ILRT on shutdown risk is addressed in Section 6 using the generic results from EPRI TR-105189
[8]. The ILRT analysis evaluates very small changes in the risk metrics. To facilitate the calculation of these changes and the evaluation of sensitivity cases, the calculations are performed in a spreadsheet.
In general, the calculations provided in this report reproduce the calculation results of the spreadsheets.
In some cases there may be minor differences in the results between the spreadsheet calculations and hand calculations due to rounding (e.g., a column total in a table may differ). To maintain consistency, results from the spreadsheets are presented in this report. 3-2
4.0 INPUTS
This section summarizes the general resources available as input (Section 4.1) and the plant specific resources required (Section 4.2). 4.1 GENERAL RESOURCES AVAILABLE Various industry studies on containment leakage risk assessment are briefly summarized here: 1. NUREG/CR-3539
[10] 2. NU REG/CR-4220
[11] 3. NUREG-1273
[12] 4. NUREG/CR-4330
[13] 5. EPRI TR-105189
[8] 6. NUREG-1493
[5] 7. EPRI TR-104285
[2] 8. NUREG-1150
[14] and NUREG/CR-4551
[26] 9. NEI Interim Guidance [3, 21] 10. Calvert Cliffs liner corrosion analysis [19] 11. NRC SER [32] on EPRI TR-1009325
- 12. EPRI 1018243 [22] The first study is applicable because it provides one basis for the threshold could be used in the Level 2 PRA for the size of containment leakage that is considered significant and to be included in the model. The second study is applicable because it provides a basis of the probability for significant pre-existing containment leakage at the time of a core damage accident.
The third study is applicable because it is a subsequent study to NUREG/CR-4220 that undertook a more extensive evaluation of the same database.
The fourth study provides an assessment of the impact of different containment leakage rates on plant risk. The fifth study provides an assessment of the impact on shutdown risk from ILRT test interval extension.
The sixth study is the NRC's cost-benefit analysis of various alternative approaches regarding extending the test intervals and increasing the allowable leakage rates for containment integrated and local leak rate tests. The seventh study is an EPRI study of the impact of extending ILRT and LLRT test intervals on at-power public risk. The eighth study documents ex-plant consequence results which may be used as surrogate results in the ILRT risk assessment.
The ninth study includes the NEI recommended methodology (promulgated in two letters) for evaluating the risk associated with obtaining a one-time extension of the 4-1 ILRT interval.
The tenth study addresses the impact of age-related degradation of the containment steel on ILRT evaluations.
The eleventh study [32] documents the NRC Final Safety Evaluation of the EPRI 2007 version of ILRT risk assessment guidance (i.e., EPRI TR-1009325, Revision 2). The last study by EPRI complements the previous EPRI report [2], integrates the NEI interim guidance and NRC SER limitations and conditions, and provides a recommended methodology and template for evaluating the risk associated with a permanent 15-year ILRT interval.
[10] Oak Ridge National Laboratory (ORNL) documented a study of the impact of containment leak rates on public risk in NUREG/CR-3539.
This study uses information from WASH-1400
[15] as the basis for its risk sensitivity calculations.
ORNL concluded that the impact of leakage rates on LWR accident risks is relatively small. NUREG/CR-4220
[11] NUREG/CR-4220 is a study performed by Pacific Northwest Laboratories for the NRC in 1985. The study reviewed over two thousand LERs, ILRT reports and other related records to calculate the unavailability of containment due to leakage. It assessed the "large" containment leak probability to be in the range of lE-3 to lE-2, with 5E-3 identified as the point estimate based on 4 events in 740 reactor years and conservatively assuming a one-year duration for each event. NUREG-1273
[12] A subsequent NRC study, NUREG-1273, performed a more extensive evaluation of the NUREG/CR-4220 database.
This assessment noted that about one-third of the reported events were leakages that were immediately detected and corrected.
In addition, this study noted that local leak rate tests can detect "essentially all potential degradations" of the containment isolation system. 4-2 NUREG/CR-4330
[131 NUREG/CR-4330 is a study that examined the risk impacts associated with increasing the allowable containment leakage rates. The details of this report have no direct impact on the modeling approach of the ILRT test interval extension, as NUREG/CR-4330 focuses on leakage rate and the ILRT test interval extension study focuses on the frequency of testing intervals.
However, the general conclusions of NUREG/CR-4330 are consistent with NUREG/CR-3539 and other similar containment leakage risk studies: " ... the effect of containment leakage on overall accident risk is small since risk is dominated by accident sequences that result in failure or bypass of containment." EPRI TR-105189
[81 The EPRI study TR-105189 is useful to the ILRT test interval extension risk assessment because this EPRI study provides insight regarding the impact of containment testing on shutdown risk. This study performed a quantitative evaluation (using the EPRI ORAM for two reference plants (a BWR-4 and a PWR) of the impact of extending ILRT and LLRT test intervals on shutdown risk. The result of the study concluded that a small but measurable safety benefit (shutdown CDF reduced by lE-8/yr to lE-7/yr) is realized from extending the test intervals from 3 per 10 years to 1 per 10 years. NUREG-1493
[5] NUREG-1493 is the NRC's cost-benefit analysis for proposed alternatives to reduce containment leakage testing intervals and/or relax allowable leakage rates. conclusions are consistent with other similar containment leakage risk studies: The NRC
- Reduction in ILRT frequency from 3 per 10 years to 1 per 20 years results in an "imperceptible" increase in risk.
- Given the insensitivity of risk to the containment leak rate and the small fraction of leak paths detected solely by Type A testing, increasing the interval between integrated leak rate tests is possible with minimal impact on public risk. EPRI TR-104285
[2] Extending the risk assessment impact beyond shutdown (the earlier EPRI TR-105189 study), the EPRI TR-104285 study is a quantitative evaluation of the impact of extending ILRT and LLRT test intervals on at-power public risk. This study combined IPE Level 2 models with 4-3 NUREG-1150
[14] Level 3 population dose models to perform the analysis.
The study also used the approach of NUREG-1493 in calculating the increase in pre-existing leakage probability due to extending the ILRT and LLRT test intervals.
EPRI TR-104285 used a simplified Containment Event Tree to subdivide representative core damage sequences into eight categories of containment response to a core damage accident:
- 1. Containment intact and isolated 2. Containment isolation failures dependent upon the core damage accident 3. Type A (ILRT) related containment isolation failures 4. Type B (LLRT) related containment isolation failures 5. Type C (LLRT) related containment isolation failures 6. Other penetration related containment isolation failures 7. Containment failure due to core damage accident phenomena
- 8. Containment bypass Consistent with the other containment leakage risk assessment studies, this study concluded: "These study results show that the proposed CLRT [containment leak rate tests] frequency changes would have a minimal safety impact. The change in risk determined by the analyses is small in both absolute and relative terms. For example, for the PWR analyzed, the change is about 0.02 person-rem per year ... " NUREG-1150
[14] and NUREG/CR-4551
[26] NUREG-1150
[14] and the technical basis, NUREG/CR-4551
[26], provide an ex-plant consequence analysis for a spectrum of accidents including a severe accident with the containment remaining intact (i.e., Tech Spec leakage).
This ex-plant consequence calculation is calculated for the SO-mile radial area surrounding Peach Bottom. The ex-plant consequence calculation for the containment remaining intact represents a very small contributor to the overall risk spectrum.
Because it is a small contributor, this ex-plant calculation (i.e., total person-rem) is considered adequate to represent Hatch if population, reactor power, and the Technical Specification leakage are scaled to represent Hatch. (The meteorology and other site differences are assumed not to play a significant role in this evaluation).
4-4 NEI Interim Guidance [3, 211 NEI "Interim Guidance for Performing Risk Impact Assessments in Support of One-Time Extensions of Containment Integrated Leakage Rate Test Surveillance Intervals" [3] was developed to provide utilities with revised guidance regarding licensing submittals.
Additional information from NEI on the "Interim Guidance" was supplied in Reference
[21]. A nine step process is defined which includes changes in the following areas of the previous EPRI guidance:
- Impact of extending surveillance intervals on dose
- Method used to calculate the frequencies of leakages detectable only by ILRTs
- Provisions for using NUREG-1150 dose calculations to support the population dose determination.
The guidance provided in this document builds on the EPRI risk impact assessment methodology
[2] and the NRC performance-based containment leakage test program [5], and considers approaches utilized in various submittals, including Indian Point 3 (and associated NRC SER) [6,7] and Crystal River [20]. Calvert Cliffs Liner Corrosion Analysis [19] This submittal to the NRC describes a method for determining the change in likelihood, due to extending the ILRT, of detecting liner corrosion, and the corresponding change in risk. The methodology was developed for Calvert Cliffs in response to a request for additional information regarding how the potential leakage due to age-related degradation mechanisms were factored into the risk assessment for the ILRT one-time extension.
The Calvert Cliffs analysis was performed for a concrete cylinder and dome and a concrete basemat, each with a steel liner. Licensees may consider approved LARs for one-time extensions involving containment types similar to their facility.
The Hatch assessment has addressed the specific differences from the Calvert Cliffs design, and the Calvert Cliffs methodology was adapted to address the specific design features.
4-5 NRC SER on ILRT Risk Assessment
[32] This report documents the NRC review and acceptance of the EPRI ILRT Risk Assessment methodology of EPRI TR-1009325 Revision 2. Based on the NRC review, four conditions and limitations were identified, summarized here as: 1. Licensees must submit documentation supporting appropriate technical adequacy of the PRA. 2. Acceptance criteria for population dose risk and CCFP were revised. 3. Assumed leakage for EPRI Class 3b is revised from 35La to lOOLa. 4. A license amendment request (LAR) is required in instances where containment over pressure is relied upon for ECCS performance.
EPRI TR-1018243
[221 (EPRI TR-1009325 Revision 2-A) This report presents a generally applicable assessment of risk involved in extension of ILRT test intervals to 15 years on a permanent basis. Appendix H of this document provides guidance for performing plant-specific supplemental risk impact assessments and builds on the previous EPRI risk impact assessment methodology TR-104285
[2], the NEI Interim Guidance [3,21], and the NRC performance-based containment leakage test program [5], and considers approaches utilized in various submittals, including Indian Point 3 (and associated NRC SER) [6,7] and Crystal River [20]. The EPRI report codifies minor changes to the ILRT methodology specified by the NRC in the NRC ILRT risk assessment approach SER [32]. The approach included in this EPRI guidance document is used in the Hatch assessment to determine the estimated increase in risk associated with the ILRT extension.
This document includes the bases for the values assigned in determining the probability of leakage for the EPRI Class 3a and 3b scenarios in this analysis as described in Section 5. 4.2 PLANT-SPECIFIC INPUTS The Hatch specific information used to perform this ILRT interval extension risk assessment includes the following:
- PRA Level 1 Model results [16]
- PRA Level 2 Model results [17], including release category definitions, and containment failure probability data
- Population Dose within a 50-mile radius [9, 29, 30]
- ILRT results to demonstrate adequacy of the administrative and hardware interfaces 4-6 Hatch Internal Events Level 1 PRA Model The Unit 1 Internal Events Level 1 PRA model [16] is an event tree / linked fault tree model characteristic of the as-built, as-operated plant. This Level 1 PRA model incorporates the resolution of findings associated with the PRA Peer Review of 2009. The total internal events core damage frequency (CDF) used in this analysis is 7.57E-06/yrC
- 1) (at lE-12/yr truncation) for Unit 1, as reflected in the combined Unit 1Level1 and Level 2 PRA models [17]. (For reference, it is noted that the CDF for the Unit 2 model is 7.42E-06/yr
[39], approximately 1.5% less than the Unit 1 CDF. The Unit 1 model is adequately representative of Unit 2 for the purposes of the ILRT risk assessment.)
Hatch Internal Events Level 2 PRA Model The Unit 1 Level 2 PRA model [17] was developed to calculate the LERF contribution as well as the other release categories evaluated in the model. This Level 2 PRA model incorporates the resolution of findings associated with the PRA Peer Review of 2009. Table 4.2-la summarizes the pertinent Hatch Unit 1 Level 2 results in terms of end states. The total Large Early Release Frequency (LERF) in Table 4.2-la for Unit 1 is 1.12E-6/yr.
The Unit 2 model LERF value is 1.03E-06/yr
[31], approximately 8% less than the Unit 1 LERF. The lower Unit 2 LERF value is primarily attributed to a plant design difference.
The Unit 2 feedwater injection lines have an additional check valve which lowers the break outside containment (BOC) contribution to LERF for Unit 2. This design difference does not impact the risk assessment because the ILRT interval does not impact the BOC LERF contribution.
Cl) The Unit 1 Level 1 CDF value of 7.57E-06/yr used in the Levei 2 evaiuation
[17] is slightly higher than the Level 1 CDF value of 7.53E-06/yr from the latest version of the Hatch Unit 1 Internal Events Level 1 PRA model [16]. To support the Level 2 quantification, Level 1 sequences are binned into accident classes. However, this separate quantification of the individual accident classes may result in duplicate or non-minimal cutsets to be binned into more than one accident class. This may result in the numerical sum of all individual accident classes to be higher than the CDF if all the cutsets were merged together.
However, the apparent deviation of the Level 1 CDF quantified for the Level 2 model is less than 1 % and is judged not to significantly alter the results. 4-7 The Level 2 release category end states are defined [38] as follows: Release Magnitude High Moderate/Medium Low Low-Low Release Timing Early Intermediate Late CsI Release Fraction > 10% 1% to 10% 0.1% to 1% < 0.1% Time (hrs) <5 5 to 24 > 24 Table 4.2-lb summarizes the core damage frequency contributions by the PRA accident class. 4-8 Table 4.2-la HATCH LEVEL 2 DETAILED RELEASE CATEGORIESC 1> RELEASE FREQUENCY CATEGORY DEFINITION
(/YR) (1) INTACT Containment remains intact. 1.18E-06 H-E High-early release (i.e., LERF). Dominant accident class 1.12E-06 contributors are as follows:
6.13E-08/yr . Class ID (loss of RPV injection, RPV at low pressure):
6.17E-08/yr
- Class 4 (ATWS) : 1.93E-07/yr . Class 5 (BOC): 7. 79E-07 /yr H-I High-intermediate release. Dominant accident class contributor 2.83E-06 is Class 2A (loss of containment heat removal, CD post-containment failure) at 3.17E-06/yr.
M-E Moderate-early release. Dominant accident class contributor is 1.19E-06 Class 1D (loss of RPV injection, RPV at low pressure) at 8.04E-07/yr. M-I Moderate-intermediate release. Dominant accident class 9.64E-07 contributor is Class 2A at 8.23E-07 /yr. M-L Moderate-late release. Dominant accident class contributor is 4.64E-08 Class 1A at 4.80E-08/yr.
L-E Low-early release. Dominant accident class contributor is Class 1.0lE-08 1A at 2.24E-09/yr.
L-I Low-intermediate release. Dominant accident class contributor 9.56E-08 is Class 1D at 1.0SE-07/yr.
L-L Low-late release. Dominant accident class contributor is Class 6.94E-09 1A at 7.42E-09/yr.
LL-E Low Low-late release. Dominant accident class contributor is 1.33E-07 Class 1D at 4.21E-08/yr.
LL-I Low Low-intermediate release. Dominant accident class 1.0SE-08 contributor is Class 1D at 1.02E-08/yr.
LL-L Low Low-late release. Dominant accident class contributor is 4.63E-09 Class 1A at 4.86E-09/yr.
Total Total Release Category Frequency (No Intact) 6.40E-06 Total Total CDF 7.SSE-06 From Table 5 of Reference
[17] for Unit 1. The High-Late release category had zero frequency and is therefore not listed. 4-9 Table 4.2-lb HATCH CDF CONTRIBUTIONS BY PRA ACCIDENT CLAssC 1> PRA FREQUENCY ACCIDENT (/YR) CLASS DESCRIPTION IA Transients
-core melt with vessel at high pressure 1.07E-06 IBE Station blackout -early 1.18E-08 IBL Station blackout -late 4.89E-07 IC with loss of injection
- 1. 73E-07 ID lrransients
-core melt with vessel at low pressure 1.35E-06 IIA Core melt after containment failure due to loss of DHR 3.39E-06 Ill Core melt after containment failure due to loss of DHR and 4.11E-10 LOCA IIIB LOCA -core melt with vessel remaining at high pressure 1.SOE-08 me LOCA -core melt with vessel at low pressure 2.75E-09 IV
-containment fails before core damage 3.SSE-07 v LOCA outside containment 7.12E-07 Total Total CDF 7.57E-06 (1) From Table 5 of Reference
[17] for Unit 1. 4-10 Population Dose Conditional population dose results for containment failure end states are available for Hatch based on the Hatch SAMA evaluation performed for Units 1 & 2 and submitted to the NRC in 2000 [9], and subsequent responses to Requests for Additional Information (RAis) [29, 30]. Conditional population dose results for an intact containment end state (not quantified for the SAMA analysis) are available via ex-plant consequence results for Peach Bottom [26] and can be scaled to represent Hatch. The Hatch specific and Peach Bottom surrogate conditional population dose results may be combined with the most recent Hatch Level 2 analysis results [17] to develop population dose risk for use in the ILRT assessment.
The SAMA dose analysis utilized the projected population to year 2030 (i.e., 498,834 people in the 50 mile radial region) and a Hatch power level of 2,763 MWth. The population projection is adequately representative for use in the ILRT assessment.
The Hatch power level used in the SAMA analysis is slightly less than the current and anticipated Hatch power level in the future, which is 2,804 MWth. The SAMA dose values may be scaled for use in the ILRT analysis by applying a reactor power level scaling factor of 1.015 (i.e., 2,804 MWth / 2,763 MWth). The Hatch SAMA population dose results are presented in Table 4.2-2. These dose results are based on MACCS2 calculations and accident sequence frequencies applicable at the time. Included in Table 4.2-2 is a column presenting the ILRT assessment dose values after applying the reactor power level scaling factor. It is noted that the release categories represented in the Hatch SAMA analysis all represent high magnitude releases.
Doses associated with large releases from containment failure can be conservatively represented by this data. The population dose associated with an intact containment (Technical Specification leakage) case can be estimated based on scaling the NUREG/CR-4551 dose results for Peach Bottom from Accident Progression Bin (APB) #8 (Core is damaged, Vessel is breached, no containment failure)C 1 l. The Peach Bottom dose for APB #8 is not specifically identified in NUREG/CR-4551, but can be back-calculated to be 4,940 person-rem as presented in Table 4.2-3. (lJ APB #8 is described in more detail in NUREG/CR-4551
[26] Section 2.4.3. 4-11 The APB #8 person-rem result can be used as an approximation of the dose for Hatch if it is scaled for regional population, reactor power level, and allowable containment leakage rate (La). Values for these attributes for Peach Bottom (as evaluated in NUREG/CR-4551) and Hatch are summarized in Table 4.2-4, where the applicable scaling factors are calculated.
Applying the calculated scaling factors, the population dose for Hatch for an intact containment technical specification release is 1,150 pers-rem (i.e, 4,940 pers-rem
- 0.114
- 0.852
- 2.4 = 1,150 pers-rem).
Table 4.2-5 presents the current Hatch Level 2 release frequencies, the assigned dose for the category, and the calculated annual dose risk. The annual dose risk calculated in Table 4.2-5 is not directly used in the ILRT assessment since the EPRI methodology utilizes a different release category scheme, but is presented for completeness.
EPRI Release Category Definitions Table 4.2-6 defines the accident classes used in the ILRT extension evaluation, which are consistent with the EPRI methodology
[22]. These containment failure classifications are used in this analysis to determine the risk impact of extending the Containment Type A test interval as described in Section 5 of this report. Hatch ILRT Results The surveillance frequency for Type A testing in NE! 94-01 under option B criteria is at least once per ten years based on an acceptable performance history (i.e. two consecutive periodic Type A tests at lec:ist 24 months apart where the calculated performance leakage rate was less than 1.0 La) and consideration of the performance factors in NEI 94-01, Section 11.3. Based on completion of two successful ILRTs at Hatch Unit 1 and Unit 2, the ILRT interval became once per ten years. Subsequently, a one time ILRT interval frequency of once per fifteen years was approved for both Hatch Unit 1 and Unit 2 [33, 34] based on demonstrating acceptable risk impacts. Each Hatch unit has successfully completed another ILRT (i.e., Unit 1 in March 2008, Unit 2 in March 2009) since these one time ILRT interval extension approvals.
4-12 Table 4.2-2
SUMMARY
OF SAMA MACCS2 CALCULATIONS AND ILRT SCALED VALUES SAMA Frequency SAMA Dose Level 2 End State Seq# Sequence Description (per yr) <10> (Person-Rem)
Containment Bypass 5 BOC 1.66E-7C 6 l 1.15E+6C 2 l Early Cont. Failure 2 SBO 1.79E-6<6 l 1.06E+6<3 l 4 Loss of Cont. Heat 7.43E-7<6 l 1.02E+6<4 l Removal (CHR) 11 ATWS 7.43E-7C 6 l 7.02E+5<5 l Late Cont. Failure 12 High pressure transient 2.0E-7<1 l 5.7E+5 with loss of CH R 14 SBO with cont. isolation 3.1E-9(ll failure Intact Cont. (DW Vent) 15 High pressure transient 9.24E-10C 6 l 1.13E+6C 9 l with venting No Containment Failure NA NA NA NAC 7 l NA <1 l SAMA RAI response to Q#4 [29]. C 2 l SAMA RAI response to Q#14; Sequence #5 [29] clarification provided to NRC by SNC [30]. C 3 l SAMA RAI response to Q#l4; Sequence #2 [29]. <4 l SAMA RAI response to Q#14; Sequence #4 [29]. <5 l SAMA RAI response to Q#l4; Sequence #11 [29]. (GJ SAMA RAI response to Q#l.b-1 [29]. C 7 l Not calculated for SAMA. csi SAMA RAI clarification provided by SNC to Question #5 [30]. <9 l SAMA RAI response to Q#l4; Sequence 15 [29]. Adjusted Dose for ILRT Assessment (Person-Rem)
<11> 1.17E+6 1.08E+6 1.04E+6 7.13E+5 5.8E+5 1.15E+6 NA TOTAL SAMA Annual Risk (Person-Rem/Yr)
[29, 30] 0.19 1.90 0.76 0.52 3.18 total 0.ll2(B) 0.0008 0.001 NAC 7 l 3.48 <10 l It is noted that the Hatch PRA model tias been updated since the SAMA analysis and the accident sequence frequencies and the Table 4.2-3 PEACH BOTTOM APB #8 SO-MILE POPULATION DOSE CALCULATIONC 1> ALL APBS APB #8 SO-MILE APB #8 SO-APB #8 CONTRIBUTION DOSE RISK MILE DOSE APB #8 50-FREQUENCY TO SO-MILE (PERS-RISK (PERS-MILE DOSE (/YR) DOSE RISK REM/YR) REM/YR) (PERS-REM) 7.99E-7C 2) 5E-4C 3 l 7_9C 4 l 3.95E-3C 5 l 4.94E+3C 6 l Cll NUREG/CR-4551
[26] does not document dose results as a function of accident progression bin as such, the dose result for APB #8 is back calculated from the documented APB frequency and dose risk results. <2> From Figure 2.5-6 of NUREG/CR-4551 Vol. 4, Rev. 1, Part 1. Frequency for APB #8 of 7.99E-7/yr is calculated as 0.184 contribution of 4.34E-6/yr CDF. <3 l From Table 5.2-3 for the mean fractional contribution to risk (MFCR) of NUREG/CR-4551 Vol. 4, Rev. 1, Part 1. <4 J From Table 5.1-1 for mean value 50-mile population dose of NUREG/CR-4551 Vol. 4, Rev. 1, Part 1. <5 J APB dose risk is calculated by multiplying the APB dose risk fractional contribution (column 2) by the total 50-mile radius dose risk of 7.9 person-rem/yr (column 3). (GJ Calculated by dividing the APB #8 dose risk (column 4) by the APB #8 frequency (column 1) Table 4.2-4 HATCH APB-#8 DOSE SCALING FACTORS Reactor SO-mile Power TS Leakage Plant Population (MWth) (wt 0/o/day) Hatch 498.834(!)
2 804(2) 1.2% C 2> Peach Bottom 4,359,67-?(3) 3,293C 4 l 0.5%(S) Scaling Factor 0.114 0.852 2.4 <1> Hatch SAMA year 2030 population
[9] <2> Hatch current and anticipated future value. <3 J NUREG/CR-4551, Vol. 2, Rev. 1, Part 7, Appendix A.3 (SITE MACCS2 File) for Peach Bottom. Population total for 50-mile radius developed in Appendix A of this report. <4 J NUREG/CR-4551, Vol. 4, Rev. 1, Part 2, Section A.3.1. <5 l NUREG/CR-4551, Vol. 4, Rev. 1, Part 2, page B.2-9 for no containment failure. 4-14 Table 4.2-5 HATCH POPULATION DOSE RISK AT 50 MILES RELEASE POPULATION DOSE CATEGORY 2030 POPULATION RISK RELEASE FREQUENCIES ASSIGNED DOSE DOSE ASSIGNMENT (PERSON-REM/YR)
CATEGORY (PER YEAR) (PERSON-REM)C 1> BASIS (2) INTACT H-E H-1 M-E M-1 M-L L-E L-1 L-L LL-E LL-I LL-L Total (1) (2) (3) (4) 1.18E-06 1.15E+03 Peach Bottom 1.35E-03 1.12E-06 1.17E+06 Hatch SAMA BOC 1.31 E+OO 2.83E-06 5.80E+05 Hatch SAMA late CF 1.64E+OO 1.19E-06 5.80E+05 Hatch SAMA late CF (SJ. 6.90E-01 9.64E-07 5.80E+05 Hatch SAMA late CF(3 l 5.59E-01 4.64E-08 5.80E+05 Hatch SAMA late CF(3 l 2.69E-02 1.01 E-08 5.80E+05 Hatch SAMA late CF (4 l 5.86E-03 9.56E-08 5.80E+05 Hatch SAMA late CF(4 l 5.54E-02 6.94E-09 5.80E+05 Hatch SAMA late CF(4 l 4.03E-03 1.33E-07 5.80E+05 Hatch SAMA late CF(4 l 7.71 E-02 1.0SE-08 5.80E+05 Hatch SAMA late CF (4 l 6.09E-03 4.63E-09 5.80E+05 Hatch SAMA late CF(4 l 2.69E-03 7.58E-06 ----4.37E+OO Includes a scaling factor of 0.233 for application of the Peach Bottom dose results to the Intact Containment case, and includes a scaling factor of 1.015 for other release categories to account for a reactor power level increase since the Hatch SAMA analysis was performed.
Obtained by multiplying the release category frequency by the conditional dose. All Hatch SAMA dose cases represent high releases.
The late containment failure dose is approximately*
a factor of two less than that for other high magnitude releases and is considered reasonable for use for medium magnitude release cases. This is comparable to SAMA population dose results developed for Quad Cities and Dresden Generating Stations [35] (both Mark I containment designs) where moderate magnitude releases had population dose results approximately one half to nearly equal to high magnitude release population doses. All Hatch SAMA dose cases represent high releases.
Use of the late containment failure for low and low-low magnitude release cases is acceptable because the associated frequencies for these release categories are low compared to other release categories.
The population dose associated with low or low-low releases compose less than 3% of the total as developed in this table. 4-15 Table 4.2-6 EPRI CONTAINMENT FAILURE CLASSIFICATIONS
[22] CLASS DESCRIPTION 1 Containment remains intact including accident sequences that do not lead to containment failure in the long term. The release of fission products (and attendant consequences) is determined by the maximum allowable leakage rate values La, under Appendix J for that plant 2 Containment isolation failures (as reported in the IPEs) include those accidents in which there is a failure to isolate the containment.
3 Independent (or random) isolation failures include those accidents in which the pre-existing isolation failure to seal (i.e. provide a leak-tight containment) is not dependent on the sequence in progress.
4 Independent (or random) isolation failures include those accidents in which the pre-existing isolation failure to seal is not dependent on the sequence in progress.
This class is similar to Class 3 isolation failures, but is applicable to sequences involving Type B tests and their potential failures.
These are the Type B-tested components that have isolated but exhibit excessive leakage. 5 Independent (or random) isolation failures include those accidents in which the pre-existing isolation failure to seal is not dependent on the sequence in progress.
This class is similar to Class 4 isolation failures, but is applicable to sequences involving Type C tests and their potential failures.
6 Containment isolation failures include those leak paths covered in the plant test and maintenance requirements or verified per in service inspection and testing (ISI/IST) program. 7 Accidents involving containment failure induced by severe accident phenomena.
Changes in Appendix J testing requirements do not impact these accidents.
8 Accidents in which the containment is bypassed (either as an initial condition or induced by phenomena) are included in Class 8. Changes in Appendix J testing requirements do not impact these accidents.
4-16
4.3 IMPACT
OF EXTENSION ON DETECTION OF COMPONENT FAILURES THAT LEAD TO LEAKAGE (SMALL AND LARGE) The ILRT can detect a number of component failures such as containment breach, failure of certain bellows arrangements and failure of some sealing surfaces, which can lead to leakage. The proposed ILRT test interval extension may influence the conditional probability of detecting these types of failures.
To ensure that this effect is properly accounted for, the EPRI Class 3 accident class as defined in Table 4.2-6 is divided into two sub-classes representing small and large leakage failures.
These subclasses are defined as Class 3a and Class 3b, respectively.
The probabilities of the EPRI Class 3a and 3b failures are determined consistent with the EPRI guidance [22]. For Class 3a, the probability is based on the mean failure estimated from the available data (i.e., two "small" failures that could only have been discovered by the ILRT; 2 of 217 tests leads to a 0.0092 mean value). For Class 3b, the Jefferys non-informative prior distribution is assumed for no "large" failures in 217 tests (i.e., 0.5/(217+1)
= 0.0023). In a follow-on letter [21] to their ILRT guidance document [3], NEI issued additional information concerning the potential that the calculated delta LERF values for several plants may fall above the "very small change" guidelines of the NRC Regulatory Guide 1.174. This additional NEI information includes a discussion of conservatisms in the quantitative guidance for delta LERF. NEI describes ways to demonstrate that, using plant-specific calculations, the delta LERF is smaller than that calculated by the simplified method. The supplemental information states: "The methodology employed for determining LERF (Class 3b frequency) involves conservatively multiplying the CDF by the failure probability
- for this class (3b) of accident.
This was done for simplicity and to maintain conservatism.
However, some plant-specific accident classes leading to core damage are likely to include individual sequences that either may already (independently) cause a LERF or could never cause a LERF, and are thus not associated with a postulated large Type A containment leakage path (LERF). These contributors can be removed from Class 3b in the evaluation of LERF by multiplying the Class 3b probability by only that portion of CDF that may be impacted by type A leakage." 4-17
*--------------
The application of this additional guidance to the analysis for Hatch (as detailed in Section 5), involves the following:
- The EPRI Class 2 and Class 8 sequences are subtracted from the CDF that is applied to Class 3b. To be consistent, the same change is made to the Class 3a CDF, even though these events are not considered LERF. Class 2 and Class 8 events refer to sequences with either large pre-existing containment isolation failures or containment bypass events. These sequences are already considered to contribute to LERF in the Hatch Level 2 PRA analysis.
- The EPRI guidance and examples also note the potential for accident sequences involving the use of containment sprays or those resulting in late releases due to timing (e.g., long term station blackout, loss of containment heat removal) to be subtracted from the CDF that is applied to Class 3b. This is conservatively not performed for the base case analysis, but is evaluated as a sensitivity case in Section 6. Consistent with the EPRI guidance [22], the change in the leak detection probability can be estimated by comparing the average time that a leak could exist without detection.
For example, the average time that a leak could go undetected with a three-year test interval is 1.5 years (3 yr / 2), and the average time that a leak could exist without detection for a year interval is 5 years (10 yr/ 2). This change would lead to a non-detection probability that is a factor of 3.33 (5.0/1.5) higher for the probability of a leak that is detectable only by ILRT testing, given a 10-year versus a 3-yr interval.
Correspondingly, an extension of the ILRT interval to fifteen years can be estimated to lead to about a factor of 5.0 (7.5/1.5) increase in the non-detection probability of a leak. It should be noted that using the methodology discussed above is very conservative compared to previous submittals (e.g., the IP3 request for a one-time ILRT extension that was approved by the *NRC [7]) because it does not factor in the possibility that the failures could be detected by other tests (e.g., the Type B local leak rate tests that still occur.) Eliminating this possibility conservatively over-estimates the factor increases attributable to the ILRT extension.
4-18
4.4 IMPACT
OF EXTENSION ON DETECTION OF STEEL CORROSION THAT LEADS TO LEAKAGE An estimate of the likelihood and risk implications of corrosion-induced leakage of the steel containment occurring and going undetected during the extended test interval is using the methodology from the Calvert Cliffs liner corrosion analysis [19]. The Calvert Cliffs analysis was performed for a concrete cylinder and dome and a concrete basemat, each with a steel liner. The analysis approach can be applied to the Hatch Mark I containment design consisting of a steel drywell (floor encased in concrete) and steel torus. The following approach is used to determine the change in likelihood, due to extending the ILRT, of detecting corrosion of the containment steel. This likelihood is then used to determine the resulting change in risk. Consistent with the Calvert Cliffs analysis, the following issues are addressed:
- Differences between the containment drywell floor and the containment walls and head
- The historical steel flaw likelihood due to concealed corrosion
- The impact of aging
- The corrosion leakage dependency on containment pressure
- The likelihood that visual inspections will be effective at detecting a flaw Assumptions
- Consistent with the Calvert Cliffs analysis, a half failure is assumed for the drywell floor concealed steel corrosion due to the lack of identified failures.
- The two corrosion events over a 5.5 year data period are used to estimate the steel liner flaw probability in the Calvert Cliffs analysis and are assumed to be applicable to the Hatch containment analysis.
These events, one at North Anna Unit 2 and one at Brunswick Unit 2 (Mark I containment design), were initiated from the non-visible (backside) portion of the containment liner. It is noted that two additional events have occurred in recent years (based on a data search covering approximately 9 years documented in Reference
[27]). In November 2006, the Turkey Point 4 containment building liner developed a hole when a sump pump support plate was moved. In May 2009, a hole approximately 3/8" by 1" in size was identified in the Beaver Vaiiey 1 containment liner. For risk evaluation purposes, these two more recent events occurring over a 9 year period are judged to be adequately represented by the two events in the 5.5 year period of the Calvert Cliffs analysis incorporated in the EPRI guidance.
4-19
*--------*--*---------*------------------------
- Consistent with the Calvert Cliffs analysis, the estimated historical flaw probability is limited to 5.5 years to reflect the years from September 1996 when 10 CFR 50.55a started requiring visual inspection to when the Calvert Cliffs analysis was submitted.
