NL-04-155, Supporting Information for License Amendment Request Regarding Indian Point 3 Stretch Power Uprate: Difference between revisions
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{{#Wiki_filter:Entergy Nuclear Northeast Indian Point Energy Center | {{#Wiki_filter:Entergy Nuclear Northeast Indian Point Energy Center 450 Broadway, GSB | ||
~ En ergyP.O. | |||
Box 249 Buchanan, NY 10511-0249 Tel 914 734 6700 Fred Dacimo Site Vice President Administration December 15, 2004 Re: | |||
Indian Point Unit 3 Docket No. 50-286 NL-04-155 Document Control Desk U.S. Nuclear Regulatory Commission Mail Stop O-P1-17 Washington, DC 20555-0001 | |||
==Subject:== | ==Subject:== | ||
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==Reference:== | ==Reference:== | ||
: 1. Entergy Letter NL-04-069 to NRC; "Proposed Changes to Technical Specifications: Stretch Power Uprate (4.85%) and Adoption of TSTF-339", dated June 3, 2004. | : 1. Entergy Letter NL-04-069 to NRC; "Proposed Changes to Technical Specifications: Stretch Power Uprate (4.85%) and Adoption of TSTF-339", dated June 3, 2004. | ||
: 2. Entergy Letter NL-04-145 to NRC; "Supporting Information for License Amendment Request Regarding Indian Point 3 Stretch Power Uprate (TAC MC 3552)," dated November 18, 2004 | : 2. | ||
Entergy Letter NL-04-145 to NRC; "Supporting Information for License Amendment Request Regarding Indian Point 3 Stretch Power Uprate (TAC MC 3552)," dated November 18, 2004 | |||
==Dear Sir:== | ==Dear Sir:== | ||
Entergy Nuclear Operations, Inc (Entergy) is submitting additional information to support NRC review of the stretch power uprate (SPU) license amendment request (Reference 1) for Indian Point 3 (IP3). This additional information, based on NRC staff questions regarding the uprate request for Indian Point 2, is being provided as discussed during a meeting with NRC on September 14, 2004. This letter supplements the Reference 2 letter and covers the balance of questions regarding uprate request for Indian Point 2. is a summary listing of those RAls that are being addressed in this letter. The responses to the RAls are provided in Attachment 2, except for responses that contain proprietary information. The proprietary responses and the corresponding non-proprietary version of those responses are provided in Attachments 3 and 4, respectively. | Entergy Nuclear Operations, Inc (Entergy) is submitting additional information to support NRC review of the stretch power uprate (SPU) license amendment request (Reference 1) for Indian Point 3 (IP3). This additional information, based on NRC staff questions regarding the uprate request for Indian Point 2, is being provided as discussed during a meeting with NRC on September 14, 2004. This letter supplements the Reference 2 letter and covers the balance of questions regarding uprate request for Indian Point 2. is a summary listing of those RAls that are being addressed in this letter. The responses to the RAls are provided in Attachment 2, except for responses that contain proprietary information. The proprietary responses and the corresponding non-proprietary version of those responses are provided in Attachments 3 and 4, respectively. | ||
As Attachment 3 contains information proprietary to Westinghouse Electric Company, it is supported by an affidavit signed by Westinghouse, the owner of the information. The affidavit sets forth the basis on which the information may be withheld from public disclosure by the Commission and addresses with specificity the considerations listed in paragraph (b)(4) of Section 2.390 of the Commission's regulations. Accordingly, it is respectfully requested that the information that is proprietary to Westinghouse be withheld from public disclosure in accordance A.wo! | As Attachment 3 contains information proprietary to Westinghouse Electric Company, it is supported by an affidavit signed by Westinghouse, the owner of the information. The affidavit sets forth the basis on which the information may be withheld from public disclosure by the Commission and addresses with specificity the considerations listed in paragraph (b)(4) of Section 2.390 of the Commission's regulations. Accordingly, it is respectfully requested that the information that is proprietary to Westinghouse be withheld from public disclosure in accordance A.wo! | ||
NL-04-155 Docket 50-286 Page 2 of 3 with 10 CFR 2.390 of the Commission's regulations. Westinghouse authorization letter dated December 9, 2004 (CAW-04-1927), with the accompanying affidavit, Proprietary Information Notice, and Copyright Notice is provided in Enclosure A. | NL-04-155 Docket 50-286 Page 2 of 3 with 10 CFR 2.390 of the Commission's regulations. Westinghouse authorization {{letter dated|date=December 9, 2004|text=letter dated December 9, 2004}} (CAW-04-1927), with the accompanying affidavit, Proprietary Information Notice, and Copyright Notice is provided in Enclosure A. | ||
Correspondence with respect to the copyright on proprietary aspects of the items listed above or the supporting affidavit should reference CAW-04-1927 and should be addressed to J. A. | Correspondence with respect to the copyright on proprietary aspects of the items listed above or the supporting affidavit should reference CAW-04-1927 and should be addressed to J. A. | ||
Gresham, Manager, Regulatory Compliance and Plant Licensing, Westinghouse Electric Company LLC, P. 0. Box 355, Pittsburgh, Pennsylvania 15230-0355. | Gresham, Manager, Regulatory Compliance and Plant Licensing, Westinghouse Electric Company LLC, P. 0. Box 355, Pittsburgh, Pennsylvania 15230-0355. | ||
The additional supporting information provided in this letter does not alter the conclusions of the no significant hazards evaluation that supports the subject license amendment request. There are no new commitments being made in this submittal. If you have any questions or require additional information, please contact Mr. Kevin Kingsley at (914) 734-6695. | The additional supporting information provided in this letter does not alter the conclusions of the no significant hazards evaluation that supports the subject license amendment request. There are no new commitments being made in this submittal. If you have any questions or require additional information, please contact Mr. Kevin Kingsley at (914) 734-6695. | ||
I declare under penalty of perjury that the foregoing is true and correct. Executed on l__l___. | I declare under penalty of perjury that the foregoing is true and correct. Executed on l__l___. | ||
S | S Io Fred R. Dacimo Site Vice President Indian Point Energy Center : : : : | ||
Enclosure A: | |||
cc: next page Summary Listing of RAI Responses Regarding Stretch Power Uprate License Amendment Request for Indian Point 3 Additional Information for IP3 SPU License Amendment Request, Based on NRC RAls Issued for IP2 SPU Additional Information for IP3 SPU License Amendment Request, Based on NRC RAls Issued for IP2 SPU (with Proprietary Information) | |||
Additional Information for IP3 SPU License Amendment Request, Based on NRC RAls Issued for IP2 SPU (non-Proprietary version of Attachment 3) | |||
Westinghouse Withholding Request for Attachment 3 Proprietary Information | |||
NL-04-155 Docket 50-286 Page 3 of 3 cc: Mr. Patrick D. Milano, Senior Project Manager Project Directorate I Division of Licensing Project Management U.S. Nuclear Regulatory Commission Mail Stop 0 8 C2 Washington, DC 20555-0001 Mr. Samuel J. Collins Regional Administrator, Region 1 U.S. Nuclear Regulatory Commission 475 Allendale Road King of Prussia, PA 19406-1415 Resident Inspector's Office Indian Point Unit 3 U.S. Nuclear Regulatory Commission P.O. Box 337 Buchanan, NY 10511-0337 Mr. Peter R. Smith, President New York State Energy, Research and Development Authority 17 Columbia Circle Albany, NY 12203 Mr. Paul Eddy New York State Dept. of Public Service 3 Empire State Plaza Albany, NY 12223-6399 | NL-04-155 Docket 50-286 Page 3 of 3 cc: | ||
Mr. Patrick D. Milano, Senior Project Manager Project Directorate I Division of Licensing Project Management U.S. Nuclear Regulatory Commission Mail Stop 0 8 C2 Washington, DC 20555-0001 Mr. Samuel J. Collins Regional Administrator, Region 1 U.S. Nuclear Regulatory Commission 475 Allendale Road King of Prussia, PA 19406-1415 Resident Inspector's Office Indian Point Unit 3 U.S. Nuclear Regulatory Commission P.O. Box 337 Buchanan, NY 10511-0337 Mr. Peter R. Smith, President New York State Energy, Research and Development Authority 17 Columbia Circle Albany, NY 12203 Mr. Paul Eddy New York State Dept. of Public Service 3 Empire State Plaza Albany, NY 12223-6399 | |||
ATTACHMENT 1 TO NL-04-155 | ATTACHMENT 1 TO NL-04-155 | ||
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==SUMMARY== | ==SUMMARY== | ||
LISTING OF RAI RESPONSES REGARDING STRETCH POWER UPRATE LICENSE AMENDMENT REQUEST FOR INDIAN POINT 3 ENTERGY NUCLEAR OPERATIONS, INC. | LISTING OF RAI RESPONSES REGARDING STRETCH POWER UPRATE LICENSE AMENDMENT REQUEST FOR INDIAN POINT 3 ENTERGY NUCLEAR OPERATIONS, INC. | ||
INDIAN POINT NUCLEAR GENERATING UNIT NO. 3 DOCKET NO. 50-286 | INDIAN POINT NUCLEAR GENERATING UNIT NO. 3 DOCKET NO. 50-286 to NL-04-155 Docket 50-286 Page 1 of 4 No. | ||
RAI Review Area From Lefter IP3 Response I | |||
NL-04-073-FP-1 Fire Protection NL-04-073 Att 2 - Non-Proprietary 2 | |||
NL-04-073-FP-2 Fire Protection NL-04-073 Att 2 - Non-Proprietary 3 | |||
NL-04-073-FP-3a Fire Protection NL-04-073 Att 2 - Non-Proprietary 3 | |||
NL-04-073-FP-3b Fire Protection NL-04-073 Att 2 - Non-Proprietary 3 | |||
NL-04-073-FP-3c Fire Protection NL-04-073 Att 2 - Non-Proprietary 4 | |||
NL-04-073-EL-1 Electrical NL-04-073 Att 2 - Non-Proprietary 5 | |||
NL-04-073-IC-1 Instrumentation and Controls NL-04-073 See letter NL-04-145 6 | |||
NL-04-073-IC-2 Instrumentation and Controls NL-04-073 See letter NL-04-145 7 | |||
NL-04-073-IC-3 Instrumentation and Controls NL-04-073 See letter NL-04-145 8 | |||
NL-04-073-IC-4 Instrumentation and Controls NL-04-073 See letter NL-04-145 9 | |||
NL-04-073-IC-5 Instrumentation and Controls NL-04-073 See letter NL-04-145 10 NL-04-073-IC-6 Instrumentation and Controls NL-04-073 Not Applicable 11 NL-04-073-IC-7 Instrumentation and Controls NL-04-073 See letter NL-04-145 12 NL-04-073-PVM-la Pressure Vessel Materials NL-04-073 See letter NL-04-145 12 NL-04-073-PVM-1 b Pressure Vessel Materials NL-04-073 See letter NL-04-145 13 NL-04-073-PVM-2 Pressure Vessel Materials NL-04-073 See letter NL-04-145 14 NL-04-073-PVM-3a Pressure Vessel Materials NL-04-073 Not Applicable 14 NL-04-073-PVM-3b Pressure Vessel Materials NL-04-073 See letter NL-04-145 14 NL-04-073-PVM-3c Pressure Vessel Materials NL-04-073 See letter NL-04-145 15 NL-04-073-PVM-4a Pressure Vessel Materials NL-04-073 See letter NL-04-145 15 NL-04-073-PVM-4b Pressure Vessel Materials NL-04-073 See letter NL-04-145 15 NL-04-073-PVM-4c Pressure Vessel Materials NL-04-073 Att 2 - Non-Proprietary 15 NL-04-073-PVM-4d Pressure Vessel Materials NL-04-073 See letter NL-04-145 16 NL-04-073-RSA-1 Reactor Systems and Analyses NL-04-073 See letter NL-04-145 17 NL-04-073-RSA-2a Reactor Systems and Analyses NL-04-073 See letter NL-04-145 17 NL-04-073-RSA-2b Reactor Systems and Analyses NL-04-073 See letter NL-04-145 18 NL-04-073-RSA-3 Reactor Systems and Analyses NL-04-073 See letter NL-04-145 19 NL-04-073-RSA-4 Reactor Systems and Analyses NL-04-073 Not Applicable 20 NL-04-073-RSA-5 Reactor Systems and Analyses NL-04-073 Not Applicable 21 NL-04-073-RSA-6 Reactor Systems and Analyses NL-04-073 See letter NL-04-145 22 NL-04-073-RSA-7 Reactor Systems and Analyses NL-04-073 See letter NL-04-145 23 NL-04-073-RSA-8 Reactor Systems and Analyses NL-04-073 See letter NL-04-145 to NL-04-155 Docket 50-286 Page 2 of 4 No. | |||
RAI Review Area From Letter 1P3 Response 24 NL-04-073-RSA-9a Reactor Systems and Analyses NL-04-073 See letter NL-04-145 24 NL-04-073-RSA-9b Reactor Systems and Analyses NL-04-073 See letter NL-04-145 25 NL-04-073-RSA-10a Reactor Systems and Analyses NL-04-073 Not Applicable 25 NL-04-073-RSA-10b Reactor Systems and Analyses NL-04-073 See letter NL-04-145 25 NL-04-073-RSA-1Oc Reactor Systems and Analyses NL-04-073 See letter NL-04-145 25 NL-04-073-RSA-1Od Reactor Systems and Analyses NL-04-073 See letter NL-04-145 25 NL-04-073-RSA-10e Reactor Systems and Analyses NL-04-073 See letter NL-04-145 26 NL-04-073-RSA-1 1 Reactor Systems and Analyses NL-04-073 See letter NL-04-145 27 NL-04-073-RSA-12a Reactor Systems and Analyses NL-04-073 See letter NL-04-145 27 NL-04-073-RSA-12b Reactor Systems and Analyses NL-04-073 See letter NL-04-145 28 NL-04-073-RSA-13a Reactor Systems and Analyses NL-04-073 See letter NL-04-145 28 NL-04-073-RSA-13b Reactor Systems and Analyses NL-04-073 See letter NL-04-145 29 NL-04-073-RSA-14 Reactor Systems and Analyses NL-04-073 See letter NL-04-145 30 NL-04-073-RSA-15 Reactor Systems and Analyses NL-04-073 See letter NL-04-145 31 NL-04-073-RSA-16 Reactor Systems and Analyses NL-04-073 See letter NL-04-145 32 NL-04-073-RSA-17a Reactor Systems and Analyses NL-04-073 See letter NL-04-145 32 NL-04-073-RSA-17b Reactor Systems and Analyses NL-04-073 See letter NL-04-145 32 NL-04-073-RSA-17c Reactor Systems and Analyses NL-04-073 See letter NL-04-145 33 NL-04-073-RSA-18 Reactor Systems and Analyses NL-04-073 See letter NL-04-145 34 NL-04-073-RSA-19 Reactor Systems and Analyses NL-04-073 See letter NL-04-145 35 NL-04-073-RSA-20 Reactor Systems and Analyses NL-04-073 See letter NL-04-145 36 NL-04-073-ENV-1 Environmental Considerations NL-04-073 Not Applicable 37 NL-04-073-ENV-2 Environmental Considerations NL-04-073 Not Applicable 38 NL-04-073-ENV-3 Environmental Considerations NL-04-073 Att 2 - Non-Proprietary 39 NL-04-073-FAC-1 a Flow Accelerated Corrosion Program NL-04-073 See letter NL-04-145 39 NL-04-073-FAC-1b Flow Accelerated Corrosion Program NL-04-073 See letter NL-04-145 39 NL-04-073-FAC-lc Flow Accelerated Corrosion Program NL-04-073 See letter NL-04-145 39 NL-04-073-FAC-1 d Flow Accelerated Corrosion Program NL-04-073 See letter NL-04-145 39 NL-04-073-FAC-1 e Flow Accelerated Corrosion Program NL-04-073 See letter NL-04-145 40 NL-04-073-PCP-la Protective Coatings Program NL-04-073 See letter NL-04-145 40 NL-04-073-PCP-lb Protective Coatings Program NL-04-073 See letter NL-04-145 40 NL-04-073-PCP-lc Protective Coatings Program NL-04-073 See letter NL-04-145 to NL-04-155 Docket 50-286 Page 3 of 4 No. | |||
RAI Review Area From Letter 1P3 Response 41 NL-04-073-SG-1 Steam Generator Structural Integrity Evaluation NL-04-073 Not Applicable 42 NL-04-073-SG-2a Steam Generator Structural Integrity Evaluation NL-04-073 See letter NL-04-145 42 NL-04-073-SG-2b Steam Generator Structural Integrity Evaluation NL-04-073 Not Applicable 42 NL-04-073-SG-2c Steam Generator Structural Integrity Evaluation NL-04-073 See letter NL-04-145 43 NL-04-073-SG-3a Steam Generator Structural Integrity Evaluation NL-04-073 See letter NL-04-145 43 NL-04-073-SG-3b Steam Generator Structural Integrity Evaluation NL-04-073 See letter NL-04-145 44 NL-04-073-SG-4 Steam Generator Structural Integrity Evaluation NL-04-073 See letter NL-04-145 45 NL-04-073-SG-5 Steam Generator Structural Integrity Evaluation NL-04-073 See letter NL-04-145 46 NL-04-073-SG-6 Steam Generator Structural Integrity Evaluation NL-04-073 See letter NL-04-145 47 NL-04-073-SG-7 Steam Generator Structural Integrity Evaluation NL-04-073 See letter NL-04-145 48 NL-04-073-DOS-1 Dose Assessments NL-04-073 See letter NL-04-145 49 NL-04-073-DOS-2 Dose Assessments NL-04-073 See letter NL-04-145 50 NL-04-073-DOS-3 Dose Assessments NL-04-073 See letter NL-04-145 51 NL-04-073-DOS-4 Dose Assessments NL-04-073 See letter NL-04-145 52 NL-04-073-DOS-5 Dose Assessments NL-04-073 See letter NL-04-145 53 NL-04-086-FDF-1 Fuel Design Features and Components NL-04-086 See letter NL-04-145 54 NL-04-086-FDF-2 Fuel Design Features and Components NL-04-086 See letter NL-04-145 55 NL-04-086-FDF-3 Fuel Design Features and Components NL-04-086 See letter NL-04-145 56 NL-04-086-FDF-4 Fuel Design Features and Components NL-04-086 See letter NL-04-145 57 NL-04-086-FDF-5 Fuel Design Features and Components NL-04-086 See letter NL-04-145 58 NL-04-086-FDF-6 Fuel Design Features and Components NL-04-086 Not Applicable 59 NL-04-095-LOC-1 LOCA Transients NL-04-095 See letter NL-04-145 60 NL-04-095-LOC-2 LOCA Transients NL-04-095 Not Applicable NL-04-100-LOC-3 LOCA Transients NL-04-100 See NL-04-100-LOC-3 NL-04-100-LOC-4 LOCA Transients NL-04-100 See NL-04-100-LOC-4 NL-04-100-LOC-5 LOCA Transients NL-04-100 See NL-04-100-LOC-5 61 NL-04-095-NFS-1 NSSS Fluid Systems NL-04-095 See letter NL-04-145 62 NL-04-095-MDT-1 Mechanical Equipment Design Transients NL-04-095 Not Applicable 63 NL-04-095-PS-1 Piping and Supports NL-04-095 Att 2 - Non-Proprietary 64 NL-04-095-GIP-1 Generic Issues and Programs NL-04-095 See letter NL-04-145 65 NL-04-095-GIP-2 Generic Issues and Programs NL-04-095 Not Applicable 66 NL-04-095-GIP-3 Generic Issues and Programs NL-04-095 See letter NL-04-145 to NL-04-155 Docket 50-286 Page 4 of 4 No. | |||
RAI Review Area From Letter IP3 Response 67 NL-04-095-GIP-4 Generic Issues and Programs NL-04-095 See letter NL-04-145 68 NL-04-095-GIP-5 Generic Issues and Programs NL-04-095 See letter NL-04-145 69 NL-04-095-GIP-6 Generic Issues and Programs NL-04-095 See letter NL-04-145 70 NL-04-095-GIP-7 Generic Issues and Programs NL-04-095 See letter NL-04-145 71 NL-04-095-GIP-8 Generic Issues and Programs NL-04-095 See letter NL-04-145 72 NL-04-095-GIP-9 Generic Issues and Programs NL-04-095 Not Applicable 73 NL-04-095-GIP-10 Generic Issues and Programs NL-04-095 See letter NL-04-145 74 NL-04-095-GIP-1 1 Generic Issues and Programs NL-04-095 Att 2 - Non-Proprietary 75 NL-04-095-GIP-12 Generic Issues and Programs NL-04-095 Att 2 - Non-Proprietary 76 NL-04-095-GIP-13 Generic Issues and Programs NL-04-095 Att 2 - Non-Proprietary 77 NL-04-095-GIP-14 Generic Issues and Programs NL-04-095 Att 2 - Non-Proprietary 78 NL-04-100-LOC-3 LOCA Transients NL-04-100 Att 3, 4 - Proprietary 79 NL-04-100-LOC-4 LOCA Transients NL-04-1 00 Att 2 - Non-Proprietary 80 NL-04-100-LOC-5 LOCA Transients NL-04-100 Att 2 - Non-Proprietary 81 NL-04-100-PVM-3a -1 Pressure Vessel Materials NL-04-100 See letter NL-04-145 81 NL-04-100-PVM-3a -2 Pressure Vessel Materials NL-04-100 See letter NL-04-145 81 NL-04-100-PVM-3a -3 Pressure Vessel Materials NL-04-100 See letter NL-04-145 81 NL-04-100-PVM-3a -4 Pressure Vessel Materials NL-04-100 See letter NL-04-145 82 NL-04-100-PVM-4a -1 Pressure Vessel Materials NL-04-100 See letter NL-04-145 82 NL-04-100-PVM-4d -1 Pressure Vessel Materials NL-04-100 Att 2 - Non-Proprietary 82 NL-04-100-PVM-4d -2 Pressure Vessel Materials NL-04-100 Att 2 - Non-Proprietary 82 NL-04-100-PVM-4d -3 Pressure Vessel Materials NL-04-100 Att 2 - Non-Proprietary 83 NL-04-100-SG-1 Steam Generator Structural Integrity Evaluation NL-04-100 Not Applicable 84 NL-04-100-SG-3 Steam Generator Structural Integrity Evaluation NL-04-100 Not Applicable 85 NL-04-121-NRC-1 Mechanical Equipment Design Transients NL-04-121 See letter NL-04-145 86 NL-04-121-NRC-2 Piping and Supports NL-04-121 Att 2 - Non-Proprietary 87 NL-04-121-NRC-3 LOCA Transients NL-04-121 See letter NL-04-145 88 NL-04-121-NRC-4 Steam Generator Structural Integrity Evaluation NL-04-121 See letter NL-04-145 89 NL-04-121-NRC-5 NSSS Fluid Systems NL-04-121 See letter NL-04-145 90 NL-04-121-NRC-6 Pressure Vessel Materials NL-04-121 See letter NL-04-145 91 NL-04-121-NRC-7 Reactor Systems and Analyses NL-04-121 Att 2 - Non-Proprietary 92 NL-04-121-NRC-8 Pressure Vessel Materials NL-04-121 Att 2 - Non-Proprietary | |||
ATTACHMENT 2 TO NL-04-155 ADDITIONAL INFORMATION FOR IP3 SPU LICENSE AMENDMENT REQUEST BASED ON NRC RAIs ISSUED FOR IP2 SPU (Refer to Attachments 3 and 4 for other responses involving proprietary information) | ATTACHMENT 2 TO NL-04-155 ADDITIONAL INFORMATION FOR IP3 SPU LICENSE AMENDMENT REQUEST BASED ON NRC RAIs ISSUED FOR IP2 SPU (Refer to Attachments 3 and 4 for other responses involving proprietary information) | ||
ENTERGY NUCLEAR OPERATIONS, INC. | ENTERGY NUCLEAR OPERATIONS, INC. | ||
INDIAN POINT NUCLEAR GENERATING UNIT NO. 3 DOCKET NO. 50-286 | INDIAN POINT NUCLEAR GENERATING UNIT NO. 3 DOCKET NO. 50-286 to NL-04-155 Docket 50-286 Page 1 of 40 Non-Proprietary Question NL-04-073-FP-1: | ||
In NRR RS-001, Revision 0, 'Review Standard for Extended Power Uprates," Attachment 2 to Matrix 5, "Supplemental Fire Protection Review Criteria," states that "... power uprates typically result in increases in decay heat generation following plant trips. These increases in decay heat usually do not affect the elements of a fire protection program related to (1) administrative controls, (2) fire suppression and detection systems, (3) fire barriers, (4) fire protection responsibilities of plant personnel, and (5) procedures and resources necessary for the repair of systems required to achieve and maintain cold shutdown. In addition, an increase in decay heat will usually not result in an increase in the potential for a radiological release resulting from a fire. However, the licensee's application should confirm that these elements are not impacted by the extended power uprate..." | In NRR RS-001, Revision 0, 'Review Standard for Extended Power Uprates," Attachment 2 to Matrix 5, "Supplemental Fire Protection Review Criteria," states that "... power uprates typically result in increases in decay heat generation following plant trips. These increases in decay heat usually do not affect the elements of a fire protection program related to (1) administrative controls, (2) fire suppression and detection systems, (3) fire barriers, (4) fire protection responsibilities of plant personnel, and (5) procedures and resources necessary for the repair of systems required to achieve and maintain cold shutdown. In addition, an increase in decay heat will usually not result in an increase in the potential for a radiological release resulting from a fire. However, the licensee's application should confirm that these elements are not impacted by the extended power uprate..." | ||
Section 10.1, "Fire Protection (10CFR50 Appendix R) Program," of application report (Attachment IlIl to the January 29 letter) does not address these items. At a minimum, provide a statement to address each of these items. | Section 10.1, "Fire Protection (10CFR50 Appendix R) Program," of application report (Attachment IlIl to the January 29 letter) does not address these items. At a minimum, provide a statement to address each of these items. | ||
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IP3 SPU results in increased decay heat generation following plant trips. The RHR Cooldown Analysis for SPU, documents that cold shutdown is achieved and maintained within 72 hours. It should be noted that the subject analysis includes a specific "Appendix R" cooldown case that uses only the limited equipment set credited in the IP3 Appendix R Safe-Shutdown Model. The updated cooldown analysis and evaluation addressing SPU confirms that cold shutdown can be achieved and maintained using this same limited equipment set, inclusive of the additional burden associated with SPU. Appendix R program administrative controls are unchanged. The elements of the program such as Fire Suppression; Fire Barriers; Fire protection responsibilities of plant personnel are unchanged. Procedures and resources necessary for the repair of systems required to achieve and maintain cold shutdown are unaffected and the radiological release resulting from a fire is also unchanged. | IP3 SPU results in increased decay heat generation following plant trips. The RHR Cooldown Analysis for SPU, documents that cold shutdown is achieved and maintained within 72 hours. It should be noted that the subject analysis includes a specific "Appendix R" cooldown case that uses only the limited equipment set credited in the IP3 Appendix R Safe-Shutdown Model. The updated cooldown analysis and evaluation addressing SPU confirms that cold shutdown can be achieved and maintained using this same limited equipment set, inclusive of the additional burden associated with SPU. Appendix R program administrative controls are unchanged. The elements of the program such as Fire Suppression; Fire Barriers; Fire protection responsibilities of plant personnel are unchanged. Procedures and resources necessary for the repair of systems required to achieve and maintain cold shutdown are unaffected and the radiological release resulting from a fire is also unchanged. | ||
Question NL-04-073-FP-2: | Question NL-04-073-FP-2: | ||
In NRR RS-001, Attachment 2 to Matrix 5, states that "... where licensees rely on less than full capability systems for fire events..., the licensee should provide specific analyses for fire events that demonstrate that (1) fuel integrity is maintained by demonstrating that the fuel design limits are not exceeded and (2) there are no adverse consequences on the reactor pressure vessel integrity or the attached piping. Plants that rely on alternative/dedicated or backup shutdown capability for post-fire safe shutdown should analyze the impact of the power uprate on the alternative/dedicated or backup shutdown capability ... The licensee should identify the impact of the power uprate on the plant's post-fire safe shutdown procedures." | In NRR RS-001, Attachment 2 to Matrix 5, states that "... where licensees rely on less than full capability systems for fire events..., the licensee should provide specific analyses for fire events that demonstrate that (1) fuel integrity is maintained by demonstrating that the fuel design limits are not exceeded and (2) there are no adverse consequences on the reactor pressure vessel integrity or the attached piping. Plants that rely on alternative/dedicated or backup shutdown capability for post-fire safe shutdown should analyze the impact of the power uprate on the alternative/dedicated or backup shutdown capability... The licensee should identify the impact of the power uprate on the plant's post-fire safe shutdown procedures." | ||
Section 10.1, of application report does not address the items above. As a minimum, provide a statement to address each of these items. | Section 10.1, of application report does not address the items above. As a minimum, provide a statement to address each of these items. | ||
Response NL-04-073-FP-2: | Response NL-04-073-FP-2: | ||
The evaluation of the IP3 Fire Protection Program was conducted to determine the effect of SPU on the program. There are no modifications required by the SPU to the plant equipment | The evaluation of the IP3 Fire Protection Program was conducted to determine the effect of SPU on the program. There are no modifications required by the SPU to the plant equipment to NL-04-155 Docket 50-286 Page 2 of 40 Non-Proprietary used for post-fire safe shutdown. There are minor changes required for the procedures. The procedures are capable of being used to achieve post-fire safe shutdown as shown by the response to item FP-3b and as noted in section 4.1.3 of the IP3 SPU Licensing Report. | ||
The analysis and evaluations for the Appendix R cooldown show that the plant is maintained and cooled to 200'F with RCS pressure below the RCS Safety Valve setpoint, with level in the pressurizer, with positive subcooling and with decay heat being removed. Based on the analysis and evaluations for the Appendix R cooldown, the fuel remains covered and therefore fuel design limits are not exceeded and there are no adverse consequences on the reactor pressure vessel integrity or the attached piping. Additional detail regarding the Appendix R cooldown analysis and evaluation is provided in the response to question 3b. | The analysis and evaluations for the Appendix R cooldown show that the plant is maintained and cooled to 200'F with RCS pressure below the RCS Safety Valve setpoint, with level in the pressurizer, with positive subcooling and with decay heat being removed. Based on the analysis and evaluations for the Appendix R cooldown, the fuel remains covered and therefore fuel design limits are not exceeded and there are no adverse consequences on the reactor pressure vessel integrity or the attached piping. Additional detail regarding the Appendix R cooldown analysis and evaluation is provided in the response to question 3b. | ||
Alternate Shutdown Capability The normal sources of auxiliary ac power at IP3 during plant operation are both off-site power and three emergency diesel generators. If these sources are disabled by fire, the safe-shutdown loads can be supplied by an alternate diesel generator. As addressed in the Indian Point Unit 3 UFSAR, Section 9.6.2.5, "Safe Shutdown Capability in Case of Fire," there are two alternate shutdown schemes credited in compliance with 10CFR50 Appendix R, Section III.G.3, that utilize an alternate diesel generator (referred to herein as the "Appendix R diesel generator"): (1) a scheme that makes use of local control stations in the Auxiliary Feedwater (AFW) Pump Room, Primary Auxiliary Building (PAB), and the Auxiliary Boiler Feedwater Pump Building to effect shutdown following a fire that requires safe shutdown from outside the Control Room, and (2) a scheme that makes use of the'Appendix R diesel generator aligned to the 480V vital buses to ensure safe shutdown from the Control Room. | Alternate Shutdown Capability The normal sources of auxiliary ac power at IP3 during plant operation are both off-site power and three emergency diesel generators. If these sources are disabled by fire, the safe-shutdown loads can be supplied by an alternate diesel generator. As addressed in the Indian Point Unit 3 UFSAR, Section 9.6.2.5, "Safe Shutdown Capability in Case of Fire," there are two alternate shutdown schemes credited in compliance with 10CFR50 Appendix R, Section III.G.3, that utilize an alternate diesel generator (referred to herein as the "Appendix R diesel generator"): (1) a scheme that makes use of local control stations in the Auxiliary Feedwater (AFW) Pump Room, Primary Auxiliary Building (PAB), and the Auxiliary Boiler Feedwater Pump Building to effect shutdown following a fire that requires safe shutdown from outside the Control Room, and (2) a scheme that makes use of the'Appendix R diesel generator aligned to the 480V vital buses to ensure safe shutdown from the Control Room. | ||
| Line 80: | Line 89: | ||
The local control station in the PAB is provided with indication of pressurizer level, RCS pressure, and source range neutron flux. Operators at this location will control RCS boration and makeup with the charging pumps. The local control station in the AFW Pump Room is provided with indication of steam generator water level and pressure, pressurizer level, RCS pressure, and RCS loop 31 hot and cold leg temperature. The local control station for the Steam Generator atmospheric relief valves is located in the Auxiliary Feedwater Pump Building. | The local control station in the PAB is provided with indication of pressurizer level, RCS pressure, and source range neutron flux. Operators at this location will control RCS boration and makeup with the charging pumps. The local control station in the AFW Pump Room is provided with indication of steam generator water level and pressure, pressurizer level, RCS pressure, and RCS loop 31 hot and cold leg temperature. The local control station for the Steam Generator atmospheric relief valves is located in the Auxiliary Feedwater Pump Building. | ||
The SPU does not affect the above-described alternate shutdown schemes. There are no modifications required by the SPU to the plant equipment used for post-fire safe shutdown. | The SPU does not affect the above-described alternate shutdown schemes. There are no modifications required by the SPU to the plant equipment used for post-fire safe shutdown. | ||
to NL-04-155 Docket 50-286 Page 3 of 40 Non-Proprietary Evaluation of Appendix R DG load requirements under SPU conditions shows that there are no significant load increases that would affect the conclusions of the existing Appendix R DG load analysis. | |||
Question NL-04-073-FP-3: | Question NL-04-073-FP-3: | ||
Section 10.1 of Attachment IlIl (WCAP-16157-P) to the License Amendment Request, states that "for the SPU, the steam generator dryout time provides adequate time for the operator to supply feedwater to the secondary side of the steam generator. The Appendix R plant cooldown analysis under SPU conditions shows that IP2 complies with the Appendix R requirement that cold shutdown be achieved within 72 hours after reactor trip following a fire." | Section 10.1 of Attachment IlIl (WCAP-16157-P) to the License Amendment Request, states that "for the SPU, the steam generator dryout time provides adequate time for the operator to supply feedwater to the secondary side of the steam generator. The Appendix R plant cooldown analysis under SPU conditions shows that IP2 complies with the Appendix R requirement that cold shutdown be achieved within 72 hours after reactor trip following a fire." | ||
| Line 93: | Line 101: | ||
Response NL-04-073-FP-3b: | Response NL-04-073-FP-3b: | ||
For purposes of Appendix R cooldown analysis, the RHR cooldown analysis for Appendix R conditions is discussed in Section 4.1.3 of WCAP-16212-P and documents the cooldown from the RHR cooldown initiation to achieving cold shutdown with in the Appendix R requirement of 72 hours. The evaluation of a natural circulation cooldown from normal operating temperature (NOT) to RHR cooldown initiation conditions at 350"F is discussed below. | For purposes of Appendix R cooldown analysis, the RHR cooldown analysis for Appendix R conditions is discussed in Section 4.1.3 of WCAP-16212-P and documents the cooldown from the RHR cooldown initiation to achieving cold shutdown with in the Appendix R requirement of 72 hours. The evaluation of a natural circulation cooldown from normal operating temperature (NOT) to RHR cooldown initiation conditions at 350"F is discussed below. | ||
to NL-04-155 Docket 50-286 Page 4 of 40 Non-Proprietary Natural Circulation Cooling Analysis (NOT to 3500F) | |||
To demonstrate that the stretch power uprate (SPU) does not adversely affect the natural circulation cooling capability of the IP3 plant, an evaluation for post-fire safe shutdown was performed. The evaluation considered only on the limited equipment set available for the IP3 Appendix R safe-shutdown conditions. It was based on the scheme that makes use of local control stations in the Auxiliary Feedwater (AFW) Pump Room, Primary Auxiliary Building (PAB), and the Auxiliary Boiler Feedwater Pump Building to effect shutdown following a fire that requires safe shutdown from outside the Control Room. Following plant trip and control room evacuation, the plant is cooled by steam relief from the Main Steam Safety Valves. RCPs are tripped and pressurizer PORVs and pressurizer heaters are assumed unavailable. One motor-driven AFW pump feeding 2 Steam Generators with manual flow control is credited after 30 minutes. One charging pump is assumed after 60 minutes to provide RCS makeup from the RWST and to increase RCS boron concentration. Charging flow is manually controlled. Plant cooldown at 250F/hr is commenced 4 hours after reactor trip. Steam Generator Atmospheric Relief valves are manually operated to control the cooldown. A total delay of 8 hours is assumed to allow the upper head to cool or 'soak" before depressurizing to the RHR cut-in pressure. As per the ERG generic analysis, this upper-head soak delay is included to allow the upper-head region sufficient time to cool due to the assumed loss of control rod drive mechanism (CRDM) fans. | To demonstrate that the stretch power uprate (SPU) does not adversely affect the natural circulation cooling capability of the IP3 plant, an evaluation for post-fire safe shutdown was performed. The evaluation considered only on the limited equipment set available for the IP3 Appendix R safe-shutdown conditions. It was based on the scheme that makes use of local control stations in the Auxiliary Feedwater (AFW) Pump Room, Primary Auxiliary Building (PAB), and the Auxiliary Boiler Feedwater Pump Building to effect shutdown following a fire that requires safe shutdown from outside the Control Room. Following plant trip and control room evacuation, the plant is cooled by steam relief from the Main Steam Safety Valves. RCPs are tripped and pressurizer PORVs and pressurizer heaters are assumed unavailable. One motor-driven AFW pump feeding 2 Steam Generators with manual flow control is credited after 30 minutes. One charging pump is assumed after 60 minutes to provide RCS makeup from the RWST and to increase RCS boron concentration. Charging flow is manually controlled. Plant cooldown at 250F/hr is commenced 4 hours after reactor trip. Steam Generator Atmospheric Relief valves are manually operated to control the cooldown. A total delay of 8 hours is assumed to allow the upper head to cool or 'soak" before depressurizing to the RHR cut-in pressure. As per the ERG generic analysis, this upper-head soak delay is included to allow the upper-head region sufficient time to cool due to the assumed loss of control rod drive mechanism (CRDM) fans. | ||
The SPU evaluation concluded that the RCS pressure would be stabilized at 375 psia (360 psig) with Thot < | The SPU evaluation concluded that the RCS pressure would be stabilized at 375 psia (360 psig) with Thot < 3500F in all hot legs and at the core exit at approximately 28 hours after reactor trip. | ||
From this condition, RHR cooling can be initiated to cool the RCS to < 200WF. within 72 hours. | From this condition, RHR cooling can be initiated to cool the RCS to < 200WF. within 72 hours. | ||
RHR Cooling Analysis ( | RHR Cooling Analysis (3500F to 200 0F) | ||
The SPU affects the plant cooldown time(s) since core power, and therefore the decay heat increases. The plant cooldown calculation was performed at a core power of 3216 MWt to support the SPU. The RCS heat capacity and the other RHR heat loads were explicitly considered in these analyses. The analysis was performed to confirm that the RHR and CCW systems continue to meet their design basis functional requirements and performance criteria for plant cooldown under the uprated power conditions. The two-train system alignment was considered to address the design capability in the Indian Point Unit 3 Updated Final Safety Analysis Report (UFSAR). In addition, a cooldown analysis was performed to support the worst-case scenario for the 10CFR50 Appendix R (Reference 4) fire safe shutdown analysis. | The SPU affects the plant cooldown time(s) since core power, and therefore the decay heat increases. The plant cooldown calculation was performed at a core power of 3216 MWt to support the SPU. The RCS heat capacity and the other RHR heat loads were explicitly considered in these analyses. The analysis was performed to confirm that the RHR and CCW systems continue to meet their design basis functional requirements and performance criteria for plant cooldown under the uprated power conditions. The two-train system alignment was considered to address the design capability in the Indian Point Unit 3 Updated Final Safety Analysis Report (UFSAR). In addition, a cooldown analysis was performed to support the worst-case scenario for the 10CFR50 Appendix R (Reference 4) fire safe shutdown analysis. | ||
The following considerations were applied to these cooldown analyses: | The following considerations were applied to these cooldown analyses: | ||
* The CCW and RHR HX data assumes 5-percent tube plugging, as was used for the previous cooldown analyses of record (AOR). | * The CCW and RHR HX data assumes 5-percent tube plugging, as was used for the previous cooldown analyses of record (AOR). | ||
* The design service water temperature of | * The design service water temperature of 950F was assumed. For the Appendix R cooldown, the CCWS supply temperature is limited to 1250F. | ||
* Various CCWS auxiliary heat loads and the RCS heat capacity were included in the normal cooldown cases and the Appendix R plant cooldown case. These heat loads, along with an increase in the spent fuel pool heat load (assuming a full SFP of fuel that has operated at 3216 MWt) were used in the cooldown analysis. | * Various CCWS auxiliary heat loads and the RCS heat capacity were included in the normal cooldown cases and the Appendix R plant cooldown case. These heat loads, along with an increase in the spent fuel pool heat load (assuming a full SFP of fuel that has operated at 3216 MWt) were used in the cooldown analysis. | ||
to NL-04-155 Docket 50-286 Page 5 of 40 Non-Proprietary Decay heat curves based on 24-month fuel cycles were used. | |||
Service water (SW) flow rates for Appendix R cooldown were varied to minimize SW flow demand while meeting the Appendix R criteria as shown in Table NL-04-073-FP-1. | |||
The Appendix R/safe shutdown cases continue to meet the 72-hour time limit for cold shutdown. | The Appendix R/safe shutdown cases continue to meet the 72-hour time limit for cold shutdown. | ||
For these cases, the minimum CCW HX service water flow to meet the time 72 hour cooldown time limit criterion was determined as shown in Table NL-04-073-FP-1. | For these cases, the minimum CCW HX service water flow to meet the time 72 hour cooldown time limit criterion was determined as shown in Table NL-04-073-FP-1. | ||
Acceptable RHR cooldown performance is provided at the SPU conditions for normal plant cooldown and the limiting Appendix R/safe shutdown cases, based on the service water flows shown in Table NL-04-073-FP-1. | Acceptable RHR cooldown performance is provided at the SPU conditions for normal plant cooldown and the limiting Appendix R/safe shutdown cases, based on the service water flows shown in Table NL-04-073-FP-1. | ||
Table NL-04-073-FP-1 SPU Cooldown Analyses Results Cooldown Time | Table NL-04-073-FP-1 SPU Cooldown Analyses Results Cooldown Time Cooldown Time RHR Initiation Time Total SW to 1400F (hrs. | ||
A. App. R, Enhanced CCW | to 200OF (hrs. | ||
Cooldown Time D. Same as A without SFP | @3500F (hrs. after Flow Cases after shutdown) after shutdown) shutdown)(' | ||
: 1. The 29-hour cut-in time for the Appendix | (gpm) | ||
: 2. These cases increase the component cooling water return piping temperature compared to the previous 1.4% MUR Appendix | A. App. R, Enhanced CCW N/A 64.8(2) 29.0 5700 UAIU, 5700 gpm SW Flow B. App. R, Enhanced CCW N/A 71.8 29.0 4700 UA/U, SW Flow Minimized to Meet 72-hr. Cooldown Time C. App. R, Original Design N/A 71.9 29.0 5324 SSC UANU, SW Flow Minimized to Meet 72-hr. | ||
Appendix R Cooldown analysis and evaluation demonstrate that IP3 can be cooled from the normal operating temperature to the RHR initiation conditions using a natural circulation cooling | Cooldown Time D. Same as A without SFP NIA 58.0(2) 29.0 5700 Heat Load E. Same as B without SFP N/A 71.8 29.0 3596 Heat Load F. Same as C. Without SFP N/A 72.0 29.0 3918 Heat Load Notes: | ||
: 1. The 29-hour cut-in time for the Appendix R cases, limited by the Ccws supply temperature, is also indicative of the cut-in time assumed in the radiological consequences analyses of accidents with secondary side releases (that is, SGTR). | |||
: 2. These cases increase the component cooling water return piping temperature compared to the previous 1.4% MUR Appendix R analysis. Previous Appendix R cases had a maximum return temperature of 173 0F, and the temperature for case D is 188*F, which remains bounded by post-LOCA conditions. | |||
Appendix R Cooldown analysis and evaluation demonstrate that IP3 can be cooled from the normal operating temperature to the RHR initiation conditions using a natural circulation cooling to NL-04-155 Docket 50-286 Page 6 of 40 Non-Proprietary process in 29 hours and from the RHR initiation condition to cold shutdown within the requirement of 72 hours. | |||
Response NL-04-073-FP-3c: | Response NL-04-073-FP-3c: | ||
The Indian Point Unit 3 UFSAR, Table 9.3-2, "Residual Heat Removal Loop Component Data," | The Indian Point Unit 3 UFSAR, Table 9.3-2, "Residual Heat Removal Loop Component Data," | ||
| Line 126: | Line 132: | ||
The Appendix R diesel generator (DG) is a dedicated 2500 kw diesel generator located in its own enclosure in the yard area. AC power generated by the Appendix R DG can be supplied to 6.9 kv buses 5 and 6. These buses in turn feed 6.9 kv buses 1 and 3, which supply 480V to buses 312 through 313 through step-down transformers. Supporting services for the Appendix R ac power source are independent of the supporting equipment used by the emergency diesel generators (e.g., service water, 125V dc control power, starting air, and fuel oil). | The Appendix R diesel generator (DG) is a dedicated 2500 kw diesel generator located in its own enclosure in the yard area. AC power generated by the Appendix R DG can be supplied to 6.9 kv buses 5 and 6. These buses in turn feed 6.9 kv buses 1 and 3, which supply 480V to buses 312 through 313 through step-down transformers. Supporting services for the Appendix R ac power source are independent of the supporting equipment used by the emergency diesel generators (e.g., service water, 125V dc control power, starting air, and fuel oil). | ||
The alternative power system, as described above, is designed to be independent and sufficiently isolated from the existing emergency power system to ensure the availability of power to the safe shutdown equipment of concern in the event of fires in the Control and Diesel Generator Buildings. In case of a fire affecting certain portions of the PAB and Electrical Tunnels which could disable emergency diesel generator auxiliaries, the Appendix R DG can be used to power the 480V vital buses to ensure safe shutdown from the Control Room. | The alternative power system, as described above, is designed to be independent and sufficiently isolated from the existing emergency power system to ensure the availability of power to the safe shutdown equipment of concern in the event of fires in the Control and Diesel Generator Buildings. In case of a fire affecting certain portions of the PAB and Electrical Tunnels which could disable emergency diesel generator auxiliaries, the Appendix R DG can be used to power the 480V vital buses to ensure safe shutdown from the Control Room. | ||
The local control station in the PAB is provided with indication of pressurizer level, RCS pressure, and source range neutron flux. Operators at this location will control RCS boration and makeup with the charging pumps. The local control station in the AFW Pump Room is provided with indication of steam generator water level and pressure, pressurizer level, RCS | The local control station in the PAB is provided with indication of pressurizer level, RCS pressure, and source range neutron flux. Operators at this location will control RCS boration and makeup with the charging pumps. The local control station in the AFW Pump Room is provided with indication of steam generator water level and pressure, pressurizer level, RCS to NL-04-155 Docket 50-286 Page 7 of 40 Non-Proprietary pressure, and RCS loop 31 hot and cold leg temperature. The local control station for the atmospheric dump valves is located in the Auxiliary Feedwater Pump Building. | ||
The SPU does not affect the above-described alternate shutdown schemes. There are no modifications required by the SPU to the plant equipment used for post-fire safe shutdown. | The SPU does not affect the above-described alternate shutdown schemes. There are no modifications required by the SPU to the plant equipment used for post-fire safe shutdown. | ||
Evaluation of Appendix R DG load requirements under SPU conditions shows that there are no significant load increases that would affect the conclusions of the existing Appendix R DG load analysis. | Evaluation of Appendix R DG load requirements under SPU conditions shows that there are no significant load increases that would affect the conclusions of the existing Appendix R DG load analysis. | ||
| Line 143: | Line 147: | ||
: a. Describe the analysis that determined a 0.50-inch flaw depth for the safety and relief nozzle (corner) and a 0.1 5-inch flaw depth for the upper shell will meet the fracture toughness requirements of Appendix G of the ASME Code. | : a. Describe the analysis that determined a 0.50-inch flaw depth for the safety and relief nozzle (corner) and a 0.1 5-inch flaw depth for the upper shell will meet the fracture toughness requirements of Appendix G of the ASME Code. | ||
: b. Identify whether the analysis satisfies the requirements of Article G-2220 of Section Xl of the ASME Code. Does the analysis for the safety and relief nozzles and upper shell satisfy these structural factors? | : b. Identify whether the analysis satisfies the requirements of Article G-2220 of Section Xl of the ASME Code. Does the analysis for the safety and relief nozzles and upper shell satisfy these structural factors? | ||
to NL-04-155 Docket 50-286 Page 8 of 40 Non-Proprietary | |||
: c. Describe the non-destructive examination technique which will be utilized to inspect the safety and relief nozzles and upper shell. | : c. Describe the non-destructive examination technique which will be utilized to inspect the safety and relief nozzles and upper shell. | ||
: d. Provide the data, a description of the analysis, and the probability of detection of flaws with a depth of 0.50-inch for the safety and relief nozzle and 0.1 5-inch for the upper shell. | : d. Provide the data, a description of the analysis, and the probability of detection of flaws with a depth of 0.50-inch for the safety and relief nozzle and 0.1 5-inch for the upper shell. | ||
| Line 154: | Line 157: | ||
As noted in NL-04-145 response to NL-04-073-PVM-4a, the revised calculations for the pressurizer nozzles demonstrate that the postulated flaw size meets the requirements of Appendix G (1/4t or 1 inch). | As noted in NL-04-145 response to NL-04-073-PVM-4a, the revised calculations for the pressurizer nozzles demonstrate that the postulated flaw size meets the requirements of Appendix G (1/4t or 1 inch). | ||
Safety and Relief Nozzle: | Safety and Relief Nozzle: | ||
The IP3 Pressurizer has three Code Safety Inner Radius Nozzles (201R, 21 IR, and 221R) and one Power Operated Relief Inner Radius Nozzle (231R). These nozzles are ASME Section Xl, Code Category B-D, Item B3.120. These nozzles require volumetric examinations per ASME Section Xl, 1989 Code Edition. However, for the Third | The IP3 Pressurizer has three Code Safety Inner Radius Nozzles (201R, 21 IR, and 221R) and one Power Operated Relief Inner Radius Nozzle (231R). These nozzles are ASME Section Xl, Code Category B-D, Item B3.120. These nozzles require volumetric examinations per ASME Section Xl, 1989 Code Edition. However, for the Third 1 0-year Interval, which ends in July 2009, Entergy submitted Relief Request 3-16 to perform a remote visual (VT-1) with color capability on each of the nozzle inner radius sections. The NRC approved this relief request on April 22, 2003 (TAC No. MB4766). | ||
Upper Shell: | Upper Shell: | ||
The IP3 Pressurizer shell has 9 circumferential welds (1, 3, 5, 7, 9, 11, 13, 15, 17) and 8 longitudinal welds (2, 4, 6, 8, 10, 12, 14, 16). For the purposes of this discussion, welds 16, and 17 will be considered the upper shell welds since weld 17 is the uppermost circumferential weld and weld 16 is its intersecting longitudinal weld. These welds are the welds required to be inspected by ASME Section Xl, Table IWB-2500-1, Code Category B-B, Item B2.11 and B2.12. | The IP3 Pressurizer shell has 9 circumferential welds (1, 3, 5, 7, 9, 11, 13, 15, 17) and 8 longitudinal welds (2, 4, 6, 8, 10, 12, 14, 16). For the purposes of this discussion, welds 16, and 17 will be considered the upper shell welds since weld 17 is the uppermost circumferential weld and weld 16 is its intersecting longitudinal weld. These welds are the welds required to be inspected by ASME Section Xl, Table IWB-2500-1, Code Category B-B, Item B2.11 and B2.12. | ||
Table IWB-2500-1, Category B-B, Note 4 requires the volumetric coverage stipulated by Figures IWB-2500-1 and 2 be performed on 100% of the Code Class 1 circumferential welds and the adjoining 1 foot section of the longitudinal welds. The upper circumferential (17) and longitudinal (16) welds are enclosed in a biological and missile shield and are completely inaccessible for volumetric examination (NDE). Therefore, for the Third | Table IWB-2500-1, Category B-B, Note 4 requires the volumetric coverage stipulated by Figures IWB-2500-1 and 2 be performed on 100% of the Code Class 1 circumferential welds and the adjoining 1 foot section of the longitudinal welds. The upper circumferential (17) and longitudinal (16) welds are enclosed in a biological and missile shield and are completely inaccessible for volumetric examination (NDE). Therefore, for the Third 1 0-year Interval, which ends in July 2009, Entergy submitted Relief Request 3-14 to perform a visual examination (VT- | ||
: 2) for leakage during system pressure tests performed each refueling outage in accordance with IWB-2500, Category B-P and Code Case N-498-1. The NRC approved this relief request on April 22, 2003 (TAC No. MB4766). | : 2) for leakage during system pressure tests performed each refueling outage in accordance with IWB-2500, Category B-P and Code Case N-498-1. The NRC approved this relief request on April 22, 2003 (TAC No. MB4766). | ||
to NL-04-155 Docket 50-286 Page 9 of 40 Non-Proprietary Response NL-04-073-PVM-4d: | |||
See letter NL-04-145 for response. | See letter NL-04-145 for response. | ||
Question NL-04-073-ENV-3: | Question NL-04-073-ENV-3: | ||
| Line 169: | Line 171: | ||
The qualitative assessment is based on methodology and equations found in NUREG-0017 Rev. 1 (Ref 1), and a comparison of the change in power level and in plant coolant system parameters (e.g., reactor coolant mass, steam generator liquid mass, steam flow rate, reactor coolant letdown flow rate, flow rate to the cation demineralizer, letdown flow rate for boron control, steam generator blowdown flow rate, steam generator moisture carryover, etc.) for both pre-uprate and uprate conditions. To estimate an upper bound impact on off-site doses, the highest factor found for any chemical group of radioisotopes pertinent to the release pathway is applied to the average doses previously determined as representative of operation at pre-uprate conditions (at 100% availability) to estimate the maximum potential increase in effluent doses due to the uprate and demonstrate that the estimated off-site doses following uprate, although increased, will continue to remain below regulatory limits. | The qualitative assessment is based on methodology and equations found in NUREG-0017 Rev. 1 (Ref 1), and a comparison of the change in power level and in plant coolant system parameters (e.g., reactor coolant mass, steam generator liquid mass, steam flow rate, reactor coolant letdown flow rate, flow rate to the cation demineralizer, letdown flow rate for boron control, steam generator blowdown flow rate, steam generator moisture carryover, etc.) for both pre-uprate and uprate conditions. To estimate an upper bound impact on off-site doses, the highest factor found for any chemical group of radioisotopes pertinent to the release pathway is applied to the average doses previously determined as representative of operation at pre-uprate conditions (at 100% availability) to estimate the maximum potential increase in effluent doses due to the uprate and demonstrate that the estimated off-site doses following uprate, although increased, will continue to remain below regulatory limits. | ||
The criteria used in the evaluation include a liquid and gaseous radwaste systems' design capable of maintaining normal operation offsite releases and doses within the requirements of 10CFR50, Appendix I (Ref. 2) following power uprate. (Note that actual performance and operation of installed equipment, and reporting of actual offsite releases and doses continues to be controlled by the requirements of the Technical Specifications and the Offsite Dose Calculation Manual.) | The criteria used in the evaluation include a liquid and gaseous radwaste systems' design capable of maintaining normal operation offsite releases and doses within the requirements of 10CFR50, Appendix I (Ref. 2) following power uprate. (Note that actual performance and operation of installed equipment, and reporting of actual offsite releases and doses continues to be controlled by the requirements of the Technical Specifications and the Offsite Dose Calculation Manual.) | ||
to NL-04-155 Docket 50-286 Page 10 of 40 Non-Proprietary The non-radiological impact of the IP3 SPU to 3216 MWt was reviewed and evaluated considering the information contained in the Final Environmental Statement (FES) (Ref. 3) for the station. Section 1 of Appendix B of the Facility Operating License requires environmental concerns identified in the FES that relate to water quality matters to be regulated by way of the State Pollutant Discharge Elimination System (SPDES) permit (Ref. 4) limits. The Indian Point SPDES restrictions on discharge temperatures and discharge flow rates for the station were evaluated along with the flow limits set forth in IP3 SPDES Consent Order (Ref. 5). | |||
The criteria used in the evaluation required that the environmental impacts associated with the proposed changes be within the existing regulatory release permits. | The criteria used in the evaluation required that the environmental impacts associated with the proposed changes be within the existing regulatory release permits. | ||
Uprate Evaluation Radiological Effects The power uprate has no significant impact on the expected annual radwaste effluent releases/doses (i.e. all doses remain a small percentage of allowable Appendix I doses) as summarized below. | Uprate Evaluation Radiological Effects The power uprate has no significant impact on the expected annual radwaste effluent releases/doses (i.e. all doses remain a small percentage of allowable Appendix I doses) as summarized below. | ||
: 1. | : 1. | ||
: 2. | Expected Reactor Coolant Source Terms The requested SPU is an increase of 4.85% in reactor power and the source term would increase by the same amount. However, based on a comparison of base vs. power uprate input parameters, and the methodology outlined in NUREG 0017, the effective factor increase in dose depending on chemical group of isotopes released, ranges between 1.11 to 1.12;, Note that-the maximum expected increase in the reactor coolant source due to the uprate is well within the uncertainty of the existing (NUREG 0017 based) expected reactor coolant isotopic inventory used for radwaste effluent analyses. | ||
: 2. | |||
Estimated Impact on Effluent Doses due to Uprate Gaseous Effluents Dose Gamma Air (mrad) 3.74E-04 Beta Air (mrad) 7.60E-04 Iodine and Particulate (mrem) 8.22E-04 Liquid Effluents Dose Organ Dose (mrem) 3.OOE-03 Adult Total Body (mrem) 1.22E-03 The estimated doses due to uprate are presented above and are a fraction of that allowable under 10CFR50 Appendix I. | |||
: 3. | to NL-04-155 Docket 50-286 Page 11 of 40 Non-Proprietary | ||
: 3. | |||
Solid Radioactive Waste Though solid radwaste is not specifically addressed in 10 CFR 50, Appendix I, for completeness relative to radwaste assessments, the impact of core uprate on solid radwaste generation is summarized below. | |||
For a 'new' facility, the estimated volume and activity of solid waste is linearly related to the core power level. However, for an existing facility that is undergoing power uprate, the volume of solid waste would not be expected to increase proportionally, since the power uprate neither appreciably impacts installed equipment performance, nor does it require drastic changes in system operation or maintenance. Only minor, if any, changes in waste generation volume are expected. However, it is expected that the activity levels for most of the solid waste would increase proportionately to the increase in long half-life coolant activity bounded by maximum increase in power. | For a 'new' facility, the estimated volume and activity of solid waste is linearly related to the core power level. However, for an existing facility that is undergoing power uprate, the volume of solid waste would not be expected to increase proportionally, since the power uprate neither appreciably impacts installed equipment performance, nor does it require drastic changes in system operation or maintenance. Only minor, if any, changes in waste generation volume are expected. However, it is expected that the activity levels for most of the solid waste would increase proportionately to the increase in long half-life coolant activity bounded by maximum increase in power. | ||
Therefore, following uprate, the liquid and gaseous radwaste effluent treatment system will remain capable of maintaining normal operation offsite doses within the requirements of 10 CFR 50 Appendix I. Only minor, if any, changes in solid waste generation volume are expected. | Therefore, following uprate, the liquid and gaseous radwaste effluent treatment system will remain capable of maintaining normal operation offsite doses within the requirements of 10 CFR 50 Appendix I. Only minor, if any, changes in solid waste generation volume are expected. | ||
| Line 185: | Line 188: | ||
The environmental issues associated with the issuance of an operating license for Indian Point Unit 3 were originally evaluated in the Indian Point Unit 3 FES that was approved by the AEC in February 1975. The AEC approved Final Environmental Statement (FES) relates to operation of Indian Point Nuclear Generating Plant Unit No. 3 (Volume 1, page 1-1 Section I) and has addressed plant operation up to a maximum calculated thermal power of 3,216.5 MWt. The SPU does not significantly change the types or the amount of any effluents that may be released offsite that have not already been evaluated and approved in the FES for a power rating of 3,216.5 MWt. Since the AEC approved FES has already addressed plant operation up to a maximum calculated thermal power of 3,216.5 MWt, the SPU has been determined to not significantly impact the FES. | The environmental issues associated with the issuance of an operating license for Indian Point Unit 3 were originally evaluated in the Indian Point Unit 3 FES that was approved by the AEC in February 1975. The AEC approved Final Environmental Statement (FES) relates to operation of Indian Point Nuclear Generating Plant Unit No. 3 (Volume 1, page 1-1 Section I) and has addressed plant operation up to a maximum calculated thermal power of 3,216.5 MWt. The SPU does not significantly change the types or the amount of any effluents that may be released offsite that have not already been evaluated and approved in the FES for a power rating of 3,216.5 MWt. Since the AEC approved FES has already addressed plant operation up to a maximum calculated thermal power of 3,216.5 MWt, the SPU has been determined to not significantly impact the FES. | ||
State Pollutant Discharge Elimination System (SPDES) Permit and Consent Order Flows The State Pollutant Discharge Elimination System (SPDES) permit places restrictions on discharge temperatures and discharge flow rates to the river for the station. The Indian Point SPDES restrictions on discharge temperatures and discharge flow rates for the station were evaluated along with the flow limits set forth in Indian Point 3 Consent Order. | State Pollutant Discharge Elimination System (SPDES) Permit and Consent Order Flows The State Pollutant Discharge Elimination System (SPDES) permit places restrictions on discharge temperatures and discharge flow rates to the river for the station. The Indian Point SPDES restrictions on discharge temperatures and discharge flow rates for the station were evaluated along with the flow limits set forth in Indian Point 3 Consent Order. | ||
IP3 operation at the SPU power level of 3216 MWt will increase the exhaust steam flow and | IP3 operation at the SPU power level of 3216 MWt will increase the exhaust steam flow and to NL-04-155 Docket 50-286 Page 12 of 40 Non-Proprietary duty of the main condenser and, therefore, increase the heat load rejected by the Circulating Water System (CWS). The SPU evaluation assumes the existing CWS pumps are not modified and continue to operate at the same flow rates. Heat load increases due to SPU in the Normal and Emergency Service Water System (SWS) will also result in increase in the SWS discharge temperature. | ||
The SPDES permit has the following limitations that regulate the discharge temperature: | The SPDES permit has the following limitations that regulate the discharge temperature: | ||
The maximum discharge temperature at station DSNO01 shall not exceed 43. | The maximum discharge temperature at station DSNO01 shall not exceed 43.30C (11 0F) and Between April 15 and June 30 the daily average discharge temperature at station DSNO01 shall not exceed 340C (93.20F) for an average of more than 10 days per year during the term of the permit beginning with 1981; provided that in no event shall the daily average discharge temperature at Station DSNO01 exceed 340C (93.20F) on more than 15 days between April 15 and June 30 in any year. | ||
The Station's discharge temperatures were evaluated using the heat balance model (PEPSE). | The Station's discharge temperatures were evaluated using the heat balance model (PEPSE). | ||
The temperature rise across each condenser from the model was tuned based on plant data from July 28, 2003. In addition, State Consent Order flows were used as input to the PEPSE model. Additional conservatism was added to the calculated temperature to account for miscellaneous plant cooling to determine plant discharge temperature. Plant historic data for the river water inlet temperature was iterated to predict the maximum plant discharge temperatures. | The temperature rise across each condenser from the model was tuned based on plant data from July 28, 2003. In addition, State Consent Order flows were used as input to the PEPSE model. Additional conservatism was added to the calculated temperature to account for miscellaneous plant cooling to determine plant discharge temperature. Plant historic data for the river water inlet temperature was iterated to predict the maximum plant discharge temperatures. | ||
Based on conservative maximum plant discharge temperatures and the existing administrative controls imposed on plant operation, it is concluded that the station will remain capable of meeting SPDES permit limits at SPU conditions. | Based on conservative maximum plant discharge temperatures and the existing administrative controls imposed on plant operation, it is concluded that the station will remain capable of meeting SPDES permit limits at SPU conditions. | ||
References | References | ||
: 1. | : 1. | ||
: 2. | NUREG 0017, Rev. 1, April 1985, 'Calculation of Releases of Radioactive Materials in Gaseous and Liquid Effluents from Pressurized Water Reactors" | ||
: 3. | : 2. | ||
: 4. | Code of Federal Regulations Title 10, Part 50, Appendix I, "Numerical Guides for Design Objectives and Limiting Conditions for Operation to Meet the Criterion As Low As Reasonably Achievable for Radioactive Material in Light Water Cooled Nuclear Power Reactor Effluents". | ||
: 5. | : 3. | ||
Final Environmental Statement Related to Operation of Indian Point Nuclear Generating Plant Unit No. 3, Consolidated Edison Company of New York, Inc. Docket No. 50-286, February 1975 | |||
: 4. | |||
New York State Department of Environmental Conservation, State Pollutant Discharge Elimination System (SPDES) Discharge Permit, 11/90 | |||
: 5. | |||
Fourth Amended Stipulation of Settlement and Judicial Consent Order, Index No. 6570-91, RJI No. 0191-ST3251 to NL-04-155 Docket 50-286 Page 13 of 40 Non-Proprietary Question NL-04-095-LOC-3: | |||
The LOCA submittals did not address slot breaks at the top and side of the pipe. | The LOCA submittals did not address slot breaks at the top and side of the pipe. | ||
Justify why these breaks are not considered for the IP2 LBLOCA response Response NL-04-095-LOC-3: | Justify why these breaks are not considered for the IP2 LBLOCA response Response NL-04-095-LOC-3: | ||
| Line 216: | Line 220: | ||
In Section 9.9.3 of the Application Report, the justifications provided on page 9.9-3 for not evaluating the piping and support systems where the increase in temperature, pressure and flow rate are less than 5 percent of the current rated design basis condition are qualitative and nonspecific. For instance, the licensee stated that these increases are some what offset by conservatism in analytical methods used. The licensee also indicated that conservatism may include the enveloping of multiple thermal operating conditions. | In Section 9.9.3 of the Application Report, the justifications provided on page 9.9-3 for not evaluating the piping and support systems where the increase in temperature, pressure and flow rate are less than 5 percent of the current rated design basis condition are qualitative and nonspecific. For instance, the licensee stated that these increases are some what offset by conservatism in analytical methods used. The licensee also indicated that conservatism may include the enveloping of multiple thermal operating conditions. | ||
Provide the technical basis for not evaluating these piping and support systems. The technical justifications should be based on specific quantitative assessment or intuitively conservative deduction. Also, discuss how the flow effects on the transient loads, which may increase non-proportional to the ratio of flow rate change, are considered (see page 9.9.2). | Provide the technical basis for not evaluating these piping and support systems. The technical justifications should be based on specific quantitative assessment or intuitively conservative deduction. Also, discuss how the flow effects on the transient loads, which may increase non-proportional to the ratio of flow rate change, are considered (see page 9.9.2). | ||
to NL-04-155 Docket 50-286 Page 14 of 40 Non-Proprietary Response NL-04-095-PS-1: | |||
All piping systems with change factors greater than 1.0 were evaluated to document pipe stress and support system acceptability. | All piping systems with change factors greater than 1.0 were evaluated to document pipe stress and support system acceptability. | ||
The method used to qualify the main steam piping involved detailed computer analysis of the piping system. Although operating temperatures and pressures at SPU conditions were bounded by the existing data considered in the design basis piping evaluations, the main steam piping was evaluated using detailed computer analysis in order to reconcile an approximate 6 percent flow rate increase that results due to SPU conditions. These detailed evaluations were performed to assess the potential increase in fluid transient stresses and loads resulting from a turbine stop valve (TSV) closure event. | The method used to qualify the main steam piping involved detailed computer analysis of the piping system. | ||