Additional success data was not used to limit the aging impact of this corrosion issue, even though inspections were being performed prior to this date and have been performed since the time frame of the Calvert analysis. (See Table 4.4-1, Step 1).
- Consistent with the Calvert Cliffs analysis, the steel 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 ages. (See Table 4.4-1, Steps 2 and 3.) Sensitivity studies are included that address doubling this rate every two years and every ten years.
- In the Calvert Cliffs analysis the likelihood of the containment atmosphere reaching the outside atmosphere given that a flaw exists was estimated as 1.1% for the cylinder and dome region, and 0.11% (10% of the cylinder failure probability) for the basemat. These values were determined from an assessment of the probability versus containment pressure, and the selected values are consistent with a pressure that corresponds to the ILRT target pressure of 37 psig. For the Hatch Mark I containment, the containment failure probabilities are conservatively assumed to be 1 % for the drywell vertical walls and head along with the wetwell torus, and 0.1 % for the drywell floor for this analysis.
Sensitivity studies are included that increase and decrease the probabilities by an order of magnitude. (See Table 4.4-1, Step 4.)
- Consistent with the Calvert Cliffs analysis, the likelihood of leakage escape (due to crack formation) in the concrete encased drywell floor region is considered less likely than the containment walls and had region. (See Table 4.4-1, Step 4)
- Consistent with the Calvert Cliffs analysis, a 5% visual inspection detection failure likelihood given the flaw is visible and a total detection failure likelihood of 10% is used. To date, all iiner corrosion events have been detected through visual inspection.
For Hatch, there is generally 100% accessibility for visual inspection of the interior surfaces of the drywell above the floor elevation, the outside surfaces of the suppression pool, the inside surfaces of the suppression pool (using divers below the water line), and the vent system. (See Table 4.4-1, Step 5.) Sensitivity studies are included that evaluate total detection failure likelihood of 5% and 15%, respectively.
- Consistent with the Calvert Cliffs analysis, all non-detectable containment failures are assumed to result in early releases.
This approach avoids a detailed analysis of containment failure timing and operator recovery actions. 4-20 Table 4.4-1 STEEL CONTAINMENT CORROSION BASE CASE STEP DESCRIPTION 1 Historical Steel Flaw Likelihood 2 3 4 Failure Data: Containment location specific (consistent with Calvert Cliffs analysis).
Age Adjusted Steel Flaw Likelihood During 15-year interval, assume failure rate doubles every five years (14.9% increase per year). The average for 5th to 10th year is set to the historical failure rate (consistent with Calvert Cliffs analysis).
Flaw Likelihood at 3, 10, and 15 years Uses age adjusted flaw likelihood (Step 2), assuming failure rate doubles every five years (consistent with Calvert Cliffs analysis -See Table 6 of Reference
[19]). Likelihood of Breach in Containment Given Steel Flaw The failure probability of the DW walls, head, and torus is assumed to be 1% (compared to 1.1 % in the Calvert Cliffs analysis).
The DW floor failure probability is assumed to be a factor of ten less, 0.1%, (compared to 0.11% in the Calvert Cliffs analysis).
DW WALLS AND HEAD, AND TORUS DRYWELL FLOOR Events: 2 Events: O (assume half a failure) 2/(70
- 5.5) = 5.2E-3 0.5/(70
- 5.5) = 1.3E-3 Year 1 avg 5-10 15 Failure Rate 2.1E-3 5.2E-3 1.4E-2 15 year average = 6.27E-3 0.71% (1 to 3 years) 4.060/o (1 to 10 years) 9.400/o (1 to 15 years) (Note that the Calvert Cliffs analysis presents the delta between 3 and 15 years of 8.7% to utilize in the estimation of the delta-LERF value. For this analysis the values are calculated based on the 3, 10, and 15 year intervals.)
Year 1 avg 5-10 15 Failure Rate 5.0E-4 1.3E-3 3.SE-3 15 year average = 1.57E-3 0.180/o (1 to 3 years) 1.020/o (1 to 10 years) 2.350/o (1 to 15 years) (Note that the Calvert Cliffs analysis presents the delta between 3 and 15 years of 2.2% to utilize in the estimation of the delta-LERF value. For this analysis, however, v_alues are calculated based on the 3, 10, and 15 year intervals.)
0.1°/o 4-21 Table 4.4-1 STEEL CONTAINMENT CORROSION BASE CASE OW WALLS AND HEAD, STEP DESCRIPTION AND TORUS DRYWELL FLOOR 5 Visual Inspection Detection 100/o 100°/o Failure Likelihood 5% failure to identify visual Cannot be visually inspected.
Utilize assumptions consistent flaws plus 5% likelihood that with Calvert Cliffs analysis the flaw is not visible (not while also accouting for the through-wall but could be unique arrangement of the detected by ILRT). Hatch containment.
All events have been detected through visual inspection.
A 5% visible failure detection is a conservative assumption.
6 Likelihood of Non-Detected 0.000710/o (at 3 years) 0.000180/o (at 3 years) Containment Leakage =0.71%
- 1%
- 10% =0.18%
- 0.1%
- 100% (Steps 3
- 4
- 5) 0.00410/o (at 10 years) 0.00100/o (at 10 years) =4.1%
- 1%
- 10% =1.0%
- 0.1%
- 100% 0.00940/o (at 15 years) 0.00240/o (at 15 years) =9.4%
- 1%
- 10% =2.4%
- 0.1%
- 100% 4-22 The total likelihood of the corrosion-induced, non-detected containment leakage is the sum of Step 6 for the DW walls, head, and torus, and the drywell floor: At 3 years : 0.00071% + 0.00018% = 0.00089% = 8.9E-6 At 10 years: 0.0041% + 0.0010% = 0.0051% = 5.lE-5 At 15 years: 0.0094% + 0.0024% = 0.012% = 1.2E-4 Based on the above, a corrosion impact factor due to undetected corrosion is calculated as follows for the three ILRT cases investigated:
Corrosion impact factor = (3b Conditional Failure Probability
+ Total Likelihood of detected containment leakage due to corrosion at interval) 3b Conditional Failure Probability Case 1: 3 ILRT per 10 years 2.30E-03 + 8.9E-06 = 1.004 2.30E-03 Case 2: 1 ILRT Per 10 years 7.67E-03 + 5.lE-05 = 1.007 7.67E-03 Case 3: 1 ILRT per 15 years 1.lSE-02 + 1.2E-04 = 1.01 1.lSE-02 These impact factors are used to adjust the EPRI 3b class frequencies to model the impact of undetected corrosion.
4-23
5.0 RESULTS
The application of the approach based on the guidance contained in EPRI TR-1018243
[22], EPRI-TR-104285
[2] and previous risk assessment submittals on this subject [6, 7, 19, 20, 23] have led to the following results. The results are displayed according to the eight accident classes defined in the EPRI report. Table 5.0-1 lists these accident classes. The analysis performed examined Hatch specific accident sequences in which the containment remains intact or the containment is impaired.
Specifically, the break down of the severe accidents contributing to risk were considered in the following manner:
- Core damage sequences in which the containment remains intact initially and in the long term (EPRI TR-104285 Class 1 sequences).
- Core damage sequences in which containment integrity is impaired due to random isolation failures of plant components other than those associated with Type B or Type C test components.
For example, containment breach or bellows leakage. (EPRI TR-104285 Class 3 sequences).
- Core damage sequences in which containment integrity is impaired due to containment isolation failures of pathways left "opened" following a plant post-maintenance test. (For example, a valve failing to close following a valve stroke test.) (EPRI TR-104285 Class 6 sequences).
Consistent with the NEI Guidance, this class is not specifically examined since it will not significantly influence the results of this analysis.
- Accident sequences involving containment bypassed (EPRI TR-104285 Class 8 sequences), large containment isolation failures (EPRI TR-104285 Class 2 sequences), and small containment isolation to-seal" events (EPRI TR-104285 Class 4 and 5 sequences) are accounted for in this evaluation as part of the baseline risk profile. However, they are not affected by the ILRT frequency change.
- Class 4 and 5 sequences are impacted by changes in Type B. and C test intervals; therefore, changes in the Type A test interval do not impact these sequences.
5-1 Table 5.0-1 EPRI ACCIDENT CLASSES ACCIDENT CLASSES (CONTAINMENT RELEASE TYPE) DESCRIPTION 1 No Containment Failure 2 Large Isolation Failures (Failure to Close) 3a Small Isolation Failures (containment breach) 3b Large Isolation Failures (containment breach) 4 Small Isolation Failures (Failure to seal -Type B) 5 Small Isolation Failures (Failure to seal-Type C) 6 other Isolation Failures (e.g., dependent failures) 7 Failures Induced by Phenomena (Early and Late) 8 Bypass (SGTR and Interfacing System LOCA) CDF All CET End states (including very low and no release) The steps taken to perform this risk assessment evaluation are as follows: Step 1 Step 2 Step 3 Step 4 Step 5 Step 6 Quantify the base-line risk in terms of frequency per reactor year for each of the eight accident classes presented in Table 5.0-1. Develop plant-specific person-rem dose (population dose) per reactor year for each of the eight accident classes. Evaluate risk impact of extending Type A test interval from 3 to 15 and 10 to 15 years. Determine the change in risk in terms of Large Early Release Frequency (LERF) in accordance with RG 1.174. Determine the impact on the Conditional Containment Failure Probability (CCFP) Determine the impact on the 50-mile population dose risk. 5-2 5.1 STEP 1 -QUANTIFY THE BASE-LINE RISK IN TERMS OF FREQUENCY PER REACTOR YEAR As previously described, the extension of the Type A interval does not influence those accident progressions that involve large containment isolation failures, Type B or Type C testing, or containment failure induced by severe accident phenomena.
For the assessment of ILRT impacts on the risk profile, the potential for pre-existing leaks is included in the model. These events are represented by the EPRI Class 3 sequences.
Two failure modes were considered for the Class 3 sequences.
These are Class 3a (small breach) and Class 3b (large breach). The frequencies for the EPRI accident classes defined in Table 5.0-1 were developed for Hatch by first determining the frequencies for Classes 1, 2, 7, and 8, then determining the frequencies for Classes 3a and 3b, and finally determining the frequency for Class 1. Classes 4, 5, and 6 are not impacted by the ILRT interval and are therefore not specifically evaluated.
Adjustments are made to the Class 3b frequency and hence Class 1 frequency to account for the impact of undetected corrosion of the steel containment per the methodology described in Section 4.4. Class 1 Sequences This group represents the frequency when the containment remains intact (modeled as Technical Specification Leakage).
The EPRI Class 1 frequency is calculated as the intact containment release frequency from Table 4.2-la (1.18E-06/yr) minus the EPRI Class 3a and 3b frequencies (6.31E-08/yr and 1.58E-08/yr, respectively) calculated below. For this analysis, the associated maximum containment leakage for this group is lla, consistent with an intact containment evaluation.
The EPRI Class 1 frequency is 1. lOE-06/yr.
Class 2 Sequences This group consists of all core damage accident sequences for which a large containment isolation failure(s) occurs (e.g., valve failure to close). 5-3 ATTACHMENT 4 Clean Copies of Technical Specification Pages 5.0-16 TS 5.5.12 Programs and Manuals 5.5 5.5 Programs and Manuals (continued) 5.5.12 Primary Containment Leakage Rate Testing Program A program shall be established to implement the leakage rate testing of the primary containment as required by 1 O CFR 50.54(0) and 1 O 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 1 O CFR 50, Appendix J," Revision 3-A, dated July 2012, and the conditions and limitations specified in NEI 94-01, Revision 2-A, dated October 2008. The peak calculated primary containment internal pressure for the design basis loss of coolant accident, Pa, is 50.8 psig. The maximum allowable primary containment leakage rate, La, at Pa is 1.2% of primary containment air weight per day. Leakage rate acceptance criteria are: a. 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 Band Type C tests, and:::; 0.75 La for Type A tests; b. Air lock testing acceptance criteria are: 1) Overall air lock leakage rate is :::; 0.05 La when tested at?: Pa, 2) For each door, leakage rate is :::; 0.01 La when the gap between the door seals is pressurized to?: 1 O psig for at least 15 minutes. The provisions of SR 3.0.2 do not apply to the test frequencies specified in the Primary Containment Leakage Rate Testing Program. (continued)
HATCH UNIT 1 5.0-16 Amendment No.
Programs and Manuals 5.5 5.5 Programs and Manuals (continued) 5.5.12 Primary Containment Leakage Rate Testing Program A program shall be established to implement the leakage rate testing of the primary containment as required by 1 O CFR 50.54(0) and 1 O 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. The peak calculated primary containment internal pressure for the design basis loss of coolant accident, Pa, is 47.3 psig. The maximum allowable primary containment leakage rate, La, at Pa is 1.2°/ci of primary containment air weight per day. Leakage rate acceptance criteria are: a. 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; b. Air lock testing acceptance criteria are: 1) Overall air lock leakage rate is :::; 0.05 La when tested at:::; Pa, 2) For each door, leakage rate is :::; 0.01 La when the gap between the door seals is pressurized to ;::: 1 O psig for at least 15 minutes. The provisions of SR 3.0.2 do not apply to the test frequencies specified in the Primary Containment Leakage Rate Testing Program. (continued)
HATCH UNIT 2 5.0-16 Amendment No.
Charles R. Pierce Regulatory Affa.irs Director JUL O 1 201& Docket Nos.: 50-321 50-366 Southern Nuclear Operating Company, Inc. 40 Inverness Center Parkway Post Office Box 1295 Birmingham, AL 35242 Tel 205.992.7872 Fax 205.992.7601 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D.C. 20555-0001 Southern Nuclear Operating Company SOUTHERN NUCLEAR A SOUTHERN COMPANY NL-16-0626 Edwin I. Hatch Nuclear Plant Units 1 and 2; License Amendment Request to Revise Technical Specification Section 5.5.12 for Permanent Extension of Type A and Type C Leak Rate Test Frequencies Ladies and Gentlemen:
Pursuant to 1 O CFR 50.90, Southern Nuclear Operating Company (SNC) requests an amendment to the Edwin I. Hatch Nuclear Plant (HNP) Unit 1, Renewed Facility Operating License (DPR-57), and Unit 2, Renewed Facility Operating License (NPF-5), by incorporating the attached proposed change into the Unit 1 and Unit 2 Technical Specifications (TS). Specifically, the proposed change is a request to revise TS 5.5.12 "Primary Containment Leakage Rate Testing Program" to allow the following:
- Increase in the existing Type A integrated leakage rate test (ILRT) program test interval from 1 O years to 15 years in accordance with Nuclear Energy Institute (NEI) Topical Report NEI 94-01, Revision 3-A and the and limitations specified in NEI 94-01, Revision 2-A.
- Adopt an extension of the containment isolation valve (CIV) leakage testing (Type C) frequency from the 60 months currently permitted by 1 O CFR 50, Appendix J, 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.
- Adopt the use of American National Standards Institute/American Nuclear Society (ANSI/ANS) 56.8-2002, Containment System Leakage Testing Requirements.
- Adopt a more conservative grace interval of 9 months, for Type A, Type B and Type C leakage tests in accordance with NEI 94-01, Revision 3-A. The proposed change to the TS contained herein would revise HNP TS 5.5.12, by replacing the references to Regulatory Guide (RG) 1.163, Performance-Based Containment Leak-Test Program and 1 O CFR 50, Appendix J, Option B with a reference to NEI topical report NEI 94-01, Revision 3-A (Reference 2), dated July 2012, and the conditions and limitations specified in NEI 94-01, Revision 2-A U.S. Nuclear Regulatory Commission NL-16-0626 Page 2 dated October 2008, as the documents used by HNP to implement the performance-based leakage testing program in accordance with Option B of 1 O CFR 50, Appendix J. This license amendment request (LAA) also proposes the following administrative changes to TS 5.5.12:
- Deleting the information regarding the performance of the next HNP Unit 1 and Unit 2 Type A test to be performed no later than April 2008 for Unit 1 and no later than November 201 O for Unit 2, as both Type A tests have already occurred.
In addition, the Basis for TS Surveillance Requirement (SR) 3.6.1.1.1 is revised to incorporate the references to the NEI 94-01 documents and ANSI/ANS 56.8-2002, Containment System Leakage Testing Requirements.
The Bases changes are being provided for informational purposes only and will be implemented in accordance with the TS Bases Control Program based upon approval of this LAA. SNC requests approval within 12 months. The proposed changes will be implemented within six months of issuance of the amendment.
Enclosure 1 provides the evaluation of the proposed change and includes attachments with mark-ups and clean copies of the TS pages, mark-ups of TS Bases pages, and the risk assessment supporting the proposed amendment.
This letter contains no NRC commitments.
If you have any questions, please contact Ken McElroy at (205) 992-7369.
Mr. C. R. Pierce states he is the Regulatory Affairs Director for Southern Nuclear Operating Company, is authorized to execute this oath on behalf of Southern Nuclear Operating Company and, to the best of his knowledge and belief, the facts set forth in this letter are true. C. R. Pierce Regulatory Affairs Director crp/efb/lac ex_ subscribed before me this j sf day of :Ji"t ) '1 '2016. My commission expires: /-2 .. Z0/ 11 -. '
U.S. Nuclear Regulatory Commission NL-16-0626 Page 3
Enclosure:
- 1. Evaluation of Proposed Change cc: Southern Nuclear Operating Company Mr. S. E. Kuczynski, Chairman, President
& CEO Mr. D. G. Bost, Executive Vice President
& Chief Nuclear Officer Mr. D. R. Vineyard, Vice President
-Hatch Mr. M. D. Meier, Vice President
-Regulatory Affairs Mr. B. J. Adams, Vice President
-Engineering Mr. Demitrius Davis, Fleet Programs Director Mr. W. David Morrow, Fleet Programs Manager Mr. Mitch Etten-Bohm, Senior Engineer Mr. G. L. Johnson, Regulatory Affairs Manager -Hatch RType: Hatch=CHA02.004 U.S. Nuclear Regulatory Commission Ms. C. Haney, Regional Administrator Mr. M. D. Orenak, NRR Senior Project Manager -Hatch Mr. D. H. Hardage, Senior Resident Inspector
-Hatch Alabama Department of Public Health Dr. T. M. Miller, MD, State Health Officer State of Georgia Mr. J. H. Turner, Director -Environmental Protection Division Southern Nuclear Operating Company Edwin I. Hatch Nuclear Plant Units 1 and 2; License Amendment Request for Changes to License Amendment Request to Revise Technical Specification Section 5.5.12 for Permanent Extension of Type A and Type C Leak Rate Test Frequencies Enclosure 1 Evaluation of Proposed Change EVALUATION OF PROPOSED CHANGE Enclosure Page 1 of 81
SUBJECT:
License Amendment Request -Revise Technical Specification Section 5.5.12 for Permanent Extension of Type A and Type C Leak Rate Test Frequencies 1.0
SUMMARY
DESCRIPTION
2.0 DETAILED
DESCRIPTION
3.0 TECHNICAL
EVALUATION
4.0 REGULATORY EVALUATION
4.1 Applicable
Regulatory Requirements/Criteria
4.2 Precedent
4.3 No Significant Hazards Consideration
4.4 Conclusion
5.0 ENVIRONMENTAL
CONSIDERATION
6.0 REFERENCES
Attachments:
- 1. Technical Specifications Pages Markups 2. Bases Page Markups (For Information Only) 3. Plant Hatch Units 1 & 2 Risk Assessment to Support ILRT (Type A) Interval Extension Request 4. Technical Specifications Pages Clean Copies Hatch Nuclear Plant Units 1 and 2 1.0
SUMMARY
DESCRIPTION Enclosure Page 2 of 81 Pursuant to 10 CFR 50.90, Southern Nuclear Operating Company (SNC) requests an amendment to the Edwin I. Hatch Nuclear Plant (HNP) Unit 1, Renewed Facility Operating License (DPR-57), and Unit 2, Renewed Facility Operating License (NPF-5), by incorporating the attached proposed change into the Unit 1 and Unit 2 Technical Specifications (TS). Specifically, the proposed change is a request to revise TS 5.5.12 "Primary Containment Leakage Rate Testing Program" to allow the following:
- Increase in 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 NEI 94-01, Revision 3-A and the conditions and limitations specified in NEI 94-01, Revision 2-A.
- Adopt an extension of the containment isolation valve (CIV) leakage testing (Type C) frequency from the 60 months currently permitted by 10 CFR 50, Appendix J, 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.
- Adopt the use of American National Standards Institute/American Nuclear Society (ANSI/ANS) 56.8-2002, Containment System Leakage Testing Requirements.
- Adopt a more conservative grace interval of 9 months, for Type A, Type B and Type C leakage tests in accordance with NEI 94-01, Revision 3-A. The proposed change to the TS contained herein would revise HNP TS 5.5.12, by replacing the references to Regulatory Guide (RG) 1.163, Performance-Based Containment Leak-Test Program, (Reference
- 1) and 10 CFR 50, Appendix J, Option B with a reference to NEI topical report NEI 94-01, Revision 3-A (Reference 2), dated July 2012, and the conditions and limitations specified in NEI 94-01, Revision 2-A (Reference 8), dated October 2008, as the documents used by HNP to implement the performance-based leakage testing program in accordance with Option B of 1 O CFR 50, Appendix J. This license amendment request (LAR) also proposes the following administrative changes to TS 5.5.12:
- Deleting the information regarding the performance of the next HNP Unit 1 and Unit 2 Type A test to be performed no later than April 2008 for Unit 1 and no later than November 2010 for Unit 2, as both Type A tests have already occurred.
In addition, the Basis for TS Surveillance Requirement (SR) 3.6.1.1.1 is revised to incorporate the references to the NEI 94-01 documents and ANSI/ANS 56.8-2002, Containment System Leakage Testing Requirements.
The Bases changes are being provided for informational purposes only and will be implemented in accordance with the TS Bases Control Program based upon approval of this LAR.
2.0 DETAILED
DESCRIPTION
2.1 Current
Containment Leakage Rate Testing Program Enclosure Page 3 of 81 HNP, Units 1 and 2 TS 5.5.12, "Primary Containment Leakage Rate Testing Program," currently states, in part: * " A program shall be established to implement the leakage rate testing of the primary containment as required by 10 CFR 50.54(0) 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-Test Program/'
dated September 1995, as modified by the following exception to NEI 94-01, Rev. 0, "Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J": Unit 1: Unit 2: Section 9.2.3: The first Type A test after the April 1993 Type A test shall be performed no later than April 2008. Section 9.2.3: The first Type A test after the November 2, 1995, Type A test shall be performed no later than November 201 O." 2.2 TS Change Description The proposed changes to HNP, Units 1and2, TS 5.5.12 will remove Unit 1 and Unit 2 TS exceptions, and replace the reference to RG 1.163 with a reference to NEI Topical Report NEI 94-01 Revisions 2-A and 3-A. The proposed change would allow an increase in the Integrated Leak Rate Test (ILRT) test interval from its current 10-year frequency to a maximum of 15 years and the extension of the CIV leakage test (Type C tests) from the current 60-month frequency to 75 months, in accordance with NEI 94-01, Revision 3-A and the conditions and limitations specified in NEI 94-01, Revision 2-A. In addition, this LAR proposes to adopt a more conservative grace interval of 9 months, for Type A, Type B and Type C leakage tests in accordance with NEI 94-01, Revision 3-A, for non-routine, emergent conditions.
This LAR also proposes the following administrative changes to TS 5.5.12:
- Deleting the information regarding the performance of the next HNP Unit 1 Type A test no later than April 2008 and the next HNP Unit 2 Type A test no later than November 2010, as both Type A tests have already occurred.
The proposed change will revise TS 5.5.12 to state, in part: Enclosure Page 4 of 81 "A program shall be established to implement the leakage testing of the containment as required by 10 CFR 50.54(0) 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." Markups of TS 5.5.12 for both HNP Units 1 and 2 are provided in Attachment
- 1. Markups of TS Bases for SR 3.6.1.1 Primary Containment, and SR 3.6.1.1.1 for both HNP Units 1 and 2 are provided in Attachment 2 for informational purposes only. Based upon approval of this LAR, these TS Bases changes will be implemented in accordance with the TS Bases Control Program. Attachment 3 contains the plant specific risk assessment conducted to support this proposed change. This risk assessment followed the guidelines of NRC RG 1.17 4, Revision 2 (Reference
- 3) and NRC RG 1.200, Revision 2 (Reference 4). The risk assessment concluded that increasing the ILRT interval to 15 years is considered to represent an insignificant change in risk for HNP. 3.0 TECHNICAL EVALUATION
3.1 Description
of Primary Containment System The primary containment system houses the reactor pressure vessel, the reactor coolant recirculation system, and other branch connections of the reactor coolant system (RCS). The primary containment consists of the drywell, the suppression chamber that stores a large volume of water, a connecting vent system between the drywell and suppression chamber, isolation valves, a vacuum relief system, containment cooling systems, and other service equipment.
The drywell is a steel pressure vessel in the shape of a light bulb, and the suppression chamber is a torus-shaped steel pressure vessel located below and encircling the drywell. The primary containment system is designed to withstand the pressures resulting from a breach of the nuclear system process piping up to and including an instantaneous circumferential break of the reactor recirculation piping. The primary containment system provides a holdup for the decay of any released radioactive material and stores sufficient water to:
Enclosure Page 5 of 81
- Condense the steam released as a result of a breach in the nuclear system process barrier.
- Supply the emergency core cooling system (ECCS). The primary containment system free volume is filled with a nitrogen atmosphere during normal operation.
The containment atmospheric control system is capaQle of reducing and maintaining the oxygen content of the atmosphere below 4 percent during normal operation.
3.1.1 Drywall
The drywall is a steel pressure vessel with a spherical lower portion 65 feet (ft.) in diameter and a cylindrical upper portion 35 ft. 7 inches (in.) in diameter for Unit 1 and 37 ft 1 in. in diameter for Unit 2. The overall height of the drywall is approximately 111 ft. The design, fabrication, inspection, and testing of the Unit 1 drywall comply with the requirements of the American Society of Mechanical Engineers (ASME) Code, Section Ill, Subsection 8, Requirements for Class 8 Vessels, which pertains to containment vessels for nuclear power stations.
The primary containment is fabricated of SA-516 grade 70 plates. The design, fabrication, inspection, and testing of the Unit 2 drywall vessel comply with requirements of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code, Section Ill, Nuclear Power Plant Components, Subsection NE, Requirements for Class MC Components, 1971 Edition, including 1971 Summer Addenda which pertain to containment vessels for nuclear power plants. The steel head and shell of the drywall are fabricated of SA-516 GR70 steel plate. The Unit 1 drywall is designed for an internal pressure of 56 pounds per square inch gage (psig) coincident with a temperature of 281 degrees Fahrenheit
(°F) for Unit 1 and 340 °F for Unit 2, with applicable dead, live, and seismic loads imposed on the shell. Thermal stresses in the steel shell due to temperature gradients are also incorporated into the design. Thus, in accordance with the ASME Code, Section Ill, the maximum drywall pressure is 62 psig. Charpy V-notch impact tests were performed on specimens of all plate and forged materials.
Plates, forgings, and pipes of the drywall have an initial nil ductility transition temperature (NOTT) of -0°F when tested in accordance with the appropriate code for these materials.
It can be reasonably expected that the drywall is neither pressurized nor subjected to a substantial stress at temperatures below 30°F. The drywall is enclosed in a reinforced concrete structure for shielding purposes.
Resistance to deformation and buckling of the drywall plate is provided in areas where the concrete backs up the steel shell. Above the transition zone, the drywall is separated from the reinforced concrete by an airgap of approximately 2 in. Shielding Enclosure Page 6 of 81 over the top of the drywell is provided by removable, segmented, reinforced concrete shield plugs. 3.1.2 Suppression Chamber The suppression chamber is a steel pressure vessel in the shape of a torus located below and encircling the drywell, with a major diameter of approximately 107 ft. for Unit 1 and 107 ft. 1 in. for Unit 2, a cross-sectional diameter of approximately 28 ft. for Unit 1 and 28 ft. 1 in. for Unit 2. The suppression chamber contains the suppression pool and the air space above the pool. The suppression chamber transmits seismic loading to the reinforced concrete foundation slab of the reactor building.
Space is provided outside the chamber for inspection.
The torus-shaped suppression chamber is designed to the same material and code requirements as the steel drywell vessel. The material has an NOTT ::5 0°F. Modifications were made to the suppression chamber due to hydrodynamic loads identified during the Mark I Containment Long-Term Program. 3.1.3 Vent System Large vent pipes connect the drywell and the suppression chamber. Eight circular vent pipes, each having a diameter of 5 ft. 11 in. for Unit 1 and 6 ft. 3 in. for Unit 2, are provided.
The vent pipes are designed for the same pressure and temperature conditions as the drywell and suppression chamber. Jet deflectors in the drywell at the entrance of each vent pipe prevent possible damage to the vent pipe from jet forces that can accompany a pipe break within the drywell. Modifications were made to the vent system due to hydrodynamic loads identified during the Mark I Containment Long-Term Program. The drywell vents are connected to a 4-ft 6-in. diameter vent header from the torus that is contained within the suppression chamber airspace.
Projecting downward from the header are 80 downcomer pipes that are 24 in. in diameter and terminate 4 ft. 0 in. below the water surface of the suppression pool for Unit 1 and 4 ft. 4 in. for Unit 2. The vent system inside the torus is not pressure tested, although the vent pipes from the drywell to the suppression chamber are tested as part of the primary containment test. The vent system, which is designed for a differential pressure (LiP) of 56 psi between the drywell and suppression chamber, would be subjected to < 35 pounds per square inch differential (psid) during a loss of coolant accident (LOCA). 3.1.4 Suppression Pool The suppression pool contains demineralized water; serves as a heat sink for postulated anticipated operational occurrences (AOOs), accidents, and special events; and is a source of water for the ECCS. Enclosure Page 7 of 81 The suppression pool receives energy in the form of steam and water from either the safety relief valve (SRV) discharge piping or the drywall vent system downcomers that discharge under water. The steam is condensed in the suppression pool. The condensed steam and any water carryover cause an increase in pool volume and temperature.
Energy is removed from the suppression pool when the residual heat removal (RHR) system is operating in the suppression pool cooling mode. 3.1.5 Penetrations 3.1.5.1 Pipe Penetrations Two general types of pipe penetrations are provided:
- Penetrations that must accommodate thermal movement.
- Penetrations that experience relatively little thermal stress. Some piping penetrations, such as those used for the steam lines, have special provisions for thermal movement.
In these penetrations, the process line is enclosed in a guard pipe attached to the main steam line (MSL) through a multiple head fitting. This fitting is a one-piece forging with integral flues and is designed to meet all requirements of the ASME Code, Section Ill, Subsection B. The forging is radiographed and ultrasonically tested as specified by the ASME Code. The guard pipe and flued head are designed to the same pressure requirements as the process line. The process line penetration sleeve is welded to the drywall and extends through the biological shield where it is welded to a two-ply expansion bellows assembly that is welded to the flued-head fitting. The pipe is guided through pipe supports at the end of the penetration assembly to allow steam line movement parallel to the penetration and limit pipe reactions of the penetration to allowable stress levels. Where necessary, the penetration assemblies are anchored outside the containment to limit the movement of the line relative to the containment.
The bellows accommodate the movement between the pipe and the containment shell. The bellows-type expansion joints used in the containment penetrations were designed,
- manufactured, and inspected to ASME Code, Section Ill, in conjunction with Code Cases 1177-7 and 1330-2. These code cases, along with Section Ill, delineate the allowable stress limits for the bellows-type expansion joints and nondestructive examination requirements for bellows used in nuclear service. The cold piping, ventilation duct, and instrument line penetrations are generally welded directly to the sleeves. Double-flued head fittings are used in some cases where stress Enclosure Page 8 of 81 analyses indicate the need. Bellows and guard pipes are not necessary in these designs, since the thermal stresses are small and are accounted for in the design of the weld joint. 3.1.5.2 Electrical Penetrations All penetrations are hermetically sealed with provisions for periodic leak testing at design pressure.
The penetration canisters are factory assembled and tested with the number of field welds held to a minimum. These seals also meet the intent ASME Code, Section Ill, even though the Code has no provisions for qualifying the procedures or performances.
3.1.5.3 Traversing lncore Probe (TIP) Penetrations The TIP guide tubes pass from the reactor building through the primary containment.
The guide tube penetrations through the primary containment are sealed by means of brazing that meets the requirements of the ASME Code,Section VIII. These seals also meet the intent of ASME Code, Section Ill, even though the Code has no provisions for qualifying procedures or performances.
3.1.5.4 Personnel and Equipment Access Locks One personnel access lock provides access to the drywell. The lock has two gasketed doors in series that are designed and constructed to withstand the drywell design pressure.
The doors are mechanically interlocked to ensure that at least one door is locked at times when primary containment is required.
However, in case of a threat to plant personnel safety, breakglass stations are provided inside the drywell, as well as inside the airlock, with a selector switch inside the reactor building to defeat these interlocks.
Breakage of the glass or operation of the selector switch is annunciated in the MCA. The locking mechanisms are designed to maintain a tight seal when the doors are subjected to either internal or external pressure.
The seals on this access opening are capable of being tested for leakage. A bolted-in-place personnel access hatch in the drywell head contains double, testable seals. Two bolted-in-place equipment access hatches contain double, testable seals. Personnel and equipment hatches are sized and located with full consideration of service required, accessibility for maintenance, and periodic testing programs.
A 2-in. minimum gap is maintained around the barrel of the personnel and equipment hatches where they pass through or enter the concrete shield wall. A bolted-in-place control rod drive removal hatch, with double, testable seals permits extensive maintenance of the drive mechanism, if required.
3.1:5.5 Access to Suppression Chamber Enclosure Page 9 of 81 Access to the suppression chamber is provided at two locations via two 4-ft diameter manhole entrances with double-gasketed, bolted covers connected to the chamber by 4-ft diameter steel pipes. These access ports are bolted closed when primary containment is required and are opened only when the primary system temperature is s 212°F and the pressure-suppression system is not required to be operable.
3.1.5.6 Access for Refueling Operations The top portion of the drywell is removed during refueling operations.
The head is held in place by bolts and is sealed with a double seal arrangement.
The head is bolted closed when primary containment is required and is opened only when the primary coolant temperature is < 212°F and the pressure-suppression system is not required to be operable.
The double seal on the head flange provides a method for determining leak tightness after the drywell head has been replaced.