Although operating temperatures and pressures at SPU conditions were bounded by the existing data considered in the design basis piping evaluations, the main steam piping was evaluated using detailed computer analysis in order to reconcile an approximate 6 percent flow rate increase that results due to SPU conditions. These detailed evaluations were performed to assess the potential increase in fluid transient stresses and loads resulting from a turbine stop valve (TSV) closure event. | |||
A summary of revised main steam system stress levels corresponding to SPU conditions is provided in Table 1. The results presented include existing stress levels (i.e., pre-uprate), | A summary of revised main steam system stress levels corresponding to SPU conditions is provided in Table 1. The results presented include existing stress levels (i.e., pre-uprate), | ||
revised pipe stress levels for SPU conditions, allowable stress for the applicable loading condition, and the resulting design margin for each piping analysis that was evaluated to reconcile SPU conditions. The design margin provided is based on the ratio of the calculated stress divided by the allowable stress. | revised pipe stress levels for SPU conditions, allowable stress for the applicable loading condition, and the resulting design margin for each piping analysis that was evaluated to reconcile SPU conditions. The design margin provided is based on the ratio of the calculated stress divided by the allowable stress. | ||
- to NL-04-155 Docket 50-286 Page 15 of 40 Non-Proprietary Table I Stress Summary at SPU Conditions Piping Analysis Loading Existing SPU Allowable Design Description Condition Stress Stress Stress Margin (psi) | |||
Main Steam Line 1 | (psi) | ||
(psi) | |||
Main Steam Line 1 DL + LP +TSV 12,410 12,587 21,000 0.60 Main Steam Line 2 11,993 (Inside Containment) | |||
DL + LP + TSV 11,833 21,000 0.57 Main Steam Line 3 DL + LP + TSV 12,812 13,234 21,000 0.63 (inside Containment) | |||
DL+L+TS 12823,4 2,00.6 Inside Containment) | |||
DL + LP + TSV 12,649 12,811 21,000 0.61 Main Steam Lines 1, Thermal 2, 3 and 4 (Outside expansion 18,489 19,171 19,950 0.96 Containment) | |||
Notes: | Notes: | ||
: 1. Loading condition "DL + LP + TSV" corresponds to the combination of stresses due to deadweight + pressure + turbine stop valve effects. | : 1. Loading condition "DL + LP + TSV" corresponds to the combination of stresses due to deadweight + pressure + turbine stop valve effects. | ||
: 2. Stress Ratio reported is based on the ratio of SPU stress divided by the allowable stress. | : 2. Stress Ratio reported is based on the ratio of SPU stress divided by the allowable stress. | ||
For the remaining piping systems with thermal and pressure change factors greater than 1.0, these piping systems (i.e., condensate, feedwater, extraction steam, feedwater heaters vents and drains, and moisture separator and reheater drains systems) were evaluated using computer analyses, as well as performing a field walkdown of the piping systems. | For the remaining piping systems with thermal and pressure change factors greater than 1.0, these piping systems (i.e., condensate, feedwater, extraction steam, feedwater heaters vents and drains, and moisture separator and reheater drains systems) were evaluated using computer analyses, as well as performing a field walkdown of the piping systems. | ||
The results presented in Tables 2 through 5 contain stress data for the critical portions of the Condensate, Feedwater, Extraction Steam and Feedwater Heater Vent & Drains Systems. The results provided include existing stress levels (i.e., pre-uprate), revised pipe stress*levels for SPU conditions, allowable stress for the applicable loading condition, and the resulting design margin for each piping analysis that was evaluated to reconcile SPU conditions. The design margin provided is based on the ratio of the calculated SPU stress divided by the allowable stress. | The results presented in Tables 2 through 5 contain stress data for the critical portions of the Condensate, Feedwater, Extraction Steam and Feedwater Heater Vent & Drains Systems. The results provided include existing stress levels (i.e., pre-uprate), revised pipe stress* levels for SPU conditions, allowable stress for the applicable loading condition, and the resulting design margin for each piping analysis that was evaluated to reconcile SPU conditions. The design margin provided is based on the ratio of the calculated SPU stress divided by the allowable stress. | ||
to NL-04-155 Docket 50-286 Page 16 of 40 Non-Proprietary Table 3 Fcedwatcr System Stress Summary Piping Analysis Loading Existing SPU Stress Allowable Design Description Condition Stress (psi) | |||
(psi) | |||
Table 5 FWN' Heater Vents and Drains System Stress Summary Piping Analysis | Stress (psi) | ||
Margin Feedwater to SG 31 DL + LP 6,532 7,162 17,500 0.41 Feedwater to SG 32 DL + LP 8,095 8,725 17,500 0.50 Feedwater to SG 33 DL + LP 7,569 8,199 17,500 0.47 Feedwater to SG 34 DL + LP 7,532 7,982 17,500 0.46 Table 4 Extraction Steam System Stress Summary Piping Analysis Loading Existing SPU Stress Allowable Design Description Condition Stress (psi) | |||
(psi) | |||
Stress (psi) | |||
Margin Extraction Steam to DL + LP 1,734 1,780 15,000 0.12 Heaters 33A/B/C Extraction Steam to Thermal 4,620 4,727 22,500 0.21 Heaters 33A/B/C Table 5 FWN' Heater Vents and Drains System Stress Summary Piping Analysis Loading Existing SPU Stress Allowable Design Description Condition Stress (psi) | |||
(psi) | |||
Stress (psi) | |||
Margin Heaters 34A/B/C to DL + LP 1,808 1,825 15,000 0.12 Heaters 33A/B/C Heaters 34A/B/C to Thermal 13,308 13,544 22,500 0.60 Heaters 33A/B/C In addition to the detailed evaluations that were performed of the critical portions of the Condensate, Feedwater, Extraction and Feedwater Heater Vents and Drains Systems described above, a turbine building plant walkdown of these piping systems was also performed to review the individual piping layouts and associated pipe support configurations. The purpose of these piping system walkdowns was to assess the adequacy of the installed piping deadweight spans and to review the existing thermal flexibility of the piping systems. The overall assessment from the walkdowns performed concluded that the existing piping that was observed was adequately supported and contained adequate flexibility to accommodate the small pressure and temperature changes resulting from SPU. Piping systems were determined to be adequately supported if the piping was supported by vertical supports, rod hangers or to NL-04-155 Docket 50-286 Page 17 of 40 Non-Proprietary spring hangers, such that piping spans were consistent with the guidance presented in ASA B31.1-1955, Code for Pressure Piping. Piping systems were determined to have adequate flexibility if the following attributes were observed: | |||
Piping lengths and offsets were consistent with simplified industry methods of determining flexibility (for example, nomographs). | |||
There were no non-integral or integrally welded piping anchors installed. | |||
There was a sufficient and reasonable number of piping elbows installed providing thermal flexibility. | |||
Hence, based on the detailed evaluations of the critical portions of these systems along with the additional plant walkdowns that were performed, it is concluded that these piping systems remain acceptable and will continue to satisfy design basis requirements when considering the temperature and pressure effects resulting from SPU conditions. | Hence, based on the detailed evaluations of the critical portions of these systems along with the additional plant walkdowns that were performed, it is concluded that these piping systems remain acceptable and will continue to satisfy design basis requirements when considering the temperature and pressure effects resulting from SPU conditions. | ||
Question NL-04-095-GIP-11: | Question NL-04-095-GIP-11: | ||
| Line 245: | Line 259: | ||
The equipment types in the main steam and feedline penetration area on the EQ list are ASCO solenoid valves, Namco limit switches, Westinghouse and Buchanan terminal blocks, and associated cables manufactured by GE PVC and Rockbestos Firewall IlIl Cable, CONAX Connectors, and Fisher E/P Transducers. There are no EQ pumps in this area. The EQ valves evaluated are the ASCO valves. | The equipment types in the main steam and feedline penetration area on the EQ list are ASCO solenoid valves, Namco limit switches, Westinghouse and Buchanan terminal blocks, and associated cables manufactured by GE PVC and Rockbestos Firewall IlIl Cable, CONAX Connectors, and Fisher E/P Transducers. There are no EQ pumps in this area. The EQ valves evaluated are the ASCO valves. | ||
The equipment was evaluated using the thermal analysis of the components for a 1.4 square foot MSLB header break downstream from the Main Steam Isolation Valves, summer building ventilation configuration for the outdoor louvers and 102% SPU power. | The equipment was evaluated using the thermal analysis of the components for a 1.4 square foot MSLB header break downstream from the Main Steam Isolation Valves, summer building ventilation configuration for the outdoor louvers and 102% SPU power. | ||
The results are presented in Graph | The results are presented in Graph 1 for the ASCO solenoid valves. The temperature of the ASCO case and the coil are very close. The coil is only energized for 20 seconds to perform the safety function of tripping the MSIVs, so there is little heat generated within the component. | ||
As shown on Graph 1, the temperature of the ASCO coil and case remain below the qualification test temperature. The qualification testing for the ASCO valves included a pre-test accident soak to assure the ASCOs reached the test chamber temperature. | As shown on Graph 1, the temperature of the ASCO coil and case remain below the qualification test temperature. The qualification testing for the ASCO valves included a pre-test accident soak to assure the ASCOs reached the test chamber temperature. | ||
The cables that are associated with the ASCO solenoid valves are installed in conduit. These cables were also thermally analyzed. Graph 2 indicates that the cables remain below their qualification temperature. | The cables that are associated with the ASCO solenoid valves are installed in conduit. These cables were also thermally analyzed. Graph 2 indicates that the cables remain below their qualification temperature. | ||
to NL-04-155 Docket 50-286 Page 18 of 40 Non-Proprietary | |||
: 1. ASCO solenoid valves are qualified for both the 10-minute and the 15-minute operator response time. The peak temperature of the 15-minute operator response time is 350.7490F. The ASCO test report (Reference 1) demonstrates that the ASCO solenoid valves have been tested to temperatures enveloping this peak temperature. | |||
: 1. ASCO solenoid valves are qualified for both the 10-minute and the 15-minute operator response time. The peak temperature of the 15-minute operator response time is 350. | : 2. Buchanan terminal blocks are qualified for both the 10-minute and the 15-minute operator response time because the qualification test envelopes the accident profile. The maximum thermal lag temperature of the terminal blocks is 322.30F. The qualification test peaks at 3460F. | ||
: 2. Buchanan terminal blocks are qualified for both the 10-minute and the 15-minute operator response time because the qualification test envelopes the accident profile. The maximum thermal lag temperature of the terminal blocks is 322. | : 3. The Westinghouse terminal blocks are not qualified for the 322.30F temperature (15 minute response), but are qualified for the 10-minute operator response time with the peak thermal lag temperature of 2790F compared to the qualification test temperature of 2950F (Reference 2). | ||
: 3. The Westinghouse terminal blocks are not qualified for the 322. | |||
: 4. GE Flamenol PVC cable is shown to be qualified for the 10-minute operator response time. | : 4. GE Flamenol PVC cable is shown to be qualified for the 10-minute operator response time. | ||
The peak temperature of the 15-minute operator response time is 362.6760 F (1.4 SF break in winter with 15-minute operator response). The peak test temperature is 370OF. The time over the qualification curve can be shown to reduce the time of the qualification temp of | The peak temperature of the 15-minute operator response time is 362.6760 F (1.4 SF break in winter with 15-minute operator response). The peak test temperature is 370OF. The time over the qualification curve can be shown to reduce the time of the qualification temp of 3500F long term by only 748 seconds. The impact is an 8% reduction of thermal life at 3500F but no impact on the overall transient being enveloped by the qualification test. | ||
Therefore the GE Cable is considered also qualified for the 15-minute operator response time. | Therefore the GE Cable is considered also qualified for the 15-minute operator response time. | ||
: 5. The Rockbestos Firewall IlIl cable is qualified to | : 5. The Rockbestos Firewall IlIl cable is qualified to 6740F (Reference 3). | ||
: 6. Conax conduit seals are qualified for both the 10-minute operator response time and the 15-minute operator response time. The peak thermal lag temperature of the Conax is 329.8760F (1.4 SF break in winter with 15 minute operator response time). The qualification test peaks at 3800. | : 6. Conax conduit seals are qualified for both the 10-minute operator response time and the 15-minute operator response time. The peak thermal lag temperature of the Conax is 329.8760F (1.4 SF break in winter with 15 minute operator response time). The qualification test peaks at 3800. | ||
: 7. Namco limit switches are qualified for the 10-minute operator response time. The peak temperature of the 15 minute operator response time of 335.313'F (1.4 SF break in winter with 15 minute operator response) exceeds the existing qualification test of 315'F. However, the following qualification test reports yield higher temperatures: QTR 157, Rev 1 peaks at | : 7. Namco limit switches are qualified for the 10-minute operator response time. The peak temperature of the 15 minute operator response time of 335.313'F (1.4 SF break in winter with 15 minute operator response) exceeds the existing qualification test of 315'F. However, the following qualification test reports yield higher temperatures: QTR 157, Rev 1 peaks at 3640F and QTR 155 peaks at 341OF. Also, the length of time that the Namco exceeds the test temperature of 315 0F is 1777 seconds and results conservatively in reducing the thermal life at 3150F slightly (4%) which does not affect the test enveloping the accident temperature. Therefore, the Namco limit switches are considered also qualified for the 15-minute operator response time. | ||
: 8. The Fisher E/P Transducers were already evaluated for the higher Pre-SPU power level and were found acceptable. | : 8. The Fisher E/P Transducers were already evaluated for the higher Pre-SPU power level and were found acceptable. | ||
Summary: All of the equipment, except the Westinghouse terminal blocks, is qualified for accident conditions for the longer 15-minute operator response time. All of the equipment is qualified for the 10-minute operator response time. | Summary: All of the equipment, except the Westinghouse terminal blocks, is qualified for accident conditions for the longer 15-minute operator response time. All of the equipment is qualified for the 10-minute operator response time. | ||
to NL-04-155 Docket 50-286 Page 19 of 40 Non-Proprietary | |||
==References:== | ==References:== | ||
: 1. ASCO Test Report, EQ-QR 03.02.01, AQR-67368, Rev. 1 | : 1. ASCO Test Report, EQ-QR 03.02.01, AQR-67368, Rev. 1 | ||
: 2. EQ file EQ-SE-17.01.01, Westinghouse Terminal Blocks | : 2. EQ file EQ-SE-17.01.01, Westinghouse Terminal Blocks | ||
: 3. Wyle Qualification Report 4795R01, 12/24/2002, "Environmental Qualification Extension of Rockbestos Firewall IlIl XLPE and GE Flamenol PVC Cables for use in Entergy Nuclear Northeast Indian Point Energy Center Unit 3" | : 3. Wyle Qualification Report 4795R01, 12/24/2002, "Environmental Qualification Extension of Rockbestos Firewall IlIl XLPE and GE Flamenol PVC Cables for use in Entergy Nuclear Northeast Indian Point Energy Center Unit 3" to NL-04-155 Docket 50-286 Page 20 of 40 Non-Proprietary Graph I for NL-04-095-GIP-1I ASCO Thermal Lag Temperature Response 15 minute Operator Response Time 4500-ir ___ C__H j | ||
1 1PeakCase~~ | |||
350 nW cE | |||
1 | !\\ | ||
350 | Area -Summer 25 -0 Housin -- lW\\int* | ||
ciler j-I.......Coil | |||
-Winter D- | |||
\\ | |||
Housing. Summer Colt - Summer L | |||
Housing. Summer Colt - Summer | 200 a -ACR-67368 Fig 4 2 Revised Model Case | ||
¢X/ | |||
Revised Model Coil 150 100 ------. | |||
1 10 100 1000 10000 100000 Time (sec) to NL-04-155 Docket 50-286 Page 21 of 40 Non-Proprietary Graph 2 for NL-04-095-GIP-11 CABLE Thermal Lag Temperature Response 15 minute Operator Response Time Area-Winter I | |||
100 ------. | 4I A\\ | ||
1 | - -C Area - Summer 450-- | ||
Conduit -Winter l | |||
Cable - Winter | |||
!Conduit | |||
-Summer 400 - -------------- | |||
.,. Cable - Sume_ | |||
Peak Test Peak Accident jM-47951RO2 373 3,362.676F | |||
jM-47951RO2 | = | ||
:350 | 74751R2 | ||
2 00 | :350 250 | ||
200 j | ~ | ||
~ | |||
~ | |||
~ | |||
~ | |||
Time (sec) | ~ | ||
~ | |||
__I_ | |||
=g 2 00 0.--_---- | |||
-l 200 j | |||
7 1 | |||
2 2 | |||
!.I o | |||
I.____... | |||
I | |||
.~ | |||
Time (sec) to NL-04-155 Docket 50-286 Page 22 of 40 Non-Proprietary Question NL-04-095-GIP-12: | |||
Section 10.10, "Generic Letter 95-07," states that the effect of the SPU on the current pressure locking and thermal binding evaluation was reviewed, and that the SPU does not introduce any increased challenge for thermal binding and/or pressure locking and does not effect the results and conclusions of the current evaluation. | Section 10.10, "Generic Letter 95-07," states that the effect of the SPU on the current pressure locking and thermal binding evaluation was reviewed, and that the SPU does not introduce any increased challenge for thermal binding and/or pressure locking and does not effect the results and conclusions of the current evaluation. | ||
Discuss, with examples, the evaluation of the effect of the SPU on the potential for thermal binding and pressure locking of safety-related POVs, including consideration of increased ambient temperatures in applicable locations. | Discuss, with examples, the evaluation of the effect of the SPU on the potential for thermal binding and pressure locking of safety-related POVs, including consideration of increased ambient temperatures in applicable locations. | ||
| Line 309: | Line 330: | ||
The following is a summary of the current evaluations I key parameters and impact of the SPU on these evaluations / parameters for MOVs and AOVs subject to pressure locking. The evaluations considered two types of pressure locking: hydraulically induced pressure locking (HIPL) and thermally induced pressure locking (TIPL). | The following is a summary of the current evaluations I key parameters and impact of the SPU on these evaluations / parameters for MOVs and AOVs subject to pressure locking. The evaluations considered two types of pressure locking: hydraulically induced pressure locking (HIPL) and thermally induced pressure locking (TIPL). | ||
: 1. Pressure locking of RHR Pump Discharge Isolation Valve (MOV): | : 1. Pressure locking of RHR Pump Discharge Isolation Valve (MOV): | ||
a) HIPL: This valve may be required to be opened following transfer from cold leg to hot leg recirculation during a LOCA event. The evaluation considers pressure trapped in the valve bonnet under both small break and large break LOCA conditions. Under SPU conditions, the time interval for transferring from cold leg to hot leg recirculation is being changed from 14 hours to 6.5 hours (Section 6.2). For the small break LOCA case, credit is taken in the evaluation for bonnet depressurization during the time interval between cold leg and hot leg recirculation. The above change in time interval would result in a small differential pressure between the bonnet pressure and the downstream line pressure under SPU conditions, as opposed to zero differential pressure under pre-SPU conditions. However, the large break LOCA case remains bounding in the evaluation, since pressure trapped in the valve bonnet, which is based on shutoff head | a) HIPL: This valve may be required to be opened following transfer from cold leg to hot leg recirculation during a LOCA event. The evaluation considers pressure trapped in the valve bonnet under both small break and large break LOCA conditions. Under SPU conditions, the time interval for transferring from cold leg to hot leg recirculation is being changed from 14 hours to 6.5 hours (Section 6.2). For the small break LOCA case, credit is taken in the evaluation for bonnet depressurization during the time interval between cold leg and hot leg recirculation. The above change in time interval would result in a small differential pressure between the bonnet pressure and the downstream line pressure under SPU conditions, as opposed to zero differential pressure under pre-SPU conditions. However, the large break LOCA case remains bounding in the evaluation, since pressure trapped in the valve bonnet, which is based on shutoff head to NL-04-155 Docket 50-286 Page 23 of 40 Non-Proprietary of the RHR pumps, is conservatively assumed not to depressurize, and the upstream and downstream line pressures are conservatively assumed to be zero. The shutoff head of the RHR pumps is not affected by the SPU. | ||
b) TIPL: The valve is located outside Containment in the Pipe Penetration Area. Maximum temperature of this area does not change during a LOCA from the normal maximum ambient temperature. The valve is thermally insulated. During a large break LOCA, the valve is potentially cooled to RWST temperature. Evaluation shows that, for the scenario where there is thermal addition due to increase in the ambient temperature, bonnet pressure decays at a faster rate than it increases by thermal addition, and therefore there is no pressure increase due to thermal addition. The SPU does not affect this evaluation. | b) TIPL: The valve is located outside Containment in the Pipe Penetration Area. Maximum temperature of this area does not change during a LOCA from the normal maximum ambient temperature. The valve is thermally insulated. During a large break LOCA, the valve is potentially cooled to RWST temperature. Evaluation shows that, for the scenario where there is thermal addition due to increase in the ambient temperature, bonnet pressure decays at a faster rate than it increases by thermal addition, and therefore there is no pressure increase due to thermal addition. The SPU does not affect this evaluation. | ||
: 2. Pressure locking of PORV Block Valves (MOVs): | : 2. Pressure locking of PORV Block Valves (MOVs): | ||
| Line 320: | Line 339: | ||
a) HIPL: Pressure trapped in valve bonnet is based on the discharge pressure of the recirculation pumps. This condition is bounded by the conditions evaluated in the TIPL evaluation, discussed below. | a) HIPL: Pressure trapped in valve bonnet is based on the discharge pressure of the recirculation pumps. This condition is bounded by the conditions evaluated in the TIPL evaluation, discussed below. | ||
b) TIPL: These valves are required to be opened following transfer from cold leg to hot leg recirculation during a LOCA event. The evaluation assumes water trapped in bonnet of the valves heats up from RWST temperature (350F) to maximum ambient temperature at the location of the valves outside containment (850F). The maximum pressure in the bonnet of the valves includes the thermally induced pressure from the bonnet fluid temperature change plus pressure trapped in the bonnet based on discharge pressure of the recirculation pumps. Under SPU conditions, the time interval for transferring from cold leg to hot leg recirculation is being changed from 14 hours to 6.5 hours (Section 6.2). However, the evaluation conservatively assumes the valves heat up to the maximum ambient temperature and that there is no depressurization of the pressure trapped in the bonnet during this time interval. Accordingly, the change in the time interval for transferring from cold leg to hot leg recirculation does not affect the evaluation results. Also, the SPU does not impact the temperature parameters used in the evaluation and does not impact recirculation pump head. | b) TIPL: These valves are required to be opened following transfer from cold leg to hot leg recirculation during a LOCA event. The evaluation assumes water trapped in bonnet of the valves heats up from RWST temperature (350F) to maximum ambient temperature at the location of the valves outside containment (850F). The maximum pressure in the bonnet of the valves includes the thermally induced pressure from the bonnet fluid temperature change plus pressure trapped in the bonnet based on discharge pressure of the recirculation pumps. Under SPU conditions, the time interval for transferring from cold leg to hot leg recirculation is being changed from 14 hours to 6.5 hours (Section 6.2). However, the evaluation conservatively assumes the valves heat up to the maximum ambient temperature and that there is no depressurization of the pressure trapped in the bonnet during this time interval. Accordingly, the change in the time interval for transferring from cold leg to hot leg recirculation does not affect the evaluation results. Also, the SPU does not impact the temperature parameters used in the evaluation and does not impact recirculation pump head. | ||
to NL-04-155 Docket 50-286 Page 24 of 40 Non-Proprietary | |||
: 4. Pressure locking of Safety Injection Pump #32 Discharge Isolation Valves (MOVs): | : 4. Pressure locking of Safety Injection Pump #32 Discharge Isolation Valves (MOVs): | ||
a) HIPL: Pressure trapped in valve bonnet is based on the developed head of the recirculation pumps plus the safety injection pumps. Safety injection pump head is not affected by the SPU. Pump head for the recirculation pumps is not affected by the SPU. | a) HIPL: Pressure trapped in valve bonnet is based on the developed head of the recirculation pumps plus the safety injection pumps. Safety injection pump head is not affected by the SPU. Pump head for the recirculation pumps is not affected by the SPU. | ||
| Line 332: | Line 350: | ||
supply to accommodate thermal expansion of water trapped in the bonnet. However, an evaluation was performed to address the scenario of leakage of nitrogen from the IVSWS supply line. In this evaluation, pressure trapped in the bonnet is based on the setpoint of the RHR heat exchanger outlet safety valves, which is not affected by the SPU. | supply to accommodate thermal expansion of water trapped in the bonnet. However, an evaluation was performed to address the scenario of leakage of nitrogen from the IVSWS supply line. In this evaluation, pressure trapped in the bonnet is based on the setpoint of the RHR heat exchanger outlet safety valves, which is not affected by the SPU. | ||
b) TIPL: These valves are located in the PAB Pipe Penetration Area, where the ambient temperature can be 105OF during normal operation, as well as post-LOCA. The area temperature may rise above this value during a HELB, but these valves are not required to open during an HELB. During the injection phase of a LOCA, RWST water circulating in the line upstream of the valves will tend to cool them, reducing bonnet pressure. As the event continues, gradual reheating results in the bonnet temperature returning to the ambient range until the signal to open. Therefore, TIPL is not a concern for these valves. | b) TIPL: These valves are located in the PAB Pipe Penetration Area, where the ambient temperature can be 105OF during normal operation, as well as post-LOCA. The area temperature may rise above this value during a HELB, but these valves are not required to open during an HELB. During the injection phase of a LOCA, RWST water circulating in the line upstream of the valves will tend to cool them, reducing bonnet pressure. As the event continues, gradual reheating results in the bonnet temperature returning to the ambient range until the signal to open. Therefore, TIPL is not a concern for these valves. | ||
to NL-04-155 Docket 50-286 Page 25 of 40 Non-Proprietary | |||
: 7. | |||
: 7. Pressure locking of Boron Injection Tank Outlet Isolation Valves (MOVs): | Pressure locking of Boron Injection Tank Outlet Isolation Valves (MOVs): | ||
a) HIPL: | a) HIPL: | ||
SI Actuation following a LOCA The normal positions of SI-MOV-1 835A & B were changed utilizing the 10 CFR 50.59 (Reference 1) process from normally closed to normally open to eliminate the potential for the valves to pressure lock when required to open for this event. | SI Actuation following a LOCA The normal positions of SI-MOV-1 835A & B were changed utilizing the 10 CFR 50.59 (Reference 1) process from normally closed to normally open to eliminate the potential for the valves to pressure lock when required to open for this event. | ||
Post-LOCA Cold Leq and Hot Leg Recirculation Phases These valves are maintained open in the post-LOCA cold leg and hot leg recirculation phases, and therefore HIPL is not a concern. | Post-LOCA Cold Leq and Hot Leg Recirculation Phases These valves are maintained open in the post-LOCA cold leg and hot leg recirculation phases, and therefore HIPL is not a concern. | ||
b) TIPL: As addressed above, these valves are normally open and maintained in the open position post-LOCA, and therefore TIPL is not a concern. | b) TIPL: As addressed above, these valves are normally open and maintained in the open position post-LOCA, and therefore TIPL is not a concern. | ||
: 8. Pressure locking of AFW Pump Turbine Steam Supply Isolation Valves (AOVs): | : 8. | ||
a) HIPL: If the valves close due to a steam line break in the AFW Pump Room, steam will be trapped in the valve bonnet. However, the plant must be cooled down below | Pressure locking of AFW Pump Turbine Steam Supply Isolation Valves (AOVs): | ||
a) HIPL: If the valves close due to a steam line break in the AFW Pump Room, steam will be trapped in the valve bonnet. However, the plant must be cooled down below 3500F to effect repairs to the line, which would significantly reduce the pressure in the bonnet as the steam condensed to water. This will allow for re-opening the valve. The SPU does not affect this evaluation. | |||
b) TIPL: If the valves close due to high temperature in the AFW Pump Room due to a fire, and it is desired to open the valves, the valve need only open against the normal differential pressure of main steam on the upstream side and turbine backpressure on the downstream side. This is considered a normal operating requirement for the valve. | b) TIPL: If the valves close due to high temperature in the AFW Pump Room due to a fire, and it is desired to open the valves, the valve need only open against the normal differential pressure of main steam on the upstream side and turbine backpressure on the downstream side. This is considered a normal operating requirement for the valve. | ||
No thermal addition to pressure in the bonnet will be experienced from external sources, since the process fluid is at a much higher temperature than the maximum ambient room temperature. In addition, procedural guidance specifies equalizing pressure across the valves prior to opening. The SPU does not affect this evaluation. | No thermal addition to pressure in the bonnet will be experienced from external sources, since the process fluid is at a much higher temperature than the maximum ambient room temperature. In addition, procedural guidance specifies equalizing pressure across the valves prior to opening. The SPU does not affect this evaluation. | ||
The following is a summary of the current evaluations and impact of the SPU on these evaluations for MOVs subject to thermal binding (TB). For thermal binding evaluations, the Westinghouse Owners Group has developed additional criteria for determining susceptibility based on temperature change: For flexible wedge gate valves, only temperatures above | The following is a summary of the current evaluations and impact of the SPU on these evaluations for MOVs subject to thermal binding (TB). For thermal binding evaluations, the Westinghouse Owners Group has developed additional criteria for determining susceptibility based on temperature change: For flexible wedge gate valves, only temperatures above 2000F, and temperature changes above 1 00F are considered significant for thermal binding. | ||
: 1. Thermal binding of PORV Block Valves: | : 1. Thermal binding of PORV Block Valves: | ||
Although these flexible wedge gate valves are potentially susceptible to thermal binding, they are considered acceptable in the current condition based on: (1) | Although these flexible wedge gate valves are potentially susceptible to thermal binding, they are considered acceptable in the current condition based on: (1) | ||
The maximum differential temperature between closing and subsequent opening these valves would experience is 150 0F, which, although it exceeds the 100OF temperature change criteria identified above, is not large, (2) Based on an 18 plant survey, no occurrences of thermal binding of these valves were reported | The maximum differential temperature between closing and subsequent opening these valves would experience is 150 0F, which, although it exceeds the 100OF temperature change criteria identified above, is not large, (2) Based on an 18 plant survey, no occurrences of thermal binding of these valves were reported to NL-04-155 Docket 50-286 Page 26 of 40 Non-Proprietary over many years of operation, (3) High conductivity of valve materials, and insulation of the valves and adjacent piping, minimize temperature differences which may contribute to thermal binding, (4) the valve body and wedge are both stainless steel having nearly identical thermal expansion coefficients, and (5) | ||
Past performance history of these valves during plant cooldowns has been satisfactory. The SPU does not affect this evaluation. | Past performance history of these valves during plant cooldowns has been satisfactory. The SPU does not affect this evaluation. | ||
: 2. Thermal binding of Safety Injection Pump #31 Discharge Isolation Valves: | : 2. Thermal binding of Safety Injection Pump #31 Discharge Isolation Valves: | ||
These flexible wedge gate valves are potentially susceptible to thermal binding. | These flexible wedge gate valves are potentially susceptible to thermal binding. | ||