3.1.6 Net Positive Suction Head Analysis for HNP Unit 1 and Unit 2 3.1.6.1 HNP-1 Short-Term Response Calculations performed at 156 °F (Unit 1) 155 °F (Unit 2) suppression pool temperature at a power level of 2804 MWt and reactor operating pressure of 1060 psia demonstrate that containment overpressure is not required for either the RHR or CS pumps during the short-term post-LOCA period. 3.1.6.2. HNP-2 Short-Term Response The LPCI mode of RHR and the CS system are designed to ensure adequate NPSH margin availability under all combinations of foreseeable adverse conditions.
The point of minimum margin for all pumps occurs at the peak suppression pool temperature calculated on the basis of conservative assumptions.
No dependence is placed on positive containment pressure.
The regulatory position given in RG 1.1 (November 1970) is met. 3.1.6.3 HNP-1 Long Term Response Using the results of the long-term analysis and the equation for available NPSH, it was determined that 2.91 psig (6.7 ft.) of containment overpressure is required to ensure adequate NPSH to the RHR pumps, and 2.85 psig (6,6 ft.) of containment overpressure is required to ensure adequate NPSH to the CS pumps at the peak calculated suppression pool temperature of 210°F.
Enclosure Page 10 of 81 Using the calculated suppression pool temperature profile, containment overpressure is required for a period from approximately
2.6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />s
(hrs.) to 18.7 hrs. after LOCA initiation.
To provide sufficient margin for the peak suppression pool temperature of 210 °F, the long-term NPSH evaluation takes credit for a containment overpressure of 4.2 psig (1 Oft.). The overpressure credit is applied for a period of 1.5 to 26.5 hrs. following LOCA initiation.
Any changes resulting in an individual or collective increase of 1 ft. (approximately 0.4 psig) of the containment overpressure margin of 10 ft. (4.2 psig) requires NRC notification.
3.1.6.4 HNP-2 Long-Term Response The long-term containment response analysis demonstrates the RHR and CS pumps have NPSH ma,rgin without taking credit for containment overpressure.
3.2 Justification
for the Technical Specification Change 3.2.1 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. Title 10 CFR 50, Appendix J also ensures that periodic surveillance of reactor containment penetrations and isolation valves is performed so that proper maintenance and repairs are made during the service'life of the containment and the systems 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 design basis accident.
Appendix J identifies three types of required tests: 1) Type A tests, intended to measure the primary containment overall integrated leakage rate; 2) Type B tests, intended to detect local leaks and to measure leakage across pressure-containing or leakage limiting boundaries (other than valves) for primary containment penetrations, and; 3) Type C tests, intended to measure containment isolation valve leakage rates. Types B and C tests identify the vast majority of potential containment leakage paths. Type A tests identify the overall (integrated) containment leakage rate and serve to ensure continued leakage integrity of the containment structure by evaluating those structural parts of the containment not covered by Type B and C testing. In 1995, 10 CFR 50, Appendix J, "Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors," 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 Enclosure Page 11 of 81 failure. The use* of the term "performance-based" in 1 O 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 8. Also in 1995, RG 1.163 (Reference
- 5) with certain modifications and additions.
Option 8, 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 was considered in the establishment of the intervals allowed by RG 1.163 and NEI 94-01, but that this "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 8 to 10 CFR 50, Appendix J, subject to the limitations and conditions noted in Section 4.0 of the NRC Safety Evaluation Report (SER) on NEI 94-01. The NRC SER was included in the front matter of the NEI 94-01, Revision 2-A report. 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 (September 1995). It delineates a performance-based approach for determining Type A, Type 8, 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 8 to 10 CFR 50, Appendix J and includes provisions for extending Type A ILRT intervals to up to 15 years. NEI 94-01 has been endorsed by RG 1.163 and NRC SERs of June 25, 2008 (Reference
- 9) and June 8, 2012 (Reference
- 10) as an acceptable methodology for complying with the provisions of Option 8 to 10 CFR 50. The regulatory positions stated in RG 1.163 as modified by NRC SERs dated June 25, 2008 and June 8, 2012 are incorporated in this document.
It delineates a performance-based approach for determining Type A, Type 8, and Type C containment leakage rate surveillance testing frequencies.
Justification of extending test intervals is based on the performance history and risk insights.
Extensions of Type 8 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 administrative limits. Intervals may be increased from 30 months up to a maximum of 120 months for Type 8 tests (except for containment airlocks) and Enclosure Page 12 of 81 up to a maximum of 75 months for Type G tests. If a licensee considers extended test intervals of greater than 60 months for Type B or Type G 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 NRG has provided the following concerning the use of grace in the deferral of ILRTs beyond the 15-year interval in NEI 94-01, Revision 2-A, NRG SER Section 3.1 .1 .2, which states, in part: " ... Section 9.2.3, NEI TR 94-01, Revision 2, states, "Type A testing shall be performed during a period of reactor shutdown at a frequency of at least once per 15 years based on acceptable performance history." However, Section 9.1 states that the "required surveillance intervals for recommended Type A testing given in this section may be extended by up to 9 months to accommodate unforeseen emergent conditions but should not be used for routine scheduling and planning purposes." The NRC staff believes that extensions of the performance-based Type A test interval beyond the required 15 years should be infrequent and used only for compelling reasons. Therefore, if a licensee wants to use the provisions of Section 9.1 in TR NEI 94-01, Revision 2, the licensee will have to demonstrate to the NRG staff that an unforeseen emergent condition exists." NEI 94-01, Revision 3-A, Section 10.1 concerning the use of grace *in the deferral of Type B and Type C LLRTs past intervals of up to 120 months for the recommended surveillance frequency for Type B testing and up to 75 months for Type C testing, states: "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 MS IVs) or to valves held to the base interval (30 months) due to unsatisfactory LLRT performance." The NRG has also provided the following concerning the extension of ILRT intervals to 15 years in NEI 94-01, Revision 3-A, NRG SER Section 4.0, Condition 2, which states, in part:
Enclosure Page 13 of 81 "The basis for acceptability of extending the ILRT interval out to once per 15 years was the enhanced and robust primary containment inspection program and the local leakage rate testing of penetrations.
Most of the primary containment leakage experienced has been attributed to penetration leakage and penetrations are thought to be the most likely location of most containment leakage at any time." 3.2.2 Current HNP ILRT Requirements 10 CFR 50, Appendix J was revised, effective October 26, 1995, to allow licenses to choose containment leakage testing under either Option A, "Prescriptive Requirements," or Option B, "Performance-Based Requirements." On March 6, 1996 the NRC approved License Amendment No. 200 for HNP, Unit 1 and Amendment 141 for Unit 2 (Reference
- 19) authorizing the implementation of 10 CFR 50, Appendix J, Option B for Type A, B and C tests. Current TS 5.5.12 requires that a program be established to comply with the containment leakage rate testing requirements of 10 CFR 50.54(0) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions.
The program is required to be in accordance with the guidelines contained in RG 1.163. RG 1.163 endorses, with certain exceptions, NEI 94-01, Revision 0, as an acceptable method for complying with the provisions of Appendix J, Option 8. RG 1.163, Section C.1 states that licensees intending to comply with 10 CFR 50, Appendix J, Option B, should establish test intervals based upon the criteria in Section 11.0 of NEI 94-01 (Reference
- 5) rather than using test intervals specified in ANSI/ANS 56.8-1994.
NEI 94-01, Section 11.0 refers to Section 9, which states that Type A testing shall be performed during a period of reactor shutdown at a frequency of at least once per ten years based on acceptable performance history. Acceptable performance history is defined as completion of two consecutive periodic Type A tests where the calculated performance leakage was less than 1.0la (where La is the maximum allowable leakage rate at design pressure).
Elapsed time between the first and last tests in a series of consecutive satisfactory tests used to determine performance shall be at least 24 months. Adoption of the Option B performance based containment leakage rate testing program altered the frequency of measuring primary containment leakage in Types A, 8, 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 11 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 types of containment types, including a post tensioned, shallow domed concrete containment similar to HNP's containment structures.
NUREG-1493 concluded in Section 10.1.2 that reducing the frequency of Type A tests (ILRT} from the original three (3) tests per Enclosure Page 14 of 81 10 years to one (1) test per 20 years was found to lead to an imperceptible increase in risk. The estimated increase in risk is very small because ILRTs identify only a few potential containment leakage paths that cannot be identified by Types B and C testing, and the leaks that have been found by Type A tests have been only marginally above existing requirements.
Given the insensitivity of risk to containment leakage rate and the small fraction of leakage paths detected solely by Type A testing, NUREG-1493 concluded that increasing the interval between ILRTs is possible with minimal impact on public risk. 3.2.3 HNP 10 CFR 50, Appendix J, Option B Licensing History March 6, 1996 The Commission issued on March 6, 1996 Amendments Nos. 200 and 141 to Facility Operating License Nos. DPR-57 and NFP-5 for the HNP, Units 1 and 2, respectively (Reference 19). The amendments revised the TS for containment systems to reflect the adoption of the requirements of 10 CFR 50, Appendix J, Option B, and the implementation of a performance-based containment leak-rate testing program at the HNP, Units 1 and 2. February 20, 2002 The Commission issued Amendment No. 226 to Facility Operating License No. DPR-57 for HNP, Unit 1 (Reference
- 14) on February 20, 2002. This amendment revised TS 5.5.12, Primary Containment Leakage Rate testing Program, to allow a one-time deferral of the Type A Containment ILRT based on the risk-informed guidance in RG 1.174. Specifically, the proposed TS says that the first Type A test performed after the April 1993 Type A test shall be performed no later than April 2008. May 28, 2004 The Commission issued on May 28, 2004 Amendment No. 241 to Renewed Facility Operating License DPR-57 and Amendment No. 184 to Renewed Facility Operating License NPF-5 for HNP, Units 1 and 2, respectively (Reference 16). This amendment changed the peak calculated post-accident primary containment internal pressure values, Pa, in TS 5.5.12, "Primary Containment Leakage Rate Testing Program," for Units 1 and Unit 2. The proposed change supported a 10-psi increase in the nominal reactor steam dome operating pressure at each unit. The purpose of the pressure increase in the nominal reactor steam dome pressure is to allow'for additional flow control margin for the high-pressure turbine. This flow margin is needed to operate the plants at 100 percent of the increased (Reference
- 13) rated thermal power level of 2804 MW (t).
February 1, 2005 Enclosure Page 15 of 81. The Commission issued on February 1, 2005 Amendment No. 187 to Renewed Facility Operating License No. NPF-5 for HNP, Unit 2 (Reference 15). This amendment modified TS 5.5.12, Primary Containment Leakage Rate testing Program. The change would allow a one-time change in the Appendix J, Type A test (containment ILRT) interval from the required 10 years to a test interval of 15 years. Specifically, the exception states that the first Type A test performed after the November 2, 1995, Type A test shall be performed no later than November 2010. August 28, 2008 The Commission issued on August 28, 2008 Amendment No. 256 to Renewed Facility Operating License DPR-57 and Amendment No. 200 to Renewed Facility Operating License NPF-5 for HNP Units 1 and 2, respectively (Reference 17). The amendments revised the licensing basis with a full scope implementation of an alternative source term (AST) for HNP. TS 3.6.1.3 Primary Containment Isolation Valves The proposed license amendment revised the following TS that are associated with the analyses performed to support the AST. The proposed change for Unit 1, added a new SR 3.6.1 .3.13, which establishes a maximum combined leakage rate for all secondary containment bypass leakage paths of 0.02La. The proposed change for Unit 2, revised SR 3.6.1 .3.10 to increase the maximum combined leakage rate for all secondary containment bypass leakage paths from O.OQ9La to 0.02La. La is defined in 10 CFR 50, Appendix J. The secondary containment bypass leakage rate assumptions in the radiological dose consequences analysis for the LOCA form the basis for the revised TS limits. The increase in bypass leakage is necessary to allow for newly identified bypass leakage paths. The addition of this TS SR to Unit 1 reflects a required RG 1 .183 assumption in the accident analyses and standardizes the TS between units. The NRG staff's assessment found these changes acceptable since the proposed secondary bypass leakage rate limit of 0.02La was assumed in the accident analysis and regulatory criteria have been met. Another proposed change was to eliminate the per line main steam isolation valve (MSIV) leakage rate limits from the TS SR for both units (SR 3.6.1.3.10 and SR 3.6.1.3.11, respectively).
Specifically, for Unit 1, the licensee proposed to establish a combined maximum leakage rate of 100 standard cubic feet per hour (scfh) when tested at > 28.0 psig and < 50.8 psig and for Unit 2, a combined maximum leakage rate is reduced from 250 scfh to 100 scfh when tested at> 28.8 psig and < 47.3 psig. The licensee indicated that the pressure values of 50.8 psig and 47.3 psig represent Enclosure Page 16 of 81 calculated peak drywell pressures for Unit 1 and Unit 2, respectively, in the event of a LOCA. The revised proposed values for MSIV combined maximum leakage rates are used in the radiological dose consequences analysis for the LOCA. The contribution to total combined leakage from any individual MSIV is not considered in the analysis.
The analysis assumes that the maximum allowed combined leakage rate is entirely through one MSIV. The NRC staff found this change acceptable since this value was assumed in the revised accident analysis, and calculated doses are below the regulatory criteria of 10 CFR 50.67. A second test pressure range, with a corresponding leakage rate criterion, was proposed for both units when test pressure exceeds the peak calculated drywell pressure during a LOCA. This is in addition to the 100 scfh combined maximum leakage rate specification when tested within the specified test pressure range that is below the calculated peak drywell pressure.
For Unit 1, a combined maximum leakage rate of 144 scfh is established when tested at > 50.8 psig. For Unit 2, a combined maximum leakage rate of 144 scfh is established when tested at> 47.3 psig. The addition of a second MSIV leakage rate criterion for testing at or above calculated peak drywell pressure provides a more accurate leakage rate acceptance criterion for test pressures that are higher than calculated post-LOCA peak drywell pressures.
This facilitates testing the MSIVs in the accident direction at peak accident drywell pressure as preferred by 10 CFR 50 Appendix J, as opposed to testing the MS IVs in the reverse direction at a lower test pressure as allowed by existing HNP Appendix J exemptions.
A higher pressure would result in a higher mass flow rate through a given leakage area. The higher leakage rate (mass flow rate) acceptance criterion is based on a pressure and mass flow rate analysis.
This allows for the use of a different MSIV Appendix J test configuration as dictated by plant configuration during the outage, while also ensuring that the appropriate acceptance criterion exists for the actual test pressure used. For Unit 2, the requirement to restore MSIV leakage to 11.5 scfh upon discovery of leakage not meeting the 100 scfh leakage rate limit was proposed to be eliminated.
The NRC staff found this change to be acceptable since it is not an input or assumption in the radiological dose consequence analysis.
3.2.4 ILRT History As noted previously, HNP 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 Option B. Since the adoption of Option B, the performance leakage rates are calculated in accordance with NEI 94-01, Section 9.1.1 for Type A testing. Tables 3.2.4-1 and 3.2.4-2 list the past Periodic Type A ILRT results for Units 1 and 2, respectively.
Enclosure Page 17 of 81 Table 3.2.4-1, Unit 1 Type A ILRT History Test Date June 1978 February 1983 April 1986 November 1988 April 1993 March 2008 Leakage Rate (1) (Containment air weight %/day) 0.456 0.442 0.428 0.4968 0.3488 0.3485 (1) The Commission issued on May 28, 2004 Amendment No. 241 to Renewed Facility Operating License DPR-57 for HNP, Unit 1 (Reference 16). This amendment changed the peak calculated post-accident primary containment internal pressure values, Pa, in TS Section 5.5.12. The peak calculated primary containment internal pressure for the design basis LOCA, Pa, was increased to 50.8 psig. Table 3.2.4-2, Unit 2 Type A ILRT History Test Date May 1982 January 1986 November 1989 November 1992 November 1995 March 2009 Leakage Rate (1 ), (Containment air weight %/day) 0.7890 0.5870 0.8000 0.8839 0.3175 0.5422 (1) The Commission issued on May 28, 2004 Amendment 184 to Renewed Facility Operating License NPF-5 for HNP, Unit 2 (Reference 16). This amendment changed the peak calculated post-accident primary containment internal pressure values, Pa, in TS Section 5.5.12. The peak calculated primary containment internal pressure for the design basis LOCA, Pa, was increased to 47.3 psig. The results of the last two Type A ILRTs for both HNP, Units 1 and 2 are less than the maximum allowable containment leakage rate of 1.2 wt%/day. As a result, since both tests for both units were successful, both units have been placed on extended ILRT frequencies.
The current ILRT interval frequency for HNP Units 1 and 2 is 10 years. 3.3 Plant Specific Confirmatory Analysis 3.3.1 Methodology Enclosure Page 18 of 81 An evaluation has been performed to assess the risk impact of extending the currently allowed containment Type A integrated leak rate test (ILRT) interval to a permanent 15 years for HNP Units 1 and 2. The extension would allow for substantial cost savings as the ILRT could be deferred for additional scheduled refueling outages. The risk assessment follows the guidelines from the following:
e NEI 94-01 Revision 3-A (Reference 2),
- The methodology used in EPRI TR-104285 (Reference 7),
- The NEI "Interim Guidance for Performing Risk Impact Assessments In Support of One-Time Extensions for Containment Integrated Leakage Rate Test Surveillance Intervals" (References 33, 37),
- The NRC regulatory guidance on the use of PAA as stated in RG 1.200 (Reference
- 4) as applied to ILRT interval extensions, and risk insights in support of a request for a change in the plant's licensing basis as outlined in RG 1.174 (Reference 3),
- The methodology used for Calvert Cliffs to estimate the likelihood and risk implications of corrosion-induced leakage of steel liners going undetected during the extended test interval (Reference 32),
- The methodology used in EPRI TR-1009325, Revision 2-A (Reference
- 20) for performing a risk impact assessment of extended ILRT intervals.
- The EPRI TR-1009325 Revision 2-A methodology incorporates the specific limitations
- and conditions outlined in the NRC acceptance of the EPRI TR-1009325 Revision 2 methodology documented in the NRC Final Safety Evaluation (Reference 9). The format of this document is consistent with the intent of the Risk Impact Assessment Template for evaluating extended ILRT intervals provided in Appendix Hof the EPRI TR methodology report (Reference 20). The NRG report on performance-based leak testing, NUREG-1493, analyzed the effects of containment leakage on the health and safety of the public and the benefits realized from the containment leak rate testing. In that analysis, it was determined that for a representative PWR plant, (i.e., Surry) containment isolation failures contribute less than 0.1 percent to the latent risks from reactor accidents.
Consequently, it is desirable to show that extending the ILRT interval will not lead to a substantial increase in risk from containment isolation failures for HNP. Earlier ILRT frequency extension submittals have used the EPRI TR-104285 (Reference
- 7) methodology to perform the risk assessment.
In October 2008, EPRI TR-1018243 (Reference 20} was issued to update the generic methodology for ILRT extensions to 15 years using current performance data and to incorporate the specific limitations and conditions outlined by the NRC in the final safety evaluation of the methodology (Reference 9). This more recent EPRI document considers additional risk metrics and criteria including the change in population dose, large early release Enclosure Page 19 of 81 frequency (LERF), and conditional containment failure probability (CCFP), whereas EPRI TR-104285 considered only the change in population dose. In the SER 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 extend the ILRT surveillance interval to 15 years, subject to the limitations and conditions noted in Section 4.0 of the Safety Evaluation (SE). Table 3.3.1-1 addresses each of the four limitations and conditions for the use of EPRI 1009325, Revision 2. Table 3.3.1-1, EPRI Report No. 1009325 Revision 2 Limitations and Conditions Limitation/Condition lFrom Section 4.2 of SE) HNP Resoonse 1. The licensee submits documentation HNP PRA technical adequacy is addressed in indicating that the technical adequacy of Section 3.3.2 of this LAR and Attachment 3, their PRA is consistent with the "Plant Hatch Units 1 & 2 Risk Assessment to requirements of RG 1.200 relevant to the Support ILRT (Type A) Interval Extension I LRT extension.
Request," Appendix B, "Hatch PRA Technical Adequacy Evaluation In Support of ILRT Interval Extension Risk Assessment." 2.a The licensee submits documentation Because the ILRT does not impact core indicating that the estimated risk increase damage frequency (CDF), the relevant associated with permanently extending the criterion is LEAF. The increase in internal ILRT surveillance interval to 15 years is events LEAF resulting from a change in the small, and consistent with the clarification Type A ILRT test frequency from three in ten provided in Section 3.2.4.5 of this SE. years to one in fifteen years is conservatively estimated as 6.39E-08/yr using the EPRI guidance as written and including potential corrosion impacts. The LEAF increase using the EPRI Expert Elicitation values is substantially less (i.e., 7.52E-09/yr).
Using both approaches, the estimated change in LEAF is determined to be very small" using the acceptance guidelines of RG 1.17 4.
Limitation/Condition
<From Section 4.2 of SE) 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.
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. 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 La instead of 35 La. Enclosure Page 20 of 81 HNP Resoonse The change in Type A test frequency from three in ten years to one in fifteen years, measured as an increase in the total integrated plant dose risk for those accident sequences influenced by Type A testing, is 9.90E-03 person-rem/yr using the EPRI guidance values, and drops to 1.96E-03 person-rem/yr using the EPRI Expert Elicitation values. The EPRI guidance states that a very small population dose is defined as an increase of <1 .0 person-rem/yr or <1 % of the total population dose, whichever is less restrictive for the risk impact assessment of the extended I LRT intervals.
The Hatch dose increase results are significantly less than 1.0 person-rem/yr.
Moreover, the risk impact when compared to other severe accident risks is negligible.
The increase in CCFP when comparing the three in ten-year frequency to one in fifteen-year frequency is about 0.84% using the EPRI guidance values, and drops to about 0.10% using the EPRI Expert Elicitation values. The EPRI guidance states that increases in CCFP < 1.5 percentage points are very small. Therefore the increase for Hatch is determined to be very small. The representative containment leakage for Class 3b sequences used by HNP is 100 La, 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 La for the Class 3b sequences.
Limitation/Condition (From Section 4.2 of SEl 4. A licensee amendment request (LAR) is required in instances where containment over-pressure is relied upon for ECCS performance.
3.3.2 Technical
Adequacy of the PAA Enclosure Page 21 of 81 HNP Resoonse For HNP Unit 1 containment overpressure is not required for either the RHR or CS pumps during the short-term post-LOCA period. For HNP Unit 1 containment overpressure is required for a period from approximately 2.6 hr. to 18.7 hr. after LOCA initiation.
To provide sufficient margin for the peak suppression pool temperature of 210 °F, the long-term NPSH evaluation takes credit for a containment overpressure of 4.2 psig (1 Oft.). The overpressure credit is applied for a period of 1.5 to 26.5 hrs. following LOCA initiation.
Any changes resulting in an individual or collective increase of 1 ft. (approximately 0.4 psig) of the containment overpressure margin of 1 O ft. ( 4.2 psig) requires NRG notification.
For HNP Unit 2 the short term and long-term containment response analysis demonstrates the RHR and CS pumps have NPSH margin without taking credit for containment overpressure.
An additional amendment request is not required in this instance, as the over-pressure requirement has previously been incorporated in the HNP-2 operating license as documented in the FSAR. Technical adequacy is presented in Appendix B, "Hatch PRA Technical Adequacy in Support of ILRT Interval Extension Risk Assessment," of Attachment 3 of this submittal.
A PRA technical adequacy evaluation was performed consistent with the requirements of RG-1.200, Revision 2 (Reference 4). 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 HNP Units 1 and 2 to fifteen years on a permanent basis satisfies the risk acceptance guidelines in RG 1.174.
3.3.2.1 Demonstrate the Technical Adequacy of the PAA Enclosure Page 22 of 81 The guidance provided in RG 1.200, 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:
- Identification of permanent plant changes (such as design or operational practices) that have an impact on the PRA but have not been incorporated in the PAA.
- The parts of the PAA used to produce the results are performed consistently with the PAA Standard as endorsed by RG 1 .200.
- A summary of the risk assessment methodology used to assess the risk of the application, including how the PAA model was modified to appropriately model the risk impact of the application.
- Identification of key assumptions and approximations in the PRA relevant to the results used in the decision making process.
- A discussion of the resolution of peer review or self-assessment findings and observations (F&Os) that are applicable to the parts of the PAA required for the application.
- Identification of parts of the PAA used in the analysis that were assessed to have capability categories less than that required for the application.
3.3.2.2 Technical Adequacy of the PAA Model The PAA model version used for the ILRT extension assessment is the Hatch Unit 1 Internal Events PRA model version 4.1 , change notice PRA-CN-H-13-003, which was completed in October 2013, updated with the Level 2 model documented in SNC calculation H-RIE-IEIF-U01-010.
This is a maintenance update of the HNP Unit 1 Internal Events PAA, Revision 4, which incorporated the resolution of F&Os associated with the November 2009 Peer Review of the HNP Unit 1 Internal Events PAA model. Revision 4.1 of the HNP PAA model is the most recent evaluation of the risk profile at HNP for internal event challenges.
The PAA 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 HNP PAA is based on the event tree I fault tree methodology, which is a well-known methodology in the industry.
The HNP PRA model is controlled in accordance with SNC procedure RIE-001, "Generation and Maintenance of Probabilistic Risk Assessment Models and Associated Enclosure Page 23 of 81 Updates," and associated guidelines.
This procedure defines the process for implementing regularly scheduled and interim PRA model updates, for tracking issues identified as potentially affecting the PRA models (e.g., due to changes in the plant, errors or limitations identified in the model, industry operating experience, etc.), and for controlling the model and associated computer files. To ensure that the current PRA model remains an accurate reflection of the as-built, as-operated plants, RIE-001 requires that following activities outlined in the procedure are routinely performed:
- Design changes and procedure changes are reviewed for their impact on the PRA model on an on-going basis.
- Reliability data, unavailability data, initiating events frequency data, human reliability data, and other such PRA inputs shall be reviewed approximately every two fuel cycles and updated as necessary to maintain the PRA consistent with the as-operated plant. As indicated previously, RG 1.200 also requires that additional information be provided as part of the submittal to demonstrate the technical adequacy of the PRA model used for the risk assessment.
Each of these items are addressed in the following sections.
3.3.2.3 Plant Changes Not Yet Incorporated into the PRA Model As part of PRA model configuration control, SNC maintains a PRA model maintenance database that tracks all issues that have been identified that could impact the Hatch PRA model. Per SNC procedure RIE-001 the significance of the pending items in the database is evaluated to determine the impact on model results. Each pending item is prioritized for future model updates according to its significance to model results. A review of the current open items in the database for HNP identified no permanent plant design or operational changes that would significantly impact the results of the risk assessment performed for the ILRT interval extension evaluation.
3.3.2.4 Previous Peer Review and Self Assessment of the HNP PRA Model The HNP PRA model was reviewed extensively during development and undergoes independent internal review during each update. The Hatch PRA was reviewed twice prior to issuance of the ASME PRA Standard for peer review. The initial peer review was conducted by the BWR Owners Group (BWROG) in April 2001. The review team used Revision A-3 NEI draft "Probabilistic Risk Assessment (PRA) *Peer Review Process Guidance" dated June 2, 2000 as the basis for review. This review was observed by a team from the NRC. In 2006, a gap analysis was performed against the available versions of the ASME PRA Standard and RG 1.200, Revision 0 (2003 trial version).
Enclosure Page 24 of 81 3.3.2.5 RG 1.200 PRA Review of the HNP PRA Model against the ASME PRA Standard Requirements A PRA Peer Review of all elements of the HNP Internal Events PRA PRA model including Internal Flooding against RG 1.200, Revision 2 clarifications, the ASME/ANS PRA Standard (Reference 30), and NEI 05-04 was performed in November 2009. A summary of the results of the PRA Peer Review (Reference
- 21) previously provided to the NRC as part of the NEI Risk Informed Technical Specification (RITS) Initiative 5b LAR submittal (ML 103140510) for which SNC received a NRC SER as discussed in Attachment 3, Appendix B, section B.2.7 of this submittal, is shown below. Based on the results of the Peer Review, 95% of the SRs evaluated met Category II or better. There were 10 supporting requirements that were noted as "Not Met" and 5 that were noted "Met" at Category I only. All of the "Not Met" findings were resolved as part of the update of the Hatch Internal Events PRA Model, Revision 4.0, to Revision 4.1 as noted in Attachment 3, Appendix B, Tables B.2-1 and B.2-2 of this submittal.
3.3.2.6 PRA Portions With Inadequate Technical Adequacy As previously noted, the NRC safety evaluation (Reference
- 9) of the EPRI ILRT methodology specifies that Capability Category I is appropriate for the applicable PRA Standard supporting requirements.
Based on the update to the HNP Internal Events PRA model to Revision 4.1, following the 2009 PRA Peer Review, all PRA Standard supporting requirements are met at Capability Category 11 or higher, as applicable.
3.3.2.7 NRC SER for HNP Units 1 and 2 NEI Risk-Informed Technical Specification (RITS) 5b Submittal SNC submitted a LAR and received an SER for NEI RITS Initiative 5b to implement the Surveillance Frequency Control Program (SFCP) at Hatch. The NEI RITS Initiative 5b application is similar to this ILRT interval extension submittal in that they both deal with surveillance frequency extensions.
Excerpts from the NRC SER for HNP pertaining to the HNP PRA quality are provided in Attachment 3, Appendix B, section B.4 of this submittal, and the overall conclusions are considered applicable to this submittal.
3.3.2.8 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 of the ILRT interval for HNP, Units 1 and 2, to fifteen (15) years on a permanent basis satisfies the risk acceptance guidelines in RG 1.174.
3.3.3 Summary
of Plant-Specific Risk Assessment Results Enclosure Page 25 of 81 The findings of the HNP, Units 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 very small. The HNP plant-specific results for extending ILRT interval from the current 10 years to 15 years are summarized below: Based on the results from Attachment 3, Section 7.0, "Conclusions," and the sensitivity calculations presented in Section 6.0 "Sensitivities," the following conclusions regarding the assessment of the plant risk associated with permanently extending the Type A ILRT test frequency to 15 years:
- RG 1.174 (Reference
- 3) provides guidance for determining the risk impact of plant-specific changes to the licensing basis. RG 1.17 4 defines "very small" changes in risk as resulting in increases of CDF below 1 o-6/yr and increases in LERF below 1 o-7/yr. Because the ILRT does not impact CDF, the relevant criterion is LERF. The increase in internal events LERF resulting from a change in the Type A ILRT test frequency from three in ten years to one in fifteen years is conservatively estimated as 6.39E-08/yr using the EPRI guidance as written and including potential corrosion impacts. The LERF increase using the EPRI Expert Elicitation values is substantially less (i.e., 7.52E-09/yr).
Using both approaches, the estimated change in LERF is determined to be "very small" using the acceptance guidelines of RG 1.17 4.
- The change in Type A test frequency from three in ten years to one in fifteen years, measured as an increase in the total integrated plant dose risk for those accident sequences influenced by Type A testing, is 9.90E-03 person-rem/yr using the EPRI guidance values, and drops to 1.96E-03 person-rem/yr using the EPRI Expert Elicitation values. The EPRI guidance states that a very small population dose is defined as an increase of <1.0 person-rem/yr or <1 % of the total population dose, whichever is less restrictive for the risk impact assessment of the extended ILRT intervals.
The Hatch dose increase results are significantly less than 1.0 person-rem/yr.
Moreover, the risk impact when compared to other severe accident risks is negligible.
- The increase in the CCFP when comparing the three in ten-year frequency to one in fifteen-year frequency is about 0.84% using the EPRI guidance values, and drops to about 0.10% using the EPRI Expert Elicitation values. The EPRI guidance states that increases in CCFP < 1 .5 percentage points are very small. Therefore, the increase for Hatch is determined to be very small.
- The potential impact on LERF from external events was quantitatively assessed utilizing information from the Individual Plant Examination of External Events (IPEEE). The total increase in LERF due to internal and external events using Enclosure Page 26 of 81 the EPRI guidance values is estimated to be 9.SE-8/yr, which remains in the "very small" change region (i.e., < 1 E-7/yr) of the RG 1.174 acceptance guidelines.
Therefore, increasing the ILRT interval to 15 years is considered to represent an insignificant change in risk for HNP. 3.3.4 Previous Assessments The NRG in NUREG-1493 (Reference
- 6) has previously concluded that:
- Reducing the frequency of Type A tests (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 Type B and C testing, and the leaks that have been found by Type A tests have been only marginally above existing requirements.
- Given the insensitivity of risk to containment leakage rate and the small fraction of leakage paths detected solely by Type A testing, increasing the interval between integrated leakage-rate tests is possible with minimal impact on public risk. The impact of relaxing the ILRT frequency beyond 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 HNP confirm these general findings on a plant specific basis considering the severe accidents evaluated for HNP, the HNP containment failure modes, and the local population surrounding HNP. Details of the HNP, Units 1 and 2, risk assessment are contained in Attachment 3 of this submittal.
3.4 Non-Risk Based Assessment Consistent with the defense-in-depth philosophy discussed in RG 1.17 4, HNP has assessed other non-risk based considerations relevant to the proposed amendment.
HNP has multiple inspections and testing programs that ensure the containment structure remains capable of meeting its design functions and that are designed to identify any degrading conditions that might affect that capability.
These programs are discussed below. 3.4.1 Protective Coatings Program (PCP) The Plant Hatch PCP provides a means of preventing or minimizing loss of material that would otherwise result from contact of the base material with a corrosive environment.
Enclosure Page 27 of 81 The PCP is a mitigation and condition monitoring program designed to provide base metal aging management through surface application, maintenance, and inspection of protective coatings on selected components and structures.
Coating Service Level I are those coating systems applied inside the primary containment where coating failure could adversely affect the operation of post-accident fluid systems and, thereby, impair safe shutdown of the plant. Program Scope . The PCP provides specifications for coatings applied to structures and components within the scope of license renewal. The PCP includes specific inspection techniques and frequencies for Service Level I coatings (which include non-immersion coatings applied to the suppression chamber and drywall airspace and immersion coatings applied to the suppression chamber interior below the normal water level). The current term PCP has been enhanced for the renewal term to provide inspection techniques and frequencies for certain accessible non-service level I coatings.
These requirements apply to external surfaces of carbon steel commodities outside of primary containment and within the scope of license renewal that are expected to experience significant atmospheric corrosion.
The PCP has also been enhanced to provide for inspection and documentation of the condition of normally inaccessible (underground or embedded) carbon steel components within the scope of license renewal, whenever these components are exposed or uncovered.
Parameters Inspected or Monitored Periodic inspection of components is conducted in order to identify areas of degraded coatings and associated corrosion of base metals, which may indicate a loss of material.
Detection of Aging Effects Detection of degraded coatings and associated corrosion of base metals is accomplished primarily through visual inspection techniques.
For surfaces determined to be suspect, dry film thickness, adhesion, and continuity tests may also be performed.
Monitoring and Trending Service level I coatings are inspected at set intervals.
A baseline inspection of service level I coated components within the scope of license renewal will be performed.
Coated components are monitored for changes in previously identified findings and for newly developed conditions.
Trending of such findings is performed to predict degrading conditions and to determine the potential long-term impact of the finding. Inspection results are maintained in plant records. Engineering personnel track and trend results in accordance with site procedures.
Acceptance Criteria Enclosure Page 28 of 81 Any significant degradation of structural components that is observed during the visual inspection activities are noted and corrective actions implemented in accordance with the corrective actions program. Acceptance criteria are specifically stated in the PCP and the implementing procedures.
Torus Coatings A visual inspection is performed during each refueling outage of the torus coating in the area above and below the water line to the extent it is visible from the surface. It is expected that if corrosion effects or loss of coating from peeling occurs, the most likely place would be in the area of the water line. If during the visual inspection significant corrosion is indicated, an ultrasonic inspection of this area is performed to determine if the thickness of the torus wall meets the minimum wall thickness required.
If it is observed during the surveillance program that excessive coating loss has occurred, the latest developments in the industry are surveyed and will be considered in applying a replacement coating. Containment
-Non-Immersion Coatings General walk-down of the Drywall is performed every refueling outage. Unqualified/Degraded Coatings in Containment The limitation on the quantity of non-acceptable coatings assumed in various calculations, such as ECCS sump/strainer blockage, is 3, 150 ft 2 in either unit. The total amount of unqualified coatings in each containment as documented in most recent inspections is as follows:
- Unit 1 total square footage of non-acceptable coatings is 426.2 ft 2.
- Unit 2 total square footage of non-acceptable coatings is 87.9 ft 2. 3.4.2 lnservice Inspection Program (ISi) Class MC Components Inspection Plan This inspection plan provides a summary of the examinations and tests applicable to components treated as Class MC for ISi. This plan was developed utilizing the ASME Section XI Code, 2007 Edition through the 2008 Addenda, Subsection IWE. ASME Class MC components include: the drywall, the suppression pool (torus), the verit headers, penetrations, airlocks and manways. This plan includes examinations required by ASME XI Subsection IWE as modified by 10 CFR 50.55a(b)(2)(ix)(A), (B), (F), (G), (H), and (I) and any applicable relief requests, exemptions or alternatives.
A listing of applicable sections of 10 CFR 50.55a and Code Cases as well as relief requests, Enclosure Page 29 of 81 exemptions, and alternatives can be found in Volume 1 of the ISi Plan. This plan also includes examinations not required by Subsection IWE that SNC has elected to perform due to specific industry concerns.
Relief Request By letter dated July 16, 2015, as supplemented by letter dated December 16, 2015, SNC submitted a request to the NRC for relief from the requirements of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code (B&PV Code) at HNP, Units 1 and 2. SNC requested to use the current ASME B&PV code of record, the 2001 edition through the 2003 addenda, in combination with the 2007 edition through the 2008 addenda for certain inservice inspection and containment inservice inspection activities from January 1, 2016, through November 30, 2017. The NRG staff reviewed the subject request and concludes, as set forth in the enclosed safety evaluation, that the licensee has adequately addressed all of the regulatory requirements set forth in 10 CFR 50.55a(z)(1
). Therefore, the NRC staff authorized the use of Relief Request HNP-ISl-AL T-5-01 at HNP, Units 1 and .2, from January 1, 2016, to November 30, 2017. (Reference
- 35) The application of Relief Request HNP-ISl-AL T-5-01 as applicable to Sub-section IWE is displayed in the following table: Table 3.4.2-1, Proposed ASME Section XI, Sub-section IWE, Code Of Record For HNP ASME Section XI Code Provision ASME Section XI Code Edition/ Addenda 1 Sub-section Article 2001 Edition/ 2001 Edition/ 2007 Edition/ No Addenda 2003 2008 Addenda Addenda IWE Requirements IWE-1000 x2 for Class MC IWE-2000 x2 Components IWE-3000 x IWE-5000 x 1 SNC will also comply with all NRG conditions, limitations, and restrictions specified in 10 CFR 50.55a as they apply to the specific edition and addenda referenced.
2 The selection, planning, and scheduling of ISi examinations/tests will comply with these ASME Section XI articles (e.g. IWB-1000 and 2000) from the 2007 Edition/2008 Addenda or applicable NRG approved alternatives that are specified in the HNP ISl/Cll Program Plans. Implementation Schedule The current 10-year inspection interval began January 1, 2016 and goes through December 31, 2025. All inspections required during the previous containment inspection Enclosure Page 30 of 81 interval were completed during the previous interval.
Exams required to be performed on an interval frequency will be performed at the same point in time as would be required if the containment inspection interval had not changed. All other code required exams are required on a period basis. The change of inspection interval will have no impact on the scheduling of these exams. The ISi inspection interval is broken into three periods. The period durations, in order, are 3-years, 4-years, and 3-years. Inspection period dates for the 5th ISi inspection interval is displayed in Tables 3.4.2-1 and 3.4.2-2. Table 3.4.2-2, HNP Unit 1 IWE Examination Schedule 5th Interval (ll 1/1/16 through 12/31/18 1st Period 1 R27-2016 1R28 -2018 5th Interval (ll 1/1/19 through 12/31/23 2nd Period 1 R29 -2020 1 R30 -2022 5th Interval (ll 1/1/24 through 12/31/26 3rd Period 1R31 -2024 1R32-2026 (1) Intervals and Periods are being extended in accordance with IWA-2430.
Table 3.4.2-3, HNP Unit 2 IWE Examination Schedule 5th Interval (1 l 1/1/16 through 12/31/19 1st Period 2R24-2017 2R25 -2019 5th Interval (1 l 1/1/16 through 12/31/23 2nd Period 2R26-2021 2R27-2023 5th Interval (1 l 1/1/24 through 12/31/27 3rd Period 2R28-2025 2R29 -2027 (1) Intervals and Periods are being extended in accordance with IWA-2430.
Program In order to minimize duplication of efforts to the maximum extent practical, the Containment Inspection Program at Plant Hatch is mainly comprised of existing plant programs and procedures that have been appropriately modified and drawn together, under the overall direction of the Containment Inspection Program Responsible Engineer (CIPRE), to provide a complete and comprehensive program for examination Enclosure Page 31 of 81 of the pressure retaining surfaces of containment, structures that are part of reinforcement, and any associated permanent attachments.
Beginning with this lnservice Inspection Plan at the programmatic level and moving to the implementation level, the program is largely made up of the following documents:
- Fifth Ten-Year Examination Plan (ISi Plan) This inspection plan provides a summary of the examinations and tests applicable to components treated as Class MC for the purposes of ISi. It provides a list of the examinations and tests to be performed during the Fifth ten-year interval and the appropriate schedule, by period, for implementation of each.
- SNC lnservice Inspection Engineering Program This administrative control procedure establishes provisions for the implementation of a program which satisfies the requirements of the ASME Section XI Code as required by Technical Requirements Manual Unit 2, Section T3.4.2.1.
In particular, this procedure applies to the implementation of the ISi Program (including containment inspection) and the Repair/Replacement Program.
- IWE/IWL Roles and Responsibilities This administrative control procedure establishes the roles and responsibilities of the individuals within the IWE program.
- IWE Implementation This Nuclear Management Instruction (NMI) provides the general instructions applicable to the implementation and management of the ASME Boiler and Pressure Vessel Code,Section XI, Subsection IWE requirements, as supplemented by 10 CFR 50.55a.
- Visual Examination of the Drywall Air Gap and Sand Cushion Drain Lines This procedure is intended to address examinations that are associated with the Containment Inspection Program but which are not required by the ASME Code,Section XI. Those examinations have been included in the plan document as a convenience.
This procedure defines the requirements for the visual examination of the drywall air gap and sand cushion drain lines, including providing instruction for their examination.
These examinations are performed in order to detect conditions that are indicative of degradation or problems with functionality and include direct and remote visual examination techniques.
- Orywell Surfaces Visual Inspection Enclosure Page 32 of 81 This procedure provides instructions for performing the inspection of the interior Orywell surfaces and interior and exterior Orywell Head surfaces to satisfy the requirements of TS SR 3.6.1.1.1 and also provides instructions for performing the inspection as required by the ISi Plan.
- Venting Assembly and Suppression Chamber Surfaces Visual Inspection This procedure provides instructions for performing the inspection of the interior (vapor phase) and exterior surfaces of the Suppression Chamber to satisfy the requirements of TS SR 3.6.1 .1.1 and also provides instruction for performing the inspection as required by the ISi Plan.
- Nuclear Coatings Program This procedure establishes the responsibilities for implementing, maintaining, and periodically assessing the effectiveness of the Nuclear Coatings Program and comprises all those systematic and planned actions necessary to ensure that safety and non-safety related coatings activities satisfy the applicable requirements.
- Procedure for Condition Assessments This procedure provides instructions for performing surveillance inspection and monitoring of all coatings systems that are classified as safety related and reporting inspection results. Periodic completion of a portion of the total scope of inspections described in this procedure also satisfies the ASME Code,Section XI, Subsection IWE visual examination (VT -3) requirement for the submerged surfaces of the containment pressure retaining boundary.
- Primary Containment Integrated Leakage Rate Test This procedure establishes the criteria and detailed procedure to demonstrate that containment leakage at design basis accident pressure does not exceed the acceptance limit specified in TS SR 3.6.1.1.1.
This procedure also provides for containment structural inspection prior to each Type A test and at a periodic interval between tests based on performance of the containment system. General Visual Examination (GVE) This examination is considered to be an increased level, controlled, surveillance activity and not a formalized nondestructive examination (NOE) method in the true sense of recognized, established NOE methods. This position is based on the following considerations:
Enclosure Page 33 of 81
- GVE is not addressed in ASME Section XI, Subsection IWA, and since it is not included in the scope of NOE, the provisions of Subsection IWA are not applicable.
GVE is addressed only in Subsection IWE, paragraph IWE-3510.1.
- The requirements of ASME Section XI, Subsection IWA, paragraph IWA-2240 do not apply since GVE is the examination specified and not a proposed alternative method.
- The personnel qualification requirements of SNT-TC-1A do not apply and, as described in IWE-3510, are the responsibility of the Owner, under the direction of a qualified, responsible individual "knowledgeable in the requirements for design, inservice inspection, and testing of Class MC components.
11
- Per 10 CFR 50.55a(b)(2)(ix)(B), minimum illumination, maximum distance, and resolution requirements have not been defined for GVE and are left to the judgment of trained, knowledgeable, and experienced individuals, selected at the discretion of, and under the direction of a qualified, responsible individual 11 knowledgeable in the requirements for design, inservice inspection and testing of Class MC components" provided that conditions or indications for which the visual examination is performed can be detected at the chosen distance or illumination.
For the purposes of General Visual Examination, ASME Section XI surface areas of Class MC containment vessels, parts, appurtenances may be considered inaccessible if visual access by line of sight with adequate lighting from permanent vantage points is obstructed by permanent plant structures, equipment, or components, provided these surface areas do not require examination in accordance with the inspection plan or IWE-1240." (i.e., surface areas requiring augmented examination).
This defines inaccessible as defined in this examination plan. Containment Visual (VT-3) 10 CFR 50.55a(b)(2)(ix)(G) requires that a VT-3 be performed on wetted surfaces of submerged areas (i.e., submerged areas of the torus) and accessible surface areas of the vent system for Item E1 .12 and E1 .20 of ASME Section XI Table IWE-2500-1.
Pressure retaining bolted connections also require a VT-3 examination.
ISl-EX-01 allows the performance of a General Visual in lieu of the VT -3 for non-submerged accessible surface areas of the vent system.
- Submerged Surfaces of the Torus Plant Hatch has implemented a torus submerged surfaces examination and coatings repair program since the late 1980s. A coatings contractor performs visual examinations and spot coatings repairs using underwater divers. This Enclosure Page 34 of 81 same contractor provides VT-3 certified personnel to perform the Subsection IWE required VT-3 examinations and provides the results to SNC for evaluation and resolution of any deficient conditions, as appropriate.
SNC decided to perform the initial Subsection IWE, VT-3 visual examination of the torus submerged surfaces prior to the Code required schedule date. The initial VT-3 was performed on Unit 1 in 1999 (1 R18) and on Unit 2 in 1998 (2R14). Subsequent VT-3 examination of the torus submerged surfaces will be performed in accordance with the Code required schedule or more frequently if deemed appropriate by the CIPRE or personnel responsible for the Plant Hatch safety related coatings program. Repair and Replacement Activities All containment pressure retaining component repairs, modifications, or replacements that affect the containment leakage boundary shall be tested in accordance with 10 CFR 50 Appendix J. General Discussion for Category E-A Drvwell Shell The exterior surface of the drywell shell, with the exception of the drywell head, is exempt from examination per IWE-1220(b) and IWE-1232(a).
The exterior surface is inaccessible due to the concrete shield wall and the 2" air gap. All shell welds were solution film tested at 56 psig after completion of construction which met the construction code requirements and IWE-1232(a)(2) for Unit 1 and Unit 2. The interior and exterior embedded portions of the drywell shell (i.e., below the 114 foot elevation) are exempt from examination per IWE-1220(b) and IWE-1232(a).
Shell welds below the 114 1 -8" elevation were examined per the ASME Section 111 Code (1968 Edition and Addenda in effect through June 30, 1968, FSAR K.2.2.), paragraphs N-1410 and N-1411 (gas medium test) and all shell welds were solution film tested at 56 psig after completion of construction which met the construction code requirements and thus the requirements of IWE-1232(a)(2).
The interior surfaces of the drywell shell are generally accessible for visual examination.
1 OCFR 50.55a(b)(2)(ix)(B) allows for relaxation of the distance and lighting requirements when performing remote visual examination provided that the conditions or indications for which the visual examination is performed can be detected at the chosen distance and illumination.
Visual examination from the 114 1 -0" floor elevation, various catwalks and ladders, and access provided from piping and components should provide adequate access to perform the general visual and VT-3 in order to assess the condition of the interior drywell surfaces.
Enclosure Page 35 of 81 The provisions of IWE-1220(c), IWE-1231 (a), IWE-1231 (b) and IWE-1232, which require that containment surfaces remain accessible, must be complied with for any repairs, replacements, or modifications to the drywell. Suppression Pool Exterior Surfaces The outside surfaces of the suppression pool are generally accessible for visual examination.
10 CFR 50.55a(b){2)(ix)(B) allows for relaxation of the distance and lighting requirements when performing remote visual examination provided that the conditions or indications for which the visual examination is performed can be detected at the chosen distance and illumination.
Therefore, the visual examination of virtually 100% (easily> 80%) of the exterior suppression pool surface can be performed for the 87' -0 11 floor elevation, the 114' -0 11 elevation inner and outer circumference catwalks, and the top of the suppression pool with adequate resolution to detect any degradation of the surfaces.
Suppression Pool Interior Surfaces Virtually 100% of the interior non-submerged (vapor space) suppression pool surfaces are accessible for visual examination from the 114' -0 11 interior catwalk, or from the top of the vent header if the provisions of 10 CFR 50.55a(b )(2)(ix)(B) are applied. Visual examination from these vantage points should provide adequate access to perform visual examination of these surfaces.
Visual examination of this suppression pool vapor space is performed by QC personnel each inspection period. The results of these examinations indicate only minor coating loss, and virtually no degradation of the shell material.
Therefore, classification of this area as IWE, Category E-A is warranted.
Suppression Pool Interior Submerged Surfaces The submerged surfaces of the suppression pool are only accessible for visual examination using underwater divers or by draining the pool. Draining the pool is not an attractive option due to the time and expenses involved.
Divers beginning with the spring 1990 refueling outage have performed visual examinations of these surfaces for Unit 1 and the spring 1991 refueling outage for Unit 2. An extensive de-sludging, visual examination, and patch coating repair program was initiated beginning in 1991. These activities have continued and a long-range suppression pool maintenance program is in place at HNP. Examination Results HNP Unit 1: The results of these examinations indicated that there was some coating degradation and shell pit measurements were taken to determine the maximum degradation and the Enclosure Page 36 of 81 rate of degradation.
Subsequent review and evaluation in 1996 revealed a maximum pit depth of approximately 0.030" with a corrosion rate of 0.15 mils (0.00015")
per year. The nominal thickness of the submerged area is 0.594" with a minimum design thickness of 0.440". Ultrasonic thickness measurements in 1997 of an 18" X 36" grid in Bay 14 revealed an actual average shell thickness of 0.680" with a minimum thickness of 0.643" and a maximum thickness of 0.729". Therefore, since this area was recoated in 1981 there has been no significant degradation of the submerged area of the suppression pool shell and the current degradation rate is very slow (0.00015 inches/year).
HNP Unit 2: The results of these examinations indicated that there was some coating degradation and shell pit measurements were taken to determine the maximum degradation and the rate of degradation.
Subsequent review and evaluation in 1997 revealed a maximum pit depth of approximately 0.040" with a corrosion rate of 1.74 mils (0.00174")
per year. The nominal thickness of the submerged area is 0.594" with a minimum design thickness of 0.440". There has been no significant degradation of the submerged area of the suppression pool shell and the current degradation rate is very slow (0.00174 inches/year).
Since HNP plans to continue de-sludging, examination, and spot coating repair as necessary, there is no justification to classify the submerged areas as IWE, Category EC, which would require VT -1 and ultrasonic thickness measurements.
Classification of the HNP Unit 1 submerged surfaces as IWE, Category E-A is warranted at the present time. The results of these examinations for HNP Unit 2 indicated that there was some coating degradation and shell pit measurements were taken to determine the maximum degradation and the rate of degradation.
Subsequent review and evaluation in 1997 revealed a maximum pit depth of approximately 0.040" with a corrosion rate of 1.74 mils (0.00174")
per year. The nominal thickness of the submerged area is 0.594" with a minimum design thickness of 0.440". There has been no significant degradation of the submerged area of the suppression pool shell and the current degradation rate is very slow (0.00174 inches/year).
Since HNP plans to continue de-sludging, examination, and spot coating repair as necessary, there is no justification to classify the submerged areas as IWE, Category E-C, which would require VT-1 and ultrasonic thickness measurements.
Classification of the HNP Unit 2 submerged surfaces as IWE, Category E-A is warranted at the present time. Vent System Examination Position The results of visual examinations performed on the vent system, located inside the suppression pool, in conjunction with the suppression pool vapor space examination indicate only minor coating loss, and virtually no degradation of the shell material.
Therefore, classification of this area as IWE, Category E-A is warranted.
Enclosure Page 37 of 81 Virtually 100% of the exterior vent system (located inside the suppression pool) surfaces are accessible for visual examination from the 114' -0" interior catwalk, or from the top of the vent header if the provisions of 10 CFR 50.55a(b)(2)(ix)(B) are applied. Visual examination of the exterior vent system surfaces located outside the suppression pool are accessible from the inner circumference catwalk, the top of the vent pipe and the 87' -0" floor elevation if the provisions of 10 CFR 50.55a(b)(2)(ix)(B) are applied. Visual examination of the interior vent system is accessible from the drywell. Visual examination of the vent system from these vantage points should provide adequate access to perform visual examination of these surfaces.
There have been no reports of significant degradation of the exterior or interior surfaces of the vent system during examination and classification as IWE, Category E-A is warranted at the present time. Category E-A Specific Evaluation and Examination Position Item E1.10 Evaluation Item E1.10 includes the containment vessel pressure retaining boundary and the examinations listed in items E1.11 and E1.12. The examinations described in E1.11 and E1 .12 are applicable as described in the appropriate sections below. Item E1 .11 Evaluation (General Visual Examination)
Table IWE-2500-1, Item E1 .11 references the below listed footnotes relative to containment surface examination requirements.
- 1. Examinations shall include all accessible interior and exterior surfaces of Class MC components, parts, and appurtenances, and metallic shell and penetration liners of Class CC components.
The following items shall be considered for examination: (a) integral attachments and structures are parts of reinforcing structure, such as stiffening rings, manhole frames, and reinforcement around openings. (b) surfaces of attachment welds between structural attachments and the pressure retaining boundary or reinforcing structure, except for nonstructural or temporary attachments as defined in NE-4435 and minor permanent attachments as defined in CC-4543.4. (c) surfaces of containment structural and pressure boundary welds, including longitudinal welds (Category A), circumferential welds (Category B), flange welds (Category C), and nozzle-to-shell welds (Category D) as defined in NE-3351 for Class MC; and surfaces of Flued Head and Bellows Seal Circumferential Welds joined to the Penetration.
Enclosure Page 38 of 81 (d} pressure-retaining bolted connections, including bolts, studs, nuts, bushings, washers, and threads in base material and flange ligaments between fastener holes. Bolted connections need not be disassembled for performance of examinations, and bolting may remain in place under tension. Table IWE-2500-1 requires the General Visual Examination prior to each inspection period. 10 CFR 50 Appendix J requires the exam prior to each Type A test. Item E1 .11 Examination Position A General Visual Examination of the accessible containment surfaces is required once each inspection period and prior to each Type A test. The General Visual Examination includes the following areas.
- Accessible surfaces of the interior of the drywell shell above the 114-foot floor elevation.
- Interior and exterior surfaces of the drywall head.
- Accessible interior and exterior surfaces of drywell penetrations.
- Accessible interior and exterior surfaces of the drywall to torus vent lines.
- Accessible interior and exterior surfaces of the torus vent header and downcomers.
- Accessible exterior surfaces of the torus shell and torus supports.
- Accessible interior surfaces of the torus shell above the water level. The exterior drywell shell surface is exempt from examination per IWE-1220(b) and IWE-1232(a).
The requirements of IWE-1231 (a}(3) are satisfied (i.e., at least 80% of the accessible surface area can be examined either directly or remotely}
by performing examination from existing catwalks, walkways, ladders, floor elevations and adjacent structures of the drywell shell, drywell head, drywell to torus vent lines, vent header and downcomers, containment penetrations, the interior torus shell above the water level, and the torus exterior shell surfaces.
Item E1 .11 Evaluation (Bolting VT-3) 10 CFR 50.55a(b)(2)(ix)(G) and Item E1 .11 (Bolting) applies to the examination/testing of pressure retaining bolted connections where the pressure retaining function is considered to apply to bolting which is in tension during the accident.
Item E1 .11 requires a general visual examination of all pressure retaining bolted connections which are part of the Class MC containment structure once each 10-year inspection interval.
10 CFR 50.55a(b)(2}(ix}(G}
requires a VT-3 exam. 10 CFR 50.55a(b)(2)(ix)(H) requires that the VT-3 be performed each inspection interval.
Flaws or degradation identified during the performance of the VT-3 examination must be examined in accordance with the VT-1 examination method. The criteria in the material specification or IWB-3517 .1 Enclosure Page 39 of 81 must be used to evaluate containment bolting flaws or degradation.
While disassembly is not required to support the examination, examination is required for any appropriate bolted connections that are disassembled.
Bolting may be examined in place under tension when disassembly is not otherwise required during the inspection interval.
Item E 1.11 Examination (Bolting VT-3) Position All Class MC pressure retaining bolted connections are listed in the examination plan and will be VT-3 examined in accordance with IWE as amended by 10 CFR 50.55a at least once each inspection interval if disassembled.
Any connections that are not disassembled during normal outage activities will be examined with the bolting in place. Flaws or degradation identified during the performance of the VT-3 examination will be examined in accordance with the VT-1 examination method. All bolted Class MC connections, except Penetration X-218B, are normally disassembled during the interval.
Electrical penetrations used at Plant Hatch are weld-in design, do not utilize pressure retaining bolting, and are not specifically listed in the examination tables. These penetrations are part of the general visual examinations performed on a periodic basis. All bolted connections are also included in the Appendix J leakrate testing program. Appendix J leakrate testing is required anytime the connection is disassembled, and at least every 10 years if not disassembled, which confirms containment leak tight integrity.
Item E 1.12 Evaluation (VT-3 Visual Examination)
Table IWE-2500-1, Item E1 .12 references the below listed footnotes relative to containment surface examination requirements.
- 1. Examinations shall include all accessible interior and exterior surfaces of Class MC components, parts, and appurtenances, and metallic shell and penetration liners of Class CC components.
The following items shall be considered for examination: (a) integral attachments and structures are parts of reinforcing structure, such as stiffening rings, manhole frames, and reinforcement around openings. (b) surfaces of attachment welds between structural attachments and the pressure retaining boundary or reinforcing structure, except for nonstructural or temporary attachments as defined in NE-4435 and minor permanent attachments as defined in CC-4543.4.
Examination shall include the weld metal and the base metal for 1/2 in. beyond the edge of the weld. (c) surfaces of containment structural and pressure boundary welds, including longitudinal welds (Category A), circumferential welds (Category B), flange welds (Category C), and nozzle-to-shell welds (Category D) as defined in NE-3351 for Class MC; and surfaces of Flued Head and Bellows Seal Circumferential Welds joined to the Penetration.
Enclosure Page 40 of 81 (d) pressure-retaining bolted connections, including bolts, studs, nuts, bushings, washers, and threads in base material and flange ligaments between fastener holes. Bolted connections need not be disassembled for performance of examinations, and bolting may remain in place under tension. 10 CFR 50.55a(b)(2)(ix)(G) requires VT-3 Visual Examination of 100% of the accessible containment surfaces once each inspection interval.
Item E 1.12 Examination Position A VT-3 Visual Examination of the wetted surfaces of submerged areas is required once each inspection interval.
A VT-3 visual examination will be performed each interval on the following submerged, accessible, pressure boundary surfaces of the Drywell, Torus, and Vent System: 1) Accessible interior surfaces of the torus shell which are submerged (utilizing divers). 2) Accessible submerged surfaces of the vent header downcomers, vent header supports, and interior submerged attachments welded to the torus shell (utilizing divers). Item E1 .20 Evaluation (General Visual Examination)
Table IWE-2500-1, Item E1 .20 references the below listed footnotes relative to containment vent system surface examination requirements. 1 . Examinations shall include all accessible interior and exterior surfaces of Class MC components, parts, and appurtenances, and metallic shell and penetration liners of Class CC components.
The following items shall be considered for examination: (a) integral attachments and structures are parts of reinforcing structure, such as stiffening rings, manhole frames, and reinforcement around openings. (b) surfaces of attachment welds between structural attachments and the pressure retaining boundary or reinforcing structure, except for nonstructural or temporary attachments as defined in NE-4435 and minor permanent attachments as defined in CC-4543.4.
Examination shall include the weld metal and the base metal for 1/2 in. beyond the edge of the weld. (c) surfaces of containment structural and pressure boundary welds, including longitudinal welds (Category A), circumferential welds (Category B), flange welds (Category C), and nozzle-to-shell welds (Category D) as defined in NE-Enclosure Page 41 of 81 3351 for Class MC; and surfaces of Flued Head and Bellows Seal Circumferential Welds joined to the Penetration. (d) pressure-retaining bolted connections, including bolts, studs, nuts, bushings, washers, and threads in base material and flange ligaments between fastener holes. Bolted connections need not be disassembled for performance of examinations, and bolting may remain in place under tension. 2. Includes flow-channeling devices within containment vessels. 10 CFR 50.55a(b)(2)(ix)(G) requires a VT-3 visual examination of 100% of the accessible containment vent system surfaces once each inspection interval.
Exemption Request ISl-EX-01 allows the use of a general visual type inspection in lieu of performing the VT-3. Item E1 .20 Examination Position A General Visual Type Examination of the accessible containment vent system surfaces is required once each inspection interval per exemption request ISl-EX-01.
A VT-3 Visual Examination will be performed on the submerged, accessible; pressure boundary surfaces of the Vent System in accordance with item E1 .12. The containment vent system is comprised of the drywall to torus vent lines, the vent header and associated downcomers.
The vent header and downcomers are located inside the torus. A General Visual Type Examination will be performed in the following areas, which are included within the scope of the E1 .20 examinations described above. 1) Accessible (virtually 100%) interior surfaces of the drywall to torus vent lines. 2) Accessible exterior surfaces of the drywell to torus vent lines (portions visible from the exterior torus catwalk, and from the interior torus catwalk 3) Accessible (virtually 100%) interior surfaces of the torus vent header. 4) Accessible (approx. 50%) exterior surfaces of the torus vent header. 5) Accessible (approx. 50%) exterior surfaces of the vent header downcomers.
Examination shall include the inside and outside of the vent system shell per Table IWE-2500-1, Category E-A, Footnote 1. The requirements of IWE-1231 (a)(3) are satisfied (i.e., at least 80% of the accessible surface area can be examined either directly or remotely) from the interior/exterior of the vent lines and vent header, existing torus catwalks and walkways, ladders, adjacent structures.
The requirements of IWE-1232(a) were satisfied during construction.
Item E1 .30 Evaluation (General Visual Examination)
Enclosure Page 42 of 81 Item E 1 .30 requires general visual examination of containment moisture barrier materials at concrete-to-metal interfaces.
HNP has only one such moisture barrier that i$ located inside the drywall at the 114-foot concrete floor elevation to drywall shell interface.
This moisture barrier provides a seal to prevent seepage of water that might accumulate on this floor elevation, into the space between the concrete and the drywall shell. SCS evaluated the potential for shell degradation below the 114-foot elevation should water accumulate in this region. Their evaluation indicated that due to the concrete and water interaction in this area, the pH of the resulting environment was not conducive to shell degradation.
Item E1 .30 Position HNP will implement a general visual examination of the moisture barrier located at the 114-foot floor elevation inside the drywall. The moisture barrier will be examined at least once each inspection period. SNC Engineering Department (Civil) evaluation of the examination results is anticipated to support acceptance or recommendation for corrective action, as required.
CATEGORY E-C Category E-C applies to containment surfaces requiring augmented examinations.
Surfaces that should be evaluated as requiring augmented examinations are defined by IWE-1240.
The basic premise of IWE-1240 is: (a) containment surfaces that are subject to accelerated corrosion with no or minimal corrosion allowance or areas where the absence or repeated loss of protective coatings has resulted in substantial corrosion and pitting, and (b) containment surfaces subjected to excessive wear from abrasion or erosion that causes a loss of protective coatings, deformation, or material loss. The areas described in IWE-1240 were considered for their applicability at HNP and a discussion of each area is provided below. Interior Submerged Surfaces of Suppression Pool (Torus) (See General Discussion for Category E-A) The torus design accounted for maintenance of a specific water level during all modes of plant operation and post accident.
The interior and exterior surfaces were initially provided with protective coatings, which have been inspected and patch coated as needed since commercial operation of the plant. HNP implements periodic VT-3 visual examination, utilizing underwater divers, of the submerged surfaces to determine any areas of coating or shell degradation.
A recoating process has been implemented for any areas that indicated coating degradation.
Pitting depth measurements were taken in conjunction with these examinations to determine torus shell corrosion rates. Test specimens have also been placed inside the torus, Enclosure Page 43 of 81 below the water level, to provide additional information relative to coating degradation and potential shell corrosion rates. Evaluation of the HNP Unit 1 and Unit 2 examination results to date does not indicate that the submerged areas of the torus have experienced any significant degradation that presently warrants classification as IWE Category E-C. The interior submerged surfaces of the torus have been included in the examination plan as IWE Category E-A subject to VT-3 visual examination.
The results of future VT -3 examinations, performed by underwater divers, will be evaluated to determine if these areas should be categorized.
Interior Torus Surfaces Exposed to Periodic Wetting and Drying The containment spray mode of RHR system operation is only used infrequently to control suppression pool pressure.
This has resulted in discoloration of the protective coating on the areas adjacent to the spray nozzles. However, periodic examination of the interior torus surfaces has not indicated any significant degradation of the protective coating or the shell surface. Some minor areas of the coating have been cleaned and recoated, but no significa,nt shell degradation has been identified.
These surfaces are visually examined in accordance with Category E-A, and the performance of augmented examinations per Category E-C is not presently warranted for these surface areas. Bottom Interior of Torus Adjacent to SRV Discharge Lines The SRV discharge lines at Plant Hatch were modified in the early 1980s incorporating a "T-quencher" design, which evenly distributes the discharged steam and prevents steam-jets that could damage the protective coating or the shell surface. Periodic VT-3 visual examination by underwater divers has not indicated any significant coating degradation, which would indicate potential shell degradation.
These surfaces are included within the scope of the Category E-A examinations and are periodically inspected by underwater divers. Therefore, the performance of augmented examinations per Category E-C is not presently warranted for these surface areas. Torus Seismic Restraints (Earthquake Ties-4) The torus is provided with 4 seismic restraints to account for the possibility of any seismic loads that could be experienced.
These restraints are located at the 87-foot floor elevation in the torus room and are accessible during the general examinations (Category E-A) of the containment surfaces.
The torus room is not a harsh environment and HNP has not been subjected to any seismic events that would affect the torus or the restraints.
These seismic restraints are included within the scope of the Category A examinations and performance of augmented examinations per Category E-C is not presently warranted for these restraint areas.
Exterior Drvwell Shell Below the 114-Foot Floor Elevation Enclosure Page 44 of 81 The exterior of the drywell shell at and below the 114-foot elevation was considered as possibly subject to accelerated degradation due to problems reported at Oyster Creek. This area at Oyster Creek was found to be severely corroded due to exposure to water and corrosive chemicals that had accumulated in the air gap region because of a leak in the refueling bellows, chemicals in the gap forming material (that was left in place), and drain lines that were not functional.
The refueling bellows at HNP is of a different design than that at Oyster Creek and virtually all of the gap forming material was removed during construction.
The sand cushion drain lines have been modified at HNP (discharge elbows removed) to facilitate visual examination.
The air gap drain lines and the sand cushion drain lines have been , examined using a video probe to assure that they are functional and that any water that might leak into the drywell air gap region would be discharged from the area. These visual examinations did not indicate the present or past existence of moisture in these areas. The discharge of each drain is also examined for evidence of moisture during each refueling outage, while the reactor cavity is flooded, to assure that no water is present in this area. Therefore, the performance of augmented examinations per Category E-C is not presently warranted for these surface areas. Drvwell Equipment Hatches and Personnel Air Lock The equipment hatches and personnel air lock are used as entry/exit openings during refueling outages for equipment and personnel.
The air lock is provided with floor grating which prevents abrasion of the lower portion of the shell. Wooden platforms are constructed in the equipment hatches to prevent abrasion of the shell. Therefore, there is no reason to expect accelerated degradation in these areas and the general visual examination requirements of Category E-A are adequate to monitor the structural integrity.
Category E-C Position Based on a review of IWE-1240 relative to the containment design at HNP and the results of previous HNP Unit 1 and Unit 2 examinations related to the integrity of the containment, there are no areas that should be designated for augmented examination per Category E-C at the present time. The results of future containment examinations, related to IWE, Appendix J, and the Maintenance Rule, will be evaluated to determine if any areas are experiencing degradation that would result in the need to implement augmented examinations.