However, thermal binding is not a concern for these valves based on the following: During closure of these valves after safety injection, the valve temperatures will not exceed | However, thermal binding is not a concern for these valves based on the following: During closure of these valves after safety injection, the valve temperatures will not exceed 1200F. When the valves are required to open to transfer from cold leg to hot leg recirculation, the valves and the fluid at the valves will be at ambient temperature (maximum of 850F). The low temperature at closure, and the relatively minor temperature difference between closure and opening are both well within the temperature criteria for thermal binding susceptibility noted above. The SPU does not affect this evaluation. | ||
: 3. Thermal binding of RHR Heat Exchangers #31 and #32 Outlet Isolation Valves: | : 3. Thermal binding of RHR Heat Exchangers #31 and #32 Outlet Isolation Valves: | ||
These valves (two per HX) are open and energized during normal power operation, safety injection, low head recirculation, and RHR operation. The valves are closed, post-LOCA, to initiate high head cold leg or hot leg recirculation. If closed during high head cold leg recirculation, operating procedures direct the operator to open one HX pair to establish low head recirculation if RCS pressure decreases sufficiently. However, the valves are not designed with the intent to ensure opening after closure while mitigating an accident. The valves' control mechanism has been modified to control valve closing via geared limit switches to minimize seating forces. The motors are de-energized prior to the valves' discs swinging, thus preventing the valves from being wedged too tightly. | These valves (two per HX) are open and energized during normal power operation, safety injection, low head recirculation, and RHR operation. The valves are closed, post-LOCA, to initiate high head cold leg or hot leg recirculation. If closed during high head cold leg recirculation, operating procedures direct the operator to open one HX pair to establish low head recirculation if RCS pressure decreases sufficiently. However, the valves are not designed with the intent to ensure opening after closure while mitigating an accident. The valves' control mechanism has been modified to control valve closing via geared limit switches to minimize seating forces. The motors are de-energized prior to the valves' discs swinging, thus preventing the valves from being wedged too tightly. | ||
| Line 360: | Line 377: | ||
==Reference:== | ==Reference:== | ||
: 1. 10 CFR 50.59, "Changes, Tests, and Experiments." | : 1. 10 CFR 50.59, "Changes, Tests, and Experiments." | ||
to NL-04-155 Docket 50-286 Page 27 of 40 Non-Proprietary Question NL-04-095-GIP-13: | |||
Section 10.15.4, "Startup Testing," states that power escalation will be controlled by a specific procedure that includes controls for power escalation, hold points, and data collection requirements. Section 10.15.4 also states that a vibration monitoring activity will be initiated to monitor plant response at various power levels. | Section 10.15.4, "Startup Testing," states that power escalation will be controlled by a specific procedure that includes controls for power escalation, hold points, and data collection requirements. Section 10.15.4 also states that a vibration monitoring activity will be initiated to monitor plant response at various power levels. | ||
Discuss the plans for power escalation including specific hold points and duration, inspections, and plant walkdowns. Also, discuss the vibration monitoring activity including data collection methods and locations, baseline vibration measurements, and planned data evaluation. | Discuss the plans for power escalation including specific hold points and duration, inspections, and plant walkdowns. Also, discuss the vibration monitoring activity including data collection methods and locations, baseline vibration measurements, and planned data evaluation. | ||
| Line 369: | Line 385: | ||
Discuss the evaluation of potential flow vibration effects resulting from SPU conditions for reactor pressure vessel internals, and steam and feedwater systems and their associated components, including impact on structural capability and performance during normal operations, anticipated transients (initiation and response), and design-basis conditions; and preparation for responding to the potential occurrence of loose parts as a result of the power uprate. | Discuss the evaluation of potential flow vibration effects resulting from SPU conditions for reactor pressure vessel internals, and steam and feedwater systems and their associated components, including impact on structural capability and performance during normal operations, anticipated transients (initiation and response), and design-basis conditions; and preparation for responding to the potential occurrence of loose parts as a result of the power uprate. | ||
Response NL-04-095-GIP-14: | Response NL-04-095-GIP-14: | ||
Reactor Vessel Internals Flow induced vibrations (FIV) of pressurized water reactor internals have been'studied at Westinghouse for a number of years. The objective of these studies is to assure the structural integrity and reliability of the reactor internals components. These efforts have included in-plant tests, scale model tests, tests in fabricators' shops, bench tests of components, and various analytical investigations. The results of scale model and in-plant tests indicate that the vibrational behavior of 2-, 3-, and 4-loop plants is essentially similar; the results obtained from each of the tests complement one another and make possible a better understanding of the flow induced vibration phenomena. | |||
As described in References 1 and 2, Westinghouse performed a comprehensive instrumented reactor internals testing program at the Indian Point Unit 2 plant. This test program included heatup and cooldown as well as operation with 1, 2, 3, and 4 reactor coolant pumps, including starting and stopping transient operations. The initial program was performed without the core present (Reference 1). A subsequent program was performed with the core in place (Reference 2). The results of this program were used to develop theories and concepts related to reactor internals vibration under various operating conditions as well as to assess the fatigue and stress effects of operational vibrations. The testing performed at Indian Point 2 included the acquisition of data during hot functional testing (without core present) and subsequently with the core installed. The results of this comprehensive testing program showed that the vibrational response of the reactor internals is small and that adequate margins of safety exist with regard to flow induced vibration. | As described in References 1 and 2, Westinghouse performed a comprehensive instrumented reactor internals testing program at the Indian Point Unit 2 plant. This test program included heatup and cooldown as well as operation with 1, 2, 3, and 4 reactor coolant pumps, including starting and stopping transient operations. The initial program was performed without the core present (Reference 1). A subsequent program was performed with the core in place (Reference 2). The results of this program were used to develop theories and concepts related to reactor internals vibration under various operating conditions as well as to assess the fatigue and stress effects of operational vibrations. The testing performed at Indian Point 2 included the acquisition of data during hot functional testing (without core present) and subsequently with the core installed. The results of this comprehensive testing program showed that the vibrational response of the reactor internals is small and that adequate margins of safety exist with regard to flow induced vibration. | ||
to NL-04-155 Docket 50-286 Page 28 of 40 Non-Proprietary To address the SPU program at IP3 an evaluation was performed to show that the vibration characteristics of reactor internals do not change significantly and the structural adequacy of the reactor internals in regards to FIV is not impaired. | |||
The reactor internal components that are generally addressed for FIV consists of lower internals (core barrel, thermal shield support flexures, thermal shield support bolts and dowel pins) and upper internals (guide tubes). The current design temperature range between Tcold and Thot is 58.60F and changes to 63.4 with the implementation of SPU at IP3. | |||
The reactor internal components that are generally addressed for FIV consists of lower internals (core barrel, thermal shield support flexures, thermal shield support bolts and dowel pins) and upper internals (guide tubes). The current design temperature range between Tcold and Thot is 58. | |||
This SPU design condition will slightly alter TCO.d and Thot fluid densities, which will slightly change the forces, induced by flow. The corresponding TCOfd and ThOt fluid densities will increase by about 2%. | This SPU design condition will slightly alter TCO.d and Thot fluid densities, which will slightly change the forces, induced by flow. The corresponding TCOfd and ThOt fluid densities will increase by about 2%. | ||
Evaluations performed for the SPU conditions show that the FIV loads on the guide tubes and the upper support columns increases by about 6% and the impact on the lower internals is negligible. Benchmark tests of guide tubes and upper support columns together with previous FIV analysis for similar 4-loop reactors has shown that a large margin exists in regards to calculated stresses versus the code allowable. Therefore, the effect on the FIV on the reactor internals is considered negligible or essentially non-existent for the SPU conditions at the IP3 plant. | Evaluations performed for the SPU conditions show that the FIV loads on the guide tubes and the upper support columns increases by about 6% and the impact on the lower internals is negligible. Benchmark tests of guide tubes and upper support columns together with previous FIV analysis for similar 4-loop reactors has shown that a large margin exists in regards to calculated stresses versus the code allowable. Therefore, the effect on the FIV on the reactor internals is considered negligible or essentially non-existent for the SPU conditions at the IP3 plant. | ||
| Line 380: | Line 395: | ||
: 1. WCAP-7879-P-A, "Four Loop PWR Internals Assurance and Test Program", July 1972. | : 1. WCAP-7879-P-A, "Four Loop PWR Internals Assurance and Test Program", July 1972. | ||
: 2. WCAP-7879-AD1, "Four Loop PWR Internals Assurance and Test Program Addendum 1, IPP-2 Reactor Internals Vibration with-Core Testing Program", October 1972. | : 2. WCAP-7879-AD1, "Four Loop PWR Internals Assurance and Test Program Addendum 1, IPP-2 Reactor Internals Vibration with-Core Testing Program", October 1972. | ||
Steam Generator Steam generator tube vibration and wear are addressed in Section 5.6.6 of the LAR. | |||
Steam and Feedwater Systems and Their Associated Components The main steam and feedwater piping systems and their associated components will be evaluated for potential flow vibration effects resulting from SPU conditions. These piping systems will be included in the piping vibration monitoring plan to be performed in support of SPU. The piping vibration monitoring plan will identify the specific piping locations for monitoring, the monitoring methods to be used (e.g. accelerometers, hand held devices), as well as acceptance criteria to determine piping vibration acceptability. | |||
Refer to response for Generic Issues and Programs Question 3 for additional details related to the overall piping vibration monitoring plan | Refer to response for Generic Issues and Programs Question 3 for additional details related to the overall piping vibration monitoring plan Response to the potential occurrence of loose parts as a result of the power uprate. | ||
Entergy has procedures in place for the control of and exclusion of foreign objects during maintenance activities, including during outages. These procedures have been successful in controlling foreign objects. Entergy has installed metal impact monitors to detect the occurrence of loose parts or foreign objects in the reactor coolant system. Detection of unusual signals to NL-04-155 Docket 50-286 Page 29 of 40 Non-Proprietary from the metal impact monitors triggers investigations and evaluations to determine the source of the signals and to take corrective actions if that is needed. | |||
Entergy has procedures in place for the control of and exclusion of foreign objects during maintenance activities, including during outages. These procedures have been successful in controlling foreign objects. Entergy has installed metal impact monitors to detect the occurrence of loose parts or foreign objects in the reactor coolant system. Detection of unusual signals | |||
Question NL-04-100-LOC-3: | Question NL-04-100-LOC-3: | ||
The LOCA submittals did not address slot breaks at the top and side of the pipe. | The LOCA submittals did not address slot breaks at the top and side of the pipe. | ||
| Line 401: | Line 413: | ||
Figure 3 shows the collapsed liquid level in the core channels. As seen on Figure 3, a trend of decreasing core collapsed liquid levels is established between 130 and 380 seconds, due to downcomer boiling. During this period, the downcomer collapsed liquid levels also tend to decrease (Figure 2). Later in the transient, a reverse trend of stable and gradual increase of core inventory and downcomer levels is observed, due to the adequate SI injection rate. This is consistent with the expected result based on the removal of the initial core stored energy and the gradual reduction in decay heat. | Figure 3 shows the collapsed liquid level in the core channels. As seen on Figure 3, a trend of decreasing core collapsed liquid levels is established between 130 and 380 seconds, due to downcomer boiling. During this period, the downcomer collapsed liquid levels also tend to decrease (Figure 2). Later in the transient, a reverse trend of stable and gradual increase of core inventory and downcomer levels is observed, due to the adequate SI injection rate. This is consistent with the expected result based on the removal of the initial core stored energy and the gradual reduction in decay heat. | ||
Figures 4 shows the collapsed liquid level established in the upper plenum. It is evident that liquid pool is established in the upper plenum and maintained until the end of the transient, with the level approaching the bottom of the hot legs. | Figures 4 shows the collapsed liquid level established in the upper plenum. It is evident that liquid pool is established in the upper plenum and maintained until the end of the transient, with the level approaching the bottom of the hot legs. | ||
to NL-04-155 Docket 50-286 Page 30 of 40 Non-Proprietary Figure 5 shows the vessel liquid mass and indicates an increasing trend beginning at about 340 seconds. This indicates that the increase in inventory due to the pumped safety injection is more than offsetting the loss of inventory through the break. | |||
Based on these results, it is concluded that stable and sustained quench has been established for the Indian Point Unit 3 Large Break LOCA analysis. | Based on these results, it is concluded that stable and sustained quench has been established for the Indian Point Unit 3 Large Break LOCA analysis. | ||
- to NL-04-155 Docket 50-286 Page 31 of 40 Non-Proprietary Indian Point Unit PCT 1 | |||
-PCT 2 | |||
PCT 3 | |||
PCT 4 | |||
PCT 5 | |||
2500 - | |||
2000-1500-0.) | 2000-1500-0.) | ||
E 1000. | E 1000. | ||
500 - | 500 - | ||
0-927:930:219276/29 -Nov-04 Figure 1 - Peak Cladding Temperatures | 0-234442828 3 LBLOCA 0 | ||
0 Rod 0 | |||
0 Rod o | |||
0 Rod 0 | |||
0 Rod 0 | |||
0 Rod CORE QUENCH 2 | |||
3 4 | |||
5 927:930:219276/29 -Nov-04 Figure 1 - Peak Cladding Temperatures to NL-04-155 Docket 50-286 Page 32 of 40 Non-Proprietary 234442828 Indian Point L0-LEVEL LO-LEVEL 0------- | |||
L-LEVEL LO-LEVEL Unit 7 | |||
8 9 | |||
1 0 3 LBLOCA 0 | |||
0 DC 0 | |||
0 DC 0 | |||
0 DC 0 | |||
0 DC CORE QUENCH 2 | |||
3 4 | |||
40 35 30 4 | |||
t t | |||
4 a 25 CJ 20 a).-5 | |||
-C) | |||
En 0l 5 | |||
0 P;jq? | |||
1-ttt | |||
_~l %.==- | |||
¢ | |||
=== | |||
0 100 200 300 400 500 610 927 930 219276/29-Nov-04 Figure 2 - Downcomer Collapsed Liquid Levels to NL-04-155 Docket 50-286 Page 33 of 40 Non-Proprietary Indian Point LO-LEVEL LO-LEVEL | |||
------- LO-LEVEL LO-LEVEL Unit 3 | |||
4 5 | |||
6 234442828 3 LBLOCA CORE QUENCH 0 | |||
0 LP CHANNEL 0 | |||
0 OH/SC/OP CHANNEL 0 | |||
0 GT CHANNEL 0 | |||
0 HA CHANNEL 12 10 a, | |||
-J 6 | |||
= | |||
6 | |||
.2 | |||
-0 anQ) | |||
CaDL | CaDL | ||
- o | |||
= | |||
4 927:930:219276/29 -Nov-04 Figure 3 - Core Collapsed Liquid Levels to NL-04-155 Docket 50-286 Page 34 of 40 Non-Proprietary 234442828 Indian Point LO-L EVEL Unit 3 LBLOCA CORE QUENCH 12 0 | |||
0 COLLAPSED LIQ. LEVEL 3 | |||
2.4 | |||
2.4 | -J C2-, | ||
1.8 1.2 | |||
.6 0 | |||
927:930:219276/29 -Nov-04 Figure 4- Upper Plenum Collapsed Liquid Level (All channels) | 927:930:219276/29 -Nov-04 Figure 4-Upper Plenum Collapsed Liquid Level (All channels) to NL-04-155 Docket 50-286 Page 35 of 40 Non-Proprietary 234442828 Indian Point V F MASS Unit 3 LBLOCA CORE QUENCH 0 | ||
0 0 | |||
VESSEL WATER MASS 250000 200000 IS- | |||
)C, U, | |||
150000 100000 | |||
100000 | _I | ||
_ m of 1 an AJIn l1 50000 0 | |||
A U | A U | ||
IU LUU JUu WUu DUU DUU 927:930:219276/29-Nov-04 Figure 5 - Vessel Liquid Mass to NL-04-155 Docket 50-286 Page 36 of 40 Non-Proprietary Question NL-04-100-LOC-5: | |||
Tables 6.2-3 and 6.2.5 in the Application Report provide LBLOCA and SBLOCA analysis results for the IP2 SPU. Provide all results (peak clad temperature, maximum local oxidation and total hydrogen generation) for both LBLOCA and SBLOCA. For maximum local oxidation include consideration of both pre-existing and post-LOCA oxidation, cladding outside and post-rupture inside oxidation. Also include the results for fuel resident from previous cycles. | Tables 6.2-3 and 6.2.5 in the Application Report provide LBLOCA and SBLOCA analysis results for the IP2 SPU. Provide all results (peak clad temperature, maximum local oxidation and total hydrogen generation) for both LBLOCA and SBLOCA. For maximum local oxidation include consideration of both pre-existing and post-LOCA oxidation, cladding outside and post-rupture inside oxidation. Also include the results for fuel resident from previous cycles. | ||
Response NL-04-100-LOC-5: | Response NL-04-100-LOC-5: | ||
| Line 459: | Line 493: | ||
: 2) Later in life, the clad creep-down benefit still remains in effect. In addition, with increasing irradiation, the power production from the fuel will naturally decrease as a result of depletion of the fissionable isotopes. Reductions in achievable peaking factors in the burned fuel relative to the fresh fuel are realized before the middle of the second cycle of operation. The achievable linear heat rates decrease steadily from this point until the fuel is discharged, at which point the transient oxidation will be negligible. | : 2) Later in life, the clad creep-down benefit still remains in effect. In addition, with increasing irradiation, the power production from the fuel will naturally decrease as a result of depletion of the fissionable isotopes. Reductions in achievable peaking factors in the burned fuel relative to the fresh fuel are realized before the middle of the second cycle of operation. The achievable linear heat rates decrease steadily from this point until the fuel is discharged, at which point the transient oxidation will be negligible. | ||
The pre-transient oxidation increases with burnup, from zero at beginning of life (BOL) to a maximum value at the discharge of the fuel (end of life, or EOL). The design limit 95% upper bound value for each of the fuel designs that will be included in the SPU cores is < 15%. The actual upper bound values predicted for each of the fuel designs are expected to be well below this value. | The pre-transient oxidation increases with burnup, from zero at beginning of life (BOL) to a maximum value at the discharge of the fuel (end of life, or EOL). The design limit 95% upper bound value for each of the fuel designs that will be included in the SPU cores is < 15%. The actual upper bound values predicted for each of the fuel designs are expected to be well below this value. | ||
to NL-04-155 Docket 50-286 Page 37 of 40 Non-Proprietary Based on the above discussion, the transient oxidation decreases from a very conservative maximum of 7.6% at BOL to a negligible value at EOL, while the pre-transient oxidation increases from zero at BOL to a very conservative maximum at EOL of <16%. Additional WCOBRAITRAC and HOTSPOT calculations were performed at an intermediate burnup, accounting for burnup effects on fuel performance data (primarily initial stored energy and rod internal pressure). These calculations support the conclusion that the sum of the transient and pre-transient oxidation remains below 16% at all times in life. This conclusion is applicable to each of the fuel designs that will be included in the SPU cores, and confirms IP3 conformance with the 10 CFR 50.46 acceptance criterion for local oxidation. | |||
Small Break LOCA Pre-existinq and Post-LOCA Oxidation: | Small Break LOCA Pre-existinq and Post-LOCA Oxidation: | ||
As part of the IP3 SPU program, a new SBLOCA analysis was performed. The break spectrum that was analyzed yielded a maximum peak clad temperature of 1543 | As part of the IP3 SPU program, a new SBLOCA analysis was performed. The break spectrum that was analyzed yielded a maximum peak clad temperature of 1543 o F for a 3 inch equivalent break diameter. The break spectrum results are summarized in Tables 6.2-2 and 6.2-3 of Reference 1. Because of the low clad temperatures, fuel rod burst was not predicted to occur, and the maximum transient oxidation was only 1.04%. Because this is so low, the SBLOCA transient needs no further justification since the local oxidation limit will not be challenged even when the end of life initial (steady state) oxide layer is considered. This confirms IP3 conformance with the 10 CFR 50.46 acceptance criterion for local oxidation. | ||
References | References | ||
: 1. | : 1. | ||
Table LOC-5-1 IP3 DESIGN BASIS ANALYSIS LOCA RESULTS LBLOCA | WCAP-16212-P, "Indian Point Nuclear Generating Unit No. 3, Stretch Power Uprate NSSS and BOP Licensing Report," J. R. Stukus, et al., June 2004. | ||
Transient = <7.6% | Table LOC-5-1 IP3 DESIGN BASIS ANALYSIS LOCA RESULTS LBLOCA SBLOCA Peak Clad Temperature 19440F (PCT95%) | ||
Total Hydrogen Generation | 15430F Maximum Local Oxidation Pre-transient = 0% | ||
Pre-transient = 0% | |||
Transient = <7.6% | |||
Transient = 1.04% | |||
Total Hydrogen Generation 0.620% | |||
<< 1% | |||
Regarding prior response to PVM RAI 4d provided in NL-04-073: | Regarding prior response to PVM RAI 4d provided in NL-04-073: | ||
Question NL-04-100-PVM-4d-1: | Question NL-04-100-PVM-4d-1: | ||
| Line 475: | Line 513: | ||
Question NL-04-100-PVM-4d-2: | Question NL-04-100-PVM-4d-2: | ||
Was the technique equivalent to VIP-1 08? | Was the technique equivalent to VIP-1 08? | ||
to NL-04-155 Docket 50-286 Page 38 of 40 Non-Proprietary Response NL-04-100-PVM-4d-2: | |||
As noted in NL-04-145 response to NL-04-073-PVM-4a, the revised calculations for the pressurizer nozzles demonstrate that the postulated flaw size meets the requirements of Appendix G (1/4t or 1 inch). Therefore this RAI is not applicable. | As noted in NL-04-145 response to NL-04-073-PVM-4a, the revised calculations for the pressurizer nozzles demonstrate that the postulated flaw size meets the requirements of Appendix G (1/4t or 1 inch). Therefore this RAI is not applicable. | ||
Question NL-04-100-PVM-4d-3: | Question NL-04-100-PVM-4d-3: | ||
| Line 484: | Line 521: | ||
Question NL-04-121-NRC Item 2: | Question NL-04-121-NRC Item 2: | ||
The Entergy response for Piping and Supports Question 1, in letter NL-04-095 dated August 3, 2004, provides a stress summary table for main steam piping. Please provide similar quantitative results for evaluations performed for other balance-of-plant (BOP) piping systems. | The Entergy response for Piping and Supports Question 1, in letter NL-04-095 dated August 3, 2004, provides a stress summary table for main steam piping. Please provide similar quantitative results for evaluations performed for other balance-of-plant (BOP) piping systems. | ||
Response NL-04-121- NRC Item 2: | Response NL-04-121-NRC Item 2: | ||
Stress summary tables for the other critical balance of plant (BOP) piping systems have been included in the response to PS-1. | Stress summary tables for the other critical balance of plant (BOP) piping systems have been included in the response to PS-1. | ||
Question NL-04-121-NRC Item 7: | Question NL-04-121-NRC Item 7: | ||
| Line 492: | Line 529: | ||
The CVCS malfunction event is discussed in WCAP-1 6212, Licensing Report Section 6.3.5. The question is best addressed by plant mode and the operation of the Reactor Coolant Pumps and the RHR System. | The CVCS malfunction event is discussed in WCAP-1 6212, Licensing Report Section 6.3.5. The question is best addressed by plant mode and the operation of the Reactor Coolant Pumps and the RHR System. | ||
Modes 1, 2, 3: One or more Reactor Coolant Pumps are in service and thus adequate mixing is assured. | Modes 1, 2, 3: One or more Reactor Coolant Pumps are in service and thus adequate mixing is assured. | ||
to NL-04-155 Docket 50-286 Page 39 of 40 Non-Proprietary Modes 4 and 5: At least one Reactor Coolant Pump is in service on shutdowns until Reactor Coolant System temperature is less than approximately 170'F. The RHR System is placed in service when the Reactor Coolant System temperature is less than approximately 350'F thus assuring adequate mixing. Similarly, during startup, the RHR System is in service and a Reactor Coolant Pump is placed in service while Reactor Coolant System temperature is less than 200'F. In addition, the Westinghouse Interim Operating Procedure was developed specifically for these modes, addressing the potential effects of a "dilution front" and a limited active mixing volume, and has been incorporated in plant procedures. | |||
In addition, for modes 4 and 5, at the pressures in the Reactor Coolant System associated with RHR operation (less than 450 psig) letdown flow is limited to 120 gpm. Second, only two charging pumps (90 gpm each) are permitted to be available due to low temperature over pressurization restrictions. | In addition, for modes 4 and 5, at the pressures in the Reactor Coolant System associated with RHR operation (less than 450 psig) letdown flow is limited to 120 gpm. Second, only two charging pumps (90 gpm each) are permitted to be available due to low temperature over pressurization restrictions. | ||
Mode 6: At least one RHR pump (providing a minimum flow rate of 1000 gpm) is in service except during short periods. This flow rate is considered adequate for mixing in the lower plenum. The actual flow from one RHR pump would be much higher than 1000 gpm. While the CVCS Malfunction event has been analyzed in the refueling mode, it is administratively precluded. Plant procedures require that the valve in the boron addition/dilution path be placed in manual and closed upon shutting down the last Reactor Coolant Pump. Thus in Mode 6 (Refueling), plant procedures preclude a dilution event. | Mode 6: At least one RHR pump (providing a minimum flow rate of 1000 gpm) is in service except during short periods. This flow rate is considered adequate for mixing in the lower plenum. The actual flow from one RHR pump would be much higher than 1000 gpm. While the CVCS Malfunction event has been analyzed in the refueling mode, it is administratively precluded. Plant procedures require that the valve in the boron addition/dilution path be placed in manual and closed upon shutting down the last Reactor Coolant Pump. Thus in Mode 6 (Refueling), plant procedures preclude a dilution event. | ||
| Line 507: | Line 543: | ||
Also, Section 5.10.4 of the Stretch Power Uprate Licensing Report provides an estimated increase in PWSCC susceptibility of 9 percent for the RV hot leg nozzle weld as a result of SPU. | Also, Section 5.10.4 of the Stretch Power Uprate Licensing Report provides an estimated increase in PWSCC susceptibility of 9 percent for the RV hot leg nozzle weld as a result of SPU. | ||
How will the 9 percent increase be accommodated in the future? | How will the 9 percent increase be accommodated in the future? | ||
to NL-04-155 Docket 50-286 Page 40 of 40 Non-Proprietary Response NL-04-121-NRC Item 8: | |||
The approach used in Section 5.10.4, was to estimate a relative effect of PWSCC susceptibility by estimating the temperature change in the upper head region based on a conservatively wide range of operating temperatures that correspond to a full-power programmed Tavg range from 5490F to 5720F. The resulting temperature increase of 5.30F was evaluated using the crack initiation probability methodology described in Reference 2 of Section 5.10. | |||
The approach used in Section 5.10.4, was to estimate a relative effect of PWSCC susceptibility by estimating the temperature change in the upper head region based on a conservatively wide range of operating temperatures that correspond to a full-power programmed Tavg range from | |||
In practice, Entergy is required to establish RPV head inspection requirements in accordance with NRC Order EA-03-009. The Order provides for a time-at-temperature methodology to determine the effective degradation years (EDY) value that is used to determine the inspection category. Based on the current plant operating history and cycle-specific temperature data, the projected EDY value increase is 11.8%. As required by the NRC Order, Entergy will recalculate the EDY value to establish the inspection requirements for each refueling outage using plant data for each operating cycle. | In practice, Entergy is required to establish RPV head inspection requirements in accordance with NRC Order EA-03-009. The Order provides for a time-at-temperature methodology to determine the effective degradation years (EDY) value that is used to determine the inspection category. Based on the current plant operating history and cycle-specific temperature data, the projected EDY value increase is 11.8%. As required by the NRC Order, Entergy will recalculate the EDY value to establish the inspection requirements for each refueling outage using plant data for each operating cycle. | ||
Entergy is assessing options to mitigate the effects of PWSCC on continued plant operation. | Entergy is assessing options to mitigate the effects of PWSCC on continued plant operation. | ||
| Line 518: | Line 553: | ||
ATTACHMENT 4 TO NL-04-155 ADDITIONAL INFORMATION FOR IP3 SPU LICENSE AMENDMENT REQUEST BASED ON NRC RAls ISSUED FOR IP2 SPU Non-Proprietary version of responses containing proprietary information (from Westinghouse transmittal PU3-W-04-161) | ATTACHMENT 4 TO NL-04-155 ADDITIONAL INFORMATION FOR IP3 SPU LICENSE AMENDMENT REQUEST BASED ON NRC RAls ISSUED FOR IP2 SPU Non-Proprietary version of responses containing proprietary information (from Westinghouse transmittal PU3-W-04-161) | ||
ENTERGY NUCLEAR OPERATIONS, INC. | ENTERGY NUCLEAR OPERATIONS, INC. | ||
INDIAN POINT NUCLEAR GENERATING UNIT NO. 3 DOCKET NO. 50-286 | INDIAN POINT NUCLEAR GENERATING UNIT NO. 3 DOCKET NO. 50-286 to NL-04-155 Docket 50-286 Page 1 of 2 Question NL-04-100-LOC-3: | ||
The LOCA submittals did not address slot breaks at the top and side of the pipe. | The LOCA submittals did not address slot breaks at the top and side of the pipe. | ||
Justify why these breaks are not considered for the IP2 LBLOCA response Response NL-04-100-LOC-3: | Justify why these breaks are not considered for the IP2 LBLOCA response Response NL-04-100-LOC-3: | ||
| Line 530: | Line 563: | ||
A review of the analysis conditions associated with potential core uncovery due to loop seal re-plugging has previously been performed in Reference 3. Reference 3 documents the Westinghouse position with regards to the potential for Inadequate Core Cooling (ICC) scenarios following Large and Intermediate Break LOCAs as a result of loop seal re-plugging. | A review of the analysis conditions associated with potential core uncovery due to loop seal re-plugging has previously been performed in Reference 3. Reference 3 documents the Westinghouse position with regards to the potential for Inadequate Core Cooling (ICC) scenarios following Large and Intermediate Break LOCAs as a result of loop seal re-plugging. | ||
Reference 3 concludes the following: | Reference 3 concludes the following: | ||
The reactor coolant system response following a LOCA is a dynamic process and the expected response in the long term is similar to the response that occurs in the short term. This short term response has been analyzed extensively through computer analysis and tests and is well documented. | |||
Consideration of the physical mechanisms for liquid plugging of the pump suction leg U-bend piping following large and intermediate break LOCA at realistic decay heat levels precludes quasi steady-state inadequate core cooling conditions. | |||
It is important to emphasize that the operator guidance provided in the Emergency Response Guidelines includes actions to be taken in the event of an indication of a chal-lenge to adequate core cooling following a LOCA. | |||
A review of the key contributors associated with long-term loop seal plugging core uncovery scenarios, under LOCA conditions (specifically extended term SBLOCA conditions), was performed as part of Reference 4 including a review of pertinent experimental data. | A review of the key contributors associated with long-term loop seal plugging core uncovery scenarios, under LOCA conditions (specifically extended term SBLOCA conditions), was performed as part of Reference 4 including a review of pertinent experimental data. | ||
to NL-04-155 Docket 50-286 Page 2 of 2 a,c From References 3 and 4 it can be concluded that post-LOCA core uncovery scenarios as a result of loop seal re-plugging do not constitute a significant concern to Indian Point Unit 3 plant safety. | |||
References | References | ||
: 1. WCAP-1 1372-A, -Westinghouse Small Break LOCA ECCS Evaluation Model Generic Study With the NOTRUMP Code", S. D. Rupprecht, et al., 1986. | : 1. WCAP-1 1372-A, -Westinghouse Small Break LOCA ECCS Evaluation Model Generic Study With the NOTRUMP Code", S. D. Rupprecht, et al., 1986. | ||
| Line 542: | Line 574: | ||
: 4. NSD-NRC-97-5092, "Core Uncovery Due to Loop Seal Re-Plugging During Post-LOCA Recovery," Letter from N. J. Liparulo (W) to NRC, March, 1997. | : 4. NSD-NRC-97-5092, "Core Uncovery Due to Loop Seal Re-Plugging During Post-LOCA Recovery," Letter from N. J. Liparulo (W) to NRC, March, 1997. | ||
ENCLOSURE A TO NL-04-155 Westinghouse authorization letter dated December 8, 2004 (CAW-04-1927), with the accompanying affidavit, Proprietary Information Notice, and Copyright Notice ENTERGY NUCLEAR OPERATIONS, INC. | ENCLOSURE A TO NL-04-155 Westinghouse authorization {{letter dated|date=December 8, 2004|text=letter dated December 8, 2004}} (CAW-04-1927), with the accompanying affidavit, Proprietary Information Notice, and Copyright Notice ENTERGY NUCLEAR OPERATIONS, INC. | ||
INDIAN POINT NUCLEAR GENERATING UNIT NO. 3 DOCKET NO. 50-286 | INDIAN POINT NUCLEAR GENERATING UNIT NO. 3 DOCKET NO. 50-286 | ||
Westinghouse Proprietary Classi | Westinghouse Proprietary Classi -3 Westinghouse U.S. Nuclear Regulatory Commission Document Control Desk Washington, DC 20555-0001 Westinghouse Electric Company Nuclear Services P.O. Box 355 Pittsburgh, Pennsylvania 15230-0355 USA Direct tel: | ||
Direct fax: | |||
e-mail: | |||
(412) 374-4643 (412) 374-4011 greshaja@westinghouse.com Our ref: CAW-04-1927 December 9, 2004 APPLICATION FOR WITHHOLDING PROPRIETARY INFORMATION FROM PUBLIC DISCLOSURE | |||
==Subject:== | ==Subject:== | ||
| Line 551: | Line 586: | ||
Accordingly, this letter authorizes the utilization of the accompanying affidavit by Entergy Nuclear Operations. | Accordingly, this letter authorizes the utilization of the accompanying affidavit by Entergy Nuclear Operations. | ||
Correspondence with respect to the proprietary aspects of the application for withholding or the Westinghouse affidavit should reference this letter, CAW-04-1927, and should be addressed to J. A. Gresham, Manager, Regulatory Compliance and Plant Licensing, Westinghouse Electric Company LLC, P.O. Box 355, Pittsburgh, Pennsylvania 15230-0355. | Correspondence with respect to the proprietary aspects of the application for withholding or the Westinghouse affidavit should reference this letter, CAW-04-1927, and should be addressed to J. A. Gresham, Manager, Regulatory Compliance and Plant Licensing, Westinghouse Electric Company LLC, P.O. Box 355, Pittsburgh, Pennsylvania 15230-0355. | ||
Very truly yo rs, re am, Manager Regulatory Compliance and Plant Licensing Enclosures cc: | Very truly yo rs, re am, Manager Regulatory Compliance and Plant Licensing Enclosures cc: | ||
B. Benney L. Feizollahi A BNFL Group company | |||
CAW-04-1 927 AFFIDAVIT COMMONWEALTH OF PENNSYLVANIA: | CAW-04-1 927 AFFIDAVIT COMMONWEALTH OF PENNSYLVANIA: | ||
ss COUNTY OF ALLEGHENY: | ss COUNTY OF ALLEGHENY: | ||
Before me, the undersigned authority, personally appeared J. A. Gresham, who, being by me duly sworn according to law, deposes and says that he is authorized to execute this Affidavit on behalf of Westinghouse Electric Company LLC (Westinghouse), and that the averments of fact set forth in this Affidavit are true and correct to the best of his knowledge, information, and belief: | Before me, the undersigned authority, personally appeared J. A. Gresham, who, being by me duly sworn according to law, deposes and says that he is authorized to execute this Affidavit on behalf of Westinghouse Electric Company LLC (Westinghouse), and that the averments of fact set forth in this Affidavit are true and correct to the best of his knowledge, information, and belief: | ||
0 J.A. resham, Manager Regulatory Compliance and Plant Licensing Sworn to and subscribed before me this Ad day of ___ | |||
, 2004 Notary Public Notarial Seal Sharon L Rori, Notary Pubric Monroeville Boro, Allegheny Couruy My Comrission Expires January 29.2007 Member, Pennsylria so tion Of Notares | |||
2 | 2 CAW-04-1 927 (1) | ||
(2) I am making this Affidavit in conformance with the provisions of 10 CFR Section 2.390 of the Commission's regulations and in conjunction with the Westinghouse "Application for Withholding" accompanying this Affidavit. | I am Manager, Regulatory Compliance and Plant Licensing, in Nuclear Services, Westinghouse Electric Company LLC (Westinghouse), and as such, I have been specifically delegated the function of reviewing the proprietary information sought to be withheld from public disclosure in connection with nuclear power plant licensing and rule making proceedings, and am authorized to apply for its withholding on behalf of Westinghouse. | ||
(3) I have personal knowledge of the criteria and procedures utilized by Westinghouse in designating information as a trade secret, privileged or as confidential commercial or financial information. | (2) | ||
(4) Pursuant to the provisions of paragraph (b)(4) of Section 2.390 of the Commission's regulations, the following is furnished for consideration by the Commission in determining whether the information sought to be withheld from public disclosure should be withheld. | I am making this Affidavit in conformance with the provisions of 10 CFR Section 2.390 of the Commission's regulations and in conjunction with the Westinghouse "Application for Withholding" accompanying this Affidavit. | ||
(i) | (3) | ||
(ii) | I have personal knowledge of the criteria and procedures utilized by Westinghouse in designating information as a trade secret, privileged or as confidential commercial or financial information. | ||
(4) | |||
Pursuant to the provisions of paragraph (b)(4) of Section 2.390 of the Commission's regulations, the following is furnished for consideration by the Commission in determining whether the information sought to be withheld from public disclosure should be withheld. | |||
(i) | |||
The information sought to be withheld from public disclosure is owned and has been held in confidence by Westinghouse. | |||
(ii) | |||
The information is of a type customarily held in confidence by Westinghouse and not customarily disclosed to the public. Westinghouse has a rational basis for determining the types of information customarily held in confidence by it and, in that connection, utilizes a system to determine when and whether to hold certain types of information in confidence. The application of that system and the substance of that system constitutes Westinghouse policy and provides the rational basis required. | |||
Under that system, information is held in confidence if it falls in one or more of several types, the release of which might result in the loss of an existing or potential competitive advantage, as follows: | Under that system, information is held in confidence if it falls in one or more of several types, the release of which might result in the loss of an existing or potential competitive advantage, as follows: | ||
3 | 3 CAW-04-1 927 (a) | ||
(b) | The information reveals the distinguishing aspects of a process (or component, structure, tool, method, etc.) where prevention of its use by any of Westinghouse's competitors without license from Westinghouse constitutes a competitive economic advantage over other companies. | ||
(c) | (b) | ||
(d) | It consists of supporting data, including test data, relative to a process (or component, structure, tool, method, etc.), the application of which data secures a competitive economic advantage, e.g., by optimization or improved marketability. | ||
(e) | (c) | ||
(f) | Its use by a competitor would reduce his expenditure of resources or improve his competitive position in the design, manufacture, shipment, installation, assurance of quality, or licensing a similar product. | ||
(d) | |||
It reveals cost or price information, production capacities, budget levels, or commercial strategies of Westinghouse, its customers or suppliers. | |||
(e) | |||
It reveals aspects of past, present, or future Westinghouse or customer funded development plans and programs of potential commercial value to Westinghouse. | |||
(f) | |||
It contains patentable ideas, for which patent protection may be desirable. | |||
There are sound policy reasons behind the Westinghouse system which include the following: | There are sound policy reasons behind the Westinghouse system which include the following: | ||
(a) | (a) | ||
(b) | The use of such information by Westinghouse gives Westinghouse a competitive advantage over its competitors. It is, therefore, withheld from disclosure to protect the Westinghouse competitive position. | ||
(b) | |||
It is information that is marketable in many ways. The extent to which such information is available to competitors diminishes the Westinghouse ability to sell products and services involving the use of the information. | |||
4 | 4 CAW-04-1 927 (d) | ||
(e) | Each component of proprietary information pertinent to a particular competitive advantage is potentially as valuable as the total competitive advantage. If competitors acquire components of proprietary information, any one component may be the key to the entire puzzle, thereby depriving Westinghouse of a competitive advantage. | ||
(f) | (e) | ||
(iii) The information is being transmitted to the Commission in confidence and, under the provisions of 10 CFR Section 2.390, it is to be received in confidence by the Commission. | Unrestricted disclosure would jeopardize the position of prominence of Westinghouse in the world market, and thereby give a market advantage to the competition of those countries. | ||
(iv) The information sought to be protected is not available in public sources or available information has not been previously employed in the same original manner or method to the best of our knowledge and belief. | (f) | ||
(v) | The Westinghouse capacity to invest corporate assets in research and development depends upon the success in obtaining and maintaining a competitive advantage. | ||
(iii) | |||
The information is being transmitted to the Commission in confidence and, under the provisions of 10 CFR Section 2.390, it is to be received in confidence by the Commission. | |||
(iv) | |||
The information sought to be protected is not available in public sources or available information has not been previously employed in the same original manner or method to the best of our knowledge and belief. | |||
(v) | |||
The proprietary information sought to be withheld in this submittal is that which is appropriately marked in "Westinghouse IP3 SPU Application (WCAP-16212-P) | |||
Responses to IP2 RAls listed as later" in NL-04-145, December 9, 2004" (Proprietary), being transmitted by the Entergy Nuclear Northeast letter and Application for Withholding Proprietary Information from Public Disclosure, to the Document Control Desk. The proprietary information as submitted for use by Westinghouse for the Indian Point Nuclear Generating Unit No. 3 is expected to be applicable for other licensee submittals in response to certain NRC requirements for justification of Stretch Power Uprate License Amendment Request. | Responses to IP2 RAls listed as later" in NL-04-145, December 9, 2004" (Proprietary), being transmitted by the Entergy Nuclear Northeast letter and Application for Withholding Proprietary Information from Public Disclosure, to the Document Control Desk. The proprietary information as submitted for use by Westinghouse for the Indian Point Nuclear Generating Unit No. 3 is expected to be applicable for other licensee submittals in response to certain NRC requirements for justification of Stretch Power Uprate License Amendment Request. | ||
This information is part of that which will enable Westinghouse to: | This information is part of that which will enable Westinghouse to: | ||
(a) Provide information in support of plant power uprate licensing submittals. | (a) Provide information in support of plant power uprate licensing submittals. | ||
5 | 5 CAW-04-1 927 (b) Provide plant specific calculations. | ||
(c) Provide licensing documentation support for customer submittals. | (c) Provide licensing documentation support for customer submittals. | ||
Further this information has substantial commercial value as follows: | Further this information has substantial commercial value as follows: | ||
(a) | (a) | ||
(b) | Westinghouse plans to sell the use of similar information to its customers for purposes of meeting NRC requirements for licensing documentation associated with power uprate licensing submittals. | ||
(c) | (b) | ||
Westinghouse can sell support and defense of the technology to its customers in the licensing process. | |||
(c) | |||
The information requested to be withheld reveals the distinguishing aspects of a methodology which was developed by Westinghouse. | |||
Public disclosure of this proprietary information is likely to cause substantial harm to the competitive position of Westinghouse because it would enhance the ability of competitors to provide similar calculations, evaluations, analyses and licensing defense services for commercial power reactors without commensurate expenses. | Public disclosure of this proprietary information is likely to cause substantial harm to the competitive position of Westinghouse because it would enhance the ability of competitors to provide similar calculations, evaluations, analyses and licensing defense services for commercial power reactors without commensurate expenses. | ||
Also, public disclosure of the information would enable others to use the information to meet NRC requirements for licensing documentation without purchasing the right to use the information. | Also, public disclosure of the information would enable others to use the information to meet NRC requirements for licensing documentation without purchasing the right to use the information. | ||
| Line 603: | Line 663: | ||
Copies made by the NRC must include the copyright notice in all instances and the proprietary notice if the original was identified as proprietary. | Copies made by the NRC must include the copyright notice in all instances and the proprietary notice if the original was identified as proprietary. | ||
Westin hou~se | Westin hou~se Westinghouse Electric Company 9 | ||
Nuclear Services P.O. Box 355 Pittsburgh, Pennsylvania 15230-0355 USA Direct tel: (412) 374-4643 Direct fax: (412) 374-4011 U.S. Nuclear Regulatory Commission e-mail: greshaja~westinghouse.com Document Control Desk Washington, DC 20555-0001 Our ref: CAW-04-1923 Rev. 1 November 17, 2004 APPLICATION FOR WITHHOLDING PROPRIETARY INFORMATION FROM PUBLIC DISCLOSURE | |||
==Subject:== | ==Subject:== | ||
| Line 615: | Line 676: | ||
Ss COUNTY OF ALLEGHENY: | Ss COUNTY OF ALLEGHENY: | ||
Before me, the undersigned authority, personally appeared J. A. Gresham, who, being by me duly sworn according to law, deposes and says that he is authorized to execute this Affidavit on behalf of Westinghouse Electric Company LLC (Westinghouse), and that the averments of fact set forth in this Affidavit are true and correct to the best of his knowledge, information, and belief: | Before me, the undersigned authority, personally appeared J. A. Gresham, who, being by me duly sworn according to law, deposes and says that he is authorized to execute this Affidavit on behalf of Westinghouse Electric Company LLC (Westinghouse), and that the averments of fact set forth in this Affidavit are true and correct to the best of his knowledge, information, and belief: | ||
J. S. Galembush, Acting Manager Regulatory Compliance and Plant Licensing Sworn to and subscribed before me this | J. S. Galembush, Acting Manager Regulatory Compliance and Plant Licensing Sworn to and subscribed before me this /G A day of | ||
)' | |||
, 2004 Notary Public NotarWal Seal Sharon L Rod, Notary Public Monroeville Boro, Allegheny County My Cn=Isslon Ejraes January 29,2007 Member, Pennesymvnia Associaio of Notaries | |||
2 | 2 CAW-04-1 923 (1) | ||
(2) I am making this Affidavit in conformance with the provisions of 10 CFR Section 2.390 of the Commission's regulations and in conjunction with the Westinghouse "Application for Withholding" accompanying this Affidavit. | I am an Acting Manager, Regulatory Compliance and Plant Licensing, in Nuclear Services, Westinghouse Electric Company LLC (Westinghouse), and as such, I have been specifically delegated the function of reviewing the proprietary information sought to be withheld from public disclosure in connection with nuclear power plant licensing and rule making proceedings, and am authorized to apply for its withholding on behalf of Westinghouse. | ||
(3) I have personal knowledge of the criteria and procedures utilized by Westinghouse in designating information as a trade secret, privileged or as confidential commercial or financial information. | (2) | ||
(4) Pursuant to the provisions of paragraph (b)(4) of Section 2.390 of the Commission's regulations, the following is furnished for consideration by the Commission in determining whether the information sought to be withheld from public disclosure should be withheld. | I am making this Affidavit in conformance with the provisions of 10 CFR Section 2.390 of the Commission's regulations and in conjunction with the Westinghouse "Application for Withholding" accompanying this Affidavit. | ||
(i) | (3) | ||
(ii) | I have personal knowledge of the criteria and procedures utilized by Westinghouse in designating information as a trade secret, privileged or as confidential commercial or financial information. | ||
(4) | |||
Pursuant to the provisions of paragraph (b)(4) of Section 2.390 of the Commission's regulations, the following is furnished for consideration by the Commission in determining whether the information sought to be withheld from public disclosure should be withheld. | |||
(i) | |||
The information sought to be withheld from public disclosure is owned and has been held in confidence by Westinghouse. | |||
(ii) | |||
The information is of a type customarily held in confidence by Westinghouse and not customarily disclosed to the public. Westinghouse has a rational basis for determining the types of information customarily held in confidence by it and, in that connection, utilizes a system to determine when and whether to hold certain types of information in confidence. The application of that system and the substance of that system constitutes Westinghouse policy and provides the rational basis required. | |||
Under that system, information is held in confidence if it falls in one or more of several types, the release of which might result in the loss of an existing or potential competitive advantage, as follows: | Under that system, information is held in confidence if it falls in one or more of several types, the release of which might result in the loss of an existing or potential competitive advantage, as follows: | ||
3 | 3 CAW-04-1 923 (a) | ||
(b) | The information reveals the distinguishing aspects of a process (or component, structure, tool, method, etc.) where prevention of its use by any of Westinghouse's competitors without license from Westinghouse constitutes a competitive economic advantage over other companies. | ||
(c) | (b) | ||
(d) | It consists of supporting data, including test data, relative to a process (or component, structure, tool, method, etc.), the application of which data secures a competitive economic advantage, e.g., by optimization or improved marketability. | ||
(e) | (c) | ||
(f) | Its use by a competitor would reduce his expenditure of resources or improve his competitive position in the design, manufacture, shipment, installation, assurance of quality, or licensing a similar product. | ||
(d) | |||
It reveals cost or price information, production capacities, budget levels, or commercial strategies of Westinghouse, its customers or suppliers. | |||
(e) | |||
It reveals aspects of past, present, or future Westinghouse or customer funded development plans and programs of potential commercial value to Westinghouse. | |||
(f) | |||
It contains patentable ideas, for which patent protection may be desirable. | |||
There are sound policy reasons behind the Westinghouse system which include the following: | There are sound policy reasons behind the Westinghouse system which include the following: | ||
(a) | (a) | ||
(b) | The use of such information by Westinghouse gives Westinghouse a competitive advantage over its competitors. It is, therefore, withheld from disclosure to protect the Westinghouse competitive position. | ||
(b) | |||
It is information that is marketable in many ways. The extent to which such information is available to competitors diminishes the Westinghouse ability to sell products and services involving the use of the information. | |||
4 | 4 CAW-04-1 923 (c) Use by our competitor would put Westinghouse at a competitive disadvantage by reducing his expenditure of resources at our expense. | ||
(d) | (d) | ||
(e) | Each component of proprietary information pertinent to a particular competitive advantage is potentially as valuable as the total competitive advantage. If competitors acquire components of proprietary information, any one component may be the key to the entire puzzle, thereby depriving Westinghouse of a competitive advantage. | ||
(f) | (e) | ||
(iii) | Unrestricted disclosure would jeopardize the position of prominence of Westinghouse in the world market, and thereby give a market advantage to the competition of those countries. | ||
(iv) | (f) | ||
The Westinghouse capacity to invest corporate assets in research and development depends upon the success in obtaining and maintaining a competitive advantage. | |||
(iii) | |||
The information is being transmitted to the Commission in confidence and, under the provisions of 10 CFR Section 2.390, it is to be received in confidence by the Commission. | |||
(iv) | |||
The information sought to be protected is not available in public sources or available information has not been previously employed in the same original manner or method to the best of our knowledge and belief. | |||
(v) The proprietary information sought to be withheld in this submittal is that which is appropriately marked in Attachment A to PU3-W-04-153, "Indian Point Nuclear Generating Unit No. 3 Stretch Power Uprate Westinghouse Responses to RAls" (Proprietary) dated November 16, 2004, being transmitted by the Entergy Nuclear Northeast letter and Application for Withholding Proprietary Information from Public Disclosure, to the Document Control Desk. The proprietary information as submitted for use by Westinghouse for the Indian Point Nuclear Generating Unit No. 3 is expected to be applicable for other licensee submittals | (v) The proprietary information sought to be withheld in this submittal is that which is appropriately marked in Attachment A to PU3-W-04-153, "Indian Point Nuclear Generating Unit No. 3 Stretch Power Uprate Westinghouse Responses to RAls" (Proprietary) dated November 16, 2004, being transmitted by the Entergy Nuclear Northeast letter and Application for Withholding Proprietary Information from Public Disclosure, to the Document Control Desk. The proprietary information as submitted for use by Westinghouse for the Indian Point Nuclear Generating Unit No. 3 is expected to be applicable for other licensee submittals | ||
5 | 5 CAW-04-1 923 in response to certain NRC requirements for justification of Stretch Power Uprate License Amendment Request. | ||
This information is part of that which will enable Westinghouse to: | This information is part of that which will enable Westinghouse to: | ||
(a) Provide information in support of plant power uprate licensing submittals. | (a) Provide information in support of plant power uprate licensing submittals. | ||
| Line 649: | Line 731: | ||
(c) Provide licensing documentation support for customer submittals. | (c) Provide licensing documentation support for customer submittals. | ||
Further this information has substantial commercial value as follows: | Further this information has substantial commercial value as follows: | ||
(a) | (a) | ||
(b) | Westinghouse plans to sell the use of similar information to its customers for purposes of meeting NRC requirements for licensing documentation associated with power uprate licensing submittals. | ||
(c) | (b) | ||
Westinghouse can sell support and defense of the technology to its customers in the licensing process. | |||
(c) | |||
The information requested to be withheld reveals the distinguishing aspects of a methodology which was developed by Westinghouse. | |||
Public disclosure of this proprietary information is likely to cause substantial harm to the competitive position of Westinghouse because it would enhance the ability of competitors to provide similar calculations, evaluations, analyses and licensing defense services for commercial power reactors without commensurate expenses. | Public disclosure of this proprietary information is likely to cause substantial harm to the competitive position of Westinghouse because it would enhance the ability of competitors to provide similar calculations, evaluations, analyses and licensing defense services for commercial power reactors without commensurate expenses. | ||
Also, public disclosure of the information would enable others to use the information to meet NRC requirements for licensing documentation without purchasing the right to use the information. | Also, public disclosure of the information would enable others to use the information to meet NRC requirements for licensing documentation without purchasing the right to use the information. | ||
The development of the technology described in part by the information is the result of applying the results of many years of experience in an intensive Westinghouse effort and the expenditure of a considerable sum of money. | The development of the technology described in part by the information is the result of applying the results of many years of experience in an intensive Westinghouse effort and the expenditure of a considerable sum of money. | ||
6 | 6 CAW-04-1 923 In order for competitors of Westinghouse to duplicate this information, similar technical programs would have to be performed and a significant manpower effort, having the requisite talent and experience, would have to be expended. | ||
Further the deponent sayeth not. | Further the deponent sayeth not. | ||
Latest revision as of 00:16, 16 January 2025
| ML043570328 | |
| Person / Time | |
|---|---|
| Site: | Indian Point  |
| Issue date: | 12/15/2004 |
| From: | Dacimo F Entergy Nuclear Northeast |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| NL-04-155, TAC MC3552 | |
| Download: ML043570328 (69) | |
Text
Entergy Nuclear Northeast Indian Point Energy Center 450 Broadway, GSB
~ En ergyP.O.
Box 249 Buchanan, NY 10511-0249 Tel 914 734 6700 Fred Dacimo Site Vice President Administration December 15, 2004 Re:
Indian Point Unit 3 Docket No. 50-286 NL-04-155 Document Control Desk U.S. Nuclear Regulatory Commission Mail Stop O-P1-17 Washington, DC 20555-0001
Subject:
Supporting Information for License Amendment Request Regarding Indian Point 3 Stretch Power Uprate (TAC MC 3552)
Reference:
- 1. Entergy Letter NL-04-069 to NRC; "Proposed Changes to Technical Specifications: Stretch Power Uprate (4.85%) and Adoption of TSTF-339", dated June 3, 2004.
- 2.
Entergy Letter NL-04-145 to NRC; "Supporting Information for License Amendment Request Regarding Indian Point 3 Stretch Power Uprate (TAC MC 3552)," dated November 18, 2004
Dear Sir:
Entergy Nuclear Operations, Inc (Entergy) is submitting additional information to support NRC review of the stretch power uprate (SPU) license amendment request (Reference 1) for Indian Point 3 (IP3). This additional information, based on NRC staff questions regarding the uprate request for Indian Point 2, is being provided as discussed during a meeting with NRC on September 14, 2004. This letter supplements the Reference 2 letter and covers the balance of questions regarding uprate request for Indian Point 2. is a summary listing of those RAls that are being addressed in this letter. The responses to the RAls are provided in Attachment 2, except for responses that contain proprietary information. The proprietary responses and the corresponding non-proprietary version of those responses are provided in Attachments 3 and 4, respectively.
As Attachment 3 contains information proprietary to Westinghouse Electric Company, it is supported by an affidavit signed by Westinghouse, the owner of the information. The affidavit sets forth the basis on which the information may be withheld from public disclosure by the Commission and addresses with specificity the considerations listed in paragraph (b)(4) of Section 2.390 of the Commission's regulations. Accordingly, it is respectfully requested that the information that is proprietary to Westinghouse be withheld from public disclosure in accordance A.wo!
NL-04-155 Docket 50-286 Page 2 of 3 with 10 CFR 2.390 of the Commission's regulations. Westinghouse authorization letter dated December 9, 2004 (CAW-04-1927), with the accompanying affidavit, Proprietary Information Notice, and Copyright Notice is provided in Enclosure A.
Correspondence with respect to the copyright on proprietary aspects of the items listed above or the supporting affidavit should reference CAW-04-1927 and should be addressed to J. A.
Gresham, Manager, Regulatory Compliance and Plant Licensing, Westinghouse Electric Company LLC, P. 0. Box 355, Pittsburgh, Pennsylvania 15230-0355.
The additional supporting information provided in this letter does not alter the conclusions of the no significant hazards evaluation that supports the subject license amendment request. There are no new commitments being made in this submittal. If you have any questions or require additional information, please contact Mr. Kevin Kingsley at (914) 734-6695.
I declare under penalty of perjury that the foregoing is true and correct. Executed on l__l___.
S Io Fred R. Dacimo Site Vice President Indian Point Energy Center : : : :
Enclosure A:
cc: next page Summary Listing of RAI Responses Regarding Stretch Power Uprate License Amendment Request for Indian Point 3 Additional Information for IP3 SPU License Amendment Request, Based on NRC RAls Issued for IP2 SPU Additional Information for IP3 SPU License Amendment Request, Based on NRC RAls Issued for IP2 SPU (with Proprietary Information)
Additional Information for IP3 SPU License Amendment Request, Based on NRC RAls Issued for IP2 SPU (non-Proprietary version of Attachment 3)
Westinghouse Withholding Request for Attachment 3 Proprietary Information
NL-04-155 Docket 50-286 Page 3 of 3 cc:
Mr. Patrick D. Milano, Senior Project Manager Project Directorate I Division of Licensing Project Management U.S. Nuclear Regulatory Commission Mail Stop 0 8 C2 Washington, DC 20555-0001 Mr. Samuel J. Collins Regional Administrator, Region 1 U.S. Nuclear Regulatory Commission 475 Allendale Road King of Prussia, PA 19406-1415 Resident Inspector's Office Indian Point Unit 3 U.S. Nuclear Regulatory Commission P.O. Box 337 Buchanan, NY 10511-0337 Mr. Peter R. Smith, President New York State Energy, Research and Development Authority 17 Columbia Circle Albany, NY 12203 Mr. Paul Eddy New York State Dept. of Public Service 3 Empire State Plaza Albany, NY 12223-6399
ATTACHMENT 1 TO NL-04-155
SUMMARY
LISTING OF RAI RESPONSES REGARDING STRETCH POWER UPRATE LICENSE AMENDMENT REQUEST FOR INDIAN POINT 3 ENTERGY NUCLEAR OPERATIONS, INC.
INDIAN POINT NUCLEAR GENERATING UNIT NO. 3 DOCKET NO. 50-286 to NL-04-155 Docket 50-286 Page 1 of 4 No.
RAI Review Area From Lefter IP3 Response I
NL-04-073-FP-1 Fire Protection NL-04-073 Att 2 - Non-Proprietary 2
NL-04-073-FP-2 Fire Protection NL-04-073 Att 2 - Non-Proprietary 3
NL-04-073-FP-3a Fire Protection NL-04-073 Att 2 - Non-Proprietary 3
NL-04-073-FP-3b Fire Protection NL-04-073 Att 2 - Non-Proprietary 3
NL-04-073-FP-3c Fire Protection NL-04-073 Att 2 - Non-Proprietary 4
NL-04-073-EL-1 Electrical NL-04-073 Att 2 - Non-Proprietary 5
NL-04-073-IC-1 Instrumentation and Controls NL-04-073 See letter NL-04-145 6
NL-04-073-IC-2 Instrumentation and Controls NL-04-073 See letter NL-04-145 7
NL-04-073-IC-3 Instrumentation and Controls NL-04-073 See letter NL-04-145 8
NL-04-073-IC-4 Instrumentation and Controls NL-04-073 See letter NL-04-145 9
NL-04-073-IC-5 Instrumentation and Controls NL-04-073 See letter NL-04-145 10 NL-04-073-IC-6 Instrumentation and Controls NL-04-073 Not Applicable 11 NL-04-073-IC-7 Instrumentation and Controls NL-04-073 See letter NL-04-145 12 NL-04-073-PVM-la Pressure Vessel Materials NL-04-073 See letter NL-04-145 12 NL-04-073-PVM-1 b Pressure Vessel Materials NL-04-073 See letter NL-04-145 13 NL-04-073-PVM-2 Pressure Vessel Materials NL-04-073 See letter NL-04-145 14 NL-04-073-PVM-3a Pressure Vessel Materials NL-04-073 Not Applicable 14 NL-04-073-PVM-3b Pressure Vessel Materials NL-04-073 See letter NL-04-145 14 NL-04-073-PVM-3c Pressure Vessel Materials NL-04-073 See letter NL-04-145 15 NL-04-073-PVM-4a Pressure Vessel Materials NL-04-073 See letter NL-04-145 15 NL-04-073-PVM-4b Pressure Vessel Materials NL-04-073 See letter NL-04-145 15 NL-04-073-PVM-4c Pressure Vessel Materials NL-04-073 Att 2 - Non-Proprietary 15 NL-04-073-PVM-4d Pressure Vessel Materials NL-04-073 See letter NL-04-145 16 NL-04-073-RSA-1 Reactor Systems and Analyses NL-04-073 See letter NL-04-145 17 NL-04-073-RSA-2a Reactor Systems and Analyses NL-04-073 See letter NL-04-145 17 NL-04-073-RSA-2b Reactor Systems and Analyses NL-04-073 See letter NL-04-145 18 NL-04-073-RSA-3 Reactor Systems and Analyses NL-04-073 See letter NL-04-145 19 NL-04-073-RSA-4 Reactor Systems and Analyses NL-04-073 Not Applicable 20 NL-04-073-RSA-5 Reactor Systems and Analyses NL-04-073 Not Applicable 21 NL-04-073-RSA-6 Reactor Systems and Analyses NL-04-073 See letter NL-04-145 22 NL-04-073-RSA-7 Reactor Systems and Analyses NL-04-073 See letter NL-04-145 23 NL-04-073-RSA-8 Reactor Systems and Analyses NL-04-073 See letter NL-04-145 to NL-04-155 Docket 50-286 Page 2 of 4 No.
RAI Review Area From Letter 1P3 Response 24 NL-04-073-RSA-9a Reactor Systems and Analyses NL-04-073 See letter NL-04-145 24 NL-04-073-RSA-9b Reactor Systems and Analyses NL-04-073 See letter NL-04-145 25 NL-04-073-RSA-10a Reactor Systems and Analyses NL-04-073 Not Applicable 25 NL-04-073-RSA-10b Reactor Systems and Analyses NL-04-073 See letter NL-04-145 25 NL-04-073-RSA-1Oc Reactor Systems and Analyses NL-04-073 See letter NL-04-145 25 NL-04-073-RSA-1Od Reactor Systems and Analyses NL-04-073 See letter NL-04-145 25 NL-04-073-RSA-10e Reactor Systems and Analyses NL-04-073 See letter NL-04-145 26 NL-04-073-RSA-1 1 Reactor Systems and Analyses NL-04-073 See letter NL-04-145 27 NL-04-073-RSA-12a Reactor Systems and Analyses NL-04-073 See letter NL-04-145 27 NL-04-073-RSA-12b Reactor Systems and Analyses NL-04-073 See letter NL-04-145 28 NL-04-073-RSA-13a Reactor Systems and Analyses NL-04-073 See letter NL-04-145 28 NL-04-073-RSA-13b Reactor Systems and Analyses NL-04-073 See letter NL-04-145 29 NL-04-073-RSA-14 Reactor Systems and Analyses NL-04-073 See letter NL-04-145 30 NL-04-073-RSA-15 Reactor Systems and Analyses NL-04-073 See letter NL-04-145 31 NL-04-073-RSA-16 Reactor Systems and Analyses NL-04-073 See letter NL-04-145 32 NL-04-073-RSA-17a Reactor Systems and Analyses NL-04-073 See letter NL-04-145 32 NL-04-073-RSA-17b Reactor Systems and Analyses NL-04-073 See letter NL-04-145 32 NL-04-073-RSA-17c Reactor Systems and Analyses NL-04-073 See letter NL-04-145 33 NL-04-073-RSA-18 Reactor Systems and Analyses NL-04-073 See letter NL-04-145 34 NL-04-073-RSA-19 Reactor Systems and Analyses NL-04-073 See letter NL-04-145 35 NL-04-073-RSA-20 Reactor Systems and Analyses NL-04-073 See letter NL-04-145 36 NL-04-073-ENV-1 Environmental Considerations NL-04-073 Not Applicable 37 NL-04-073-ENV-2 Environmental Considerations NL-04-073 Not Applicable 38 NL-04-073-ENV-3 Environmental Considerations NL-04-073 Att 2 - Non-Proprietary 39 NL-04-073-FAC-1 a Flow Accelerated Corrosion Program NL-04-073 See letter NL-04-145 39 NL-04-073-FAC-1b Flow Accelerated Corrosion Program NL-04-073 See letter NL-04-145 39 NL-04-073-FAC-lc Flow Accelerated Corrosion Program NL-04-073 See letter NL-04-145 39 NL-04-073-FAC-1 d Flow Accelerated Corrosion Program NL-04-073 See letter NL-04-145 39 NL-04-073-FAC-1 e Flow Accelerated Corrosion Program NL-04-073 See letter NL-04-145 40 NL-04-073-PCP-la Protective Coatings Program NL-04-073 See letter NL-04-145 40 NL-04-073-PCP-lb Protective Coatings Program NL-04-073 See letter NL-04-145 40 NL-04-073-PCP-lc Protective Coatings Program NL-04-073 See letter NL-04-145 to NL-04-155 Docket 50-286 Page 3 of 4 No.