Torus Inspection Program The suppression pool, or torus, is made up of sixteen cylindrical sections or bays, that are "mitered" to form a large "donut" with a diameter from center line to center line of approximately 107', and a cross-sectional inside diameter of approximately 28'. The Enclosure Page 45 of 81 normal water depth is approximately 12.5'. At the centerline, each bay is approximately 21 '-3" long. A ring girder, which is part of the attachment and support structure of the torus, is located at the joint between each bay and provides some separation between each bay. In 1990, several inspection grids (approximately 12" square) were established in the Unit 1 torus and de-sludging was performed.
The inspection grids were then utilized to monitor loss of wall thickness at pit locations, and de-sludging was performed to minimize the possibility of ECCS strainer blockage.
In 1991, inspection grids were similarly established in the Unit 2 torus and de-sludging was performed.
During these 1990/1991 refueling outages, a visual inspection was performed by divers in the submerged areas and by plant/SGS personnel in the vapor area. Local repairs were performed whenever general corrosion exceeded established acceptance criteria.
In no case have we observed any degradation, which infringed upon the minimum wall thickness requirements of the torus. The inspections, de-sludging, and repairs have been performed as necessary since their inception in 1990. De-sludging This activity is performed in the submerged area by divers using a vacuum system. The vacuum system pulls the sludge into filter banks. The filter banks are stationed with pumps to continuously filter the water removing most of the suspended particles.
This activity requires approximately one week from set up to removal of filters. SNC has found the pitting degradation to decrease as the frequency of de-sludging is increased.
SNC has de-sludged each unit as necessary since 1993. This activity is considered as normal maintenance and therefore is not considered to be part of the ASME Section XI IWE Program requirements.
Spot Coating Repair of Submerged Areas The need for spot coating will continue to be evaluated following each inspection, and any repairs made will be in accordance with the plant's ASME Section XI Repair/Replacement Program. , Visual Inspection of Vapor Area All visual inspections of the torus vapor phase will be conducted in accordance with ASME Section XI, Subsection IWE requirements.
Spot Coating Repair of Vapor Area SNC plans to spot repair the coating on HNP Unit 1 and Unit 2 as necessary.
All spot repairs of the torus vapor phase will be conducted in accordance with ASME Section XI, Subsection IWE repair/replacement requirements.
Ultrasonic Testing (UT) Enclosure Page 46 of 81 SNC has included supplemental provisions in the IWE program to check and monitor wall degradation of both Units 1 and 2 torus surfaces.
Beginning with Unit 2 in 1998 and Unit 1 in 1999, SNC will perform ultrasonic (UT) thickness measurements in each torus bay of both Units 1 and 2. These measurements include selection of one grid location near the bottom in each torus bay. After the initial inspections, SNC will repeat the inspections every other outage to monitor degradation rates and their impact on Code minimum thickness.
Conclusion The above plan, in conjunction with the ASME Section XI, Subsection IWE Program, is intended to assure the integrity of the torus. Based on evaluation of the results from all previous examinations, there is currently no indication that there are any degradation concerns which impact the wall thickness or structural integrity of the torus. 3.4.3 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" The following HNP procedures provide instructions for performing inspections to satisfy the requirements of Unit 1 and Unit 2 TS SR 3.6.1 .1 .1:
- Drywell Surfaces Visual Inspection This procedure provides instructions for performing the inspection of the interior and exterior Drywell and Drywell Head surfaces to satisfy the requirements of Unit 1 and Unit 2 TS SR 3.6.1.1.1.
This procedure also provides instructions for performing the inspection of the drywell shell and head as required by the ISi Plans.
Enclosure Page 47 of 81 This procedure applies to Unit 1 and Unit 2 drywalls and drywall heads and shall be performed at least once each ISi Period and prior to each 1 O CFR 50 Appendix J ILRT.
- Venting Assembly and Suppression Chamber Surfaces Visual Inspection
- This procedure provides instructions for performing the suppression chamber (Torus) interior (vapor phase) and exterior surface inspection to satisfy the requirements of Unit 1 and Unit 2 TS, Section SR 3.6.1.1.1.
This procedure also provides instructions for performing the inspection of the torus as required by the ISi Plans. This procedure applies to Unit 1 and Unit 2 suppression chambers (T23) and shall be performed at least once each ISi Period and prior to each 10 CFR 50 Appendix J ILRT. For HNP, no additional inspections are required.
3.4.4 Primary
Containment Leakage Rate Testing Program -Type Band Type G Testing Program HNP 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 maintenance and repairs are made on these components
- throughout their service life. The Types B and C testing program provides a means to protect the health and safety of plant personnel and the public by maintaining leakage from these components below appropriate limits. In accordance with TS 5.5.12, the allowable maximum pathway total Types Band C leakage is 0.6 La where La equals approximately 272,320 standard cubic centimeters per minute (seem) (61, 102 actual cubic centimeters per minute (accm)) for Unit 1 and 254,937 seem (60,432 accm) for Unit 2. As discussed in NUREG-1493 (Reference 6), Type Band Type G 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 Type B and Type G test results from 2006 through the Spring of 2014 for HNP, Unit 1 and from 2007 through the Spring of 2015 for HNP, Unit 2 has shown margin between the actual As-Found (AF) and As-Left (AL) outage summations and the regulatory requirements as described below:
- The As-Found minimum pathway leak rate average for HNP, Unit 1 shows an average of 18.1 % of La with a high of 43.74% La.
Enclosure Page 48 of 81
- The As-Left maximum pathway leak rate average for HNP, Unit 1 shows an average of 12.2% of La with a high of 15.97% La.
- The As-Found minimum pathway leak rate average for HNP, Unit 2 shows an average of 52.3% of La with a high of greater than La.
- The As-Left maximum pathway leak rate average for HNP, Unit 2 shows an average of 25.3% of Li'i with a high of 50.43% La. Tables 3.4.4-1 and 3.4.4-2 provide local leak rate test (LLRT) data trend summaries for HNP Unit 1 and Unit 2 Inclusive of the Unit 1, 2008 ILRT and the Unit 2, 2009 ILRT. Table 3.4.4-1, Unit 1 Type 8 and C LLRT Combined As-Found/As-Left Trend Summary RFO 2008 2010 2012 2014 2016 1RF23 1RF24 1RF25 1RF26 1R27 AF Min Path 26724 8533 33435 28539 27,598 acem accm seem seem seem Fraction of 43.74 13.96 12.28 10.48 10.13 La AL Max Path 7640 8635 28370 26982 38, 162 accm accm seem seem seem Fraction of 12.50 14.13 . 10.42 9.91 14.0 La Table 3.4.4-2, Unit 2 Type 8 and C LLRT Combined As-Found/As-Left Trend Summary RFO 2007 2009 2011 2013 2015 2RF19 2RF20 2RF21 2RF22 2RF23 AF Min Path 32649 25414 Fail AF 132174 34458 aecm accm (1) seem seem Enclosure Page 49 of 81 Table 3.4.4-2, Unit 2 Type Band C LLRT Combined As-Found/As-Left Trend Summary RFO 2007 2009 2011 2013 2015 2RF19 2RF20 2RF21 2RF22 2RF23 Fraction of 54.03 42.05 Fail AF 51.84 13.52 La (1) AL Max Path 14166 12527 30479 43010 38794 accm accm accm seem seem Fraction of 23.44 20.73 50.43 16.87 15.22 La (1) During as-found LLRT testing of 2T48-F309 (CR 2011104286) and 2T48-F324 (CR 2011105199) each of these valves would not hold test pressure indicating gross leakage through the valve. These valves comprise a primary containment barrier. Given gross leakage the technical specification limit for leakage out of primary containment was exceeded.
This was reported under LEA 2011-001-1 (Reference 34). 3.4.5 Type Band Type C Local Leak Rate Testing Program Implementation Review The following Tables 3.4.5-1 and 3.4.5-2 identify the components that were on extended intervals and have not demonstrated acceptable performance during the previous two . outages for HNP, Units 1 and 2 respectively:
Table 3.4.5-1, Unit 1 Type B and C LLRT Program Implementation Review 1RF26 -2014 Component As-Admin As-left Cause of Corrective Scheduled found Limit SCCM Failure Action Interval SCCM SCCM 1 E41-F111 185,244 275 867 Seat Valve was 30 months Pen 221A (1) leakage, refurbished.
MNPLR Broken Acceptance of 64 wedge refurbished (1) valve As-left leakage by evaluation Enclosure Page 50 of 81 Table 3.4.5-1, Unit 1 Type B and C LLRT Program Implementation Review 1RF26 -2014 Component As-Admin As-left Cause of Corrective Scheduled found Limit SCCM Failure Action Interval SCCM SCCM 1T48-F335B 00 575 0 Seat Valve and valve 30 months Pen 26 (2) leakage operator MNPLR (2) refurbished 110 1RF27-2016 Component As-Admin As-left Cause Corrective Scheduled found Limit SCCM of Action Interval SCCM SCCM Failure H48-F334A 700 575 700 Not Acceptance of 30 months Pen 26 MNPLR identified valve As-left 53 leakage by evaluation.
(1) 1 E41-F111 failed as-found testing with an identified leakage rate of 185244 seem. It was discovered during performance of 42SV-TET-001-1 that 1 E41 F111 could not be brought to test pressure due to leakage through seat of this valve. Per engineering request, a set of data was recorded at less than prescribed test pressure.
At 47.5 psig measured leakage was 185,244 seem. The minimum pathway leakage rate for Penetration 221A was 64 seem. Excessive seat leakage was due to stellite breaking off the wedge on the downstream side. (2) 1T48-F111 failed as-found testing with a leakage rate of that could not be quantified.
Diagnostics indicate that there was leakage through 1T48-F335B.
The minimum pathway leakage rate for Penetration 26 was 110 seem. The valve and valve actuator were both refurbished.
Table 3.4.5-2, Unit 2 Type B and C LLRT Program Implementation Review 2RF22-2013 Component As-Admin As-left Cause of Corrective Scheduled found Limit SCCM Failure Action Interval SCCM SCCM 2B31-F019 280 150 2 Seat leakage Refurbished 30 months Pen 41 (1) valve 2T48-F319
& 76,220 4850 0 Seat leakage Refurbished 30 months F320 MNPLR (2) valve 2T48-Pen 26 0 F319 2RF23-2015 Component As-Admin found Limit SCCM SCCM 2T48-342D 00 250 Pen 225K MNPLR 0 As-left Cause of SCCM Failure 30 Leaking hose (3) Enclosure Page 51 of 81 Corrective Scheduled Action Interval Replaced hose 30 months (3) (1) 2B31-F019 failed as-found testing with an identified leakage rate of 280 seem. Diagnostic testing was performed and determined that leakage is through the seat. (2) 2T 48-F319 failed as-found testing with an identified leakage rate of 76220 seem. When the 2T 48-F319 and 2T 48-F320 were tested, the leakage was greater than test equipment upper measurable limit and test pressure could not be attained.
Diagnostic investigation determined that most of the leakage was attributable to the 2T48F319 valve. The minimum pathway leakage rate attributed to 2T48-F320 for Penetration 26 was 0 seem. (3) 2T48-342D failed as-found testing with a leakage rate of that could not be quantified.
The minimum pathway leakage rate for Penetration 225K was 0 seem. Failure was due to leaking hose outside of containment.
Hose was replaced.
No work performed inside containment.
3.4.6 Plant
Operational Performance During power operation the primary containment atmosphere is inerted with nitrogen to ensure that no external sources of oxygen are introduced into containment.
The containment inerting system is used during the initial purging of the primary containment prior to power operation and provides a supply of makeup nitrogen to maintain primary containment oxygen concentration within TS limits. As a result, the primary containment is maintained at a slightly positive pressure during power operation.
Primary containment pressure is continuously recorded and verified by TS surveillance on a frequency of every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> from the MCR. Although this feature, that is inherent to the HNP BWR containment design, does not challenge the structural and leak tight integrity of the containment system at post-accident pressure, the fact that the containment is continuously pressurized by the containment inerting system, and is periodically monitored, provides assurance that gross containment leakage that may develop during power operation will be detected.
3.5 Operating
Experience Enclosure Page 52 of 81 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 HNP Primary Containments, the following site specific and industry events have been evaluated for impact on the HNP Primary Containments:
- GL 87-05, Request for Additional Information Assessment of Licensee Measures to Mitigate and/or Identify Potential Degradation of Mark I Drywalls
- IN 1992-20, Inadequate Local Leak Rate Testing
- IN 2004-09, Corrosion of Steel Containment and Containment Liner
- IN 2010-12, Containment Liner Corrosion
- IN 2014-07, Degradation of Leak-Chase Channel Systems for Floor Welds of Metal Containment Shell and Concrete Containment Metallic Liner Each of these areas is discussed in detail in Sections 3.5.1 through 3.5.6, respectively.
3.5.1 NRC Generic Letter (GL) 87-05, Request for Additional Information Assessment of Licensee Measures to Mitigate and/or Identify Potential Degradation of Mark I Drywalls The NRC issued GL 87-05 (March 12, 1987) after reviewing reports of degraded containment (drywall) shell at Oyster Creek Nuclear Power Plant. In this GL, the NRC requested utilities to provide information relative to: (1) drainage of the sand cushion, (2) preventative maintenance and inspection activities to minimize any possible leakage from the refueling pool, (3) plans for ultrasonic thickness measurements for those drywall shells with open sand cushions, and (4) confirmation of information as listed in GL 87-05. The Oyster Creek Drywall was constructed leaving the air gap forming material in place. The refueling bellows design also incorporated a mechanical joint, which was subject to degradation and leakage when the reactor cavity was flooded and thus allowed water to leak into the air gap region. The sand cushion at Oyster Creek was constructed without a seal plate between the sand cushion and the air gap region. Oyster Creek discovered that their sand pocket and air gap drain lines were not functional and thus leakage from Enclosure Page 53 of 81 a degraded refueling bellows mechanical joint collected in the air gap and remained for a significant time period. After evaluation of the corrosion mechanisms, Oyster Creek determined that the moisture had reacted with chemicals in the sand cushion and gap forming material resulting in a corrosive environment, which led to the degradation of the carbon steel shell. Georgia Power Company, the original licensee of HNP and Sister Company of the current licensee, SNC, performed a review of GL 87-05 as applicable to HNP and responded to the NRC on May 11, 1987 (SL-2429).
The evaluation and resultant response indicated that HNP was not subject to the same conditions, which caused the drywell shell corrosion problem at Oyster Creek. Construction drawings indicated that the gap forming material was removed at Plant Hatch except for narrow rings at the elevation of each concrete pour. The refueling bellows do not contain any mechanical joints subject to degradation and subsequent leakage. The air gap drain lines were inspected utilizing a video probe an_d were all found to be functional.
Video inspection of the air gap drains did not reveal any evidence of moisture or collection of water. The sand cushion at Hatch was constructed with a metal seal plate, which would have directed any water into the air gap drain lines and prevented collection in the sand cushion. At HNP, supplemental visual exams are performed each outage for the Air Gap and Sand Cushion drain lines to ensure that the lines are functional and no corrosion mechanisms exist. These inspections are performed each refueling outage when the reactor cavity is flooded. 3.5.2 IN 88-82, Torus Shells with Corrosion and Degraded Coatings in BWR Containments The NRC issued IN 88-82 (October 14, 1988) after discovery of a degraded suppression pool (torus) shell at Nine Mile Point Nuclear Plant, Unit 1. The Nine Mile Point Unit 1 torus shell was constructed without any protective coatings and included a 1/16" corrosion allowance.
Inspection of the torus shell indicated that excessive corrosion was occurring and that the integrity of the suppression pool shell was in jeopardy.
The suppression pool at HNP was initially constructed with a protective coating on both the interior and exterior surfaces.
Both surfaces were partially re-painted in the early 1980s after completion of suppression pool modifications.
HNP has also implemented suppression pool de-sludging and visual inspection, which has resulted in some Enclosure Page 54 of 81 localized repairs, but the amount of shell degradation has been minimal. This inspection program will continue with periodic visual inspection, de-sludging, and localized repair as needed with a frequency of inspection based on the history of past inspections.
Per requests of HNP Nuclear Maintenance Support, SNC developed an augmented inspection program on the drywell shell and the torus. This program consists of taking UT measurements on 1' x 1' grids at the seven ring locations of the drywell. These grids are located at approximately the 0°, 90°, 180°, and 270° locations (28 total grids). UT , measurements are taken at a 10-year frequency since no significant degradation has been found. In addition to the drywell measurements, SNC will take UT measurements on 1' x 1' grids on all 16 bays of the torus. These measurements are taken every other outage since some degradation has occurred in the past. Measurements at exact locations are not required for the drywell and torus UT' s since these are used only to determine general corrosion rates. These measurements have shown that degradation rates for the drywell shell and torus have been minimal. 3.5.3 IN-92-20, Inadequate Local Leak Rate Testing The issue discussed in IN-92-20, 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 Integrated Leak Rate Test (ILRT) tests in the first three cases. In the event at Quad Cities the two-ply bellows design was not properly subjected to Local Leak Rate Test (LLRT) pressure and the conclusion of the utility was that the ply bellows design could not be Type B LLRT tested as configured.
In the events at both Dresden and Perry was that flanges were not considered a leakage path when the Type C LLRT test was designed.
This omission led to a leakage path that was not discovered until the plant performed an ILRT test. In the event at Clinton relief valve discharge lines that were assumed to terminate below the suppression pool minimum drawdown level were discovered to terminate at a level above that datum. These lines needed to be reconfigured and the valves should have been Type C LLRT tested. The applicability review performed at HNP indicated that only the bellows LLRT issues were found at Plant Hatch. The other issues identified in the IN were not a problem at HNP due to system configuration or the current LLRT program. The bellows issue was carefully considered and a number of actions taken to prevent the bellows installed at HNP from becoming a cause of ILRT test failure. Several bellows were tested by welding a plate inside containment so that the bellows could be tested properly.
The Enclosure Page 55 of 81 LLRT test method for bellows was revised. The ILRT procedure was revised to incorporate methodical leak detection walk down section. Mechanical Bellows Consistently Exceeding the Administrative Limit of 500 seem The following Table 3.5.3-1, Significant Leaking Bellows identifies all of the HNP Unit 1 and Unit 2 Mechanical Bellows, which have identified leakage rates in excess of the 500 seem administrative limit and are also tested each refueling outage: Table 3.5.3-1, Significant Leaking Bellows Penetration Exceeded Range-seem Projected End Current No. Admin Short Term of Life Guidance Mechanical Limit-year Trend Leakage-Bellows seem Last LLRT-seem (Average Outage/Date Change per RFO) 936-6216 1T23-X7A 2002 Increasing 9000 Track and Main Steam (660) Trend Line 6216 1 RF27/2016 656-1332 Track and 1T23-X8 2004 Increasing 2500 Trend Condensate (97) Drain 1332 1 RF27/2016 5629-7594 2T23-X8 1997 Decreasing 3500 Track and Condensate (179) Trend Drain 5629 2RF23/2015 625-716 2T23-X10 1997 Steady 750 Track and RCIC Steam (8) Trend 716 2RF23/2015 3236-5790 2T23-X11 1997 Increasing 5900 Track and HPCrSteam (232) Trend 4676 2RF23/2015 Table 3.5.3-1, Significant Leaking Bellows Enclosure Page 56 of 81 Penetration Exceeded Range-seem Projected End Current No. Admin Short Term of Life Guidance Mechanical Limit-year Trend Leakage-Bellows seem Last LLRT-seem (Average Outage/Date Change per RFO) 511 -771 2T23-X12 1997 Increasing 825 Track and RHR Suction (24) Trend 771 2RF23/2015 5430-7324 2T23-X42 1997 Increasing 7900 Track and Standby Liquid (172) Trend Control 6280 2RF23/2015 Current Procedural Guidance
- LLRT Engineer to continue trending for degradation.
- IF trend indicates penetration will exceed 5% of La prior to end of plant license, THEN repair prior to exceeding 5% level (currently no bellows predicted to exceed 5%).
- IF tested leakage of any Type B penetration unexpectedly exceeds 5% of La, THEN repair penetration the next refuel outage provided analysis supports an additional fuel cycle. IF analysis does not support an additional cycle, THEN repair immediately.
3.5.4 IN 2004-09, Corrosion of Steel Containment and Containment Liner The NRC issued this information notice to alert addressees to recent occurrences of corrosion in freestanding metallic containments and in liner plates of reinforced and stressed concrete containments.
Any corrosion (metal thinning) of the liner plate or freestanding metallic containment could change the failure threshold of the containment under a challenging environmental or accident condition.
Thinning changes, the geometry of the containment shell or liner plate, which may reduce the design margin of safety against postulated accident and environmental loads. Recent experience has Enclosure Page 57 of 81 shown that the integrity of the moisture barrier seal at the floor-to-liner or containment junction is important in avoiding conditions favorable to corrosion and thinning of the containment liner plate material.
Inspections of containment at the floor level, as well as at higher elevations, have identified various degrees of corrosion and containment plate thinning.
The containment structure at Plant Hatch is steel and is inspected under the plant's ISi plan. The inspections are accomplished by procedures 42SV* T23*003-0, Drywall Surfaces Visual Inspection; and 42SV-SUV-047-0, Venting Assembly and Suppression Chamber Surfaces Visual Inspection.
These procedures address examinations to be performed which are associated with the Containment Inspection Program. The procedures define the requirements for visual examination on the drywall shell, associated drain lines and the suppression pool interior and exterior surfaces.
Both coated and uncoated surfaces in the drywall and torus are monitored.
Additionally, the Drywall wall does not stop at the floor level, but progresses as one continuous piece under the drywall floor area. Inside the Drywall at the intersection of the Drywall shell and concrete floor, plant design requires a joint (mastic) sealing compound around the entire circumference of the Drywall. Areas under the mastic seal, on the Drywall surface, have previously been inspected for corrosion during repairs to the mastic seal. When inspected by representatives of the SNC Materials and Inspection Services Group and plant site personnel (using ultrasonic readings), some areas located under the mastic compound were found to be pitted. The steel thickness of the Drywall wall was evaluated and found to meet minimum thickness requirements.
The areas of pitting were coated prior to reinstallation of the new mastic seal. The results of a review of the data packages for Containment ISi of Unit 1, per T23-003-0S (Drywall Surfaces Visual Inspection, currently version 1.7), performed during the 2016 refueling outage and Unit 2 during the 2014 refueling outage, revealed that there were no reportable indications.
Therefore, there were no indications of significant corrosion of the Drywall shells. The Nitrogen lnerting System (NIS) must also be evaluated to determine its impact (if any) on moisture content (and subsequent corrosion) of the drywall environment.
Per 5.2.2.9 of the Unit 1 FSAR, the NIS system is "capable of reducing the oxygen content of the primary containment atmosphere to less than 4% by volume. The system is also capable of maintaining the oxygen content of the primary containment to less than 4% by volume during normal plant operation and following a Design Basis Accident." Therefore, there is normally a very small amount of oxygen within the drywall area. This being the case, at any time, only a small amount of corrosion could be supported in the drywall area, if all other required parameters were met. Based on the existence, continuance, and results of those monitoring programs, no additional actions in response to IN 2004-09 were deemed necessary.
3.5.5 IN 2010-12, Containment Liner Corrosion Enclosure Page 58 of 81 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 had been 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 form when the wall was poured. But the result in both cases was that the material trapped against the steel liner plate leading to corrosion.
In the third case, Salem, an insulating material placed between the concrete floor and the steel liner plate adsorbed moisture and led to corrosion of the liner plate. All three events reported issues with water trapped on the exterior side of the containment.
This event should not occur in HNP because HNP proactively examines for any adverse trending by performing the air gap and sand cushion inspections for evidence of water each refueling outage and have been doing so for many years. The situation that occurred in Salem is likely to take place at HNP if a 100% inspection of the moisture barrier and above surfaces is not completed.
HNP should not experience the event that took place in Beaver Valley and Brunswick, given that efforts were taken to remove any forming material.
Below is a section taken from the ISi Plan Volume 5, which describes other actions taken in the past that ensures that this event does not take place in Plant Hatch:
- Construction drawings indicated that the gap forming material was removed at Plant Hatch except for narrow rings at the elevation of each concrete pour.
- The ai,r gap drain lines were inspected utilizing a video probe and were all found to be functional.
Video inspection of the air gap drains did not reveal any evidence of moisture or collection of water.
- The sand cushion at Hatch was constructed with a metal seal plate, which would have directed any water into the air gap drain lines and prevented collection in the sand cushion. Since March 12, 1987 the NRC has taken interest on how operating nuclear plants assure that the integrity of the primary containment is not compromised.
Because of this interest from the NRC and the importance of the integrity of our Primary Containment, HNP designed the "Containment Inspection Program".
This program is comprised of existing plant programs and procedures in order to provide a complete and comprehensive program for examination of the pressure retaining surfaces of containment, structures that are part of reinforcement and any associated permanent attachment.
Enclosure Page 59 of 81 The following documents provide assurance and instruction on how to do the necessary task to maintain the integrity of the containment.
- Fifth Ten-Year Examination Plan (ISi Plan) This plan provides a summary of all the examinations and tests applicable to components treated as Class MC. It provides the appropriate schedule, period for implementing each exam/test.
- SNC In-Service Inspection Engineering Program This is an administrative control procedure, which establishes provisions for the implementation of a program, which satisfies the requirements of the ASME Section XI Code as required by TRM Section T3.4.2.1 (Structural Integrity).
In particular, this procedure applies to the implementation of the In-Service Inspection Program, in which containment inspection is a part of, and the Repair Replacement (R&R) program.
- Drywall Surfaces Visual Inspection This procedure provides instruction on how to perform the inspection of the interior Drywall surfaces and Interior and Exterior Drywall Head surfaces in order to satisfy TS SR 3.6.1.1.1:
11 Perform required visual examinations and leakage rate testing, except for primary containment air lock testing, in accordance with the primary Containment Leakage Rate Testing Program.11 It also provides instruction for performing the inspection per the ISi Plan requirements.
This is done every outage by the QC personnel.
After the inspection they submit the findings to the engineer, who will evaluate condition and decide if conditions identified are acceptable or not.
- Venting Assembly and Suppression Chamber Surfaces Visual Inspection This procedure provides instruction on how to perform the inspection of the interior (vapor phase) and exterior surfaces of the Suppression Chamber to satisfy requirements specified in TS Section SR 3.6.1.1.1.
It also provides instruction for performing the inspection per the ISi Plan requirements.
This is done every outage by the QC personnel who go out and inspect the respective areas. After inspection is done, QC will submit the findings to the responsible engineer, who will evaluate and decide if any further action is needed.
- Nuclear Coatings Program Enclosure Page 60 of 81 This procedure establishes the responsibilities for implementing and maintaining and periodically assessing the effectiveness of the Protective Coatings Program.
- Procedure for Coating Condition Assessments This procedure provides the method for performing condition assessments of Service Level I coatings used by SNC. This may also be used for performing condition assessments on non-safety related coatings and Service Level II and Ill coatings.
This addresses frequency, documentation and corrective action to be performed.
- Primary Containment Integrated Leakage Rate Testing This procedure establishes the criteria and detailed procedure to demonstrate that containment leakage at a design basis accident pressure does not exceed the acceptance limit specified in the TS SR 3.6.1.1.1.
This procedure also provides for containment structural inspection prior to each Type A Test and at a periodic interval between tests based on performance of the containment system.
- Visual Examination of the Drywell Air Gap and Sand Cushion Drain Lines This procedure addresses examinations, which are associated with the Containment Inspection Program but not required by the ASME Code,Section XI; however, they have been included in the Fifth Ten-Year Examination Plan Edwin I. Hatch Nuclear Plant. This inspection is done every outage. The engineer goes out and examines the discharge end of each sand cushion drain line as well as the air gap drain line for evidence of water each refueling outage while the reactor cavity is flooded. One reason for this test is to address the integrity of the refueling bellows. If a small quantity of water is observed in these areas, the situation can be addressed to minimize the water trapped in the sand cushion. If this situation is not addressed and a large amount of water is trapped in the cushion, the water could rust the outer wall of the drywell, thus compromising the integrity of our primary containment.
As a final point, the structural integrity of the HNP primary containment is vital for the generation of electricity as well as for the safety of plant personnel and the public. It is for this reason that this compendium of programs and procedures provide the guidance to ensure that the Primary Containment will not be compromised.
3.5.6 IN 2014-07, Degradation of Leak-Chase Channel Systems for Floor Welds of Metal Containment Shell and Concrete Containment Metallic Liner Enclosure Page 61 of 81 The containment basemat metallic shell and liner plate seam welds of pressurized water reactors 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 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 Gunction) 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. Plant Hatch does not have leak chase channels attached to its containment vessel, thus they would not have these leak chase test connections.
Subsequently no other known penetrations are known to exist to have contact with the inaccessible portions of the containment liner. 3.5.7 Results of recent Inspections Drvwell Air Gap Drain Lines and Drywell Sand Pocket Drain Lines 2016 Outage (1 R27) and 2015 Outage (2R23) All four drywell air gap drain lines and all four drywell sand pocket drain lines were visually examined to determine the existence or evidence of moisture and/or leakage. No moisture or leakage was observed at any drain line. There was no evidence of leakage identified.
Drvwell Ultrasonic Thickness Measurements 2014 Outage (1 R26) Examination Description Eight (8) drywell shell rings were examined in accordance with the Hatch Unit 1 Class MC Component Surveillance Schedule listed in the Fourth Ten-Year lnservice Inspection Plan. These exams were conducted to determine the relative condition of the Enclosure Page 62 of 81 primary containment shell. An ultrasonic test to obtain wall thickness measurements was performed on each of the eight (8) shell rings at the 0, 90, 180, and 270 degree azimuths using a 12" x 12" grid. Examination Results Based on the wall thickness measurements that were taken for each the eight (8) shell rings, there has been no significant change in the relative condition of the drywell since the drywell shell wall thickness measurements were taken during Outage 1 R21 in 2004. The minimum and maximum wall thickness values from the 2014 outage were compared against those taken during the 2004 outage. The minimum wall thickness values were compared to the nominal ring thicknesses, and there is presently no indication that the drywell shell wall thickness of the shell rings has degraded such that it is less than the nominal wall thickness.
2015 Outage (2R23) Examination Description Seven (7) drywell shell rings were examined in accordance with the Hatch Unit 2 Class MC Component Surveillance Schedule listed in the Fourth Ten-Year lnservice Inspection Plan. These exams were conducted to determine the relative condition of the primary containment shell. An ultrasonic test to obtain wall thickness measurements was performed on each of the seven (7) shell rings at the 0, 90, 180, and 270 degree azimuths using a 12" x 12" grid. Examination Results Based on the wall thickness measurements that were taken for each the seven (7) shell rings, there has been no significant change in the relative condition of the drywell since the drywell shell wall thickness measurements were taken during Outage 2R18 in 2005. The minimum and maximum wall thickness values from the 2015 outage were compared against those taken during the 2005 outage. The minimum wall thickness values were compared to the nominal ring thicknesses, and there is presently no indication that the drywell shell wall thickness of the shell rings has degraded such that it is less than the nominal wall thickness.
Torus Ultrasonic Thickness Measurements 2014 Outage (1 R26) Examination Description The submerged portion of the torus shell at each of the sixteen (16) torus bays was examined in accordance with HNP-1 Fourth Ten-Year Interval lnservice Inspection Plan, Volume 5 (IWE), Version 6. Wall thickness measurements were taken on the submerged portion of the torus shell at each of the sixteen torus bays and were recorded on an Ultrasonic Thickness Report. These examinations for wall thickness Enclosure Page 63 of 81 were conducted in order to determine the relative condition of the torus shell. Each bay was tested using a 12" x 12" grid located on each torus bay. Examination Results Based on the wall thickness measurements that were taken for each of the sixteen torus bays, there has been no significant change in the relative condition of the torus since torus shell wall thickness measurements were taken during Outage 1 R24 in 2010. The minimum and maximum wall thickness values from the 2014 outage were compared against those taken during the 2010 outage. The minimum wall thickness values were compared to the torus nominal thickness value (0.594"), and there is presently no indication that the wall thickness of the torus bays has degraded such that they are less than the nominal wall thickness.
Comparison of the 2010 and 2014 wall thickness measurements demonstrated continued adequacy of the current torus shell wall thickness condition.
2013 Outage (2R22) Examination Description On February 7,2013, the submerged portion of the torus shell at each of the sixteen (16) torus bays was examined in accordance with the HNP-2 Fourth Ten-Year Interval lnservice Inspection Plan, Volume 5 (IWE), Version 4.0. Wall thickness measurements were taken of the submerged portion of the torus shell at each of the sixteen torus bays. Each bay was examined using a 12" x 12" grid located on each torus bay. Examination Results Based on the wall thickness measurements that were taken for each of the sixteen torus bays, there has been no significant change in the relative condition of the torus since torus shell wall thickness measurements were last taken during Outage 2R20 in 2009. The minimum wall thickness values from the 2013 outage were compared against those taken during the 2009 outage. No maximum wall thickness measurements were identified for the examinations conducted in 2009. The minimum wall thickness values from the 2009 and 2013 outages were compared to the torus shell nominal wall thickness of 0.594 inches. There is presently no indication that the torus shell wall thickness of the torus bays has degraded such that they are less than the nominal wall thickness of 0.594 inches. Drvwell Surfaces Visual Inspection 2016 Outage (1 R27) Examination Description Interior and Exterior Surfaces (including personnel air lock and equipment hatches) of Drywell, as well as performing a general visual exam of the Mastic Seal, Interior and Exterior Surfaces of Drywell Head, Venting Assembly, Torus Interior, Torus Exterior and Support Inspection.
Examination Results Inspection findings were characterized as follows: Enclosure Page 64 of 81
- Exterior surface of the Torus -Areas of missing paint, flaking paint, unqualified coatings and delaminated coatings on torus shell. Areas of corrosion, rusting on torus shell.
- Interior surface of the Torus -Areas of corrosion on torus shell.
- Interior Surface of the Vent Pipe, Vent Header and Downcomers
-Areas of flaking paint, unqualified coatings and delaminated coatings.
- Interior surface of the Drywell -Areas of flaking paint, blistering and missing paint. Two 6 inch areas where the mastic has separated from the edge of the edge of the floor. None of the items identified were determined to need immediate repair. 2011 Outage (2R21) Examination Description Interior and Exterior Surfaces (including personnel air lock and equipment hatches) of Drywell, as well as performing a general visual exam of the Mastic Seal, Interior and Exterior Surfaces of Drywell Head, Venting Assembly, Torus Interior, Torus Exterior and Support Inspection.