RAI Review Area From Letter 1P3 Response 41 NL-04-073-SG-1 Steam Generator Structural Integrity Evaluation NL-04-073 Not Applicable 42 NL-04-073-SG-2a Steam Generator Structural Integrity Evaluation NL-04-073 See letter NL-04-145 42 NL-04-073-SG-2b Steam Generator Structural Integrity Evaluation NL-04-073 Not Applicable 42 NL-04-073-SG-2c Steam Generator Structural Integrity Evaluation NL-04-073 See letter NL-04-145 43 NL-04-073-SG-3a Steam Generator Structural Integrity Evaluation NL-04-073 See letter NL-04-145 43 NL-04-073-SG-3b Steam Generator Structural Integrity Evaluation NL-04-073 See letter NL-04-145 44 NL-04-073-SG-4 Steam Generator Structural Integrity Evaluation NL-04-073 See letter NL-04-145 45 NL-04-073-SG-5 Steam Generator Structural Integrity Evaluation NL-04-073 See letter NL-04-145 46 NL-04-073-SG-6 Steam Generator Structural Integrity Evaluation NL-04-073 See letter NL-04-145 47 NL-04-073-SG-7 Steam Generator Structural Integrity Evaluation NL-04-073 See letter NL-04-145 48 NL-04-073-DOS-1 Dose Assessments NL-04-073 See letter NL-04-145 49 NL-04-073-DOS-2 Dose Assessments NL-04-073 See letter NL-04-145 50 NL-04-073-DOS-3 Dose Assessments NL-04-073 See letter NL-04-145 51 NL-04-073-DOS-4 Dose Assessments NL-04-073 See letter NL-04-145 52 NL-04-073-DOS-5 Dose Assessments NL-04-073 See letter NL-04-145 53 NL-04-086-FDF-1 Fuel Design Features and Components NL-04-086 See letter NL-04-145 54 NL-04-086-FDF-2 Fuel Design Features and Components NL-04-086 See letter NL-04-145 55 NL-04-086-FDF-3 Fuel Design Features and Components NL-04-086 See letter NL-04-145 56 NL-04-086-FDF-4 Fuel Design Features and Components NL-04-086 See letter NL-04-145 57 NL-04-086-FDF-5 Fuel Design Features and Components NL-04-086 See letter NL-04-145 58 NL-04-086-FDF-6 Fuel Design Features and Components NL-04-086 Not Applicable 59 NL-04-095-LOC-1 LOCA Transients NL-04-095 See letter NL-04-145 60 NL-04-095-LOC-2 LOCA Transients NL-04-095 Not Applicable NL-04-100-LOC-3 LOCA Transients NL-04-100 See NL-04-100-LOC-3 NL-04-100-LOC-4 LOCA Transients NL-04-100 See NL-04-100-LOC-4 NL-04-100-LOC-5 LOCA Transients NL-04-100 See NL-04-100-LOC-5 61 NL-04-095-NFS-1 NSSS Fluid Systems NL-04-095 See letter NL-04-145 62 NL-04-095-MDT-1 Mechanical Equipment Design Transients NL-04-095 Not Applicable 63 NL-04-095-PS-1 Piping and Supports NL-04-095 Att 2 - Non-Proprietary 64 NL-04-095-GIP-1 Generic Issues and Programs NL-04-095 See letter NL-04-145 65 NL-04-095-GIP-2 Generic Issues and Programs NL-04-095 Not Applicable 66 NL-04-095-GIP-3 Generic Issues and Programs NL-04-095 See letter NL-04-145 to NL-04-155 Docket 50-286 Page 4 of 4 No.
RAI Review Area From Letter IP3 Response 67 NL-04-095-GIP-4 Generic Issues and Programs NL-04-095 See letter NL-04-145 68 NL-04-095-GIP-5 Generic Issues and Programs NL-04-095 See letter NL-04-145 69 NL-04-095-GIP-6 Generic Issues and Programs NL-04-095 See letter NL-04-145 70 NL-04-095-GIP-7 Generic Issues and Programs NL-04-095 See letter NL-04-145 71 NL-04-095-GIP-8 Generic Issues and Programs NL-04-095 See letter NL-04-145 72 NL-04-095-GIP-9 Generic Issues and Programs NL-04-095 Not Applicable 73 NL-04-095-GIP-10 Generic Issues and Programs NL-04-095 See letter NL-04-145 74 NL-04-095-GIP-1 1 Generic Issues and Programs NL-04-095 Att 2 - Non-Proprietary 75 NL-04-095-GIP-12 Generic Issues and Programs NL-04-095 Att 2 - Non-Proprietary 76 NL-04-095-GIP-13 Generic Issues and Programs NL-04-095 Att 2 - Non-Proprietary 77 NL-04-095-GIP-14 Generic Issues and Programs NL-04-095 Att 2 - Non-Proprietary 78 NL-04-100-LOC-3 LOCA Transients NL-04-100 Att 3, 4 - Proprietary 79 NL-04-100-LOC-4 LOCA Transients NL-04-1 00 Att 2 - Non-Proprietary 80 NL-04-100-LOC-5 LOCA Transients NL-04-100 Att 2 - Non-Proprietary 81 NL-04-100-PVM-3a -1 Pressure Vessel Materials NL-04-100 See letter NL-04-145 81 NL-04-100-PVM-3a -2 Pressure Vessel Materials NL-04-100 See letter NL-04-145 81 NL-04-100-PVM-3a -3 Pressure Vessel Materials NL-04-100 See letter NL-04-145 81 NL-04-100-PVM-3a -4 Pressure Vessel Materials NL-04-100 See letter NL-04-145 82 NL-04-100-PVM-4a -1 Pressure Vessel Materials NL-04-100 See letter NL-04-145 82 NL-04-100-PVM-4d -1 Pressure Vessel Materials NL-04-100 Att 2 - Non-Proprietary 82 NL-04-100-PVM-4d -2 Pressure Vessel Materials NL-04-100 Att 2 - Non-Proprietary 82 NL-04-100-PVM-4d -3 Pressure Vessel Materials NL-04-100 Att 2 - Non-Proprietary 83 NL-04-100-SG-1 Steam Generator Structural Integrity Evaluation NL-04-100 Not Applicable 84 NL-04-100-SG-3 Steam Generator Structural Integrity Evaluation NL-04-100 Not Applicable 85 NL-04-121-NRC-1 Mechanical Equipment Design Transients NL-04-121 See letter NL-04-145 86 NL-04-121-NRC-2 Piping and Supports NL-04-121 Att 2 - Non-Proprietary 87 NL-04-121-NRC-3 LOCA Transients NL-04-121 See letter NL-04-145 88 NL-04-121-NRC-4 Steam Generator Structural Integrity Evaluation NL-04-121 See letter NL-04-145 89 NL-04-121-NRC-5 NSSS Fluid Systems NL-04-121 See letter NL-04-145 90 NL-04-121-NRC-6 Pressure Vessel Materials NL-04-121 See letter NL-04-145 91 NL-04-121-NRC-7 Reactor Systems and Analyses NL-04-121 Att 2 - Non-Proprietary 92 NL-04-121-NRC-8 Pressure Vessel Materials NL-04-121 Att 2 - Non-Proprietary
ATTACHMENT 2 TO NL-04-155 ADDITIONAL INFORMATION FOR IP3 SPU LICENSE AMENDMENT REQUEST BASED ON NRC RAIs ISSUED FOR IP2 SPU (Refer to Attachments 3 and 4 for other responses involving proprietary information)
ENTERGY NUCLEAR OPERATIONS, INC.
INDIAN POINT NUCLEAR GENERATING UNIT NO. 3 DOCKET NO. 50-286 to NL-04-155 Docket 50-286 Page 1 of 40 Non-Proprietary Question NL-04-073-FP-1:
In NRR RS-001, Revision 0, 'Review Standard for Extended Power Uprates," Attachment 2 to Matrix 5, "Supplemental Fire Protection Review Criteria," states that "... power uprates typically result in increases in decay heat generation following plant trips. These increases in decay heat usually do not affect the elements of a fire protection program related to (1) administrative controls, (2) fire suppression and detection systems, (3) fire barriers, (4) fire protection responsibilities of plant personnel, and (5) procedures and resources necessary for the repair of systems required to achieve and maintain cold shutdown. In addition, an increase in decay heat will usually not result in an increase in the potential for a radiological release resulting from a fire. However, the licensee's application should confirm that these elements are not impacted by the extended power uprate..."
Section 10.1, "Fire Protection (10CFR50 Appendix R) Program," of application report (Attachment IlIl to the January 29 letter) does not address these items. At a minimum, provide a statement to address each of these items.
Response NL-04-073-FP-1:
IP3 SPU results in increased decay heat generation following plant trips. The RHR Cooldown Analysis for SPU, documents that cold shutdown is achieved and maintained within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. It should be noted that the subject analysis includes a specific "Appendix R" cooldown case that uses only the limited equipment set credited in the IP3 Appendix R Safe-Shutdown Model. The updated cooldown analysis and evaluation addressing SPU confirms that cold shutdown can be achieved and maintained using this same limited equipment set, inclusive of the additional burden associated with SPU. Appendix R program administrative controls are unchanged. The elements of the program such as Fire Suppression; Fire Barriers; Fire protection responsibilities of plant personnel are unchanged. Procedures and resources necessary for the repair of systems required to achieve and maintain cold shutdown are unaffected and the radiological release resulting from a fire is also unchanged.
Question NL-04-073-FP-2:
In NRR RS-001, Attachment 2 to Matrix 5, states that "... where licensees rely on less than full capability systems for fire events..., the licensee should provide specific analyses for fire events that demonstrate that (1) fuel integrity is maintained by demonstrating that the fuel design limits are not exceeded and (2) there are no adverse consequences on the reactor pressure vessel integrity or the attached piping. Plants that rely on alternative/dedicated or backup shutdown capability for post-fire safe shutdown should analyze the impact of the power uprate on the alternative/dedicated or backup shutdown capability... The licensee should identify the impact of the power uprate on the plant's post-fire safe shutdown procedures."
Section 10.1, of application report does not address the items above. As a minimum, provide a statement to address each of these items.
Response NL-04-073-FP-2:
The evaluation of the IP3 Fire Protection Program was conducted to determine the effect of SPU on the program. There are no modifications required by the SPU to the plant equipment to NL-04-155 Docket 50-286 Page 2 of 40 Non-Proprietary used for post-fire safe shutdown. There are minor changes required for the procedures. The procedures are capable of being used to achieve post-fire safe shutdown as shown by the response to item FP-3b and as noted in section 4.1.3 of the IP3 SPU Licensing Report.
The analysis and evaluations for the Appendix R cooldown show that the plant is maintained and cooled to 200'F with RCS pressure below the RCS Safety Valve setpoint, with level in the pressurizer, with positive subcooling and with decay heat being removed. Based on the analysis and evaluations for the Appendix R cooldown, the fuel remains covered and therefore fuel design limits are not exceeded and there are no adverse consequences on the reactor pressure vessel integrity or the attached piping. Additional detail regarding the Appendix R cooldown analysis and evaluation is provided in the response to question 3b.
Alternate Shutdown Capability The normal sources of auxiliary ac power at IP3 during plant operation are both off-site power and three emergency diesel generators. If these sources are disabled by fire, the safe-shutdown loads can be supplied by an alternate diesel generator. As addressed in the Indian Point Unit 3 UFSAR, Section 9.6.2.5, "Safe Shutdown Capability in Case of Fire," there are two alternate shutdown schemes credited in compliance with 10CFR50 Appendix R,Section III.G.3, that utilize an alternate diesel generator (referred to herein as the "Appendix R diesel generator"): (1) a scheme that makes use of local control stations in the Auxiliary Feedwater (AFW) Pump Room, Primary Auxiliary Building (PAB), and the Auxiliary Boiler Feedwater Pump Building to effect shutdown following a fire that requires safe shutdown from outside the Control Room, and (2) a scheme that makes use of the'Appendix R diesel generator aligned to the 480V vital buses to ensure safe shutdown from the Control Room.
The Appendix R diesel generator (DG) is a dedicated 2500 kw diesel generator located in its
- own enclosure in the yard area. AC power generated by the Appendix R DG can be supplied to 6.9 kv buses 5 and 6. These buses in turn feed 6.9 kv buses 1 and 3, which supply 480V to buses 312 through 313 through step-down transformers. Supporting services for the Appendix R ac power source are independent of the supporting equipment used by the emergency diesel generators (e.g., service water, 125V dc control power, starting air, and fuel oil).
The alternative power system, as described above, is designed to be independent and sufficiently isolated from the existing emergency power system to ensure the availability of power to the safe shutdown equipment of concern in the event of fires in the Control and Diesel Generator Buildings. In case of a fire affecting certain portions of the PAB and Electrical Tunnels which could disable emergency diesel generator auxiliaries, the Appendix R DG can be used to power the 480V vital buses to ensure safe shutdown from the Control Room.
The local control station in the PAB is provided with indication of pressurizer level, RCS pressure, and source range neutron flux. Operators at this location will control RCS boration and makeup with the charging pumps. The local control station in the AFW Pump Room is provided with indication of steam generator water level and pressure, pressurizer level, RCS pressure, and RCS loop 31 hot and cold leg temperature. The local control station for the Steam Generator atmospheric relief valves is located in the Auxiliary Feedwater Pump Building.
The SPU does not affect the above-described alternate shutdown schemes. There are no modifications required by the SPU to the plant equipment used for post-fire safe shutdown.
to NL-04-155 Docket 50-286 Page 3 of 40 Non-Proprietary Evaluation of Appendix R DG load requirements under SPU conditions shows that there are no significant load increases that would affect the conclusions of the existing Appendix R DG load analysis.
Question NL-04-073-FP-3:
Section 10.1 of Attachment IlIl (WCAP-16157-P) to the License Amendment Request, states that "for the SPU, the steam generator dryout time provides adequate time for the operator to supply feedwater to the secondary side of the steam generator. The Appendix R plant cooldown analysis under SPU conditions shows that IP2 complies with the Appendix R requirement that cold shutdown be achieved within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> after reactor trip following a fire."
- a. Provide a discussion, including numerical values, of the change, if any, in steam generator dry-out time as a result of the SPU, and reference to the calculations performed to determine there is adequate time for the required operator action.
- b. Provide a discussion, including numerical values, of the change, if any, in time to achieve cold shutdown as a result of the SPU, and reference to the calculations performed to determine that it can be achieved within the required time frame.
- c. Provide corresponding references, including appropriate extracts from the Updated Final Safety Analysis Report (UFSAR), plant-specific Appendix R evaluation, etc.,
that justify these claims.
Response NL-04-073-FP-3a:
The Indian Point Fire Protection Plan states that the steam generators would not dryout in 30 minutes. For the Stretch Power Uprate, the steam generator dry out time was predicted using the RETRAN code and an IP3 plant-specific calculation. The initiating event was a Loss of all AC Power to the Station Auxiliaries. The analysis conservatively assumed an initial power level of 102% of 3216 MWt and a minimum initial SG level of 35%. Decay heat was based on the 1979 version of ANS 5.1 and includes a 2 sigma uncertainty. The results of this analysis showed that the steam generators would boil dry after approximately 39 minutes.
To assure continued natural circulation and removal of decay heat by steaming to the atmosphere, auxiliary feedwater should be injected prior to the steam generator dryout. This ability was demonstrated by timed field walkdowns, which showed that auxiliary feedwater could be injected well within 30 minutes.
Response NL-04-073-FP-3b:
For purposes of Appendix R cooldown analysis, the RHR cooldown analysis for Appendix R conditions is discussed in Section 4.1.3 of WCAP-16212-P and documents the cooldown from the RHR cooldown initiation to achieving cold shutdown with in the Appendix R requirement of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. The evaluation of a natural circulation cooldown from normal operating temperature (NOT) to RHR cooldown initiation conditions at 350"F is discussed below.
to NL-04-155 Docket 50-286 Page 4 of 40 Non-Proprietary Natural Circulation Cooling Analysis (NOT to 3500F)
To demonstrate that the stretch power uprate (SPU) does not adversely affect the natural circulation cooling capability of the IP3 plant, an evaluation for post-fire safe shutdown was performed. The evaluation considered only on the limited equipment set available for the IP3 Appendix R safe-shutdown conditions. It was based on the scheme that makes use of local control stations in the Auxiliary Feedwater (AFW) Pump Room, Primary Auxiliary Building (PAB), and the Auxiliary Boiler Feedwater Pump Building to effect shutdown following a fire that requires safe shutdown from outside the Control Room. Following plant trip and control room evacuation, the plant is cooled by steam relief from the Main Steam Safety Valves. RCPs are tripped and pressurizer PORVs and pressurizer heaters are assumed unavailable. One motor-driven AFW pump feeding 2 Steam Generators with manual flow control is credited after 30 minutes. One charging pump is assumed after 60 minutes to provide RCS makeup from the RWST and to increase RCS boron concentration. Charging flow is manually controlled. Plant cooldown at 250F/hr is commenced 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> after reactor trip. Steam Generator Atmospheric Relief valves are manually operated to control the cooldown. A total delay of 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> is assumed to allow the upper head to cool or 'soak" before depressurizing to the RHR cut-in pressure. As per the ERG generic analysis, this upper-head soak delay is included to allow the upper-head region sufficient time to cool due to the assumed loss of control rod drive mechanism (CRDM) fans.
The SPU evaluation concluded that the RCS pressure would be stabilized at 375 psia (360 psig) with Thot < 3500F in all hot legs and at the core exit at approximately 28 hours3.240741e-4 days <br />0.00778 hours <br />4.62963e-5 weeks <br />1.0654e-5 months <br /> after reactor trip.
From this condition, RHR cooling can be initiated to cool the RCS to < 200WF. within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
RHR Cooling Analysis (3500F to 200 0F)
The SPU affects the plant cooldown time(s) since core power, and therefore the decay heat increases. The plant cooldown calculation was performed at a core power of 3216 MWt to support the SPU. The RCS heat capacity and the other RHR heat loads were explicitly considered in these analyses. The analysis was performed to confirm that the RHR and CCW systems continue to meet their design basis functional requirements and performance criteria for plant cooldown under the uprated power conditions. The two-train system alignment was considered to address the design capability in the Indian Point Unit 3 Updated Final Safety Analysis Report (UFSAR). In addition, a cooldown analysis was performed to support the worst-case scenario for the 10CFR50 Appendix R (Reference 4) fire safe shutdown analysis.
The following considerations were applied to these cooldown analyses:
- The CCW and RHR HX data assumes 5-percent tube plugging, as was used for the previous cooldown analyses of record (AOR).
- The design service water temperature of 950F was assumed. For the Appendix R cooldown, the CCWS supply temperature is limited to 1250F.
- Various CCWS auxiliary heat loads and the RCS heat capacity were included in the normal cooldown cases and the Appendix R plant cooldown case. These heat loads, along with an increase in the spent fuel pool heat load (assuming a full SFP of fuel that has operated at 3216 MWt) were used in the cooldown analysis.
to NL-04-155 Docket 50-286 Page 5 of 40 Non-Proprietary Decay heat curves based on 24-month fuel cycles were used.
Service water (SW) flow rates for Appendix R cooldown were varied to minimize SW flow demand while meeting the Appendix R criteria as shown in Table NL-04-073-FP-1.
The Appendix R/safe shutdown cases continue to meet the 72-hour time limit for cold shutdown.
For these cases, the minimum CCW HX service water flow to meet the time 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> cooldown time limit criterion was determined as shown in Table NL-04-073-FP-1.
Acceptable RHR cooldown performance is provided at the SPU conditions for normal plant cooldown and the limiting Appendix R/safe shutdown cases, based on the service water flows shown in Table NL-04-073-FP-1.
Table NL-04-073-FP-1 SPU Cooldown Analyses Results Cooldown Time Cooldown Time RHR Initiation Time Total SW to 1400F (hrs.
to 200OF (hrs.
@3500F (hrs. after Flow Cases after shutdown) after shutdown) shutdown)('
(gpm)
A. App. R, Enhanced CCW N/A 64.8(2) 29.0 5700 UAIU, 5700 gpm SW Flow B. App. R, Enhanced CCW N/A 71.8 29.0 4700 UA/U, SW Flow Minimized to Meet 72-hr. Cooldown Time C. App. R, Original Design N/A 71.9 29.0 5324 SSC UANU, SW Flow Minimized to Meet 72-hr.
Cooldown Time D. Same as A without SFP NIA 58.0(2) 29.0 5700 Heat Load E. Same as B without SFP N/A 71.8 29.0 3596 Heat Load F. Same as C. Without SFP N/A 72.0 29.0 3918 Heat Load Notes:
- 1. The 29-hour cut-in time for the Appendix R cases, limited by the Ccws supply temperature, is also indicative of the cut-in time assumed in the radiological consequences analyses of accidents with secondary side releases (that is, SGTR).
- 2. These cases increase the component cooling water return piping temperature compared to the previous 1.4% MUR Appendix R analysis. Previous Appendix R cases had a maximum return temperature of 173 0F, and the temperature for case D is 188*F, which remains bounded by post-LOCA conditions.
Appendix R Cooldown analysis and evaluation demonstrate that IP3 can be cooled from the normal operating temperature to the RHR initiation conditions using a natural circulation cooling to NL-04-155 Docket 50-286 Page 6 of 40 Non-Proprietary process in 29 hours3.356481e-4 days <br />0.00806 hours <br />4.794974e-5 weeks <br />1.10345e-5 months <br /> and from the RHR initiation condition to cold shutdown within the requirement of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
Response NL-04-073-FP-3c:
The Indian Point Unit 3 UFSAR, Table 9.3-2, "Residual Heat Removal Loop Component Data,"
documents the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> requirement regarding time after plant shutdown to reach cold shutdown conditions for Appendix R fire scenarios. This table also documents the time after plant shutdown that shutdown cooling is initiated. As indicated in the response to Question FP-3b, under SPU conditions the time after plant shutdown that RHR shutdown cooling is initiated is 29 hours3.356481e-4 days <br />0.00806 hours <br />4.794974e-5 weeks <br />1.10345e-5 months <br />.
As addressed in the responses to Questions FP-3a and FP-3b, plant specific analysis and evaluation were performed to show that IP3 is capable of achieving cold shutdown conditions within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> after reactor trip following a fire.
Alternate Shutdown Capability The normal sources of auxiliary ac power at IP3 during plant operation are both off-site power and three emergency diesel generators. If these sources are disabled by fire, the safe-shutdown loads can be supplied by an alternate diesel generator. As addressed in the Indian Point Unit 3 UFSAR, Section 9.6.2.5, "Safe Shutdown Capability in Case of Fire," there are two alternate shutdown schemes credited in compliance with 10CFR50 Appendix R,Section III.G.3, that utilize an alternate diesel generator (referred to herein as the 'Appendix R diesel generator"): (1) a scheme that makes use of local control stations in the Auxiliary Feedwater (AFW) Pump Room, Primary Auxiliary Building (PAB), and the Auxiliary Boiler Feedwater Pump Building to effect shutdown following a fire that requires safe shutdown from outside the Control Room, and (2) a scheme that makes use of the Appendix R diesel generator aligned to the 480V vital buses to ensure safe shutdown from the Control Room.
The Appendix R diesel generator (DG) is a dedicated 2500 kw diesel generator located in its own enclosure in the yard area. AC power generated by the Appendix R DG can be supplied to 6.9 kv buses 5 and 6. These buses in turn feed 6.9 kv buses 1 and 3, which supply 480V to buses 312 through 313 through step-down transformers. Supporting services for the Appendix R ac power source are independent of the supporting equipment used by the emergency diesel generators (e.g., service water, 125V dc control power, starting air, and fuel oil).
The alternative power system, as described above, is designed to be independent and sufficiently isolated from the existing emergency power system to ensure the availability of power to the safe shutdown equipment of concern in the event of fires in the Control and Diesel Generator Buildings. In case of a fire affecting certain portions of the PAB and Electrical Tunnels which could disable emergency diesel generator auxiliaries, the Appendix R DG can be used to power the 480V vital buses to ensure safe shutdown from the Control Room.
The local control station in the PAB is provided with indication of pressurizer level, RCS pressure, and source range neutron flux. Operators at this location will control RCS boration and makeup with the charging pumps. The local control station in the AFW Pump Room is provided with indication of steam generator water level and pressure, pressurizer level, RCS to NL-04-155 Docket 50-286 Page 7 of 40 Non-Proprietary pressure, and RCS loop 31 hot and cold leg temperature. The local control station for the atmospheric dump valves is located in the Auxiliary Feedwater Pump Building.
The SPU does not affect the above-described alternate shutdown schemes. There are no modifications required by the SPU to the plant equipment used for post-fire safe shutdown.
Evaluation of Appendix R DG load requirements under SPU conditions shows that there are no significant load increases that would affect the conclusions of the existing Appendix R DG load analysis.
Entergy procedure 3-AOP-SSD-1 Revision 2 is the procedure for Post-Fire safe shutdown operations. This procedure has been reviewed for SPU and only minor changes are required for SPU.
Conclusions The Indian Point Unit 3 UFSAR, Table 9.3-2, 'Residual Heat Removal Loop Component Data,"
documents the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> requirement regarding time after plant shutdown to reach cold shutdown conditions for Appendix R fire scenarios. This table also documents the time after plant shutdown that shutdown cooling is initiated. As indicated in the response to Question FP-3b, under SPU conditions the time after plant shutdown that RHR cooling is initiated is 29 hours3.356481e-4 days <br />0.00806 hours <br />4.794974e-5 weeks <br />1.10345e-5 months <br />.
As addressed in the responses to Questions FP-3a and FP-3b, plant specific analysis and evaluation were performed to show that IP3 is capable of achieving cold shutdown conditions within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> after reactor trip following a fire.
Question NL-04-073-EL-1:
Address the compensatory measures that the licensee would take to compensate for the depletion of the nuclear unit megavolt-ampere reactive (MVAR) capability on a grid-wide basis.
Response NL-04-073-EL-1:
See Entergy letter NL-04-156 for the response to this question.
Question NL-04-073-PVM-4:
Table 5.9-5 of the application report indicates a flaw depth of 0.50-inch for safety and relief nozzle (corner) and 0.15-inch for upper shell meet the fracture toughness requirements of Appendix G of the ASME Code (NOTE: Table 5.9-5 indicates K/KIR is 0.94 for the safety and relief nozzle (corner) and 1.0 for the upper shell).
- a. Describe the analysis that determined a 0.50-inch flaw depth for the safety and relief nozzle (corner) and a 0.1 5-inch flaw depth for the upper shell will meet the fracture toughness requirements of Appendix G of the ASME Code.
- b. Identify whether the analysis satisfies the requirements of Article G-2220 of Section Xl of the ASME Code. Does the analysis for the safety and relief nozzles and upper shell satisfy these structural factors?
to NL-04-155 Docket 50-286 Page 8 of 40 Non-Proprietary
- c. Describe the non-destructive examination technique which will be utilized to inspect the safety and relief nozzles and upper shell.
- d. Provide the data, a description of the analysis, and the probability of detection of flaws with a depth of 0.50-inch for the safety and relief nozzle and 0.1 5-inch for the upper shell.
Response NL-04-073-PVM-4a:
See letter NL-04-145 for response.
Response NL-04-073-PVM-4b:
See letter NL-04-145 for response.
Response NL-04-073-PVM-4c:
As noted in NL-04-145 response to NL-04-073-PVM-4a, the revised calculations for the pressurizer nozzles demonstrate that the postulated flaw size meets the requirements of Appendix G (1/4t or 1 inch).
Safety and Relief Nozzle:
The IP3 Pressurizer has three Code Safety Inner Radius Nozzles (201R, 21 IR, and 221R) and one Power Operated Relief Inner Radius Nozzle (231R). These nozzles are ASME Section Xl, Code Category B-D, Item B3.120. These nozzles require volumetric examinations per ASME Section Xl, 1989 Code Edition. However, for the Third 1 0-year Interval, which ends in July 2009, Entergy submitted Relief Request 3-16 to perform a remote visual (VT-1) with color capability on each of the nozzle inner radius sections. The NRC approved this relief request on April 22, 2003 (TAC No. MB4766).
Upper Shell:
The IP3 Pressurizer shell has 9 circumferential welds (1, 3, 5, 7, 9, 11, 13, 15, 17) and 8 longitudinal welds (2, 4, 6, 8, 10, 12, 14, 16). For the purposes of this discussion, welds 16, and 17 will be considered the upper shell welds since weld 17 is the uppermost circumferential weld and weld 16 is its intersecting longitudinal weld. These welds are the welds required to be inspected by ASME Section Xl, Table IWB-2500-1, Code Category B-B, Item B2.11 and B2.12.
Table IWB-2500-1, Category B-B, Note 4 requires the volumetric coverage stipulated by Figures IWB-2500-1 and 2 be performed on 100% of the Code Class 1 circumferential welds and the adjoining 1 foot section of the longitudinal welds. The upper circumferential (17) and longitudinal (16) welds are enclosed in a biological and missile shield and are completely inaccessible for volumetric examination (NDE). Therefore, for the Third 1 0-year Interval, which ends in July 2009, Entergy submitted Relief Request 3-14 to perform a visual examination (VT-
- 2) for leakage during system pressure tests performed each refueling outage in accordance with IWB-2500, Category B-P and Code Case N-498-1. The NRC approved this relief request on April 22, 2003 (TAC No. MB4766).
to NL-04-155 Docket 50-286 Page 9 of 40 Non-Proprietary Response NL-04-073-PVM-4d:
See letter NL-04-145 for response.
Question NL-04-073-ENV-3:
Section 5.7 states that the current power uprate qualifies for a categorical exclusion under 10 CFR 51.22(c)(9). Provide the environmental evaluation performed for the proposed power uprate in accordance with Appendix B of the facility operating license. The response should include a discussion of the radiological and non-radiological impacts of the proposed uprate.
Response NL-04-073-ENV-3:
The environmental evaluation of the impact of the IP3 Stretch Power Uprate (SPU) is provided in the IP3 SPU Licensing Attachment IlIl, Sections 6.11 and 11. The evaluation concludes that the proposed license amendment to increase rated thermal power to 3216 MWt and the related changes to the plant technical specifications do 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 10CFR51.22(c)(9).
The radiological analysis for annual radwaste effluent releases estimates the impact of uprate on normal operation offsite doses using scaling techniques. The system parameters for uprated conditions used in the analysis reflect the flow rates and coolant masses at a NSSS power level of 3230 MWt and a core power level of 3280.3 MWt. The evaluation utilizes offsite doses based on an average 5 yr set of organ and whole body doses calculated from effluent reports for the years 1998 through 2002 extrapolated to 100% availability at the associated average annual core power level. Releases occurring during periods of Unit shutdown are conservatively lumped with operational releases and included in the doses scaled for 100% availability.
The qualitative assessment is based on methodology and equations found in NUREG-0017 Rev. 1 (Ref 1), and a comparison of the change in power level and in plant coolant system parameters (e.g., reactor coolant mass, steam generator liquid mass, steam flow rate, reactor coolant letdown flow rate, flow rate to the cation demineralizer, letdown flow rate for boron control, steam generator blowdown flow rate, steam generator moisture carryover, etc.) for both pre-uprate and uprate conditions. To estimate an upper bound impact on off-site doses, the highest factor found for any chemical group of radioisotopes pertinent to the release pathway is applied to the average doses previously determined as representative of operation at pre-uprate conditions (at 100% availability) to estimate the maximum potential increase in effluent doses due to the uprate and demonstrate that the estimated off-site doses following uprate, although increased, will continue to remain below regulatory limits.
The criteria used in the evaluation include a liquid and gaseous radwaste systems' design capable of maintaining normal operation offsite releases and doses within the requirements of 10CFR50, Appendix I (Ref. 2) following power uprate. (Note that actual performance and operation of installed equipment, and reporting of actual offsite releases and doses continues to be controlled by the requirements of the Technical Specifications and the Offsite Dose Calculation Manual.)
to NL-04-155 Docket 50-286 Page 10 of 40 Non-Proprietary The non-radiological impact of the IP3 SPU to 3216 MWt was reviewed and evaluated considering the information contained in the Final Environmental Statement (FES) (Ref. 3) for the station. Section 1 of Appendix B of the Facility Operating License requires environmental concerns identified in the FES that relate to water quality matters to be regulated by way of the State Pollutant Discharge Elimination System (SPDES) permit (Ref. 4) limits. The Indian Point SPDES restrictions on discharge temperatures and discharge flow rates for the station were evaluated along with the flow limits set forth in IP3 SPDES Consent Order (Ref. 5).
The criteria used in the evaluation required that the environmental impacts associated with the proposed changes be within the existing regulatory release permits.
Uprate Evaluation Radiological Effects The power uprate has no significant impact on the expected annual radwaste effluent releases/doses (i.e. all doses remain a small percentage of allowable Appendix I doses) as summarized below.
- 1.
Expected Reactor Coolant Source Terms The requested SPU is an increase of 4.85% in reactor power and the source term would increase by the same amount. However, based on a comparison of base vs. power uprate input parameters, and the methodology outlined in NUREG 0017, the effective factor increase in dose depending on chemical group of isotopes released, ranges between 1.11 to 1.12;, Note that-the maximum expected increase in the reactor coolant source due to the uprate is well within the uncertainty of the existing (NUREG 0017 based) expected reactor coolant isotopic inventory used for radwaste effluent analyses.
- 2.
Estimated Impact on Effluent Doses due to Uprate Gaseous Effluents Dose Gamma Air (mrad) 3.74E-04 Beta Air (mrad) 7.60E-04 Iodine and Particulate (mrem) 8.22E-04 Liquid Effluents Dose Organ Dose (mrem) 3.OOE-03 Adult Total Body (mrem) 1.22E-03 The estimated doses due to uprate are presented above and are a fraction of that allowable under 10CFR50 Appendix I.
to NL-04-155 Docket 50-286 Page 11 of 40 Non-Proprietary
- 3.
Solid Radioactive Waste Though solid radwaste is not specifically addressed in 10 CFR 50, Appendix I, for completeness relative to radwaste assessments, the impact of core uprate on solid radwaste generation is summarized below.
For a 'new' facility, the estimated volume and activity of solid waste is linearly related to the core power level. However, for an existing facility that is undergoing power uprate, the volume of solid waste would not be expected to increase proportionally, since the power uprate neither appreciably impacts installed equipment performance, nor does it require drastic changes in system operation or maintenance. Only minor, if any, changes in waste generation volume are expected. However, it is expected that the activity levels for most of the solid waste would increase proportionately to the increase in long half-life coolant activity bounded by maximum increase in power.
Therefore, following uprate, the liquid and gaseous radwaste effluent treatment system will remain capable of maintaining normal operation offsite doses within the requirements of 10 CFR 50 Appendix I. Only minor, if any, changes in solid waste generation volume are expected.
Non-Radiological Effects The IP3 FES that was approved by the AEC in February 1975 for a maximum calculated thermal power of 3,216.5 MWt envelops the SPU condition. Increased heat rejection to the plant
-systems is expected to result in a nominal calculated increase in discharge temperature to the Hudson River. This temperature increase falls within the applicable SPDES permit thermal limits for Indian Point.
Final Environmental Statement (FES)
The environmental issues associated with the issuance of an operating license for Indian Point Unit 3 were originally evaluated in the Indian Point Unit 3 FES that was approved by the AEC in February 1975. The AEC approved Final Environmental Statement (FES) relates to operation of Indian Point Nuclear Generating Plant Unit No. 3 (Volume 1, page 1-1 Section I) and has addressed plant operation up to a maximum calculated thermal power of 3,216.5 MWt. The SPU does not significantly change the types or the amount of any effluents that may be released offsite that have not already been evaluated and approved in the FES for a power rating of 3,216.5 MWt. Since the AEC approved FES has already addressed plant operation up to a maximum calculated thermal power of 3,216.5 MWt, the SPU has been determined to not significantly impact the FES.
State Pollutant Discharge Elimination System (SPDES) Permit and Consent Order Flows The State Pollutant Discharge Elimination System (SPDES) permit places restrictions on discharge temperatures and discharge flow rates to the river for the station. The Indian Point SPDES restrictions on discharge temperatures and discharge flow rates for the station were evaluated along with the flow limits set forth in Indian Point 3 Consent Order.
IP3 operation at the SPU power level of 3216 MWt will increase the exhaust steam flow and to NL-04-155 Docket 50-286 Page 12 of 40 Non-Proprietary duty of the main condenser and, therefore, increase the heat load rejected by the Circulating Water System (CWS). The SPU evaluation assumes the existing CWS pumps are not modified and continue to operate at the same flow rates. Heat load increases due to SPU in the Normal and Emergency Service Water System (SWS) will also result in increase in the SWS discharge temperature.
The SPDES permit has the following limitations that regulate the discharge temperature:
The maximum discharge temperature at station DSNO01 shall not exceed 43.30C (11 0F) and Between April 15 and June 30 the daily average discharge temperature at station DSNO01 shall not exceed 340C (93.20F) for an average of more than 10 days per year during the term of the permit beginning with 1981; provided that in no event shall the daily average discharge temperature at Station DSNO01 exceed 340C (93.20F) on more than 15 days between April 15 and June 30 in any year.
The Station's discharge temperatures were evaluated using the heat balance model (PEPSE).
The temperature rise across each condenser from the model was tuned based on plant data from July 28, 2003. In addition, State Consent Order flows were used as input to the PEPSE model. Additional conservatism was added to the calculated temperature to account for miscellaneous plant cooling to determine plant discharge temperature. Plant historic data for the river water inlet temperature was iterated to predict the maximum plant discharge temperatures.
Based on conservative maximum plant discharge temperatures and the existing administrative controls imposed on plant operation, it is concluded that the station will remain capable of meeting SPDES permit limits at SPU conditions.
References
- 1.
NUREG 0017, Rev. 1, April 1985, 'Calculation of Releases of Radioactive Materials in Gaseous and Liquid Effluents from Pressurized Water Reactors"
- 2.
Code of Federal Regulations Title 10, Part 50, Appendix I, "Numerical Guides for Design Objectives and Limiting Conditions for Operation to Meet the Criterion As Low As Reasonably Achievable for Radioactive Material in Light Water Cooled Nuclear Power Reactor Effluents".
- 3.
Final Environmental Statement Related to Operation of Indian Point Nuclear Generating Plant Unit No. 3, Consolidated Edison Company of New York, Inc. Docket No. 50-286, February 1975
- 4.
New York State Department of Environmental Conservation, State Pollutant Discharge Elimination System (SPDES) Discharge Permit, 11/90
- 5.
Fourth Amended Stipulation of Settlement and Judicial Consent Order, Index No. 6570-91, RJI No. 0191-ST3251 to NL-04-155 Docket 50-286 Page 13 of 40 Non-Proprietary Question NL-04-095-LOC-3:
The LOCA submittals did not address slot breaks at the top and side of the pipe.
Justify why these breaks are not considered for the IP2 LBLOCA response Response NL-04-095-LOC-3:
The response this question contains proprietary information. The proprietary and non-proprietary versions of the response are provided as response NL-04-100-LOC-3 in Attachments 3 and 4 of this letter, respectively.
Question NL-04-095-LOC-4:
Provide the LBLOCA analysis results (tables and graphs, as appropriate) to the time that stable and sustained quench is established.
Response NL-04-095-LOC-4:
See response NL-04-100-LOC-4.
Question NL-04-095-LOC-5:
Tables 6.2-3 and 6.2.5 in the Application Report provide LBLOCA and SBLOCA analyses results for the IP2 SPU.
Provide all results (peak clad temperature, maximum local oxidation, and total hydrogen generation) for both LBLOCA and SBLOCA. For maximum local oxidation include consideration of both pre-existing and post-LOCA oxidation, and cladding outside and post-rupture inside oxidation. Also include the results for fuel resident from previous cycles.
Response NL-04-095-LOC-5:
See response NL-04-100-LOC-5.
Question NL-04-095-PS-1:
In Section 9.9.3 of the Application Report, the justifications provided on page 9.9-3 for not evaluating the piping and support systems where the increase in temperature, pressure and flow rate are less than 5 percent of the current rated design basis condition are qualitative and nonspecific. For instance, the licensee stated that these increases are some what offset by conservatism in analytical methods used. The licensee also indicated that conservatism may include the enveloping of multiple thermal operating conditions.
Provide the technical basis for not evaluating these piping and support systems. The technical justifications should be based on specific quantitative assessment or intuitively conservative deduction. Also, discuss how the flow effects on the transient loads, which may increase non-proportional to the ratio of flow rate change, are considered (see page 9.9.2).
to NL-04-155 Docket 50-286 Page 14 of 40 Non-Proprietary Response NL-04-095-PS-1:
All piping systems with change factors greater than 1.0 were evaluated to document pipe stress and support system acceptability.
The method used to qualify the main steam piping involved detailed computer analysis of the piping system.
Although operating temperatures and pressures at SPU conditions were bounded by the existing data considered in the design basis piping evaluations, the main steam piping was evaluated using detailed computer analysis in order to reconcile an approximate 6 percent flow rate increase that results due to SPU conditions. These detailed evaluations were performed to assess the potential increase in fluid transient stresses and loads resulting from a turbine stop valve (TSV) closure event.
A summary of revised main steam system stress levels corresponding to SPU conditions is provided in Table 1. The results presented include existing stress levels (i.e., pre-uprate),
revised pipe stress levels for SPU conditions, allowable stress for the applicable loading condition, and the resulting design margin for each piping analysis that was evaluated to reconcile SPU conditions. The design margin provided is based on the ratio of the calculated stress divided by the allowable stress.
- to NL-04-155 Docket 50-286 Page 15 of 40 Non-Proprietary Table I Stress Summary at SPU Conditions Piping Analysis Loading Existing SPU Allowable Design Description Condition Stress Stress Stress Margin (psi)
(psi)
(psi)
Main Steam Line 1 DL + LP +TSV 12,410 12,587 21,000 0.60 Main Steam Line 2 11,993 (Inside Containment)
DL + LP + TSV 11,833 21,000 0.57 Main Steam Line 3 DL + LP + TSV 12,812 13,234 21,000 0.63 (inside Containment)
DL+L+TS 12823,4 2,00.6 Inside Containment)
DL + LP + TSV 12,649 12,811 21,000 0.61 Main Steam Lines 1, Thermal 2, 3 and 4 (Outside expansion 18,489 19,171 19,950 0.96 Containment)
Notes:
- 1. Loading condition "DL + LP + TSV" corresponds to the combination of stresses due to deadweight + pressure + turbine stop valve effects.
- 2. Stress Ratio reported is based on the ratio of SPU stress divided by the allowable stress.
For the remaining piping systems with thermal and pressure change factors greater than 1.0, these piping systems (i.e., condensate, feedwater, extraction steam, feedwater heaters vents and drains, and moisture separator and reheater drains systems) were evaluated using computer analyses, as well as performing a field walkdown of the piping systems.
The results presented in Tables 2 through 5 contain stress data for the critical portions of the Condensate, Feedwater, Extraction Steam and Feedwater Heater Vent & Drains Systems. The results provided include existing stress levels (i.e., pre-uprate), revised pipe stress* levels for SPU conditions, allowable stress for the applicable loading condition, and the resulting design margin for each piping analysis that was evaluated to reconcile SPU conditions. The design margin provided is based on the ratio of the calculated SPU stress divided by the allowable stress.
to NL-04-155 Docket 50-286 Page 16 of 40 Non-Proprietary Table 3 Fcedwatcr System Stress Summary Piping Analysis Loading Existing SPU Stress Allowable Design Description Condition Stress (psi)
(psi)
Stress (psi)
Margin Feedwater to SG 31 DL + LP 6,532 7,162 17,500 0.41 Feedwater to SG 32 DL + LP 8,095 8,725 17,500 0.50 Feedwater to SG 33 DL + LP 7,569 8,199 17,500 0.47 Feedwater to SG 34 DL + LP 7,532 7,982 17,500 0.46 Table 4 Extraction Steam System Stress Summary Piping Analysis Loading Existing SPU Stress Allowable Design Description Condition Stress (psi)
(psi)
Stress (psi)
Margin Extraction Steam to DL + LP 1,734 1,780 15,000 0.12 Heaters 33A/B/C Extraction Steam to Thermal 4,620 4,727 22,500 0.21 Heaters 33A/B/C Table 5 FWN' Heater Vents and Drains System Stress Summary Piping Analysis Loading Existing SPU Stress Allowable Design Description Condition Stress (psi)
(psi)
Stress (psi)
Margin Heaters 34A/B/C to DL + LP 1,808 1,825 15,000 0.12 Heaters 33A/B/C Heaters 34A/B/C to Thermal 13,308 13,544 22,500 0.60 Heaters 33A/B/C In addition to the detailed evaluations that were performed of the critical portions of the Condensate, Feedwater, Extraction and Feedwater Heater Vents and Drains Systems described above, a turbine building plant walkdown of these piping systems was also performed to review the individual piping layouts and associated pipe support configurations. The purpose of these piping system walkdowns was to assess the adequacy of the installed piping deadweight spans and to review the existing thermal flexibility of the piping systems. The overall assessment from the walkdowns performed concluded that the existing piping that was observed was adequately supported and contained adequate flexibility to accommodate the small pressure and temperature changes resulting from SPU. Piping systems were determined to be adequately supported if the piping was supported by vertical supports, rod hangers or to NL-04-155 Docket 50-286 Page 17 of 40 Non-Proprietary spring hangers, such that piping spans were consistent with the guidance presented in ASA B31.1-1955, Code for Pressure Piping. Piping systems were determined to have adequate flexibility if the following attributes were observed:
Piping lengths and offsets were consistent with simplified industry methods of determining flexibility (for example, nomographs).
There were no non-integral or integrally welded piping anchors installed.
There was a sufficient and reasonable number of piping elbows installed providing thermal flexibility.
Hence, based on the detailed evaluations of the critical portions of these systems along with the additional plant walkdowns that were performed, it is concluded that these piping systems remain acceptable and will continue to satisfy design basis requirements when considering the temperature and pressure effects resulting from SPU conditions.
Question NL-04-095-GIP-11:
Section 10.8.4, "SPU Equipment Qualification Evaluation," states that accident temperatures outside containment in the steam and feedline penetration area have been reanalyzed and result in higher temperatures, and that all equipment outside containment required for accident response have been justified as qualified.
Discuss the evaluation of any safety-related pumps and valves located in the steam and feedline penetration area, and the impact on their performance from higher temperature due to SPU conditions.
Response NL-04-095-GIP-1 1:
The equipment types in the main steam and feedline penetration area on the EQ list are ASCO solenoid valves, Namco limit switches, Westinghouse and Buchanan terminal blocks, and associated cables manufactured by GE PVC and Rockbestos Firewall IlIl Cable, CONAX Connectors, and Fisher E/P Transducers. There are no EQ pumps in this area. The EQ valves evaluated are the ASCO valves.
The equipment was evaluated using the thermal analysis of the components for a 1.4 square foot MSLB header break downstream from the Main Steam Isolation Valves, summer building ventilation configuration for the outdoor louvers and 102% SPU power.
The results are presented in Graph 1 for the ASCO solenoid valves. The temperature of the ASCO case and the coil are very close. The coil is only energized for 20 seconds to perform the safety function of tripping the MSIVs, so there is little heat generated within the component.
As shown on Graph 1, the temperature of the ASCO coil and case remain below the qualification test temperature. The qualification testing for the ASCO valves included a pre-test accident soak to assure the ASCOs reached the test chamber temperature.
The cables that are associated with the ASCO solenoid valves are installed in conduit. These cables were also thermally analyzed. Graph 2 indicates that the cables remain below their qualification temperature.
to NL-04-155 Docket 50-286 Page 18 of 40 Non-Proprietary
- 1. ASCO solenoid valves are qualified for both the 10-minute and the 15-minute operator response time. The peak temperature of the 15-minute operator response time is 350.7490F. The ASCO test report (Reference 1) demonstrates that the ASCO solenoid valves have been tested to temperatures enveloping this peak temperature.
- 2. Buchanan terminal blocks are qualified for both the 10-minute and the 15-minute operator response time because the qualification test envelopes the accident profile. The maximum thermal lag temperature of the terminal blocks is 322.30F. The qualification test peaks at 3460F.
- 3. The Westinghouse terminal blocks are not qualified for the 322.30F temperature (15 minute response), but are qualified for the 10-minute operator response time with the peak thermal lag temperature of 2790F compared to the qualification test temperature of 2950F (Reference 2).
The peak temperature of the 15-minute operator response time is 362.6760 F (1.4 SF break in winter with 15-minute operator response). The peak test temperature is 370OF. The time over the qualification curve can be shown to reduce the time of the qualification temp of 3500F long term by only 748 seconds. The impact is an 8% reduction of thermal life at 3500F but no impact on the overall transient being enveloped by the qualification test.
Therefore the GE Cable is considered also qualified for the 15-minute operator response time.
- 5. The Rockbestos Firewall IlIl cable is qualified to 6740F (Reference 3).
- 6. Conax conduit seals are qualified for both the 10-minute operator response time and the 15-minute operator response time. The peak thermal lag temperature of the Conax is 329.8760F (1.4 SF break in winter with 15 minute operator response time). The qualification test peaks at 3800.
- 7. Namco limit switches are qualified for the 10-minute operator response time. The peak temperature of the 15 minute operator response time of 335.313'F (1.4 SF break in winter with 15 minute operator response) exceeds the existing qualification test of 315'F. However, the following qualification test reports yield higher temperatures: QTR 157, Rev 1 peaks at 3640F and QTR 155 peaks at 341OF. Also, the length of time that the Namco exceeds the test temperature of 315 0F is 1777 seconds and results conservatively in reducing the thermal life at 3150F slightly (4%) which does not affect the test enveloping the accident temperature. Therefore, the Namco limit switches are considered also qualified for the 15-minute operator response time.
- 8. The Fisher E/P Transducers were already evaluated for the higher Pre-SPU power level and were found acceptable.
Summary: All of the equipment, except the Westinghouse terminal blocks, is qualified for accident conditions for the longer 15-minute operator response time. All of the equipment is qualified for the 10-minute operator response time.
to NL-04-155 Docket 50-286 Page 19 of 40 Non-Proprietary
References:
- 1. ASCO Test Report, EQ-QR 03.02.01, AQR-67368, Rev. 1
- 2. EQ file EQ-SE-17.01.01, Westinghouse Terminal Blocks
- 3. Wyle Qualification Report 4795R01, 12/24/2002, "Environmental Qualification Extension of Rockbestos Firewall IlIl XLPE and GE Flamenol PVC Cables for use in Entergy Nuclear Northeast Indian Point Energy Center Unit 3" to NL-04-155 Docket 50-286 Page 20 of 40 Non-Proprietary Graph I for NL-04-095-GIP-1I ASCO Thermal Lag Temperature Response 15 minute Operator Response Time 4500-ir ___ C__H j
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1 10 100 1000 10000 100000 Time (sec) to NL-04-155 Docket 50-286 Page 21 of 40 Non-Proprietary Graph 2 for NL-04-095-GIP-11 CABLE Thermal Lag Temperature Response 15 minute Operator Response Time Area-Winter I
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Time (sec) to NL-04-155 Docket 50-286 Page 22 of 40 Non-Proprietary Question NL-04-095-GIP-12:
Section 10.10, "Generic Letter 95-07," states that the effect of the SPU on the current pressure locking and thermal binding evaluation was reviewed, and that the SPU does not introduce any increased challenge for thermal binding and/or pressure locking and does not effect the results and conclusions of the current evaluation.
Discuss, with examples, the evaluation of the effect of the SPU on the potential for thermal binding and pressure locking of safety-related POVs, including consideration of increased ambient temperatures in applicable locations.
Response NL-04-095-GIP-12:
Based on recognition of the potential for pressure locking, nineteen motor-operated gate valves were field modified prior to initial startup to eliminate the potential for pressure locking. All of these valves except one have a drilled hole in the valve disc. One valve has an external vent.
line from the valve bonnet to the high pressure side of the valve.
Results of the screening of safety-related motor-operated gate valves identified 18 motor-operated valves (MOVs) that required a detailed evaluation for susceptibility to pressure locking, and 8 MOVs that required a detailed evaluation for susceptibility to thermal binding.
Subsequent to this screening, 5 of the 18 MOVs identified as susceptible to pressure locking were modified to install a hole in the valve disc to eliminate the potential for occurrence of pressure locking.
Screening of gate valves with attached hydraulic / pneumatic actuators identified two air-operated valves (AOVs) potentially susceptible to pressure locking. These valves are parallel-disc gate valves and therefore are not susceptible to thermal binding.
The following is a summary of the current evaluations I key parameters and impact of the SPU on these evaluations / parameters for MOVs and AOVs subject to pressure locking. The evaluations considered two types of pressure locking: hydraulically induced pressure locking (HIPL) and thermally induced pressure locking (TIPL).
- 1. Pressure locking of RHR Pump Discharge Isolation Valve (MOV):
a) HIPL: This valve may be required to be opened following transfer from cold leg to hot leg recirculation during a LOCA event. The evaluation considers pressure trapped in the valve bonnet under both small break and large break LOCA conditions. Under SPU conditions, the time interval for transferring from cold leg to hot leg recirculation is being changed from 14 hours1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br /> to 6.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> (Section 6.2). For the small break LOCA case, credit is taken in the evaluation for bonnet depressurization during the time interval between cold leg and hot leg recirculation. The above change in time interval would result in a small differential pressure between the bonnet pressure and the downstream line pressure under SPU conditions, as opposed to zero differential pressure under pre-SPU conditions. However, the large break LOCA case remains bounding in the evaluation, since pressure trapped in the valve bonnet, which is based on shutoff head to NL-04-155 Docket 50-286 Page 23 of 40 Non-Proprietary of the RHR pumps, is conservatively assumed not to depressurize, and the upstream and downstream line pressures are conservatively assumed to be zero. The shutoff head of the RHR pumps is not affected by the SPU.
b) TIPL: The valve is located outside Containment in the Pipe Penetration Area. Maximum temperature of this area does not change during a LOCA from the normal maximum ambient temperature. The valve is thermally insulated. During a large break LOCA, the valve is potentially cooled to RWST temperature. Evaluation shows that, for the scenario where there is thermal addition due to increase in the ambient temperature, bonnet pressure decays at a faster rate than it increases by thermal addition, and therefore there is no pressure increase due to thermal addition. The SPU does not affect this evaluation.
- 2. Pressure locking of PORV Block Valves (MOVs):
a) HIPL: Pressure trapped in valve bonnet is based on pressurizer safety valves relief setpoint, which is not affected by the SPU.
b) TIPL: Valves are not required to open for mitigation of LOCA or HELB in Containment; therefore, an assessment of TIPL under accident conditions is not required under the scope of GL 95-07.
Regarding operation of these valves during low RCS temperatures in conjunction with the Overpressure Protection System: assuming steam was trapped as a result of prior closure to isolate a leaking PORV during power operation, thermally induced pressure locking would not be of concern since the trapped steam would be cooling down. The SPU does not affect this evaluation.
- 3. Pressure locking of Safety Injection Pump #31 Discharge Isolation Valves (MOVs):
a) HIPL: Pressure trapped in valve bonnet is based on the discharge pressure of the recirculation pumps. This condition is bounded by the conditions evaluated in the TIPL evaluation, discussed below.
b) TIPL: These valves are required to be opened following transfer from cold leg to hot leg recirculation during a LOCA event. The evaluation assumes water trapped in bonnet of the valves heats up from RWST temperature (350F) to maximum ambient temperature at the location of the valves outside containment (850F). The maximum pressure in the bonnet of the valves includes the thermally induced pressure from the bonnet fluid temperature change plus pressure trapped in the bonnet based on discharge pressure of the recirculation pumps. Under SPU conditions, the time interval for transferring from cold leg to hot leg recirculation is being changed from 14 hours1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br /> to 6.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> (Section 6.2). However, the evaluation conservatively assumes the valves heat up to the maximum ambient temperature and that there is no depressurization of the pressure trapped in the bonnet during this time interval. Accordingly, the change in the time interval for transferring from cold leg to hot leg recirculation does not affect the evaluation results. Also, the SPU does not impact the temperature parameters used in the evaluation and does not impact recirculation pump head.
to NL-04-155 Docket 50-286 Page 24 of 40 Non-Proprietary
- 4. Pressure locking of Safety Injection Pump #32 Discharge Isolation Valves (MOVs):
a) HIPL: Pressure trapped in valve bonnet is based on the developed head of the recirculation pumps plus the safety injection pumps. Safety injection pump head is not affected by the SPU. Pump head for the recirculation pumps is not affected by the SPU.
b) TIPL: The fluid passing through the valves during safety injection is from the RWST, resulting in cooling the valves to RWST temperature (350F). If the valves are re-opened during recirculation, fluid in the bonnets is presumed to be at ambient temperature (850F), thus resulting in an increase in bonnet pressure and differential pressure across the disc. The thermally induced pressure locking analysis for these valves shows that the actuators are capable of opening the valves, with margin. The SPU does not affect this evaluation.
- 5. Pressure locking of Containment Spray Pump Discharge Isolation Valves (MOVs):
a) HIPL: The only pressure source to pressurize the bonnets of these valves is the containment spray suction supply, which is the head of the RWST plus elevation difference between the tank and the valves. This pressure is bounded by the requirement for the valves to open against full shutoff head of the containment spray pumps. Therefore, HIPL of these valves is ruled out.
a) TIPL: These valves experience minimal temperature gradients. Sometime after containment spray is initiated, the temperature of these valves may drop due to fluid from the RWST. However, once the valves are closed, there is no requirement to open them. Therefore, TIPL is not a concern for these valves.
- 6. Pressure locking of Low Head to High Head Recirculation Stop Valves (MOVs):
a) HIPL: These valves are fitted with Isolation Valve Seal Water System (IVSWS) nitrogen.
supply to accommodate thermal expansion of water trapped in the bonnet. However, an evaluation was performed to address the scenario of leakage of nitrogen from the IVSWS supply line. In this evaluation, pressure trapped in the bonnet is based on the setpoint of the RHR heat exchanger outlet safety valves, which is not affected by the SPU.
b) TIPL: These valves are located in the PAB Pipe Penetration Area, where the ambient temperature can be 105OF during normal operation, as well as post-LOCA. The area temperature may rise above this value during a HELB, but these valves are not required to open during an HELB. During the injection phase of a LOCA, RWST water circulating in the line upstream of the valves will tend to cool them, reducing bonnet pressure. As the event continues, gradual reheating results in the bonnet temperature returning to the ambient range until the signal to open. Therefore, TIPL is not a concern for these valves.
to NL-04-155 Docket 50-286 Page 25 of 40 Non-Proprietary
- 7.
Pressure locking of Boron Injection Tank Outlet Isolation Valves (MOVs):
a) HIPL:
SI Actuation following a LOCA The normal positions of SI-MOV-1 835A & B were changed utilizing the 10 CFR 50.59 (Reference 1) process from normally closed to normally open to eliminate the potential for the valves to pressure lock when required to open for this event.
Post-LOCA Cold Leq and Hot Leg Recirculation Phases These valves are maintained open in the post-LOCA cold leg and hot leg recirculation phases, and therefore HIPL is not a concern.
b) TIPL: As addressed above, these valves are normally open and maintained in the open position post-LOCA, and therefore TIPL is not a concern.
- 8.
Pressure locking of AFW Pump Turbine Steam Supply Isolation Valves (AOVs):
a) HIPL: If the valves close due to a steam line break in the AFW Pump Room, steam will be trapped in the valve bonnet. However, the plant must be cooled down below 3500F to effect repairs to the line, which would significantly reduce the pressure in the bonnet as the steam condensed to water. This will allow for re-opening the valve. The SPU does not affect this evaluation.
b) TIPL: If the valves close due to high temperature in the AFW Pump Room due to a fire, and it is desired to open the valves, the valve need only open against the normal differential pressure of main steam on the upstream side and turbine backpressure on the downstream side. This is considered a normal operating requirement for the valve.
No thermal addition to pressure in the bonnet will be experienced from external sources, since the process fluid is at a much higher temperature than the maximum ambient room temperature. In addition, procedural guidance specifies equalizing pressure across the valves prior to opening. The SPU does not affect this evaluation.
The following is a summary of the current evaluations and impact of the SPU on these evaluations for MOVs subject to thermal binding (TB). For thermal binding evaluations, the Westinghouse Owners Group has developed additional criteria for determining susceptibility based on temperature change: For flexible wedge gate valves, only temperatures above 2000F, and temperature changes above 1 00F are considered significant for thermal binding.
- 1. Thermal binding of PORV Block Valves:
Although these flexible wedge gate valves are potentially susceptible to thermal binding, they are considered acceptable in the current condition based on: (1)
The maximum differential temperature between closing and subsequent opening these valves would experience is 150 0F, which, although it exceeds the 100OF temperature change criteria identified above, is not large, (2) Based on an 18 plant survey, no occurrences of thermal binding of these valves were reported to NL-04-155 Docket 50-286 Page 26 of 40 Non-Proprietary over many years of operation, (3) High conductivity of valve materials, and insulation of the valves and adjacent piping, minimize temperature differences which may contribute to thermal binding, (4) the valve body and wedge are both stainless steel having nearly identical thermal expansion coefficients, and (5)
Past performance history of these valves during plant cooldowns has been satisfactory. The SPU does not affect this evaluation.
- 2. Thermal binding of Safety Injection Pump #31 Discharge Isolation Valves:
These flexible wedge gate valves are potentially susceptible to thermal binding.
However, thermal binding is not a concern for these valves based on the following: During closure of these valves after safety injection, the valve temperatures will not exceed 1200F. When the valves are required to open to transfer from cold leg to hot leg recirculation, the valves and the fluid at the valves will be at ambient temperature (maximum of 850F). The low temperature at closure, and the relatively minor temperature difference between closure and opening are both well within the temperature criteria for thermal binding susceptibility noted above. The SPU does not affect this evaluation.
- 3. Thermal binding of RHR Heat Exchangers #31 and #32 Outlet Isolation Valves:
These valves (two per HX) are open and energized during normal power operation, safety injection, low head recirculation, and RHR operation. The valves are closed, post-LOCA, to initiate high head cold leg or hot leg recirculation. If closed during high head cold leg recirculation, operating procedures direct the operator to open one HX pair to establish low head recirculation if RCS pressure decreases sufficiently. However, the valves are not designed with the intent to ensure opening after closure while mitigating an accident. The valves' control mechanism has been modified to control valve closing via geared limit switches to minimize seating forces. The motors are de-energized prior to the valves' discs swinging, thus preventing the valves from being wedged too tightly.
The worst case accident conditions for thermal binding occurs during a small break LOCA. The valves remain open during the injection phase, but are subsequently closed to support high head cold leg recirculation. The subject valves are not expected to undergo any significant cooling during this event, post closure. In addition, one pair of the valves would be required to be cycled open and closed to determine when RCS pressure has decreased sufficiently to facilitate low head recirculation. Combined, these effects and those discussed above preclude the valves from thermally binding. Furthermore, long-term cooling can be achieved without re-opening these valves, post-LOCA.
The SPU does not affect the above evaluation.
Reference:
- 1. 10 CFR 50.59, "Changes, Tests, and Experiments."
to NL-04-155 Docket 50-286 Page 27 of 40 Non-Proprietary Question NL-04-095-GIP-13:
Section 10.15.4, "Startup Testing," states that power escalation will be controlled by a specific procedure that includes controls for power escalation, hold points, and data collection requirements. Section 10.15.4 also states that a vibration monitoring activity will be initiated to monitor plant response at various power levels.
Discuss the plans for power escalation including specific hold points and duration, inspections, and plant walkdowns. Also, discuss the vibration monitoring activity including data collection methods and locations, baseline vibration measurements, and planned data evaluation.
Response NL-04-095-GIP-13:
This information has been included in Section 10.15.4 of the IP3 SPU LAR.
Question NL-04-095-GIP-14:
Discuss the evaluation of potential flow vibration effects resulting from SPU conditions for reactor pressure vessel internals, and steam and feedwater systems and their associated components, including impact on structural capability and performance during normal operations, anticipated transients (initiation and response), and design-basis conditions; and preparation for responding to the potential occurrence of loose parts as a result of the power uprate.
Response NL-04-095-GIP-14:
Reactor Vessel Internals Flow induced vibrations (FIV) of pressurized water reactor internals have been'studied at Westinghouse for a number of years. The objective of these studies is to assure the structural integrity and reliability of the reactor internals components. These efforts have included in-plant tests, scale model tests, tests in fabricators' shops, bench tests of components, and various analytical investigations. The results of scale model and in-plant tests indicate that the vibrational behavior of 2-, 3-, and 4-loop plants is essentially similar; the results obtained from each of the tests complement one another and make possible a better understanding of the flow induced vibration phenomena.
As described in References 1 and 2, Westinghouse performed a comprehensive instrumented reactor internals testing program at the Indian Point Unit 2 plant. This test program included heatup and cooldown as well as operation with 1, 2, 3, and 4 reactor coolant pumps, including starting and stopping transient operations. The initial program was performed without the core present (Reference 1). A subsequent program was performed with the core in place (Reference 2). The results of this program were used to develop theories and concepts related to reactor internals vibration under various operating conditions as well as to assess the fatigue and stress effects of operational vibrations. The testing performed at Indian Point 2 included the acquisition of data during hot functional testing (without core present) and subsequently with the core installed. The results of this comprehensive testing program showed that the vibrational response of the reactor internals is small and that adequate margins of safety exist with regard to flow induced vibration.
to NL-04-155 Docket 50-286 Page 28 of 40 Non-Proprietary To address the SPU program at IP3 an evaluation was performed to show that the vibration characteristics of reactor internals do not change significantly and the structural adequacy of the reactor internals in regards to FIV is not impaired.
The reactor internal components that are generally addressed for FIV consists of lower internals (core barrel, thermal shield support flexures, thermal shield support bolts and dowel pins) and upper internals (guide tubes). The current design temperature range between Tcold and Thot is 58.60F and changes to 63.4 with the implementation of SPU at IP3.
This SPU design condition will slightly alter TCO.d and Thot fluid densities, which will slightly change the forces, induced by flow. The corresponding TCOfd and ThOt fluid densities will increase by about 2%.
Evaluations performed for the SPU conditions show that the FIV loads on the guide tubes and the upper support columns increases by about 6% and the impact on the lower internals is negligible. Benchmark tests of guide tubes and upper support columns together with previous FIV analysis for similar 4-loop reactors has shown that a large margin exists in regards to calculated stresses versus the code allowable. Therefore, the effect on the FIV on the reactor internals is considered negligible or essentially non-existent for the SPU conditions at the IP3 plant.
References:
- 1. WCAP-7879-P-A, "Four Loop PWR Internals Assurance and Test Program", July 1972.
- 2. WCAP-7879-AD1, "Four Loop PWR Internals Assurance and Test Program Addendum 1, IPP-2 Reactor Internals Vibration with-Core Testing Program", October 1972.
Steam Generator Steam generator tube vibration and wear are addressed in Section 5.6.6 of the LAR.
Steam and Feedwater Systems and Their Associated Components The main steam and feedwater piping systems and their associated components will be evaluated for potential flow vibration effects resulting from SPU conditions. These piping systems will be included in the piping vibration monitoring plan to be performed in support of SPU. The piping vibration monitoring plan will identify the specific piping locations for monitoring, the monitoring methods to be used (e.g. accelerometers, hand held devices), as well as acceptance criteria to determine piping vibration acceptability.
Refer to response for Generic Issues and Programs Question 3 for additional details related to the overall piping vibration monitoring plan Response to the potential occurrence of loose parts as a result of the power uprate.
Entergy has procedures in place for the control of and exclusion of foreign objects during maintenance activities, including during outages. These procedures have been successful in controlling foreign objects. Entergy has installed metal impact monitors to detect the occurrence of loose parts or foreign objects in the reactor coolant system. Detection of unusual signals to NL-04-155 Docket 50-286 Page 29 of 40 Non-Proprietary from the metal impact monitors triggers investigations and evaluations to determine the source of the signals and to take corrective actions if that is needed.
Question NL-04-100-LOC-3:
The LOCA submittals did not address slot breaks at the top and side of the pipe.
Justify why these breaks are not considered for the IP2 LBLOCA response Response NL-04-100-LOC-3:
The response this question contains proprietary information. The proprietary and non-proprietary versions of the response are provided as response NL-04-100-LOC-3 in Attachments 3 and 4 of this letter, respectively.
Question NL-04-100-LOC-4:
Provide the LBLOCA analysis results (tables and graphs, as appropriate) to the time that stable and sustained quench is established.