Examination Results Inspection findings were characterized as follows:
- Mastic seal -Unknown chemical reacted with existing mastic seal causing it to become unstable.
Repair completed.4/23/2011.
Areas in which corrosion was noted were identified as areas to be monitored.
CRs as well as degraded coatings were logged and the respective were created to fix the condition.
3.6 License
Renewal Aging Management The renewed operating licenses for HNP Unit 1 and Unit 2 were issued on January 15, 2002, after NRC review of the license renewal applications submitted in February 2000. As such, the original licensed term of operation of 40 years was extended to 60 years, with the renewal term for HNP Unit 1 ending August 6, 2034, and for HNP Unit 2 on June 13, 2038.
Enclosure Page 65 of 81 As part of the process of obtaining renewed operating licenses, SNC was required to demonstrate that certain aging effects would be adequately managed for the term of the renewed operating licenses.
The process used to demonstrate adequate aging management to the NRC included the grouping of various aging management activities into 31 aging management programs.
The license renewal rule, 10 CFR 54, requires that a description of these aging management programs become part of the FSAR. As such, sections 18.2 through 18.6 are incorporated into the FSAR as approved by the NRC during the license renewal process. The program and activity descriptions in FSAR sections 18.2 through 18.6 represent the HNP Unit 1 and Unit 2 commitments for managing aging of the in-scope systems, structures, and components during the period of extended operation.
The following Programs, which are part of the supporting basis for this LAR, are also Aging Management Programs for HNP Unit 1 and Unit 2:
- Protective Coatings Program (PCP) The PCP provides a means of preventing or minimizing loss of material that would otherwise result from contact of the base material with a corrosive environment.
The PCP is a mitigation and condition monitoring program designed to provide base metal aging management through surface application, maintenance, and inspection of protective coatings on selected components and structures.
- Primary Containment Leakage Rate Testing Program (PCLRTP) The PCLRTP satisfies the requirements that primary containment meets the leakage-rate test requirements in either option A or B of 10 CFR 50, Appendix J. HNP has opted for option B which identifies the performance-based requirements and criteria for preoperational and subsequent periodic leakage-rate testing. This program is designed to ensure that (a) leakage through the primary containment or systems and components penetrating the primary containment does not exceed allowable leakage rates specified in the Technical Specifications and (b) integrity of the containment structure is maintained during its service life. The PCLRTP manages the aging effect of loss of material.
- lnservice Inspection Program (ISi) The ISi program is a condition monitoring program that provides for the implementation of ASME Section XI in accordance with the provisions of 10 CFR 50.55a. The ISi program also includes augmented examinations required to satisfy commitments made by SNC. The 10-year examination plan provides a systematic guide for performing required examinations.
The period of extended operation will include the fifth and sixth ISi intervals.
Only a portion of the ISi program is credited for license renewal. 3.7 NRC SER Limitations and Conditions Enclosure Page 66 of 81 3.7.1 Limitations and Conditions Applicable to NEI 94-01 Revision 2-A The NRC staff found that the use of NEI TR 94-01, Revision 2, was acceptable for referencing by licensees proposing to amend their TSs to permanently extend the ILRT surveillance interval to 15 years, provided the following conditions as listed in Table 3.7.1-1 were satisfied:
Table 3.7.1-1: NEI 94-01, Revision 2-A, Limitations and Conditions Limitation/Condition (From Section 4.0 of SE) HNP Resoonse For calculating the Type A leakage rate, the HNP will utilize the definition in NEI 94-01 licensee should use the definition in the NEI Revision 3-A, Section 5.0. This definition has TR 94-01, Revision 2, in lieu of that in remained unchanged from Revision 2-A to ANSl/ANS-56.8-2002. (Refer to SE Revision 3-A of NEI 94-01. Section 3.1.1.1.)
The licensee submits a schedule of Reference Tables 3.4.2-2 and 3.4.2-3 of this containment inspections to be performed submittal.
prior to and between Type A tests. (Refer to SE Section 3.1.1.3.)
The licensee addresses the areas of the Reference Sections 3.4.2 and 3.5 of this containment structure potentially subjected to submittal.
degradation. (Refer to SE Section 3.1.3.) The licensee addresses any tests and There are no major modifications planned. inspections performed following major modifications to the containment structure, as applicable. (Refer to SE Section 3.1.4.) The normal Type A test interval should be HNP will follow the requirements of NEI 94-01 less than 15 years. If a licensee has to utilize Revision 3-A, Section 9.1, This requirement the provision of Section 9.1 of NEI TR 94-01, has remained unchanged from Revision 2-A Revision 2, related to extending the ILRT to Revision 3-A of NEI 94-01. interval beyond 15 years, the licensee must demonstrate to the NRG staff that it is an In accordance with the requirements of 94-01 unforeseen emergent condition. (Refer to SE Revision 2-A, SER Section 3.1.1.2, HNP will Section 3.1.1.2.)
also demonstrate to the NRG staff that an unforeseen emergent condition exists in the event an extension beyond the 15-year interval is required.
Enclosure Page 67 of 81 Table 3.7.1-1: NEI 94-01, Revision 2-A, Limitations and Conditions Limitation/Condition (From Section 4.0 of SEl HNP Resoonse For plants licensed under 1 O CFR Part 52, Not applicable.
HNP was not licensed under applications requesting a permanent 1 O CFR Part 52. 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. 3.7.2 Limitations and Conditions Applicable to NEI 94-01 Revision 3-A The NRC staff found that the guidance in NEI TR 94-01, Revision 3, was acceptable for referencing by licensees in the implementation for the optional performance-based requirements of Option 8 to 10 CFR 50, Appendix J. However, the NRC staff identified two conditions on the use of NEI TR 94-01, Revision 3 (Reference NEI 94-01 Revision*
3-A, NRC SER 4.0, Limitations and Conditions):
Topical Report Condition 1 NEI TR 94-01, Revision 3, is requesting that the allowable extended interval for Type C LLRTs be increased to 75 months, with a permissible extension (for non-routine emergent conditions) of nine months (84 months total). The staff is allowing the extended interval for Type C LLRTs be increased to 75 months with the requirement that a licensee's post-outage report include the margin between the Type 8 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 Enclosure Page 68 of 81 Condition 1 presents three (3) separate issues that are required to be addressed.
They are as follows:
- ISSUE 1 -The allowance of an extended interval for Type C LLRTs of 75 months carries the requirement that a licensee's post-outage report include the margin between the Type B and Type C leakage rate summation and its regulatory limit.
- 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.
Response to Condition 1, ISSUE 1 The post-outage report shall include the margin between the Type B and Type C Minimum Pathway Leak Rate (MNPLR) summation value, as adjusted to include the estimate of applicable Type C leakage understatement, and its regulatory limit of 0.60 La. Response to Condition 1, ISSUE 2 When the potential leakage understatement adjusted Type Band C MNPLR total is greater than the HNP leakage summation limit of 0.50 La, but less than the regulatory limit of 0.6 La, then an analysis and determination of a corrective action plan shall be prepared to restore the leakage summation margin to less than the HNP 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 HNP will apply the 9-month grace 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 Enclosure Page 69 of 81 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 c.ontainment leakage potential, the as-found minimum pathway leakage rates for the just tested penetrations are summed with the as-left minimum pathway leakage rates for penetrations tested during the previous 1 or 2 or even 3 refueling outages. Type C tests involve valves, which in the aggregate, will show increasing leakage potential due to normal wear and tear, some predictable and some not so predictable.
Routine and appropriate maintenance may extend this increasing leakage potential.
Allowing for longer intervals between LLRTs means that more leakage rate test results from farther back in time are summed with fewer just tested penetrations and that total used to assess the current containment leakage potential.
This leads to the possibility that the LLRT totals calculated understate the actual leakage potential of the penetrations.
Given the required margin included with the performance criterion and the considerable extra margin most plants consistently show with their testing, any understatement of the LLRT total using a 5-year test frequency is thought to be conservatively accounted for. Extending the LLRT intervals beyond 5 years to a 75-month interval should be similarly conservative provided an estimate is made of the potential understatement and its acceptability determined as part of the trending specified in NEI 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 Type B and C total leakage, and must be included in a licensee's post-outage report. The report must include the reasoning and determination of the acceptability of the extension, demonstrating that the LLRT totals calculated represent the actual leakage potential of the penetrations.
Response to Condition 2 Condition 2 presents two (2) separate issues that are required to be addressed.
They are as follows:
- ISSUE 1 -Extending the LLRT intervals beyond 5 years to a 75-month interval should be similarly conservative provided an estimate is made of the potential understatement and its acceptability determined as part of the trending specified in NEI TR 94-01, Revision 3, Section 12.1.
- ISSUE 2 -When routinely scheduling any LLRT valve interval beyond 60-months and up to 75-months, the primary containment leakage rate testing program trending or monitoring must include an estimate of the amount of understatement in the Types B and C total, and must be included in a licensee's post-outage report. The report must include the reasoning and determination of the Enclosure Page 70 of 81 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, HNP 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 LLRT's being "carried forward" and will be included whenever the total leakage summation is required to be updated (either while on line or following an outage). When the potential leakage understatement adjusted leak rate total for those Type C components being tested on greater than a 60-month test interval up to the 75-month extended test interval is summed with the non-adjusted total of those Type C components being tested at less than or equal to a 60-month test interval, and the total of the Type B tested components, if the MNPLR is greater than the leakage summation limit of 0.50 La, but less than the regulatory limit of 0.6 La, then an analysis and corrective action plan shall be prepared to restore the leakage summation value to less than the HNP 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. Response to Condition 2, ISSUE 2 If the potential leakage understatement adjusted leak rate MNPLR is less than the HNP leakage summation limit of 0.50 La, then the acceptability of the greater than a 60-month test interval up to the 75-month LLRT extension for all affected Type C components has been adequately demonstrated and the calculated local leak rate total represents the actual leakage potential of the penetrations.
In addition to Condition 1, ISSUES 1 and 2, which deal with the MNPLR Type 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 ANSl/ANS-56.8-2002 and shall be available on-site for NRC review. The report shall show that the Enclosure Page 71 of 81 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 HNP, in the event an adverse trend in the aforementioned potential leakage understatement adjusted Type Band 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 HNP an adverse trend is defined as three (3) consecutive increases in the final RCS Mode Change Type Band C MNPLR leakage summation values, as adjusted to include the estimate of applicable Type C leakage understatement, as expressed in terms of La. 3.8 Conclusion NEI 94-01, Revision 3-A, dated July 2012, and the conditions and limitations specified in NEI 94-01, Revision 2-A, dated October 2008, describe an NRG-accepted approach for implementing the performance-based requirements of 10 CFR 50, Appendix J, Option B. It incorporates the regulatory positions stated in RG 1.163 and includes provisions for extending Type A intervals to 15 years and Type C test intervals to 75 months. NEI 94-01, Revision 3-A delineates a performance-based approach for determining Type A, Type B, and Type C containment leakage rate surveillance test frequencies.
HNP is adopting the guidance of NEI 94-01, Revision 3-A, and the conditions and limitations specified in NEI 94-01, Revision 2-A, for the HNP, Units 1 and 2, 10 CFR 50, Appendix J testing program plan. Based on the previous ILRTs conducted at HNP, 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 and the overlapping inspection activities performed as part of the following HNP, Units 1 and 2 inspection programs:
- Containment Inspection Program (Class MC/IWE)
- Containment Inspections per TS SR 3.6.1 .1.1
- Protective Coatings Program Enclosure Page 72 of 81 This experience is supplemented by risk analysis studies, including the HNP, Units 1 and 2 risk analysis provided in Attachment
- 3. The risk assessment concluded that increasing the ILRT interval to 15 years is considered to represent an insignificant change in risk for HNP.
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(0) 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, 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 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) indicates that, in general, the risk impact associated with ILRT interval extensions for intervals up to 15 years is small. However, plant-specific confirmatory analyses are required.
The NRC staff reviewed NEI TR 94-01, Revision 2, and EPRI Report No. 1009325, Revision 2. For NEI TR 94-01, Revision 2, the NRC staff determined that it described an acceptable approach for implementing the optional performance-based requirements Enclosure Page 73 of 81 of Option B to 1 O CFR 50, Appendix J. This guidance includes provisions for extending Type A ILRT intervals to up to 15 years and incorporates the regulatory positions stated in RG 1.163. The NRC staff finds that the Type A testing methodology as described in ANSl/ANS-56.8-2002, and the modified testing frequencies recommended by NEI TR 94-01, Revision 2, serves 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 Band Type C leakage rates support the leakage tightness of primary containment by minimizing potential leakage paths. For EPRI Report No. 1009325, Revision 2, a risk-informed methodology using specific risk insights and industry ILRT performance data to revise ILRT surveillance frequencies, the NRC staff finds that the proposed methodology satisfies the key principles of risk-informed decision making applied to changes to TSs as delineated in RG 1.177 and RG 1.174. The NRC staff, therefore, found that this guidance was acceptable for referencing by licensees proposing to amend their TS in regards to containment leakage rate testing, subject to the limitations and conditions noted in Section 4.2 of the Safety Evaluation Report (SER). The NRC staff reviewed NEI TR 94-01, Revision 3, and determined that it described an acceptable approach for implementing the optional performance-based requirements of Option B to 10 CFR 50, Appendix J, as modified by the conditions and limitations summarized in Section 4.0 of the associated Safety Evaluation.
This guidance included provisions for extending Type C LLRT intervals up to 75 months. Type C testing ensures that individual containment isolation valves are essentially leak tight. In addition, aggregate Type C leakage rates support the leakage tightness of primary containment by minimizing potential leakage paths. The NRC staff, therefore, found that this guidance, as modified to include two limitations and conditions, was acceptable for referencing by licensees proposing to amend their TS in regards to containment leakage rate testing. Any applicant may reference NEI TR 94-01, Revision 3, as modified by the associated SER and approved by the NRC, and the conditions and limitations 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)
Enclosure Page 74 of 81
- Comanche Peak Nuclear Power Plant, Units 1 and 2 (Reference
- 36) 4.3 No Significant Hazards Consideration Southern Nuclear Operating Company (SNC) has evaluated whether or not a significant hazards consideration is involved with the proposed amendment by focusing on the .three standards set forth in 10 CFR 50.92, "Issuance of amendment," as discussed below: 1. Does the proposed amendment involve a significant increase in the probability or consequences of an accident previously evaluated?
Response:
No. The proposed amendment to the Technical Specifications (TS) involves the extension of the Edwin I. Hatch Nuclear Plant (HNP), 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 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 current Type C test interval of 60 months for selected components would be extended on a performance basis to no longer than 75 months. Extensions of up to nine months (total maximum interval of 84 months for Type C tests) are permissible only for non-routine emergent conditions.
The proposed 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 Type A test frequency from three in ten years to one in fifteen years, measured as an increase in the total integrated plant dose risk for those accident sequences influenced by Type A testing, is 9.90E-03 person-rem/yr using the Electric Power Research Institute (EPRI) guidance values, and drops to 1.96E-03 person-rem/yr using the EPRI Expert Elicitation values. Therefore, this proposed extension does not involve a significant increase in the probability of an accident previously evaluated.
In addition, as documented in NUREG-1493, "Performance-Based Containment Leak-Test Program," Types Band 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 HNP, Units 1 and 2 Type A test history supports this conclusion.
Enclosure Page 75 of 81 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 leakage rate test (LLRT) requirements and administrative controls such as configuration management and procedural requirements for system restoration ensure that containment integrity is not degraded by plant modifications or maintenance activities.
The design and construction requirements of the containment 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 extensions do not significantly increase the consequences of an accident previously evaluated.
The proposed amendment also deletes exceptions previously granted to allow time extensions of the ILRT test frequency for both Units 1 and 2. These exceptions were for activities that have already taken place; therefore, their deletion is solely an administrative action that has no effect on any component and no physical impact on how the units are operated.
Therefore, the proposed change does not result in a significant increase in the probability or consequences of an accident previously evaluated.
- 2. Does the proposed change create the possibility of a new or different kind of accident from any accident previously evaluated?
Response:
No. The proposed amendment to the TS involves the extension of the HNP, Unit 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 change to the plant (i.e., no new or different type of equipment will be installed) nor does it alter the design, configuration, or change the manner in which the plant is operated or controlled beyond the standard functional capabilities of the equipment.
The proposed amendment also deletes exceptions previously granted to allow time extensions of the ILRT test frequency for both Units 1 and 2. These exceptions were for activities that would have already taken place by the time this amendment is approved; therefore, their deletion is solely an administrative action that does not result in any change in how the units are operated.
Enclosure Page 76 of 81 Therefore, the proposed change does not create the possibility of a new or different kind of accident from any 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 HNP, 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 only the extension of the interval between Type A containment leak rate tests and Type C tests for HNP, 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, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J," Revision 3-A. Industry experience supports the conclusion that Type 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 XI, 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 Type A, 8, 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 both HNP Units 1 and 2. These exceptions were for activities that have taken place; therefore, their deletion is solely an administrative action and does not change how the units are 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.
Enclosure Page 77 of 81 Based on the above, SNC concludes that the proposed amendment does not involve a significant hazards consideration under the standards set forth in 10 CFR 50.92(c), and, accordingly, a finding of no significant hazards consideration is justified.
4.4 Conclusion
In conclusion, based on the considerations discussed above, (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) such activities will be conducted in compliance with the Commission's regulations, and (3) the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public. 5.0 ENVIRONMENTAL CONSIDERATION A review has determined that the proposed amendment would change a requirement with respect to installation or use of a facility component located within the restricted area, as defined in 10 CFR 20, or would change an inspection or surveillance requirement.
However, the proposed amendment does not involve (i) a significant hazards consideration, (ii) a significant change in the types or significant increase in the amounts of any effluent that may be released offsite, or (iii) a significant increase in individual or cumulative occupational radiation exposure.
Accordingly, the proposed amendment meets the eligibility criterion for categorical exclusion set forth in 10 CFR 51.22(c)(9).
Therefore, pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the proposed amendment.
6.0 REFERENCES
- 1. Regulatory Guide 1.163, Performance-Based Containment Leak-Test Program, September 1995 2. NEI 94-01, Revision 3-A, Industry Guideline for Implementing Based Option of 10 CFR 50, Appendix J, 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, 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, March 2009 Enclosure Page 78 of 81 5. NEI 94-01, Revision 0, Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J, July 1995 6. NUREG-1493, Performance-Based Containment Leak-Test Program, January 1995 7. EPRI TR-104285, Risk Impact Assessment of Revised Containment Leak Rate Testing Intervals, August 1994 8. NEI 94-01, Revision 2-A, Industry Guideline for Implementing Based Option of 10 CFR 50, Appendix J, October 2008 9. Letter from M. J. Maxin (NRC) to J. C. Butler (NEI), dated June 25, 2008, 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) 10. Letter from S. Bahadur (NRC) to B. Bradley (NEI), dated June 8, 2012, Final Safety Evaluation of Nuclear Energy Institute (NEI) Report 94-01, Revision 3, Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, AppendixJ (TAC No. ME2164) 11. Boiling Water Reactors Owners' Group, BWROG PSA Peer Review Certification Implementation Guidelines, Revision 3, January 1997 12. Draft Regulatory Guide DG-1122, An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities, November 2002 13. Letter from S. Bloom (NRC) to H. Sumner (SNC), dated September 23, 2003, Edwin I. Hatch Nuclear Plant, Unit 1 and 2 -Issuance of Amendments Regarding Appendix K Measurement Uncertainty Recovery, (ML032590944)
- 14. Letter from L. Olshan (NRC) to H. Sumner (SNC), dated February 20, 2002, Edwin I. Hatch Nuclear Plant, Unit 1-Issuance of Amendment Re: Amendment Revises TS 5.5.12 to Allow a One-Time Deferral of the Type A Containment Integrated Leak Rate Test Based on the Risk-Informed Guidance in Regulatory Guide 1.174. (TAC No. MB2842) 15. Letter from C. Gratton (NRC) to H. Sumner (SNC), dated February 1, 2005, Edwin I. Hatch Nuclear Plant, Unit 2 Re: Issuance of Amendment Revising the Enclosure Page 79 of 81 Technical Specifications for the Primary Containment Leakage Rate Testing Program (TAC No. MC2761) 16. Letter from C. Gratton (NRG) to H. Sumner (SNC), dated May 28, 2004, Edwin I. Hatch Nuclear Plant, Units 1 and 2 Re: Issuance of Amendments Revising the Technical Specifications for the Primary Containment Leakage Rate Testing Program (TAC Nos. MC1432 and MC1433) 17. Letter from R. Martin (NRG) to D. Madison (SNC), dated August 28, 2008, Edwin I. Hatch Nuclear Plant, Unit NOS. 1 AND 2, Issuance of Amendments Regarding Alternate Source Term (TAC Nos. MD2934 and MD2935) 18. Letter from R. Ennis (NRG) to M. Pacilio (Exelon), dated August 25, 2014, Peach Bottom Atomic Power Station, Units 1 and 2 -Issuance of Amendments Re: Extended Power Uprate (TAC Nos. ME9631 and ME9632) 19. Letter from K. Jabbour (NRG) to J. Beckham Jr. (Georgia Power), dated March 6, 1996, Edwin I. Hatch Nuclear Plant, Units 1 and 2 -Issuance of Amendment Regarding the Adoption of the Requirements of 10 CFR 50, Appendix J, Option B, and the Implementation of a Performance-based Containment Leak-rate Testing Program. (TAC NOS. M94046 and M94047) 20. Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals:
Revision 2-A of 1009325. EPRI, Palo Alto, CA: October 2008. 1018243 21. Hatch Unit 1 Peer Review Report (2009), February 2010 22. Regulatory Guide 1.147, Revision 16, lnservice Inspection Code Case Acceptability, ASME Section XI, Division 1, October 2010 23. NUREG-1769, Safety Evaluation Report Related to the License Renewal of Peach Bottom Atomic Power Station, Units 1 and 2, March 2003 24. ML 14148A235, Letter to D. Heacock from S. Williams (NRG) dated July 3, 2014. Surry Power Station, Units 1 And 2 -Issuance of Amendment Regarding the Containment Type A and Type C Leak Rate Tests 25. ML15072A264, Letter to L. Weber from A. Dietrich (NRG) dated March 30, 2015. Donald C. Cook Nuclear Plant, Units 1 and 2 -Issuance of Amendments Re: Containment Leakage Rate Testing Program 26. ML15078A058, Letter to E. Larson from T. Lamb (NRG) dated April 8, 2015. Beaver Valley Power Station, Unit Nos. 1 And 2 -Issuance of Amendment Re: License Amendment Request to Extend Containment Leakage Rate Test Frequency Enclosure Page 80 of 81 27. ML 15154A661, Letter to G. Gellrich from A. Chereskin (NRG) dated July 16, 2015. Calvert Cliffs Nuclear Power Plant, Unit Nos. 1 and 2 -Issuance of Amendments Re: Extension of Containment Leakage Rate Testing Frequency
- 28. ML 15196A559, Letter to B. Hanson from R. Ennis (NRG) dated September 8, 2015. 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) 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, March 2009 31. Letter from A. Pietrangelo (NEI) to NEI Administrative Points of Contact, Time Extension of Containment Integrated Leak Rate Test Interval -Additional Information, November 30, 2001 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, Accession Number ML020920100, March 27, 2002 33. Letter from A. Pietrangelo (NEI) to NEI Administrative Points of Contact, Interim Guidance for Performing Risk Impact Assessments in Support of One-Time Extensions for Containment Integrated Leak Rate Test Surveillance Intervals, November 13, 2001 34. ML11347A198, Edwin I. Hatch Nuclear Plant -Unit 2, Licensee Event report 2011-001-01, Revision 1, Primary Containment Isolation Penetration Exceeded Overall Allowable Technical Specification Leakage Limits, December 9, 2011 35. ML 15352A294, Letter from M. Marley (NRG) to C. Pierce (SNC), Relief from the Requirements of the ASME Code (CAC Nos. MF6494 and MF6495), December 28,2015 36. ML 15309A073, Letter to R. Flores (Luminant) from B. Singal (NRG) dated December 30, 2015. 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)
Enclosure Page 81 of 81 37. Letter from A. Pietrangelo (NEI) to NEI Administrative Points of Contact, Time Extension of Containment Integrated Leak Rate Test Interval -Additional Information, November 30, 2001.
ATTACHMENT 1 Markup of Technical Specification Pages 5.0-16 TS 5.5.12 Programs and Manuals 5.5 5.5 P r ograms and Manuals (continued) 5.5.12 Primarv Containment Lea k age Rate Testing Program A prog r am shall be established to imp l ement the leakage rate testing of the primary containment as required by 10 CFR 50.54(0) 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 Test Program ," dated September 1996, as modified by the following exception to NEI 94 01, Rev. 0 , "Industry Guideline for I mp l ementing Performance Based Option of 10 CFR 60 , Appendix J": Section 9.2.3: The first Type A test after the April 1993 Type A test shall be performed no later than April 2008. The peak calculated primary containment internal pressure for the design basis loss of coolant accident, Pa. is 50.8 psig. The maximum allowable primary containment leakage rate , La. at Pa is 1.2% of primary containment air weight per day. Leakage rate acceptance criteria are: a. Primary containment overall leakage rate acceptance criterion is s 1.0 La. During the first unit startup following testing in accordance with this program, the leakage rate acceptance criteria are s 0.60 La for the combined Type Band Type C tests , and s 0.75 La for Type A tests; b. Air lock testing acceptance criteria are: 1) Overall air lock leakage rate is s 0.05 La when tested Pa. 2) For each door, leakage rate is s 0.01 La when the gap between the door seals is pressurized to 10 psig for at least 15 minutes. The provisions of SR 3.0.2 do not apply to the test frequencies specified in the Primary Containment Leakage Rate Testing Program. NEI 94-01 , "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 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." (continued)
HATCH UNIT 1 5.0-16 Amendment No. 244 Programs and Manuals 5.5 5.5 Programs and Manuals (continued) 5.5.12 Primary Containment Leakage Rate Testing Program A program shall be established to implement the leakage rate testing of the primary containment as required by 10 CFR 50.54(0) 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 , " Perfermanoe Based Containment Leak Test Program ," dated September 1995 , as modified by the following exeeption to NEI 94 01 , Rev. 0 , " Industry Guideline for Implementing Perfermanoe Based Option of 10 CFR 50 , Appendix J": Seetion 9.2.3: The first Type A test after the November 2 , 1995 , Type A test shall be performed no later than November 2010. The peak calculated primary containment internal pressure for the design basis loss of coolant accident , Pa. is 47.3 psig. The maximum allowable primary containment leakage rate, La. at Pa is 1.2% of primary containment air weight per day. Leakage rate acceptance criteria are: a. Primary containment overall leakage rate acceptance criterion is s 1.0 La. During the first unit startup following testing in accordance with this program, the leakage rate acceptance criteria are s 0.60 La for the combined Type Band Type C tests, and s 0.75 L a for Type A tests; b. Air lock testing acceptance criteria are: 1) Overall air lock leakage rate is s 0.05 La when tested at s Pa. 2) For each door, leakage rate is s 0.01 La when the gap between the door seals is pressurized 10 psig for at least 15 minutes. The provisions of SR 3.0.2 do not apply to the test frequencies specified in the Primary Conta i nment Leakage Rate Testing Program. NEI 94-01, "Industry Guideline for Implementing Based Option of 10 CFR Part 50, Appendix J," Revision 3-A , dated July 2012, and the conditions and limitations specified iri NEI 94-01, Revision 2-A , dated October 2008." (continued}
HATCH UNIT2 5.0-16 Amendment No. 487 ATTACHMENT 2 Markup of Technical Specification Bases Pages B 3.6-4, B 3.6-5 (Unit 1) B 3.6-3 thru B 3.6-5 (Unit 2) B 3.6.1.1.1.
For Information Only BASES (continued)
ACTIONS SURVEILLANCE REQUIREMENTS NEI 94-01 Revision 3-A (Ref. 7), the Limitations and Conditions of NEI 94-01 Revision 2-A (Ref.6), and ANSI/ ANS 56.8-2002 HATCH UNIT 1 Primary Containment B 3.6.1.1 In the event primary containment is inoperable, primary containment must be restored to OPERABLE status within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Completion Time provides a period of time to correct the problem commensurate with the importance of maintaining primary containment OPERABILITY during MODES 1 , 2, and 3. This time period also ensures that the probability of an accident (requiring primary containment OPERABILITY) occurring during periods where primary containment is inoperable is minimal. 8.1 and 8.2 If primary containment cannot be restored to OPERABLE status w i thin the required Completion Time , the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and to MODE 4 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The allowed Completion Times are reasonable , based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. SR 3.6.1.1.1 Maintaining the primary containment OPERABLE requires compliance with the visual examinations and leakage rate test requirements of the Primary Containment Leakage Rate Testing Program. Failure to meet air lock leakage testing (SR 3.6.1.2.1 ), or main steam isolation valve leakage (SR 3.6.1.3.10), does not necessarily result in a failure of this SR. The impact of the failure to meet these SRs must be evaluated against the Type A , B, and C acceptance criteria of the Primary Containment Leakage Rate Testing Program. The Primary Containment Leakage Rate Testing Program is based on the guidelines in Regulatory Guide 1.168 (Ref. 6), NEI 94 01 (Ref. 7), and ANSI/ANS §6.8 1994 (Ref. 8). Specific acceptance criteria for as found and as left leakage rates , as well as the methods of defining the leakage rates, are contained in the Primary Containment Leakage Rate Testing Program. At all other times between required leakage rate tests, the acceptance criteria are based on an overall Type A leakage limit of 1.0 La. At 1.0 La. the offsite dose consequences are bounded by the a ssumptions of t he safety analysis.
The Frequency is required by the Primary Containment Leak Rate Testing Program. (continued)
B 3.6-3 REVISION§ BASES SURVEILLANCE REQUIREMENTS (continued}
REFERENCES Primary Containment B3.6.1.1 SR 3.6.1.1.2 Maintaining the pressure suppression function of primary containment requires limiting the leakage from the drywell to the suppression chamber. Thus, if an event were to occur that pressurized the drywell, the steam would be directed through the downcomers into the suppression pool. This SR measures drywell to suppression chamber differential pressure during a 10 minute period to ensure that the leakage paths that would bypass the suppression pool are within allowable limits. Satisfactory performance of this SR can be achieved by establishing a known differential pressure between the drywall and the suppression chamber and verifying that the pressure in either the suppression chamber or the drywell does not change by more than 0.25 inch of water per minute over a 10 minute period. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. 1. 2. 3. 4. 5. 6. ) 7. FSAR, Section 5.2. FSAR , Section 14.4.3. 10 CFR 50 , Appendix J , Option B. NRC No.93-102 , "Final Policy Statement on Technical Specification Improvements
," July 23 , 1993. Primary Containment Leakage Rate Testing Program. Regulatory Guide 1.163 , " Perf-Ormanee Ba s ed Conta i nment Leak Test Program ," September 1995. NEI 94-01 , *industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J ," Revision 9,-JtlJy 26 , 1995. 3-A , July 2012 NEI 94-0 1, " Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50 , Appendix J ," Revision 2-A , October 2008. (continued)
HATCH UNIT 1 B 3.6-4 REVISION 69 BASES Primary Containment B 3.6.
1.1 REFERENCES
(continued)
HATCH UNIT 1 8. ANSI/ANS 56.8 1994 , " American National Standard for Containment System t akage Testing Requirements," 1994. Ame r ican Nuclear Society , " Conta i nmen t System Leakage Test ing Requ i rements ," ANSI/ANS 56.8-2002. B 3.6-5 REVISION 69 BASES (cont i nued) ACTIONS SURVEILLANCE REQUIREMENTS Primary Conta i nment B 3.6.1.1 In the event primary containment is inoperable , p r imary conta i nment must be restored to OPERABLE status wi t hin 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Completion Time provides a period of time to correct the problem commensurate with the importance of maintaining primary containment OPERABILITY during MODES 1 , 2 , and 3. This time period also ensures that the probabi l ity of an accident (requiring primary containment OPERABILITY) occurring during periods where primary containment is inoperable is minima l. B.1 and B.2 If primary containment cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To ach i eve this status , the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and to MODE 4 with i n 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The allowed Comp l etion Times are reasonab l e , based on operating experience , to reach the required plant conditions from full power cond i tions in an orderly manner and without challenging plant systems. SR 3.6.1.1.1 Mainta i ning the primary containment OPERABLE requires compliance with the visual examinations and l eakage rate test requirements of the Primary Containment Leakage Rate Testing Program. Failu r e to meet air lock leakage test i ng (SR 3.6.1.2.1 ), secondary containment bypass leakage (SR 3.6.1.3.10), or main steam isolation valve leakage (SR 3.6.1.3.11) does not necessarily result in a failure of this SR. The impact of the failure to meet these SRs must be evaluated against the Type A , B , and C acceptance c r iteria of the Primary Conta in ment Leakage Rate Testing Program. The Primary Containment Leakage Rate Testing Program is based on the guidelines in Regulatory Gu i ao 1.163 (Ref. 6), NEI 94 01 (Ref. 7), ane 56.8 1994 (Ref. 8). Specific acceptance criteria for as found and as left leakage rates , as well as the methods of defining t h e leakage rates , are contained in the Primary Containment Leakage Rate Testing Program. At all other times between requi r ed leakage rate te s ts , the acceptance criteria are based on an overall Type A leakage l imit of 1.0 L a. At 1.0 L a. the o ff site dose consequences are bounded by the assumptions of the safety analysis. The Frequency is required by the Primary Containment Leakage Rate Tes ti ng Program. NEI 94-01 Revision 3-A (Ref. 7), the Limitations and Conditions of NEI 94-01 Revision 2-A (Ref.6), and ANSI/ _ANS 56.8-2002 HATCH UNIT 2 (continued) B 3.6-3 REVISION 7-BASES SURVEILLANCE REQUIREMENTS (continued)
REFERENCES SR 3.6.1.1.2 Primary Containment B 3.6.1.1 Maintaining the pressure suppression function of primary containment requires limiting the leakage from the drywall to the suppression chamber. Thus, if an event were to occur that pressurized the drywell, the steam would be directed through the downcomers into the suppression poo l. This SR measures drywell to suppression chamber differential pressure during a 10 minute period to ensure that the leakage paths that would bypass the suppression pool are within allowab l e limits. Satisfactory performance of this SR can be achieved by establishing a known differential pressure between the drywall and the suppression chamber and verifying that the pressure in either the suppression chamber or the drywell does not change by more than 0.25 inch of water per minute over a 10 minute period. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. 1. FSAR, Section 6.2. 2. FSAR, Section 15.1.39. 3. 10 CFR 50 , Appendix J , Option 8. 4. NRC No.93-102 , "Final Policy Statement on Technica l Specification Improvements
," July 23 , 1993. 5. Primary Containment Leakage Rate Testing Program. _____ 6_')_ -Regulatory Guide 1.16a , " Performance Based Containment Leak Test Program ," September 1996. 7. NEI 94-01, "Industry Guide l ine for Implementing Perfonnance-Based Option of 10 CFR Part 50 , Appendix J," Revision G,Jt:ffy26 , 1995. ...,....,3-
-A-, -Ju-ly_2_0-12-NEI 94-01, "Industry Guideline for Implementing Based Option of 10 CFR Part 50, Appendix J ," Revision 2-A, October 2008. (continued)
HATCH UNIT2 B 3.6-4 REVISION 7Q BASES REFE:RENCES (cont i nued} HATCH UNIT2 8. Primary Containment B 3.6.1.1 ANSl!ANS 66.8 1994 , " American Nationa l Standard for Con t ainment System Leakage Testing Requirements
," 1994. I\ American Nuclear Soc i ety , " Conta i nment System L eakage Testing Requ i rements ," ANSI/ANS 56.8-2002. B 3.6-5 REVISION 71iJ ATTACHMENT 3 Plant Hatch Units 1 & 2 Risk Assessment to Support ILRT (Type A) Interval Extension Request Plant Hatch Units 1 & 2 Risk Assessment to Support ILRT (Type A) Interval Extension Request TABLE OF CONTENTS Section Page 1.0 PURPOSE OF ANALYSIS .................................................................................
1-1 1.1 PURPOSE ..........................................................................................
1-1
1.2 BACKGROUND
...................................................................................
1-1 1.3 ACCEPTANCE CRITERIA .......................................................................
1-3 2.0 METHODOLOGY
............................................................................................
2-1 3.0 GROUND RULES ...........................................................................................
3-1 4.0 INPUTS .......................................................................................................
4-1 4.1 GENERAL RESOURCES AVAILABLE
.......................................................
.4-1 4.2 PLANT-SPECIFIC INPUTS .....................................................................
4-6 4.3 IMPACT OF EXTENSION ON DETECTION OF COMPONENT FAILURES THAT LEAD TO LEAKAGE (SMALL AND LARGE) ..............................................
4-17 4.4 IMPACT OF EXTENSION ON DETECTION OF STEEL CORROSION THAT LEADS TO LEAKAGE ....................................................................................
4-19 5.0 RESULTS .....................................................................................................
5-1 5.1 STEP 1 -QUANTIFY THE BASE-LINE RISK IN TERMS OF FREQUENCY PER REACTOR YEAR ..................................................................................
5-3 5.2 STEP 2 -DEVELOP PLANT-SPECIFIC PERSON-REM DOSE (POPULATION DOSE) PER REACTOR YEAR ..................................................................
5-9 5.3 STEP 3 -EVALUATE RISK IMPACT OF EXTENDING TYPE A TEST INTERVAL FROM 10-T0-15 YEARS ....................................................................
5-12 5.4 STEP 4 -DETERMINE THE CHANGE IN RISK IN TERMS OF LARGE EARLY RELEASE FREQUENCY
.......................................................................
5-16 5.5 STEP 5 -DETERMINE THE IMPACT ON THE CONDITIONAL CONTAINMENT FAILURE PROBABILITY
......................................................................
5-17 5.6 STEP 6 -DETERMINE THE IMPACT ON THE POPULATION DOSE RISK ...... 5-18 5.7
SUMMARY
OF INTERNAL EVENTS RESULTS ..........................................
5-18 5.8 EXTERNAL EVENTS CONTRIBUTION
....................................................
5-20 6.0 SENSITIVITIES
............................................................................................
6-1 6.1 SENSITIVITY TO CORROSION IMPACT ASSUMPTIONS
.............................
6-1 6.2 EPRI EXPERT ELICITATION SENSITIVITY
...............................................
6-3 6.3 NON-EARLY RELEASE SENSITIVITY
.......................................................
6-6 6.4 ILRT EXTENSION RISK BENEFIT ...........................................................
6-8
7.0 CONCLUSION
S
.............................................................................................
7-1
8.0 REFERENCES
...............................................................................................
8-1 APPENDIX A NUREG/CR-4551 PEACH BOTTOM POPULATION ESTIMATE .......................
A-1
1.0 PURPOSE
OF ANALYSIS 1.1 PURPOSE The purpose of this analysis is to provide an assessment of the risk associated with extending , the currently allowed containment Type A integrated leak rate test (ILRT) interval to a permanent fifteen yearsC 1 l for Hatch Units 1 & 2. The extension would allow for substantial cost savings as the ILRT could be deferred for additional scheduled refueling outages. The risk assessment follows the guidelines from NEI 94-01 [1], the methodology used in EPRI TR-104285 [2], the NE! "Interim Guidance for Performing Risk Impact Assessments In Support of One-Time Extensions for Containment Integrated Leakage Rate Test Surveillance Intervals" [3, 21], the NRC regulatory guidance on the use of Probabilistic Risk Assessment (PRA) as stated in Regulatory Guide 1.200 [28] as applied to ILRT interval extensions, and risk insights in support of a request for a plant's licensing basis as outlined in Regulatory Guide (RG) 1.174 [4], the methodology used for Calvert Cliffs to estimate the likelihood and risk implications of corrosion-induced leakage of steel liners going undetected during the extended test interval [19], and the methodology used in EPRI TR-1009325, Revision 2-A [22] for performing a risk impact assessment of extended integrated leak rate testing intervals.
The EPRI TR-1009325 Revision 2-A methodology incorporates the specific limitations and conditions outlined in the NRC acceptance of the EPRI TR-1009325 Revision 2 methodology documented in the NRC Final Safety Evaluation
[32]. The format of this document is consistent with the intent of the Risk Impact Assessment Template for evaluating extended integrated leak rate testing intervals provided in Appendix H of the EPRI methodology report [22].
1.2 BACKGROUND
Revisions to lOCFRSO, Appendix J (Option B) allow individual plants to extend the Integrated Leak Rate Test (ILRT) Type A surveillance testing frequency requirements from three-in-ten years to at least once in ten years. The revised Type A frequency is based on an acceptable performance history defined as two consecutive periodic Type A tests at least 24 months apart in which the calculated performance leakage was less than limiting containment leakage rate of 1.0La (allowable leakage).
Cll The ILRT risk assessment is to be used to support a request to a 1 in 15 year ILRT test frequency on a permanent basis. The risk assessment methodology and results equally support a request to extend the ILRT test frequency to 1 in 15 years on a one time basis, as has been performed by many utilities.
1-1 The basis for a 10-year test interval is provided in Section 11.0 of NEI 94-01, Revision O, and was established in 1995 during development of the performance-based Option B to Appendix J. Section 11.0 of NEI 94-01 states that NUREG-1493
[5], "Performance-Based Containment Leak Test Program," September 1995, provides the technical basis to support rulemaking to revise leakage rate testing requirements contained in Option B to Appendix J. The basis consisted of qualitative and quantitative assessments of the risk impact (in terms of increased public dose) associated with a range of extended leakage rate test intervals.
To supplement the NRC's rulemaking basis, NEI undertook a similar study. The results of that study are documented in Electric Power Research Institute (EPRI) Research Project Report TR-104285
[2]. The NRC report on performance-based leak testing, NUREG-1493, analyzed the effects of containment leakage on the health and safety of the public and the benefits realized from the containment leak rate testing. In that analysis, it was determined that for a representative PWR plant (i.e., Surry) containment isolation failures contribute less than 0.1 percent to the latent risks from reactor accidents.
Consequently, it is desirable to show that extending the ILRT interval will not lead to a substantial increase in risk from containment isolation failures for the Hatch plants. Earlier ILRT frequency extension submittals have used the EPRI TR-104285
[2] methodology to perform the risk assessment.
In October 2008, EPRI TR-1018243
[22] was issued to update the generic methodology for ILRT extensions to 15 years using current performance data and to incorporate the specific limitations and conditions outlined by the NRC in the final safety evaluation of the methodology
[32]. This more recent EPRI document considers additional risk metric? an_d criteria including 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 population dose. Hatch requested a one-time extension of the ILRT test frequency from 1 in 10 years to 1 in 15 years for Unit 1 [23] and Unit 2 [24]. The NRC approved the one-time extensions for both Unit 1 [33] and Unit 2 [34]. It should be noted that containment leak-tight integrity is also verified through periodic inservice inspections conducted in accordance with the requirements of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code Section XI. More specifically, 1-2 Subsection IWE provides the rules and requirements for inservice inspection of Class MC pressure-retaining components and their integral attachments, and of metallic shell and penetration liners of Class CC pressure-retaining components and their integral attachments in light-water cooled plants. Furthermore, NRC regulations 10 CFR 50.55a(b)(2)(ix)(E) require licensees to conduct visual inspections of the accessible areas of the interior of the containment.
In addition, Appendix J, Type B local leak tests performed to verify the leak-tight integrity of containment penetration bellows, airlocks, seals, and gaskets are also not affected by the change to the Type A test frequency.
1.3 ACCEPTANCE
CRITERIA The acceptance guidelines in RG 1.174 -are used to assess the acceptability of this permanent extension of the Type A test interval beyond that established during the Option B rulemaking of Appendix J. RG 1.174 defines very small changes in the risk-acceptance guidelines as increases in core damage frequency (CDF) less than 10-6 per reactor year and increases in large early release frequency (LERF) less than 10-7 per reactor year. Because the Type A test does not impact CDF for Hatch, the relevant criterion is the change in LERF. RG 1.174 also defines small changes in LERF as below 10-6 per reactor year provided that the total from all contributors (including external events) can be reasonably shown to be less than 10-5 per reactor year. RG 1.174 discusses defense-in-depth and encourages the use of risk analysis techniques to help ensure and show that key principles, such as the defense-in-depth philosophy, are met. Therefore, the increase in the conditional containment failure probability (CCFP) that helps to ensure that the defense-in-depth philosophy is maintained is also calculated.
Regarding CCFP, changes of up to 1.1% have been accepted by the NRC for the one-time requests for extension of ILRT intervals.
In context, it is noted that a CCFP of 1/10 (10%) has been approved for application to evolutionary light water designs. Given these perspectives, a change in the CCFP of up to 1.5% (percentage point) is assumed to be small. This criterion is articulated in the NRC Final Safety Evaluation Report [32] associated with NEI 94-01 and the EPRI ILRT methodology.
1-3 In addition, the total annual risk (person rem/yr population dose) is examined to demonstrate both the relative change and absolute change in this parameter.
Examinations of NUREG-1493 and Safety Evaluation Reports (SER) for one-time interval extensions (summarized in Appendix G of EPRI 1018243 [22]) indicate a range of incremental increases in population dose that have been accepted by the NRcC 1>. The range of incremental population dose increases is from <= 0.01 to 0.2 person-rem/yr and/or 0.002 to 0.46% of the total accident dose. The total doses for the spectrum of all accidents (NUREG-1493
[5], Figure 7-2) result in health effects that are at least two orders of magnitude less than the NRC Safety Goal risk. Given these perspectives, a very small population dose is defined as an increase from the baseline interval (3 tests per 10 years) dose of <= 1.0 person-rem/yr or 1 % of the total baseline dose, whichever is less restrictive for the risk impact assessment of the proposed extended ILRT interval.
This criterion is articulated in the NRC Final Safety Evaluation Report [32] associated with NEI 94-01 and the EPRI ILRT methodology.
Cl) The methodology used in the one-time ILRT interval extension requests assumed a large leak magnitude (EPRI class 3b) of 35La, whereas the methodology in this document uses 100La. The dose risk is impacted by this change and will be larger than those of previous submittals.
1-4
2.0 METHODOLOGY
A simplified bounding analysis approach consistent with the latest EPRI approach [22] as accepted by the NRC [32] is used for evaluating the change in risk associated with increasing the test interval to fifteen years. The approach is consistent with that presented in EPRI TR-1018243
[22], NUREG-1493
[5] and the Calvert Cliffs liner corrosion analysis [19]. The analysis uses results from a Level 2 analysis of core damage scenarios from the current Hatch Unit 1 PRA model and the subsequent containment responses for the various fission product release categories (including containment intact release).
This risk assessment is applicable to Hatch Units 1 & 2 because Unit 2 can be adequately represented by Unit 1 PRA results (see Section 4.2). The six general steps of this assessment are as follows: 1. Quantify the baseline risk in terms of the frequency of events (per reactor year) for each of the eight containment release scenario types identified in the EPRI report. 2. Develop plant-specific person-rem (population dose) per reactor year for each of the eight containment release scenario types from plant specific consequence analyses.
- 3. Evaluate the risk impact (i.e. the change in containment release scenario type frequency and population dose) of extending the ILRT interval to fifteen years. 4. Determine the change in risk in terms of Large Early Release Frequency (LERF) in accordance with RG 1.174 [4] and compare this change with the acceptance guidelines of RG 1.174. 5. Determine the impact on the Conditional Containment Failure Probability (CCFP) 6. Evaluate the sensitivity of the results to assumptions in the corrosion analysis, external events, and to the probability of undetected leaks from containment (due to corrosion breach) to LERF. This approach is based on the information and approaches contained in the previously mentioned studies. Furthermore,
- Consistent with the other industry containment leak risk assessments, the Hatch assessment uses LERF and delta LERF in accordance with the risk acceptance guidance of RG 1.174. Changes in population dose and conditional containment failure probability (CCFP) are also considered to show that defense-in-depth and the balance of prevention and mitigation is preserved.
- This evaluation uses ground rules and methods to calculate changes in risk metrics that are consistent with those in the EPRI methodology
[22]. 2-1
- The EPRI methodology
[22] specifies that emergency core cooling system (ECCS) net positive suction head (NPSH) requirements be assessed regarding whether containment over pressure is credited in the design basis ECCS analysis, and if containment over pressure is credited, the potential impacts on the core damage frequency (CDF). As documented in Section 6.3.3.9 of the Hatch FSAR [36], containment over pressure is not required or credited for Unit 2 for either short term (i.e., < 10 minutes following LOCA initiation) or long term Residual Heat Removal (RHR) pump or Core Spray (CS) pump operation.
For Unit 1, the design basis calcu.lations indicate that 3.24 psig (7.5 ft) of containment over pressure is required to ensure adequate NPSH to the RHR pumps, and 3.2 psig (7.4 ft) of containment over pressure is required to ensure adequate NPSH to the CS pumps (at the peak calculated suppression pool temperature of 211.3 °F) for a period from about 2.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> to 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br /> after LOCA initiation.
These design basis calculations utilize conservative inputs (e.g., reactor operation at 100.5%) and one RHR heat exchanger.
To provide sufficient margin, the long term NPSH evaluation takes credit for 4.2 psig (10 ft) of containment over pressure for the period of 1.5 to 26.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> following LOCA initiation.
No over pressure credit is required for Unit 1 for the short term response (i.e., < 10 minutes following LOCA initiation).
MAAP runs in support of the Hatch PRA demonstrate that if RHR containment heat removal is available, the suppression pool water temperature stays well below 211 °F in the long term for a large LOCA and loss of ECCS NPSH is not a concern. Table 2.0-1 presents the results from four MAAP sensitivity cases performed in support of the ILRT analysis.
The MAAP cases model a large break LOCA (i.e., 28" diameter recirculation line break), core injection via core spray, one train of RHR for containment heat removal, with varied containment leakage values. MAAP Case 516Dl serves as the base case and models maximum allowed Technical Specification containment leakage (i.e., 1 La). The other three cases model increased containment leakage areas to estimate leakage for approximately lOOLa, 200La, and 400La. The general EPRI methodology is based on assuming a lOOL.13 leakage rate. Consistent with the design basis calculations, these MAAP cases utilize an initial torus water temperature of 100 °F and drywell temperature of 150 °F. The MAAP cases demonstrate that a single train of RHR containment heat removal is adequate to keep the suppression pool temperature approximately 181 °F or lower up to a leakage of 400La. With the suppression pool temperature well below 211 °F, loss of ECCS NPSH is not a concern for sequences where one or more trains of RHR containment heat removal operate. In the event that containment heat removal (i.e., RHR and containment vent) is unavailable, containment pressure will increase to the point of containment failure due to over pressure.
In the Hatch PRA, containment failure is assumed to result in a loss of ECCS core injection due to the potential for disruption of injection lines and degraded environmental conditions in plant areas housing injection equipment.
While the potential exists for a pre-existing containment failure (as might be detected by the Type A ILRT) to preclude the containment pressure from reaching the point of containment over pressure failure and instead result in loss of adequate NPSH to the ECCS pumps taking suction from the suppression 2-2 pool, the end result would be the same, i.e., loss of ECCS injection leading to core damage. Therefore, there is no change in CDF associated with loss of containment heat removal sequences.
Regarding the consideration of successful containment vent or other containment isolation failures (e.g., random containment isolation valve failures), the CDF associated with such accident sequences is not impacted by the ILRT frequency.
The ILRT frequency only impacts risk (i.e., CDF or LERF) associated intact containment configurations, (i.e., as characterized by EPRI Classes 1, 3a, and 3b in the EPRI methodology).
Containment configurations which are not intact (e.g., EPRI Class 2 for large containment isolation failures) are not impacted by the ILRT frequency because containment integrity is failed independent of the containment failure mechanisms evaluated by an ILRT. Based on the above discussion, there is no meaningful change in the CDF associated with the ILRT interval pertaining to the long term containment over pressure credit for Unit 1 ECCS NPSH. Therefore CDF is not quantitatively evaluated in this ILRT risk assessment as a figure of merit. It is additionally noted that design basis NPSH calculations include a level of conservatism.
For instance, the manufacturer recommended NPSH limit includes an operational design margin. The amount of margin depends on the specific pump design and the operating condition of the pump. Plant tests at TVA (Browns Ferry) [37] and Monticello have shown that substantial margin exists for ECCS pumps of BWR/3 and BWR/4 plants. Thus, the best estimate NPSH requirements for Hatch ECCS pump successful operation would be expected to be less than either that credited or that calculated by the design basis analysis.
2-3 Table 2.0-1 HATCH MAAP CONTAINMENT OVER PRESSURE SENSITIVITY CASEsC 1> MAAP CASE CONTAINMENT MAXIMUM TORUS TIME AT MAXIMUM ID LEAKAGE SIZE TEMP (F) TORUS TEMP 51601 5E-5 ft"2 181 6.5 to 8.5 hrs (1 La) 51602 5E-3 ft"2 181 6.9 to 8.0 hrs ("'100 La) 51603 1E-2 Ft"2 180 5.5 to 9.8 hrs ("'200 La) 51604 2E-2 ft"2 180 5.5 to 9.8 hrs ("'400 La) C 1> Cases model LLOCA, core injection via core spray, one train of RHR for containment heat removal, and varied containment leakage sizes. 2-4
3.0 GROUND
RULES The following ground rules are used in the analysis:
- The technical adequacy of the Hatch Unit 1 PRA is consistent with the requirements of Regulatory Guide 1.200 [28] as is relevant to this ILRT interval extension.
The PRA technical adequacy is documented separately.
- The Hatch Unit 1 Level 1 and Level 2 internal events PRA models provide representative results. (A Unit 2 PRA model is available and the CDF and LERF results are essentially the same as the Unit 1 results. It is judged that the Unit 2 model will not provide any unique or additional insights compared to the results from the Unit 1 model.)
- It is appropriate to use the Hatch Unit 1 internal events PRA model as a gauge to effectively describe the risk change attributable to the ILRT extension.
It is reasonable to assume that the impact from the ILRT extension (with respect to percent increases in population dose) will not substantially differ if fire and seismic events were to be included in the calculations; nevertheless fire and seismic events have been accounted for in the analysis based on the available information from the Hatch IPEEE [18] as described in Section 5.8.
- Dose results for the containment failures modeled in the PRA can be characterized by information provided in the Hatch Severe Accident Mitigation Alternatives (SAMA) analysis and associated responses to Requests for Additional Information (RAis) [9, 29, 30]. Hatch SAMA dose results all represent high magnitude releases.
These dose results can be applied to containment failure releases that are lower in magnitude (i.e., non-high releases).
- Plant specific dose calculations for containment intact cases are not available from the Hatch SAMA analysis.
NUREG-1150 results for such cases are adequately representative for use in the Hatch analysis based on scaling the NUREG-1150 results to account for differences in regional population, power level, and allowed technical specification leakage.
- Accident classes describing radionuclide release end states are defined consistent with the EPRI methodology
[22], as summarized in Section 4.2.
- The representative containment leakage for Class 1 sequences is 1La. Class 3 accounts for increased leakage due to Type A inspection failures.
- The representative containment leakage for Class 3a sequences is 10La, based on the previously approved methodology performed for Indian Point Unit 3 [6, 7].
- The representative containment leakage for Class 3b sequences is 100La, based on the NRC SER [32] and incorporated in the latest EPRI report [22]. Note that most of the previous one-time ILRT extension requests utilized 35La. 3-1
- The Class 3b can be very conservatively categorized as LERF based on the previously approved methodology
[6, 7]. The Class 3b category increase is used as a surrogate for LERF in this application even though the releases associated with a 100La release would not necessarily be consistent with a "Large" release for Hatch. * * *
- The impact on population doses from containment bypass scenarios is not altered by the proposed ILRT extension.
Rather it is accounted for in the EPRI methodology as a separate entry for comparison purposes, as accepted in the NRC SER [32]. Because the containment bypass contribution to population dose is fixed, no changes to the conclusions from this analysis will result from this separate categorization.
The reduction in ILRT frequency does not impact the reliability of containment isolation valves to close in response to a containment isolation signal. Consideration of the risk impact of the ILRT on shutdown risk is addressed in Section 6 using the generic results from EPRI TR-105189
[8]. The ILRT analysis evaluates very small changes in the risk metrics. To facilitate the calculation of these changes and the evaluation of sensitivity cases, the calculations are performed in a spreadsheet.
In general, the calculations provided in this report reproduce the calculation results of the spreadsheets.
In some cases there may be minor differences in the results between the spreadsheet calculations and hand calculations due to rounding (e.g., a column total in a table may differ). To maintain consistency, results from the spreadsheets are presented in this report. 3-2
4.0 INPUTS
This section summarizes the general resources available as input (Section 4.1) and the plant specific resources required (Section 4.2). 4.1 GENERAL RESOURCES AVAILABLE Various industry studies on containment leakage risk assessment are briefly summarized here: 1. NUREG/CR-3539
[10] 2. NU REG/CR-4220
[11] 3. NUREG-1273
[12] 4. NUREG/CR-4330
[13] 5. EPRI TR-105189
[8] 6. NUREG-1493
[5] 7. EPRI TR-104285
[2] 8. NUREG-1150
[14] and NUREG/CR-4551
[26] 9. NEI Interim Guidance [3, 21] 10. Calvert Cliffs liner corrosion analysis [19] 11. NRC SER [32] on EPRI TR-1009325
- 12. EPRI 1018243 [22] The first study is applicable because it provides one basis for the threshold could be used in the Level 2 PRA for the size of containment leakage that is considered significant and to be included in the model. The second study is applicable because it provides a basis of the probability for significant pre-existing containment leakage at the time of a core damage accident.
The third study is applicable because it is a subsequent study to NUREG/CR-4220 that undertook a more extensive evaluation of the same database.
The fourth study provides an assessment of the impact of different containment leakage rates on plant risk. The fifth study provides an assessment of the impact on shutdown risk from ILRT test interval extension.
The sixth study is the NRC's cost-benefit analysis of various alternative approaches regarding extending the test intervals and increasing the allowable leakage rates for containment integrated and local leak rate tests. The seventh study is an EPRI study of the impact of extending ILRT and LLRT test intervals on at-power public risk. The eighth study documents ex-plant consequence results which may be used as surrogate results in the ILRT risk assessment.
The ninth study includes the NEI recommended methodology (promulgated in two letters) for evaluating the risk associated with obtaining a one-time extension of the 4-1 ILRT interval.
The tenth study addresses the impact of age-related degradation of the containment steel on ILRT evaluations.
The eleventh study [32] documents the NRC Final Safety Evaluation of the EPRI 2007 version of ILRT risk assessment guidance (i.e., EPRI TR-1009325, Revision 2). The last study by EPRI complements the previous EPRI report [2], integrates the NEI interim guidance and NRC SER limitations and conditions, and provides a recommended methodology and template for evaluating the risk associated with a permanent 15-year ILRT interval.
[10] Oak Ridge National Laboratory (ORNL) documented a study of the impact of containment leak rates on public risk in NUREG/CR-3539.
This study uses information from WASH-1400
[15] as the basis for its risk sensitivity calculations.
ORNL concluded that the impact of leakage rates on LWR accident risks is relatively small. NUREG/CR-4220
[11] NUREG/CR-4220 is a study performed by Pacific Northwest Laboratories for the NRC in 1985. The study reviewed over two thousand LERs, ILRT reports and other related records to calculate the unavailability of containment due to leakage. It assessed the "large" containment leak probability to be in the range of lE-3 to lE-2, with 5E-3 identified as the point estimate based on 4 events in 740 reactor years and conservatively assuming a one-year duration for each event. NUREG-1273
[12] A subsequent NRC study, NUREG-1273, performed a more extensive evaluation of the NUREG/CR-4220 database.
This assessment noted that about one-third of the reported events were leakages that were immediately detected and corrected.
In addition, this study noted that local leak rate tests can detect "essentially all potential degradations" of the containment isolation system. 4-2 NUREG/CR-4330
[131 NUREG/CR-4330 is a study that examined the risk impacts associated with increasing the allowable containment leakage rates. The details of this report have no direct impact on the modeling approach of the ILRT test interval extension, as NUREG/CR-4330 focuses on leakage rate and the ILRT test interval extension study focuses on the frequency of testing intervals.
However, the general conclusions of NUREG/CR-4330 are consistent with NUREG/CR-3539 and other similar containment leakage risk studies: " ... the effect of containment leakage on overall accident risk is small since risk is dominated by accident sequences that result in failure or bypass of containment." EPRI TR-105189
[81 The EPRI study TR-105189 is useful to the ILRT test interval extension risk assessment because this EPRI study provides insight regarding the impact of containment testing on shutdown risk. This study performed a quantitative evaluation (using the EPRI ORAM for two reference plants (a BWR-4 and a PWR) of the impact of extending ILRT and LLRT test intervals on shutdown risk. The result of the study concluded that a small but measurable safety benefit (shutdown CDF reduced by lE-8/yr to lE-7/yr) is realized from extending the test intervals from 3 per 10 years to 1 per 10 years. NUREG-1493
[5] NUREG-1493 is the NRC's cost-benefit analysis for proposed alternatives to reduce containment leakage testing intervals and/or relax allowable leakage rates. conclusions are consistent with other similar containment leakage risk studies: The NRC
- Reduction in ILRT frequency from 3 per 10 years to 1 per 20 years results in an "imperceptible" increase in risk.
- Given the insensitivity of risk to the containment leak rate and the small fraction of leak paths detected solely by Type A testing, increasing the interval between integrated leak rate tests is possible with minimal impact on public risk. EPRI TR-104285
[2] Extending the risk assessment impact beyond shutdown (the earlier EPRI TR-105189 study), the EPRI TR-104285 study is a quantitative evaluation of the impact of extending ILRT and LLRT test intervals on at-power public risk. This study combined IPE Level 2 models with 4-3 NUREG-1150
[14] Level 3 population dose models to perform the analysis.
The study also used the approach of NUREG-1493 in calculating the increase in pre-existing leakage probability due to extending the ILRT and LLRT test intervals.
EPRI TR-104285 used a simplified Containment Event Tree to subdivide representative core damage sequences into eight categories of containment response to a core damage accident:
- 1. Containment intact and isolated 2. Containment isolation failures dependent upon the core damage accident 3. Type A (ILRT) related containment isolation failures 4. Type B (LLRT) related containment isolation failures 5. Type C (LLRT) related containment isolation failures 6. Other penetration related containment isolation failures 7. Containment failure due to core damage accident phenomena
- 8. Containment bypass Consistent with the other containment leakage risk assessment studies, this study concluded: "These study results show that the proposed CLRT [containment leak rate tests] frequency changes would have a minimal safety impact. The change in risk determined by the analyses is small in both absolute and relative terms. For example, for the PWR analyzed, the change is about 0.02 person-rem per year ... " NUREG-1150
[14] and NUREG/CR-4551
[26] NUREG-1150
[14] and the technical basis, NUREG/CR-4551
[26], provide an ex-plant consequence analysis for a spectrum of accidents including a severe accident with the containment remaining intact (i.e., Tech Spec leakage).
This ex-plant consequence calculation is calculated for the SO-mile radial area surrounding Peach Bottom. The ex-plant consequence calculation for the containment remaining intact represents a very small contributor to the overall risk spectrum.
Because it is a small contributor, this ex-plant calculation (i.e., total person-rem) is considered adequate to represent Hatch if population, reactor power, and the Technical Specification leakage are scaled to represent Hatch. (The meteorology and other site differences are assumed not to play a significant role in this evaluation).
4-4 NEI Interim Guidance [3, 211 NEI "Interim Guidance for Performing Risk Impact Assessments in Support of One-Time Extensions of Containment Integrated Leakage Rate Test Surveillance Intervals" [3] was developed to provide utilities with revised guidance regarding licensing submittals.
Additional information from NEI on the "Interim Guidance" was supplied in Reference
[21]. A nine step process is defined which includes changes in the following areas of the previous EPRI guidance:
- Impact of extending surveillance intervals on dose
- Method used to calculate the frequencies of leakages detectable only by ILRTs
- Provisions for using NUREG-1150 dose calculations to support the population dose determination.
The guidance provided in this document builds on the EPRI risk impact assessment methodology
[2] and the NRC performance-based containment leakage test program [5], and considers approaches utilized in various submittals, including Indian Point 3 (and associated NRC SER) [6,7] and Crystal River [20]. Calvert Cliffs Liner Corrosion Analysis [19] This submittal to the NRC describes a method for determining the change in likelihood, due to extending the ILRT, of detecting liner corrosion, and the corresponding change in risk. The methodology was developed for Calvert Cliffs in response to a request for additional information regarding how the potential leakage due to age-related degradation mechanisms were factored into the risk assessment for the ILRT one-time extension.
The Calvert Cliffs analysis was performed for a concrete cylinder and dome and a concrete basemat, each with a steel liner. Licensees may consider approved LARs for one-time extensions involving containment types similar to their facility.
The Hatch assessment has addressed the specific differences from the Calvert Cliffs design, and the Calvert Cliffs methodology was adapted to address the specific design features.
4-5 NRC SER on ILRT Risk Assessment
[32] This report documents the NRC review and acceptance of the EPRI ILRT Risk Assessment methodology of EPRI TR-1009325 Revision 2. Based on the NRC review, four conditions and limitations were identified, summarized here as: 1. Licensees must submit documentation supporting appropriate technical adequacy of the PRA. 2. Acceptance criteria for population dose risk and CCFP were revised. 3. Assumed leakage for EPRI Class 3b is revised from 35La to lOOLa. 4. A license amendment request (LAR) is required in instances where containment over pressure is relied upon for ECCS performance.
EPRI TR-1018243
[221 (EPRI TR-1009325 Revision 2-A) This report presents a generally applicable assessment of risk involved in extension of ILRT test intervals to 15 years on a permanent basis. Appendix H of this document provides guidance for performing plant-specific supplemental risk impact assessments and builds on the previous EPRI risk impact assessment methodology TR-104285
[2], the NEI Interim Guidance [3,21], and the NRC performance-based containment leakage test program [5], and considers approaches utilized in various submittals, including Indian Point 3 (and associated NRC SER) [6,7] and Crystal River [20]. The EPRI report codifies minor changes to the ILRT methodology specified by the NRC in the NRC ILRT risk assessment approach SER [32]. The approach included in this EPRI guidance document is used in the Hatch assessment to determine the estimated increase in risk associated with the ILRT extension.
This document includes the bases for the values assigned in determining the probability of leakage for the EPRI Class 3a and 3b scenarios in this analysis as described in Section 5. 4.2 PLANT-SPECIFIC INPUTS The Hatch specific information used to perform this ILRT interval extension risk assessment includes the following:
- PRA Level 1 Model results [16]
- PRA Level 2 Model results [17], including release category definitions, and containment failure probability data
- Population Dose within a 50-mile radius [9, 29, 30]
- ILRT results to demonstrate adequacy of the administrative and hardware interfaces 4-6 Hatch Internal Events Level 1 PRA Model The Unit 1 Internal Events Level 1 PRA model [16] is an event tree / linked fault tree model characteristic of the as-built, as-operated plant. This Level 1 PRA model incorporates the resolution of findings associated with the PRA Peer Review of 2009. The total internal events core damage frequency (CDF) used in this analysis is 7.57E-06/yrC
- 1) (at lE-12/yr truncation) for Unit 1, as reflected in the combined Unit 1Level1 and Level 2 PRA models [17]. (For reference, it is noted that the CDF for the Unit 2 model is 7.42E-06/yr
[39], approximately 1.5% less than the Unit 1 CDF. The Unit 1 model is adequately representative of Unit 2 for the purposes of the ILRT risk assessment.)
Hatch Internal Events Level 2 PRA Model The Unit 1 Level 2 PRA model [17] was developed to calculate the LERF contribution as well as the other release categories evaluated in the model. This Level 2 PRA model incorporates the resolution of findings associated with the PRA Peer Review of 2009. Table 4.2-la summarizes the pertinent Hatch Unit 1 Level 2 results in terms of end states. The total Large Early Release Frequency (LERF) in Table 4.2-la for Unit 1 is 1.12E-6/yr.
The Unit 2 model LERF value is 1.03E-06/yr
[31], approximately 8% less than the Unit 1 LERF. The lower Unit 2 LERF value is primarily attributed to a plant design difference.
The Unit 2 feedwater injection lines have an additional check valve which lowers the break outside containment (BOC) contribution to LERF for Unit 2. This design difference does not impact the risk assessment because the ILRT interval does not impact the BOC LERF contribution.
Cl) The Unit 1 Level 1 CDF value of 7.57E-06/yr used in the Levei 2 evaiuation
[17] is slightly higher than the Level 1 CDF value of 7.53E-06/yr from the latest version of the Hatch Unit 1 Internal Events Level 1 PRA model [16]. To support the Level 2 quantification, Level 1 sequences are binned into accident classes. However, this separate quantification of the individual accident classes may result in duplicate or non-minimal cutsets to be binned into more than one accident class. This may result in the numerical sum of all individual accident classes to be higher than the CDF if all the cutsets were merged together.
However, the apparent deviation of the Level 1 CDF quantified for the Level 2 model is less than 1 % and is judged not to significantly alter the results. 4-7 The Level 2 release category end states are defined [38] as follows: Release Magnitude High Moderate/Medium Low Low-Low Release Timing Early Intermediate Late CsI Release Fraction > 10% 1% to 10% 0.1% to 1% < 0.1% Time (hrs) <5 5 to 24 > 24 Table 4.2-lb summarizes the core damage frequency contributions by the PRA accident class. 4-8 Table 4.2-la HATCH LEVEL 2 DETAILED RELEASE CATEGORIESC 1> RELEASE FREQUENCY CATEGORY DEFINITION
(/YR) (1) INTACT Containment remains intact. 1.18E-06 H-E High-early release (i.e., LERF). Dominant accident class 1.12E-06 contributors are as follows:
6.13E-08/yr . Class ID (loss of RPV injection, RPV at low pressure):
6.17E-08/yr
- Class 4 (ATWS) : 1.93E-07/yr . Class 5 (BOC): 7. 79E-07 /yr H-I High-intermediate release. Dominant accident class contributor 2.83E-06 is Class 2A (loss of containment heat removal, CD post-containment failure) at 3.17E-06/yr.
M-E Moderate-early release. Dominant accident class contributor is 1.19E-06 Class 1D (loss of RPV injection, RPV at low pressure) at 8.04E-07/yr. M-I Moderate-intermediate release. Dominant accident class 9.64E-07 contributor is Class 2A at 8.23E-07 /yr. M-L Moderate-late release. Dominant accident class contributor is 4.64E-08 Class 1A at 4.80E-08/yr.
L-E Low-early release. Dominant accident class contributor is Class 1.0lE-08 1A at 2.24E-09/yr.
L-I Low-intermediate release. Dominant accident class contributor 9.56E-08 is Class 1D at 1.0SE-07/yr.
L-L Low-late release. Dominant accident class contributor is Class 6.94E-09 1A at 7.42E-09/yr.
LL-E Low Low-late release. Dominant accident class contributor is 1.33E-07 Class 1D at 4.21E-08/yr.
LL-I Low Low-intermediate release. Dominant accident class 1.0SE-08 contributor is Class 1D at 1.02E-08/yr.
LL-L Low Low-late release. Dominant accident class contributor is 4.63E-09 Class 1A at 4.86E-09/yr.
Total Total Release Category Frequency (No Intact) 6.40E-06 Total Total CDF 7.SSE-06 From Table 5 of Reference
[17] for Unit 1. The High-Late release category had zero frequency and is therefore not listed. 4-9 Table 4.2-lb HATCH CDF CONTRIBUTIONS BY PRA ACCIDENT CLAssC 1> PRA FREQUENCY ACCIDENT (/YR) CLASS DESCRIPTION IA Transients
-core melt with vessel at high pressure 1.07E-06 IBE Station blackout -early 1.18E-08 IBL Station blackout -late 4.89E-07 IC with loss of injection
- 1. 73E-07 ID lrransients
-core melt with vessel at low pressure 1.35E-06 IIA Core melt after containment failure due to loss of DHR 3.39E-06 Ill Core melt after containment failure due to loss of DHR and 4.11E-10 LOCA IIIB LOCA -core melt with vessel remaining at high pressure 1.SOE-08 me LOCA -core melt with vessel at low pressure 2.75E-09 IV
-containment fails before core damage 3.SSE-07 v LOCA outside containment 7.12E-07 Total Total CDF 7.57E-06 (1) From Table 5 of Reference
[17] for Unit 1. 4-10 Population Dose Conditional population dose results for containment failure end states are available for Hatch based on the Hatch SAMA evaluation performed for Units 1 & 2 and submitted to the NRC in 2000 [9], and subsequent responses to Requests for Additional Information (RAis) [29, 30]. Conditional population dose results for an intact containment end state (not quantified for the SAMA analysis) are available via ex-plant consequence results for Peach Bottom [26] and can be scaled to represent Hatch. The Hatch specific and Peach Bottom surrogate conditional population dose results may be combined with the most recent Hatch Level 2 analysis results [17] to develop population dose risk for use in the ILRT assessment.
The SAMA dose analysis utilized the projected population to year 2030 (i.e., 498,834 people in the 50 mile radial region) and a Hatch power level of 2,763 MWth. The population projection is adequately representative for use in the ILRT assessment.
The Hatch power level used in the SAMA analysis is slightly less than the current and anticipated Hatch power level in the future, which is 2,804 MWth. The SAMA dose values may be scaled for use in the ILRT analysis by applying a reactor power level scaling factor of 1.015 (i.e., 2,804 MWth / 2,763 MWth). The Hatch SAMA population dose results are presented in Table 4.2-2. These dose results are based on MACCS2 calculations and accident sequence frequencies applicable at the time. Included in Table 4.2-2 is a column presenting the ILRT assessment dose values after applying the reactor power level scaling factor. It is noted that the release categories represented in the Hatch SAMA analysis all represent high magnitude releases.
Doses associated with large releases from containment failure can be conservatively represented by this data. The population dose associated with an intact containment (Technical Specification leakage) case can be estimated based on scaling the NUREG/CR-4551 dose results for Peach Bottom from Accident Progression Bin (APB) #8 (Core is damaged, Vessel is breached, no containment failure)C 1 l. The Peach Bottom dose for APB #8 is not specifically identified in NUREG/CR-4551, but can be back-calculated to be 4,940 person-rem as presented in Table 4.2-3. (lJ APB #8 is described in more detail in NUREG/CR-4551
[26] Section 2.4.3. 4-11 The APB #8 person-rem result can be used as an approximation of the dose for Hatch if it is scaled for regional population, reactor power level, and allowable containment leakage rate (La). Values for these attributes for Peach Bottom (as evaluated in NUREG/CR-4551) and Hatch are summarized in Table 4.2-4, where the applicable scaling factors are calculated.
Applying the calculated scaling factors, the population dose for Hatch for an intact containment technical specification release is 1,150 pers-rem (i.e, 4,940 pers-rem
- 0.114
- 0.852
- 2.4 = 1,150 pers-rem).
Table 4.2-5 presents the current Hatch Level 2 release frequencies, the assigned dose for the category, and the calculated annual dose risk. The annual dose risk calculated in Table 4.2-5 is not directly used in the ILRT assessment since the EPRI methodology utilizes a different release category scheme, but is presented for completeness.
EPRI Release Category Definitions Table 4.2-6 defines the accident classes used in the ILRT extension evaluation, which are consistent with the EPRI methodology
[22]. These containment failure classifications are used in this analysis to determine the risk impact of extending the Containment Type A test interval as described in Section 5 of this report. Hatch ILRT Results The surveillance frequency for Type A testing in NE! 94-01 under option B criteria is at least once per ten years based on an acceptable performance history (i.e. two consecutive periodic Type A tests at lec:ist 24 months apart where the calculated performance leakage rate was less than 1.0 La) and consideration of the performance factors in NEI 94-01, Section 11.3. Based on completion of two successful ILRTs at Hatch Unit 1 and Unit 2, the ILRT interval became once per ten years. Subsequently, a one time ILRT interval frequency of once per fifteen years was approved for both Hatch Unit 1 and Unit 2 [33, 34] based on demonstrating acceptable risk impacts. Each Hatch unit has successfully completed another ILRT (i.e., Unit 1 in March 2008, Unit 2 in March 2009) since these one time ILRT interval extension approvals.
4-12 Table 4.2-2
SUMMARY
OF SAMA MACCS2 CALCULATIONS AND ILRT SCALED VALUES SAMA Frequency SAMA Dose Level 2 End State Seq# Sequence Description (per yr) <10> (Person-Rem)
Containment Bypass 5 BOC 1.66E-7C 6 l 1.15E+6C 2 l Early Cont. Failure 2 SBO 1.79E-6<6 l 1.06E+6<3 l 4 Loss of Cont. Heat 7.43E-7<6 l 1.02E+6<4 l Removal (CHR) 11 ATWS 7.43E-7C 6 l 7.02E+5<5 l Late Cont. Failure 12 High pressure transient 2.0E-7<1 l 5.7E+5 with loss of CH R 14 SBO with cont. isolation 3.1E-9(ll failure Intact Cont. (DW Vent) 15 High pressure transient 9.24E-10C 6 l 1.13E+6C 9 l with venting No Containment Failure NA NA NA NAC 7 l NA <1 l SAMA RAI response to Q#4 [29]. C 2 l SAMA RAI response to Q#14; Sequence #5 [29] clarification provided to NRC by SNC [30]. C 3 l SAMA RAI response to Q#l4; Sequence #2 [29]. <4 l SAMA RAI response to Q#14; Sequence #4 [29]. <5 l SAMA RAI response to Q#l4; Sequence #11 [29]. (GJ SAMA RAI response to Q#l.b-1 [29]. C 7 l Not calculated for SAMA. csi SAMA RAI clarification provided by SNC to Question #5 [30]. <9 l SAMA RAI response to Q#l4; Sequence 15 [29]. Adjusted Dose for ILRT Assessment (Person-Rem)
<11> 1.17E+6 1.08E+6 1.04E+6 7.13E+5 5.8E+5 1.15E+6 NA TOTAL SAMA Annual Risk (Person-Rem/Yr)
[29, 30] 0.19 1.90 0.76 0.52 3.18 total 0.ll2(B) 0.0008 0.001 NAC 7 l 3.48 <10 l It is noted that the Hatch PRA model tias been updated since the SAMA analysis and the accident sequence frequencies and the Table 4.2-3 PEACH BOTTOM APB #8 SO-MILE POPULATION DOSE CALCULATIONC 1> ALL APBS APB #8 SO-MILE APB #8 SO-APB #8 CONTRIBUTION DOSE RISK MILE DOSE APB #8 50-FREQUENCY TO SO-MILE (PERS-RISK (PERS-MILE DOSE (/YR) DOSE RISK REM/YR) REM/YR) (PERS-REM) 7.99E-7C 2) 5E-4C 3 l 7_9C 4 l 3.95E-3C 5 l 4.94E+3C 6 l Cll NUREG/CR-4551
[26] does not document dose results as a function of accident progression bin as such, the dose result for APB #8 is back calculated from the documented APB frequency and dose risk results. <2> From Figure 2.5-6 of NUREG/CR-4551 Vol. 4, Rev. 1, Part 1. Frequency for APB #8 of 7.99E-7/yr is calculated as 0.184 contribution of 4.34E-6/yr CDF. <3 l From Table 5.2-3 for the mean fractional contribution to risk (MFCR) of NUREG/CR-4551 Vol. 4, Rev. 1, Part 1. <4 J From Table 5.1-1 for mean value 50-mile population dose of NUREG/CR-4551 Vol. 4, Rev. 1, Part 1. <5 J APB dose risk is calculated by multiplying the APB dose risk fractional contribution (column 2) by the total 50-mile radius dose risk of 7.9 person-rem/yr (column 3). (GJ Calculated by dividing the APB #8 dose risk (column 4) by the APB #8 frequency (column 1) Table 4.2-4 HATCH APB-#8 DOSE SCALING FACTORS Reactor SO-mile Power TS Leakage Plant Population (MWth) (wt 0/o/day) Hatch 498.834(!)
2 804(2) 1.2% C 2> Peach Bottom 4,359,67-?(3) 3,293C 4 l 0.5%(S) Scaling Factor 0.114 0.852 2.4 <1> Hatch SAMA year 2030 population
[9] <2> Hatch current and anticipated future value. <3 J NUREG/CR-4551, Vol. 2, Rev. 1, Part 7, Appendix A.3 (SITE MACCS2 File) for Peach Bottom. Population total for 50-mile radius developed in Appendix A of this report. <4 J NUREG/CR-4551, Vol. 4, Rev. 1, Part 2, Section A.3.1. <5 l NUREG/CR-4551, Vol. 4, Rev. 1, Part 2, page B.2-9 for no containment failure. 4-14 Table 4.2-5 HATCH POPULATION DOSE RISK AT 50 MILES RELEASE POPULATION DOSE CATEGORY 2030 POPULATION RISK RELEASE FREQUENCIES ASSIGNED DOSE DOSE ASSIGNMENT (PERSON-REM/YR)
CATEGORY (PER YEAR) (PERSON-REM)C 1> BASIS (2) INTACT H-E H-1 M-E M-1 M-L L-E L-1 L-L LL-E LL-I LL-L Total (1) (2) (3) (4) 1.18E-06 1.15E+03 Peach Bottom 1.35E-03 1.12E-06 1.17E+06 Hatch SAMA BOC 1.31 E+OO 2.83E-06 5.80E+05 Hatch SAMA late CF 1.64E+OO 1.19E-06 5.80E+05 Hatch SAMA late CF (SJ. 6.90E-01 9.64E-07 5.80E+05 Hatch SAMA late CF(3 l 5.59E-01 4.64E-08 5.80E+05 Hatch SAMA late CF(3 l 2.69E-02 1.01 E-08 5.80E+05 Hatch SAMA late CF (4 l 5.86E-03 9.56E-08 5.80E+05 Hatch SAMA late CF(4 l 5.54E-02 6.94E-09 5.80E+05 Hatch SAMA late CF(4 l 4.03E-03 1.33E-07 5.80E+05 Hatch SAMA late CF(4 l 7.71 E-02 1.0SE-08 5.80E+05 Hatch SAMA late CF (4 l 6.09E-03 4.63E-09 5.80E+05 Hatch SAMA late CF(4 l 2.69E-03 7.58E-06 ----4.37E+OO Includes a scaling factor of 0.233 for application of the Peach Bottom dose results to the Intact Containment case, and includes a scaling factor of 1.015 for other release categories to account for a reactor power level increase since the Hatch SAMA analysis was performed.
Obtained by multiplying the release category frequency by the conditional dose. All Hatch SAMA dose cases represent high releases.
The late containment failure dose is approximately*
a factor of two less than that for other high magnitude releases and is considered reasonable for use for medium magnitude release cases. This is comparable to SAMA population dose results developed for Quad Cities and Dresden Generating Stations [35] (both Mark I containment designs) where moderate magnitude releases had population dose results approximately one half to nearly equal to high magnitude release population doses. All Hatch SAMA dose cases represent high releases.
Use of the late containment failure for low and low-low magnitude release cases is acceptable because the associated frequencies for these release categories are low compared to other release categories.
The population dose associated with low or low-low releases compose less than 3% of the total as developed in this table. 4-15 Table 4.2-6 EPRI CONTAINMENT FAILURE CLASSIFICATIONS
[22] CLASS DESCRIPTION 1 Containment remains intact including accident sequences that do not lead to containment failure in the long term. The release of fission products (and attendant consequences) is determined by the maximum allowable leakage rate values La, under Appendix J for that plant 2 Containment isolation failures (as reported in the IPEs) include those accidents in which there is a failure to isolate the containment.
3 Independent (or random) isolation failures include those accidents in which the pre-existing isolation failure to seal (i.e. provide a leak-tight containment) is not dependent on the sequence in progress.
4 Independent (or random) isolation failures include those accidents in which the pre-existing isolation failure to seal is not dependent on the sequence in progress.
This class is similar to Class 3 isolation failures, but is applicable to sequences involving Type B tests and their potential failures.
These are the Type B-tested components that have isolated but exhibit excessive leakage. 5 Independent (or random) isolation failures include those accidents in which the pre-existing isolation failure to seal is not dependent on the sequence in progress.
This class is similar to Class 4 isolation failures, but is applicable to sequences involving Type C tests and their potential failures.
6 Containment isolation failures include those leak paths covered in the plant test and maintenance requirements or verified per in service inspection and testing (ISI/IST) program. 7 Accidents involving containment failure induced by severe accident phenomena.
Changes in Appendix J testing requirements do not impact these accidents.
8 Accidents in which the containment is bypassed (either as an initial condition or induced by phenomena) are included in Class 8. Changes in Appendix J testing requirements do not impact these accidents.
4-16
4.3 IMPACT
OF EXTENSION ON DETECTION OF COMPONENT FAILURES THAT LEAD TO LEAKAGE (SMALL AND LARGE) The ILRT can detect a number of component failures such as containment breach, failure of certain bellows arrangements and failure of some sealing surfaces, which can lead to leakage. The proposed ILRT test interval extension may influence the conditional probability of detecting these types of failures.
To ensure that this effect is properly accounted for, the EPRI Class 3 accident class as defined in Table 4.2-6 is divided into two sub-classes representing small and large leakage failures.
These subclasses are defined as Class 3a and Class 3b, respectively.
The probabilities of the EPRI Class 3a and 3b failures are determined consistent with the EPRI guidance [22]. For Class 3a, the probability is based on the mean failure estimated from the available data (i.e., two "small" failures that could only have been discovered by the ILRT; 2 of 217 tests leads to a 0.0092 mean value). For Class 3b, the Jefferys non-informative prior distribution is assumed for no "large" failures in 217 tests (i.e., 0.5/(217+1)
= 0.0023). In a follow-on letter [21] to their ILRT guidance document [3], NEI issued additional information concerning the potential that the calculated delta LERF values for several plants may fall above the "very small change" guidelines of the NRC Regulatory Guide 1.174. This additional NEI information includes a discussion of conservatisms in the quantitative guidance for delta LERF. NEI describes ways to demonstrate that, using plant-specific calculations, the delta LERF is smaller than that calculated by the simplified method. The supplemental information states: "The methodology employed for determining LERF (Class 3b frequency) involves conservatively multiplying the CDF by the failure probability
- for this class (3b) of accident.
This was done for simplicity and to maintain conservatism.
However, some plant-specific accident classes leading to core damage are likely to include individual sequences that either may already (independently) cause a LERF or could never cause a LERF, and are thus not associated with a postulated large Type A containment leakage path (LERF). These contributors can be removed from Class 3b in the evaluation of LERF by multiplying the Class 3b probability by only that portion of CDF that may be impacted by type A leakage." 4-17
*--------------
The application of this additional guidance to the analysis for Hatch (as detailed in Section 5), involves the following:
- The EPRI Class 2 and Class 8 sequences are subtracted from the CDF that is applied to Class 3b. To be consistent, the same change is made to the Class 3a CDF, even though these events are not considered LERF. Class 2 and Class 8 events refer to sequences with either large pre-existing containment isolation failures or containment bypass events. These sequences are already considered to contribute to LERF in the Hatch Level 2 PRA analysis.
- The EPRI guidance and examples also note the potential for accident sequences involving the use of containment sprays or those resulting in late releases due to timing (e.g., long term station blackout, loss of containment heat removal) to be subtracted from the CDF that is applied to Class 3b. This is conservatively not performed for the base case analysis, but is evaluated as a sensitivity case in Section 6. Consistent with the EPRI guidance [22], the change in the leak detection probability can be estimated by comparing the average time that a leak could exist without detection.
For example, the average time that a leak could go undetected with a three-year test interval is 1.5 years (3 yr / 2), and the average time that a leak could exist without detection for a year interval is 5 years (10 yr/ 2). This change would lead to a non-detection probability that is a factor of 3.33 (5.0/1.5) higher for the probability of a leak that is detectable only by ILRT testing, given a 10-year versus a 3-yr interval.
Correspondingly, an extension of the ILRT interval to fifteen years can be estimated to lead to about a factor of 5.0 (7.5/1.5) increase in the non-detection probability of a leak. It should be noted that using the methodology discussed above is very conservative compared to previous submittals (e.g., the IP3 request for a one-time ILRT extension that was approved by the *NRC [7]) because it does not factor in the possibility that the failures could be detected by other tests (e.g., the Type B local leak rate tests that still occur.) Eliminating this possibility conservatively over-estimates the factor increases attributable to the ILRT extension.
4-18
4.4 IMPACT
OF EXTENSION ON DETECTION OF STEEL CORROSION THAT LEADS TO LEAKAGE An estimate of the likelihood and risk implications of corrosion-induced leakage of the steel containment occurring and going undetected during the extended test interval is using the methodology from the Calvert Cliffs liner corrosion analysis [19]. The Calvert Cliffs analysis was performed for a concrete cylinder and dome and a concrete basemat, each with a steel liner. The analysis approach can be applied to the Hatch Mark I containment design consisting of a steel drywell (floor encased in concrete) and steel torus. The following approach is used to determine the change in likelihood, due to extending the ILRT, of detecting corrosion of the containment steel. This likelihood is then used to determine the resulting change in risk. Consistent with the Calvert Cliffs analysis, the following issues are addressed:
- Differences between the containment drywell floor and the containment walls and head
- The historical steel flaw likelihood due to concealed corrosion
- The impact of aging
- The corrosion leakage dependency on containment pressure
- The likelihood that visual inspections will be effective at detecting a flaw Assumptions
- Consistent with the Calvert Cliffs analysis, a half failure is assumed for the drywell floor concealed steel corrosion due to the lack of identified failures.
- The two corrosion events over a 5.5 year data period are used to estimate the steel liner flaw probability in the Calvert Cliffs analysis and are assumed to be applicable to the Hatch containment analysis.
These events, one at North Anna Unit 2 and one at Brunswick Unit 2 (Mark I containment design), were initiated from the non-visible (backside) portion of the containment liner. It is noted that two additional events have occurred in recent years (based on a data search covering approximately 9 years documented in Reference
[27]). In November 2006, the Turkey Point 4 containment building liner developed a hole when a sump pump support plate was moved. In May 2009, a hole approximately 3/8" by 1" in size was identified in the Beaver Vaiiey 1 containment liner. For risk evaluation purposes, these two more recent events occurring over a 9 year period are judged to be adequately represented by the two events in the 5.5 year period of the Calvert Cliffs analysis incorporated in the EPRI guidance.
4-19
*--------*--*---------*------------------------
- Consistent with the Calvert Cliffs analysis, the estimated historical flaw probability is limited to 5.5 years to reflect the years from September 1996 when 10 CFR 50.55a started requiring visual inspection to when the Calvert Cliffs analysis was submitted.
Additional success data was not used to limit the aging impact of this corrosion issue, even though inspections were being performed prior to this date and have been performed since the time frame of the Calvert analysis. (See Table 4.4-1, Step 1).
- Consistent with the Calvert Cliffs analysis, the steel 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 ages. (See Table 4.4-1, Steps 2 and 3.) Sensitivity studies are included that address doubling this rate every two years and every ten years.
- In the Calvert Cliffs analysis the likelihood of the containment atmosphere reaching the outside atmosphere given that a flaw exists was estimated as 1.1% for the cylinder and dome region, and 0.11% (10% of the cylinder failure probability) for the basemat. These values were determined from an assessment of the probability versus containment pressure, and the selected values are consistent with a pressure that corresponds to the ILRT target pressure of 37 psig. For the Hatch Mark I containment, the containment failure probabilities are conservatively assumed to be 1 % for the drywell vertical walls and head along with the wetwell torus, and 0.1 % for the drywell floor for this analysis.
Sensitivity studies are included that increase and decrease the probabilities by an order of magnitude. (See Table 4.4-1, Step 4.)
- Consistent with the Calvert Cliffs analysis, the likelihood of leakage escape (due to crack formation) in the concrete encased drywell floor region is considered less likely than the containment walls and had region. (See Table 4.4-1, Step 4)
- Consistent with the Calvert Cliffs analysis, a 5% visual inspection detection failure likelihood given the flaw is visible and a total detection failure likelihood of 10% is used. To date, all iiner corrosion events have been detected through visual inspection.
For Hatch, there is generally 100% accessibility for visual inspection of the interior surfaces of the drywell above the floor elevation, the outside surfaces of the suppression pool, the inside surfaces of the suppression pool (using divers below the water line), and the vent system. (See Table 4.4-1, Step 5.) Sensitivity studies are included that evaluate total detection failure likelihood of 5% and 15%, respectively.
- Consistent with the Calvert Cliffs analysis, all non-detectable containment failures are assumed to result in early releases.
This approach avoids a detailed analysis of containment failure timing and operator recovery actions. 4-20 Table 4.4-1 STEEL CONTAINMENT CORROSION BASE CASE STEP DESCRIPTION 1 Historical Steel Flaw Likelihood 2 3 4 Failure Data: Containment location specific (consistent with Calvert Cliffs analysis).
Age Adjusted Steel Flaw Likelihood During 15-year interval, assume failure rate doubles every five years (14.9% increase per year). The average for 5th to 10th year is set to the historical failure rate (consistent with Calvert Cliffs analysis).
Flaw Likelihood at 3, 10, and 15 years Uses age adjusted flaw likelihood (Step 2), assuming failure rate doubles every five years (consistent with Calvert Cliffs analysis -See Table 6 of Reference
[19]). Likelihood of Breach in Containment Given Steel Flaw The failure probability of the DW walls, head, and torus is assumed to be 1% (compared to 1.1 % in the Calvert Cliffs analysis).
The DW floor failure probability is assumed to be a factor of ten less, 0.1%, (compared to 0.11% in the Calvert Cliffs analysis).
DW WALLS AND HEAD, AND TORUS DRYWELL FLOOR Events: 2 Events: O (assume half a failure) 2/(70
- 5.5) = 5.2E-3 0.5/(70
- 5.5) = 1.3E-3 Year 1 avg 5-10 15 Failure Rate 2.1E-3 5.2E-3 1.4E-2 15 year average = 6.27E-3 0.71% (1 to 3 years) 4.060/o (1 to 10 years) 9.400/o (1 to 15 years) (Note that the Calvert Cliffs analysis presents the delta between 3 and 15 years of 8.7% to utilize in the estimation of the delta-LERF value. For this analysis the values are calculated based on the 3, 10, and 15 year intervals.)
Year 1 avg 5-10 15 Failure Rate 5.0E-4 1.3E-3 3.SE-3 15 year average = 1.57E-3 0.180/o (1 to 3 years) 1.020/o (1 to 10 years) 2.350/o (1 to 15 years) (Note that the Calvert Cliffs analysis presents the delta between 3 and 15 years of 2.2% to utilize in the estimation of the delta-LERF value. For this analysis, however, v_alues are calculated based on the 3, 10, and 15 year intervals.)
0.1°/o 4-21 Table 4.4-1 STEEL CONTAINMENT CORROSION BASE CASE OW WALLS AND HEAD, STEP DESCRIPTION AND TORUS DRYWELL FLOOR 5 Visual Inspection Detection 100/o 100°/o Failure Likelihood 5% failure to identify visual Cannot be visually inspected.
Utilize assumptions consistent flaws plus 5% likelihood that with Calvert Cliffs analysis the flaw is not visible (not while also accouting for the through-wall but could be unique arrangement of the detected by ILRT). Hatch containment.
All events have been detected through visual inspection.
A 5% visible failure detection is a conservative assumption.
6 Likelihood of Non-Detected 0.000710/o (at 3 years) 0.000180/o (at 3 years) Containment Leakage =0.71%
- 1%
- 10% =0.18%
- 0.1%
- 100% (Steps 3
- 4
- 5) 0.00410/o (at 10 years) 0.00100/o (at 10 years) =4.1%
- 1%
- 10% =1.0%
- 0.1%
- 100% 0.00940/o (at 15 years) 0.00240/o (at 15 years) =9.4%
- 1%
- 10% =2.4%
- 0.1%
- 100% 4-22 The total likelihood of the corrosion-induced, non-detected containment leakage is the sum of Step 6 for the DW walls, head, and torus, and the drywell floor: At 3 years : 0.00071% + 0.00018% = 0.00089% = 8.9E-6 At 10 years: 0.0041% + 0.0010% = 0.0051% = 5.lE-5 At 15 years: 0.0094% + 0.0024% = 0.012% = 1.2E-4 Based on the above, a corrosion impact factor due to undetected corrosion is calculated as follows for the three ILRT cases investigated:
Corrosion impact factor = (3b Conditional Failure Probability
+ Total Likelihood of detected containment leakage due to corrosion at interval) 3b Conditional Failure Probability Case 1: 3 ILRT per 10 years 2.30E-03 + 8.9E-06 = 1.004 2.30E-03 Case 2: 1 ILRT Per 10 years 7.67E-03 + 5.lE-05 = 1.007 7.67E-03 Case 3: 1 ILRT per 15 years 1.lSE-02 + 1.2E-04 = 1.01 1.lSE-02 These impact factors are used to adjust the EPRI 3b class frequencies to model the impact of undetected corrosion.
4-23
5.0 RESULTS
The application of the approach based on the guidance contained in EPRI TR-1018243
[22], EPRI-TR-104285
[2] and previous risk assessment submittals on this subject [6, 7, 19, 20, 23] have led to the following results. The results are displayed according to the eight accident classes defined in the EPRI report. Table 5.0-1 lists these accident classes. The analysis performed examined Hatch specific accident sequences in which the containment remains intact or the containment is impaired.
Specifically, the break down of the severe accidents contributing to risk were considered in the following manner:
- Core damage sequences in which the containment remains intact initially and in the long term (EPRI TR-104285 Class 1 sequences).
- Core damage sequences in which containment integrity is impaired due to random isolation failures of plant components other than those associated with Type B or Type C test components.
For example, containment breach or bellows leakage. (EPRI TR-104285 Class 3 sequences).
- Core damage sequences in which containment integrity is impaired due to containment isolation failures of pathways left "opened" following a plant post-maintenance test. (For example, a valve failing to close following a valve stroke test.) (EPRI TR-104285 Class 6 sequences).
Consistent with the NEI Guidance, this class is not specifically examined since it will not significantly influence the results of this analysis.
- Accident sequences involving containment bypassed (EPRI TR-104285 Class 8 sequences), large containment isolation failures (EPRI TR-104285 Class 2 sequences), and small containment isolation to-seal" events (EPRI TR-104285 Class 4 and 5 sequences) are accounted for in this evaluation as part of the baseline risk profile. However, they are not affected by the ILRT frequency change.
- Class 4 and 5 sequences are impacted by changes in Type B. and C test intervals; therefore, changes in the Type A test interval do not impact these sequences.
5-1 Table 5.0-1 EPRI ACCIDENT CLASSES ACCIDENT CLASSES (CONTAINMENT RELEASE TYPE) DESCRIPTION 1 No Containment Failure 2 Large Isolation Failures (Failure to Close) 3a Small Isolation Failures (containment breach) 3b Large Isolation Failures (containment breach) 4 Small Isolation Failures (Failure to seal -Type B) 5 Small Isolation Failures (Failure to seal-Type C) 6 other Isolation Failures (e.g., dependent failures) 7 Failures Induced by Phenomena (Early and Late) 8 Bypass (SGTR and Interfacing System LOCA) CDF All CET End states (including very low and no release) The steps taken to perform this risk assessment evaluation are as follows: Step 1 Step 2 Step 3 Step 4 Step 5 Step 6 Quantify the base-line risk in terms of frequency per reactor year for each of the eight accident classes presented in Table 5.0-1. Develop plant-specific person-rem dose (population dose) per reactor year for each of the eight accident classes. Evaluate risk impact of extending Type A test interval from 3 to 15 and 10 to 15 years. Determine the change in risk in terms of Large Early Release Frequency (LERF) in accordance with RG 1.174. Determine the impact on the Conditional Containment Failure Probability (CCFP) Determine the impact on the 50-mile population dose risk. 5-2 5.1 STEP 1 -QUANTIFY THE BASE-LINE RISK IN TERMS OF FREQUENCY PER REACTOR YEAR As previously described, the extension of the Type A interval does not influence those accident progressions that involve large containment isolation failures, Type B or Type C testing, or containment failure induced by severe accident phenomena.
For the assessment of ILRT impacts on the risk profile, the potential for pre-existing leaks is included in the model. These events are represented by the EPRI Class 3 sequences.
Two failure modes were considered for the Class 3 sequences.
These are Class 3a (small breach) and Class 3b (large breach). The frequencies for the EPRI accident classes defined in Table 5.0-1 were developed for Hatch by first determining the frequencies for Classes 1, 2, 7, and 8, then determining the frequencies for Classes 3a and 3b, and finally determining the frequency for Class 1. Classes 4, 5, and 6 are not impacted by the ILRT interval and are therefore not specifically evaluated.
Adjustments are made to the Class 3b frequency and hence Class 1 frequency to account for the impact of undetected corrosion of the steel containment per the methodology described in Section 4.4. Class 1 Sequences This group represents the frequency when the containment remains intact (modeled as Technical Specification Leakage).
The EPRI Class 1 frequency is calculated as the intact containment release frequency from Table 4.2-la (1.18E-06/yr) minus the EPRI Class 3a and 3b frequencies (6.31E-08/yr and 1.58E-08/yr, respectively) calculated below. For this analysis, the associated maximum containment leakage for this group is lla, consistent with an intact containment evaluation.
The EPRI Class 1 frequency is 1. lOE-06/yr.
Class 2 Sequences This group consists of all core damage accident sequences for which a large containment isolation failure(s) occurs (e.g., valve failure to close). 5-3 ATTACHMENT 4 Clean Copies of Technical Specification Pages 5.0-16 TS 5.5.12 Programs and Manuals 5.5 5.5 Programs and Manuals (continued) 5.5.12 Primary Containment Leakage Rate Testing Program A program shall be established to implement the leakage rate testing of the primary containment as required by 1 O CFR 50.54(0) and 1 O 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 1 O CFR 50, Appendix J," Revision 3-A, dated July 2012, and the conditions and limitations specified in NEI 94-01, Revision 2-A, dated October 2008. The peak calculated primary containment internal pressure for the design basis loss of coolant accident, Pa, is 50.8 psig. The maximum allowable primary containment leakage rate, La, at Pa is 1.2% of primary containment air weight per day. Leakage rate acceptance criteria are: a. 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 Band Type C tests, and:::; 0.75 La for Type A tests; b. Air lock testing acceptance criteria are: 1) Overall air lock leakage rate is :::; 0.05 La when tested at?: Pa, 2) For each door, leakage rate is :::; 0.01 La when the gap between the door seals is pressurized to?: 1 O psig for at least 15 minutes. The provisions of SR 3.0.2 do not apply to the test frequencies specified in the Primary Containment Leakage Rate Testing Program. (continued)
HATCH UNIT 1 5.0-16 Amendment No.
Programs and Manuals 5.5 5.5 Programs and Manuals (continued) 5.5.12 Primary Containment Leakage Rate Testing Program A program shall be established to implement the leakage rate testing of the primary containment as required by 1 O CFR 50.54(0) and 1 O 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. The peak calculated primary containment internal pressure for the design basis loss of coolant accident, Pa, is 47.3 psig. The maximum allowable primary containment leakage rate, La, at Pa is 1.2°/ci of primary containment air weight per day. Leakage rate acceptance criteria are: a. 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; b. Air lock testing acceptance criteria are: 1) Overall air lock leakage rate is :::; 0.05 La when tested at:::; Pa, 2) For each door, leakage rate is :::; 0.01 La when the gap between the door seals is pressurized to ;::: 1 O psig for at least 15 minutes. The provisions of SR 3.0.2 do not apply to the test frequencies specified in the Primary Containment Leakage Rate Testing Program. (continued)
HATCH UNIT 2 5.0-16 Amendment No.