Response NL-04-100-LOC-4:
In order to demonstrate stable and sustained quench, the WCOBRA/TRAC calculation from the maximum local oxidation analysis for Indian Point Unit 3 was extended beyond the rod quench time.
Figure 1 shows the peak cladding temperatures for the five rods modeled in WCOBRAITRAC.
This figure indicates that quench occurs at about 260 seconds for the low power rod (Rod 5),
about 300-320 seconds for the core average rods (Rod 3 and 4), and about 400 seconds for the hot rod (Rod 1) and hot assembly average rod (Rod 2). Once quench is predicted to occur, the rod temperatures remain steady and slightly above the fluid saturation temperature for the remainder of the simulation.
Figure 2 shows the collapsed liquid level in the four downcomer quadrants and shows that increasing level trend is established at the end of the transient, with the level in each quadrant about 5 feet below the bottom of the cold leg and rising.
Figure 3 shows the collapsed liquid level in the core channels. As seen on Figure 3, a trend of decreasing core collapsed liquid levels is established between 130 and 380 seconds, due to downcomer boiling. During this period, the downcomer collapsed liquid levels also tend to decrease (Figure 2). Later in the transient, a reverse trend of stable and gradual increase of core inventory and downcomer levels is observed, due to the adequate SI injection rate. This is consistent with the expected result based on the removal of the initial core stored energy and the gradual reduction in decay heat.
Figures 4 shows the collapsed liquid level established in the upper plenum. It is evident that liquid pool is established in the upper plenum and maintained until the end of the transient, with the level approaching the bottom of the hot legs.
to NL-04-155 Docket 50-286 Page 30 of 40 Non-Proprietary Figure 5 shows the vessel liquid mass and indicates an increasing trend beginning at about 340 seconds. This indicates that the increase in inventory due to the pumped safety injection is more than offsetting the loss of inventory through the break.
Based on these results, it is concluded that stable and sustained quench has been established for the Indian Point Unit 3 Large Break LOCA analysis.
- to NL-04-155 Docket 50-286 Page 31 of 40 Non-Proprietary Indian Point Unit PCT 1
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1.8 1.2
.6 0
927:930:219276/29 -Nov-04 Figure 4-Upper Plenum Collapsed Liquid Level (All channels) to NL-04-155 Docket 50-286 Page 35 of 40 Non-Proprietary 234442828 Indian Point V F MASS Unit 3 LBLOCA CORE QUENCH 0
0 0
VESSEL WATER MASS 250000 200000 IS-
)C, U,
150000 100000
_I
_ m of 1 an AJIn l1 50000 0
A U
IU LUU JUu WUu DUU DUU 927:930:219276/29-Nov-04 Figure 5 - Vessel Liquid Mass to NL-04-155 Docket 50-286 Page 36 of 40 Non-Proprietary Question NL-04-100-LOC-5:
Tables 6.2-3 and 6.2.5 in the Application Report provide LBLOCA and SBLOCA analysis results for the IP2 SPU. Provide all results (peak clad temperature, maximum local oxidation and total hydrogen generation) for both LBLOCA and SBLOCA. For maximum local oxidation include consideration of both pre-existing and post-LOCA oxidation, cladding outside and post-rupture inside oxidation. Also include the results for fuel resident from previous cycles.
Response NL-04-100-LOC-5:
The results (peak clad temperature, maximum local oxidation and total hydrogen generation) for the Indian Point Unit 3 LBLOCA and SBLOCA design basis analyses are provided in Table LOC-5-1 below. Additional information regarding the bases for the maximum local oxidation, including consideration of both pre-existing and post-LOCA oxidation, cladding outside and post-rupture inside oxidation is discussed below.
Large Break LOCA Pre-existinq and Post-LOCA Oxidation:
The transient maximum local oxidation calculated for the Indian Point Unit 3 (IP3) large break LOCA analysis of record is 7.6 percent. Consistent with the NRC-approved methodology, this value was calculated using a LOCA transient whose nominal peak cladding temperature exceeds the 95th percentile value for both the first and second reflood peaks. The transient maximum local oxidation was predicted to occur at the burst elevation, such that the metal-water reaction occurred on both the inner and outer cladding surfaces.
The maximum local oxidation was calculated for fresh fuel, at the beginning of the cycle. This represents the maximum amount of transient oxidation that could occur at any time in life. As burnup increases, the transient oxidation decreases for the following reasons:
- 1) The cladding creeps down towards the fuel pellets, due to the system pressure exceeding the rod internal pressure. This will reduce the average initial stored energy at the hot spot by several hundred degrees relatively early in the first cycle of operation.
Accounting only for this change, which occurs early in the first cycle, reduces the transient oxidation significantly.
- 2) Later in life, the clad creep-down benefit still remains in effect. In addition, with increasing irradiation, the power production from the fuel will naturally decrease as a result of depletion of the fissionable isotopes. Reductions in achievable peaking factors in the burned fuel relative to the fresh fuel are realized before the middle of the second cycle of operation. The achievable linear heat rates decrease steadily from this point until the fuel is discharged, at which point the transient oxidation will be negligible.
The pre-transient oxidation increases with burnup, from zero at beginning of life (BOL) to a maximum value at the discharge of the fuel (end of life, or EOL). The design limit 95% upper bound value for each of the fuel designs that will be included in the SPU cores is < 15%. The actual upper bound values predicted for each of the fuel designs are expected to be well below this value.
to NL-04-155 Docket 50-286 Page 37 of 40 Non-Proprietary Based on the above discussion, the transient oxidation decreases from a very conservative maximum of 7.6% at BOL to a negligible value at EOL, while the pre-transient oxidation increases from zero at BOL to a very conservative maximum at EOL of <16%. Additional WCOBRAITRAC and HOTSPOT calculations were performed at an intermediate burnup, accounting for burnup effects on fuel performance data (primarily initial stored energy and rod internal pressure). These calculations support the conclusion that the sum of the transient and pre-transient oxidation remains below 16% at all times in life. This conclusion is applicable to each of the fuel designs that will be included in the SPU cores, and confirms IP3 conformance with the 10 CFR 50.46 acceptance criterion for local oxidation.
Small Break LOCA Pre-existinq and Post-LOCA Oxidation:
As part of the IP3 SPU program, a new SBLOCA analysis was performed. The break spectrum that was analyzed yielded a maximum peak clad temperature of 1543 o F for a 3 inch equivalent break diameter. The break spectrum results are summarized in Tables 6.2-2 and 6.2-3 of Reference 1. Because of the low clad temperatures, fuel rod burst was not predicted to occur, and the maximum transient oxidation was only 1.04%. Because this is so low, the SBLOCA transient needs no further justification since the local oxidation limit will not be challenged even when the end of life initial (steady state) oxide layer is considered. This confirms IP3 conformance with the 10 CFR 50.46 acceptance criterion for local oxidation.
References
- 1.
WCAP-16212-P, "Indian Point Nuclear Generating Unit No. 3, Stretch Power Uprate NSSS and BOP Licensing Report," J. R. Stukus, et al., June 2004.
Table LOC-5-1 IP3 DESIGN BASIS ANALYSIS LOCA RESULTS LBLOCA SBLOCA Peak Clad Temperature 19440F (PCT95%)
15430F Maximum Local Oxidation Pre-transient = 0%
Pre-transient = 0%
Transient = <7.6%
Transient = 1.04%
Total Hydrogen Generation 0.620%
<< 1%
Regarding prior response to PVM RAI 4d provided in NL-04-073:
Question NL-04-100-PVM-4d-1:
When was the last time the pressurizer nozzles were volumetrically examined?
Response Question NL-04-100-PVM-4d-1:
As noted in NL-04-145 response to NL-04-073-PVM-4a, the revised calculations for the pressurizer nozzles demonstrate that the postulated flaw size meets the requirements of Appendix G (1/4t or 1 inch). Therefore this RAI is not applicable.
Question NL-04-100-PVM-4d-2:
Was the technique equivalent to VIP-1 08?
to NL-04-155 Docket 50-286 Page 38 of 40 Non-Proprietary Response NL-04-100-PVM-4d-2:
As noted in NL-04-145 response to NL-04-073-PVM-4a, the revised calculations for the pressurizer nozzles demonstrate that the postulated flaw size meets the requirements of Appendix G (1/4t or 1 inch). Therefore this RAI is not applicable.
Question NL-04-100-PVM-4d-3:
What was the size of the largest flaw?
Response NL-04-100-PVVM-4d-3::
As noted in NL-04-145 response to NL-04-073-PVM-4a, the revised calculations for the pressurizer nozzles demonstrate that the postulated flaw size meets the requirements of Appendix G (1/4t or 1 inch). Therefore this RAI is not applicable.
Question NL-04-121-NRC Item 2:
The Entergy response for Piping and Supports Question 1, in letter NL-04-095 dated August 3, 2004, provides a stress summary table for main steam piping. Please provide similar quantitative results for evaluations performed for other balance-of-plant (BOP) piping systems.
Response NL-04-121-NRC Item 2:
Stress summary tables for the other critical balance of plant (BOP) piping systems have been included in the response to PS-1.
Question NL-04-121-NRC Item 7:
During a CVCS malfunction to induce a boron dilution transient, Entergy chose to use a mixing volume that is equal to the RHR and RCS volumes. This appears to be non-conservative. The staff feels that the transient involves, conservatively, only diluted water from the primary water storage tank is injected into the cold leg through the charging lines at maximum letdown rate.
This flow would then only mix with the volume of water in the cold leg and downcomer and lower plenum provided the RCPs were on. If they are not on, then there is less justification for mixing and it may be a dilute slug entering the core to cause a local power spike. The staff questions why the licensee is assuming RHR and RCS volume as the mixing volumes.
Response NL-04-121-NRC Item 7:
The CVCS malfunction event is discussed in WCAP-1 6212, Licensing Report Section 6.3.5. The question is best addressed by plant mode and the operation of the Reactor Coolant Pumps and the RHR System.
Modes 1, 2, 3: One or more Reactor Coolant Pumps are in service and thus adequate mixing is assured.
to NL-04-155 Docket 50-286 Page 39 of 40 Non-Proprietary Modes 4 and 5: At least one Reactor Coolant Pump is in service on shutdowns until Reactor Coolant System temperature is less than approximately 170'F. The RHR System is placed in service when the Reactor Coolant System temperature is less than approximately 350'F thus assuring adequate mixing. Similarly, during startup, the RHR System is in service and a Reactor Coolant Pump is placed in service while Reactor Coolant System temperature is less than 200'F. In addition, the Westinghouse Interim Operating Procedure was developed specifically for these modes, addressing the potential effects of a "dilution front" and a limited active mixing volume, and has been incorporated in plant procedures.
In addition, for modes 4 and 5, at the pressures in the Reactor Coolant System associated with RHR operation (less than 450 psig) letdown flow is limited to 120 gpm. Second, only two charging pumps (90 gpm each) are permitted to be available due to low temperature over pressurization restrictions.
Mode 6: At least one RHR pump (providing a minimum flow rate of 1000 gpm) is in service except during short periods. This flow rate is considered adequate for mixing in the lower plenum. The actual flow from one RHR pump would be much higher than 1000 gpm. While the CVCS Malfunction event has been analyzed in the refueling mode, it is administratively precluded. Plant procedures require that the valve in the boron addition/dilution path be placed in manual and closed upon shutting down the last Reactor Coolant Pump. Thus in Mode 6 (Refueling), plant procedures preclude a dilution event.
Based on the above, Entergy concludes that adequate mixing for the active RCS volumes is available or that administrative controls preclude boron dilution.
The time to reach criticality for the CVCS malfunction event, Modes 1, 2 and 6, is calculated based on the following equation.
Cb(t) = Cbi
- e A [ -(mdil / M)
- t]
Where:
Cb(t) = boron concentration of the system as a function of time Cbi = initial boron concentration of the system mdil = mass flow rate of diluent M = initial mass of the system t=time In using this equation, it is assumed that the system has a constant mass and that the concentration of the diluent is equal to zero.
Question NL-04-121-NRC Item 8:
Section 5.10.4 of the Stretch Power Uprate Licensing Report (WCAP-16212) provides an estimated increase in PWSCC susceptibility of 22 percent for the reactor pressure vessel head penetrations as a result of the stretch power uprate. An increase of greater than 20 percent is considered by the NRC staff to be significant. Please provide additional information regarding the estimated increase in PWSCC susceptibility and is there a plan for RPV head replacement.
Also, Section 5.10.4 of the Stretch Power Uprate Licensing Report provides an estimated increase in PWSCC susceptibility of 9 percent for the RV hot leg nozzle weld as a result of SPU.
How will the 9 percent increase be accommodated in the future?
to NL-04-155 Docket 50-286 Page 40 of 40 Non-Proprietary Response NL-04-121-NRC Item 8:
The approach used in Section 5.10.4, was to estimate a relative effect of PWSCC susceptibility by estimating the temperature change in the upper head region based on a conservatively wide range of operating temperatures that correspond to a full-power programmed Tavg range from 5490F to 5720F. The resulting temperature increase of 5.30F was evaluated using the crack initiation probability methodology described in Reference 2 of Section 5.10.
In practice, Entergy is required to establish RPV head inspection requirements in accordance with NRC Order EA-03-009. The Order provides for a time-at-temperature methodology to determine the effective degradation years (EDY) value that is used to determine the inspection category. Based on the current plant operating history and cycle-specific temperature data, the projected EDY value increase is 11.8%. As required by the NRC Order, Entergy will recalculate the EDY value to establish the inspection requirements for each refueling outage using plant data for each operating cycle.
Entergy is assessing options to mitigate the effects of PWSCC on continued plant operation.
One possible option involves a modification that would result in reduction of the upper head temperature. Entergy is also assessing eventual replacement of the reactor vessel head.
A similar assessment of PWSCC susceptibility for the RCS hot leg nozzle welds was performed.
Although the NRC Order does not establish EDY categories and inspection requirements for these locations, Entergy is required to inspect these areas in accordance.with ASME Section Xi and the IP3 Inservice Inspection Program. Also, Entergy is participating in industry programs that monitor operating experience and develop recommendations, including augmented inspections. MRP has recently issued recommendations (MRP 2003-039, dated January 20, 2004) that include visual inspection of the Alloy 600 (vessel head-to-pipe) welds within the next two refueling outages.
ATTACHMENT 4 TO NL-04-155 ADDITIONAL INFORMATION FOR IP3 SPU LICENSE AMENDMENT REQUEST BASED ON NRC RAls ISSUED FOR IP2 SPU Non-Proprietary version of responses containing proprietary information (from Westinghouse transmittal PU3-W-04-161)
ENTERGY NUCLEAR OPERATIONS, INC.
INDIAN POINT NUCLEAR GENERATING UNIT NO. 3 DOCKET NO. 50-286 to NL-04-155 Docket 50-286 Page 1 of 2 Question NL-04-100-LOC-3:
The LOCA submittals did not address slot breaks at the top and side of the pipe.
Justify why these breaks are not considered for the IP2 LBLOCA response Response NL-04-100-LOC-3:
Break location, type and size are specifically considered for the IP3 LBLOCA transient simulations. This analysis concluded that the cold leg guillotine break is limiting for IP3. The uncertainties related to break location, type and size were included in the model uncertainties for the IP3 BELBLOCA PCT.
For Small Break LOCA (SBLOCA) events, the effects of break location have been generically evaluated as part of the application of the NOTRUMP Evaluation Model (Reference 1). This document concluded that a break in the Reactor Coolant System (RCS) cold leg was limiting.
Additionally, the effects of break orientation were considered during the evaluation of Safety Injection in the Broken Loop and application of the COSI Condensation Model (Reference 2).
This work concluded that a break oriented at the bottom of the RCS cold leg piping was limiting with respect to Peak Cladding Temperature (PCT).
While these references specifically address the short-term response to the LOCA break spectrum, the long-term effects associated with potential Reactor Coolant Pump (RCP) loop seal re-plugging core uncovery is addressed in the following.
A review of the analysis conditions associated with potential core uncovery due to loop seal re-plugging has previously been performed in Reference 3. Reference 3 documents the Westinghouse position with regards to the potential for Inadequate Core Cooling (ICC) scenarios following Large and Intermediate Break LOCAs as a result of loop seal re-plugging.
Reference 3 concludes the following:
The reactor coolant system response following a LOCA is a dynamic process and the expected response in the long term is similar to the response that occurs in the short term. This short term response has been analyzed extensively through computer analysis and tests and is well documented.
Consideration of the physical mechanisms for liquid plugging of the pump suction leg U-bend piping following large and intermediate break LOCA at realistic decay heat levels precludes quasi steady-state inadequate core cooling conditions.
It is important to emphasize that the operator guidance provided in the Emergency Response Guidelines includes actions to be taken in the event of an indication of a chal-lenge to adequate core cooling following a LOCA.
A review of the key contributors associated with long-term loop seal plugging core uncovery scenarios, under LOCA conditions (specifically extended term SBLOCA conditions), was performed as part of Reference 4 including a review of pertinent experimental data.
to NL-04-155 Docket 50-286 Page 2 of 2 a,c From References 3 and 4 it can be concluded that post-LOCA core uncovery scenarios as a result of loop seal re-plugging do not constitute a significant concern to Indian Point Unit 3 plant safety.
References
- 1. WCAP-1 1372-A, -Westinghouse Small Break LOCA ECCS Evaluation Model Generic Study With the NOTRUMP Code", S. D. Rupprecht, et al., 1986.
- 2. WCAP-10081-NP Addendum 2, Revision 1, "Addendum to the Westinghouse Small Break ECCS Evaluation Model Using the NOTRUMP Code: Safety Injection into the Broken Loop and Improved Condensation Model", C. M. Thompson, et al., October, 1995.
- 3. OG-87-37, "Westinghouse Owners Group (WOG) Post LOCA Long Term Cooling, Letter from Roger Newton (WOG) to Thomas Murley (NRC)", August 26, 1987.
- 4. NSD-NRC-97-5092, "Core Uncovery Due to Loop Seal Re-Plugging During Post-LOCA Recovery," Letter from N. J. Liparulo (W) to NRC, March, 1997.
ENCLOSURE A TO NL-04-155 Westinghouse authorization letter dated December 8, 2004 (CAW-04-1927), with the accompanying affidavit, Proprietary Information Notice, and Copyright Notice ENTERGY NUCLEAR OPERATIONS, INC.
INDIAN POINT NUCLEAR GENERATING UNIT NO. 3 DOCKET NO. 50-286
Westinghouse Proprietary Classi -3 Westinghouse U.S. Nuclear Regulatory Commission Document Control Desk Washington, DC 20555-0001 Westinghouse Electric Company Nuclear Services P.O. Box 355 Pittsburgh, Pennsylvania 15230-0355 USA Direct tel:
Direct fax:
e-mail:
(412) 374-4643 (412) 374-4011 greshaja@westinghouse.com Our ref: CAW-04-1927 December 9, 2004 APPLICATION FOR WITHHOLDING PROPRIETARY INFORMATION FROM PUBLIC DISCLOSURE
Subject:
Westinghouse IP3 SPU Application (WCAP-16212-P) Responses to IP2 RAls Listed as "Later" in NL-04-145, December 9, 2004 The proprietary information for which withholding is being requested in the above-referenced report is further identified in Affidavit CAW-04-1927 signed by the owner of the proprietary information, Westinghouse Electric Company LLC. The affidavit, which accompanies this letter, sets forth the basis on which the information may be withheld from public disclosure by the Commission and addresses with specificity the considerations listed in paragraph (b)(4) of 10 CFR Section 2.390 of the Commission's regulations.
Accordingly, this letter authorizes the utilization of the accompanying affidavit by Entergy Nuclear Operations.
Correspondence with respect to the proprietary aspects of the application for withholding or the Westinghouse affidavit should reference this letter, CAW-04-1927, and should be addressed to J. A. Gresham, Manager, Regulatory Compliance and Plant Licensing, Westinghouse Electric Company LLC, P.O. Box 355, Pittsburgh, Pennsylvania 15230-0355.
Very truly yo rs, re am, Manager Regulatory Compliance and Plant Licensing Enclosures cc:
B. Benney L. Feizollahi A BNFL Group company
CAW-04-1 927 AFFIDAVIT COMMONWEALTH OF PENNSYLVANIA:
ss COUNTY OF ALLEGHENY:
Before me, the undersigned authority, personally appeared J. A. Gresham, who, being by me duly sworn according to law, deposes and says that he is authorized to execute this Affidavit on behalf of Westinghouse Electric Company LLC (Westinghouse), and that the averments of fact set forth in this Affidavit are true and correct to the best of his knowledge, information, and belief:
0 J.A. resham, Manager Regulatory Compliance and Plant Licensing Sworn to and subscribed before me this Ad day of ___
, 2004 Notary Public Notarial Seal Sharon L Rori, Notary Pubric Monroeville Boro, Allegheny Couruy My Comrission Expires January 29.2007 Member, Pennsylria so tion Of Notares
2 CAW-04-1 927 (1)
I am Manager, Regulatory Compliance and Plant Licensing, in Nuclear Services, Westinghouse Electric Company LLC (Westinghouse), and as such, I have been specifically delegated the function of reviewing the proprietary information sought to be withheld from public disclosure in connection with nuclear power plant licensing and rule making proceedings, and am authorized to apply for its withholding on behalf of Westinghouse.
(2)
I am making this Affidavit in conformance with the provisions of 10 CFR Section 2.390 of the Commission's regulations and in conjunction with the Westinghouse "Application for Withholding" accompanying this Affidavit.
(3)
I have personal knowledge of the criteria and procedures utilized by Westinghouse in designating information as a trade secret, privileged or as confidential commercial or financial information.
(4)
Pursuant to the provisions of paragraph (b)(4) of Section 2.390 of the Commission's regulations, the following is furnished for consideration by the Commission in determining whether the information sought to be withheld from public disclosure should be withheld.
(i)
The information sought to be withheld from public disclosure is owned and has been held in confidence by Westinghouse.
(ii)
The information is of a type customarily held in confidence by Westinghouse and not customarily disclosed to the public. Westinghouse has a rational basis for determining the types of information customarily held in confidence by it and, in that connection, utilizes a system to determine when and whether to hold certain types of information in confidence. The application of that system and the substance of that system constitutes Westinghouse policy and provides the rational basis required.
Under that system, information is held in confidence if it falls in one or more of several types, the release of which might result in the loss of an existing or potential competitive advantage, as follows:
3 CAW-04-1 927 (a)
The information reveals the distinguishing aspects of a process (or component, structure, tool, method, etc.) where prevention of its use by any of Westinghouse's competitors without license from Westinghouse constitutes a competitive economic advantage over other companies.
(b)
It consists of supporting data, including test data, relative to a process (or component, structure, tool, method, etc.), the application of which data secures a competitive economic advantage, e.g., by optimization or improved marketability.
(c)
Its use by a competitor would reduce his expenditure of resources or improve his competitive position in the design, manufacture, shipment, installation, assurance of quality, or licensing a similar product.
(d)
It reveals cost or price information, production capacities, budget levels, or commercial strategies of Westinghouse, its customers or suppliers.
(e)
It reveals aspects of past, present, or future Westinghouse or customer funded development plans and programs of potential commercial value to Westinghouse.
(f)
It contains patentable ideas, for which patent protection may be desirable.
There are sound policy reasons behind the Westinghouse system which include the following:
(a)
The use of such information by Westinghouse gives Westinghouse a competitive advantage over its competitors. It is, therefore, withheld from disclosure to protect the Westinghouse competitive position.
(b)
It is information that is marketable in many ways. The extent to which such information is available to competitors diminishes the Westinghouse ability to sell products and services involving the use of the information.
4 CAW-04-1 927 (d)
Each component of proprietary information pertinent to a particular competitive advantage is potentially as valuable as the total competitive advantage. If competitors acquire components of proprietary information, any one component may be the key to the entire puzzle, thereby depriving Westinghouse of a competitive advantage.
(e)
Unrestricted disclosure would jeopardize the position of prominence of Westinghouse in the world market, and thereby give a market advantage to the competition of those countries.
(f)
The Westinghouse capacity to invest corporate assets in research and development depends upon the success in obtaining and maintaining a competitive advantage.
(iii)
The information is being transmitted to the Commission in confidence and, under the provisions of 10 CFR Section 2.390, it is to be received in confidence by the Commission.
(iv)
The information sought to be protected is not available in public sources or available information has not been previously employed in the same original manner or method to the best of our knowledge and belief.
(v)
The proprietary information sought to be withheld in this submittal is that which is appropriately marked in "Westinghouse IP3 SPU Application (WCAP-16212-P)
Responses to IP2 RAls listed as later" in NL-04-145, December 9, 2004" (Proprietary), being transmitted by the Entergy Nuclear Northeast letter and Application for Withholding Proprietary Information from Public Disclosure, to the Document Control Desk. The proprietary information as submitted for use by Westinghouse for the Indian Point Nuclear Generating Unit No. 3 is expected to be applicable for other licensee submittals in response to certain NRC requirements for justification of Stretch Power Uprate License Amendment Request.
This information is part of that which will enable Westinghouse to:
(a) Provide information in support of plant power uprate licensing submittals.
5 CAW-04-1 927 (b) Provide plant specific calculations.
(c) Provide licensing documentation support for customer submittals.
Further this information has substantial commercial value as follows:
(a)
Westinghouse plans to sell the use of similar information to its customers for purposes of meeting NRC requirements for licensing documentation associated with power uprate licensing submittals.
(b)
Westinghouse can sell support and defense of the technology to its customers in the licensing process.
(c)
The information requested to be withheld reveals the distinguishing aspects of a methodology which was developed by Westinghouse.
Public disclosure of this proprietary information is likely to cause substantial harm to the competitive position of Westinghouse because it would enhance the ability of competitors to provide similar calculations, evaluations, analyses and licensing defense services for commercial power reactors without commensurate expenses.
Also, public disclosure of the information would enable others to use the information to meet NRC requirements for licensing documentation without purchasing the right to use the information.
The development of the technology described in part by the information is the result of applying the results of many years of experience in an intensive Westinghouse effort and the expenditure of a considerable sum of money.
In order for competitors of Westinghouse to duplicate this information, similar technical programs would have to be performed and a significant manpower effort, having the requisite talent and experience, would have to be expended.
Further the deponent sayeth not.
PROPRIETARY INFORMATION NOTICE Transmitted herewith are proprietary and/or non-proprietary versions of documents furnished to the NRC in connection with requests for generic and/or plant-specific review and approval.
In order to conform to the requirements of 10 CFR 2.390 of the Commission's regulations concerning the protection of proprietary information so submitted to the NRC, the information which is proprietary in the proprietary versions is contained within brackets, and where the proprietary information has been deleted in the non-proprietary versions, only the brackets remain (the information that was contained within the brackets in the proprietary versions having been deleted). The justification for claiming the information so designated as proprietary is indicated in both versions by means of lower case letters (a) through (f) located as a superscript immediately following the brackets enclosing each item of information being identified as proprietary or in the margin opposite such information. These lower case letters refer to the types of information Westinghouse customarily holds in confidence identified in Sections (4)(ii)(a) through (4)(ii)(f) of the affidavit accompanying this transmittal pursuant to 10 CFR 2.390(b)(1).
COPYRIGHT NOTICE The reports transmitted herewith each bear a Westinghouse copyright notice. The NRC is permitted to make the number of copies of the information contained in these reports which are necessary for its internal use in connection with generic and plant-specific reviews and approvals as well as the issuance, denial, amendment, transfer, renewal, modification, suspension, revocation, or violation of a license, permit, order, or regulation subject to the requirements of 10 CFR 2.390 regarding restrictions on public disclosure to the extent such information has been identified as proprietary by Westinghouse, copyright protection notwithstanding. With respect to the non-proprietary versions of these reports, the NRC is permitted to make the number of copies beyond those necessary for its internal use which are necessary in order to have one copy available for public viewing in the appropriate docket files in the public document room in Washington, DC and in local public document rooms as may be required by NRC regulations if the number of copies submitted is insufficient for this purpose.
Copies made by the NRC must include the copyright notice in all instances and the proprietary notice if the original was identified as proprietary.
Westin hou~se Westinghouse Electric Company 9
Nuclear Services P.O. Box 355 Pittsburgh, Pennsylvania 15230-0355 USA Direct tel: (412) 374-4643 Direct fax: (412) 374-4011 U.S. Nuclear Regulatory Commission e-mail: greshaja~westinghouse.com Document Control Desk Washington, DC 20555-0001 Our ref: CAW-04-1923 Rev. 1 November 17, 2004 APPLICATION FOR WITHHOLDING PROPRIETARY INFORMATION FROM PUBLIC DISCLOSURE
Subject:
Westinghouse Transmittal PU3-W-04-153 (INT-04-203), Indian Point Nuclear Generating Unit No. 3 Stretch Power Uprate Project, Westinghouse Responses to RAls, November 16, 2004.
The proprietary information for which withholding is being requested in the above-referenced report is further identified in Affidavit CAW-04-1923 signed by the owner of the proprietary information, Westinghouse Electric Company LLC. The affidavit, which accompanies this letter, sets forth the basis on which the information may be withheld from public disclosure by the Commission and addresses with specificity the considerations listed in paragraph (b)(4) of 10 CFR Section 2.390 of the Commission's regulations.
Accordingly, this letter authorizes the utilization of the accompanying affidavit by Entergy Nuclear Operations.
Correspondence with respect to the proprietary aspects of the application for withholding or the Westinghouse affidavit should reference this letter, CAW-04-1923, and should be addressed to J. A. Gresham, Manager, Regulatory Compliance and Plant Licensing, Westinghouse Electric Company LLC, P.O. Box 355, Pittsburgh, Pennsylvania 15230-0355.
Very truly yours, J. A. Gresham, Manager Regulatory Compliance and Plant Licensing Enclosures cc: W. Macon E. Peyton A BNFL Group company
CAW-04-1 923 AFFIDAVIT COMMONWEALTH OF PENNSYLVANIA:
Ss COUNTY OF ALLEGHENY:
Before me, the undersigned authority, personally appeared J. A. Gresham, who, being by me duly sworn according to law, deposes and says that he is authorized to execute this Affidavit on behalf of Westinghouse Electric Company LLC (Westinghouse), and that the averments of fact set forth in this Affidavit are true and correct to the best of his knowledge, information, and belief:
J. S. Galembush, Acting Manager Regulatory Compliance and Plant Licensing Sworn to and subscribed before me this /G A day of
)'
, 2004 Notary Public NotarWal Seal Sharon L Rod, Notary Public Monroeville Boro, Allegheny County My Cn=Isslon Ejraes January 29,2007 Member, Pennesymvnia Associaio of Notaries
2 CAW-04-1 923 (1)
I am an Acting Manager, Regulatory Compliance and Plant Licensing, in Nuclear Services, Westinghouse Electric Company LLC (Westinghouse), and as such, I have been specifically delegated the function of reviewing the proprietary information sought to be withheld from public disclosure in connection with nuclear power plant licensing and rule making proceedings, and am authorized to apply for its withholding on behalf of Westinghouse.
(2)
I am making this Affidavit in conformance with the provisions of 10 CFR Section 2.390 of the Commission's regulations and in conjunction with the Westinghouse "Application for Withholding" accompanying this Affidavit.
(3)
I have personal knowledge of the criteria and procedures utilized by Westinghouse in designating information as a trade secret, privileged or as confidential commercial or financial information.
(4)
Pursuant to the provisions of paragraph (b)(4) of Section 2.390 of the Commission's regulations, the following is furnished for consideration by the Commission in determining whether the information sought to be withheld from public disclosure should be withheld.
(i)
The information sought to be withheld from public disclosure is owned and has been held in confidence by Westinghouse.
(ii)
The information is of a type customarily held in confidence by Westinghouse and not customarily disclosed to the public. Westinghouse has a rational basis for determining the types of information customarily held in confidence by it and, in that connection, utilizes a system to determine when and whether to hold certain types of information in confidence. The application of that system and the substance of that system constitutes Westinghouse policy and provides the rational basis required.
Under that system, information is held in confidence if it falls in one or more of several types, the release of which might result in the loss of an existing or potential competitive advantage, as follows:
3 CAW-04-1 923 (a)
The information reveals the distinguishing aspects of a process (or component, structure, tool, method, etc.) where prevention of its use by any of Westinghouse's competitors without license from Westinghouse constitutes a competitive economic advantage over other companies.
(b)
It consists of supporting data, including test data, relative to a process (or component, structure, tool, method, etc.), the application of which data secures a competitive economic advantage, e.g., by optimization or improved marketability.
(c)
Its use by a competitor would reduce his expenditure of resources or improve his competitive position in the design, manufacture, shipment, installation, assurance of quality, or licensing a similar product.
(d)
It reveals cost or price information, production capacities, budget levels, or commercial strategies of Westinghouse, its customers or suppliers.
(e)
It reveals aspects of past, present, or future Westinghouse or customer funded development plans and programs of potential commercial value to Westinghouse.
(f)
It contains patentable ideas, for which patent protection may be desirable.
There are sound policy reasons behind the Westinghouse system which include the following:
(a)
The use of such information by Westinghouse gives Westinghouse a competitive advantage over its competitors. It is, therefore, withheld from disclosure to protect the Westinghouse competitive position.
(b)
It is information that is marketable in many ways. The extent to which such information is available to competitors diminishes the Westinghouse ability to sell products and services involving the use of the information.
4 CAW-04-1 923 (c) Use by our competitor would put Westinghouse at a competitive disadvantage by reducing his expenditure of resources at our expense.
(d)
Each component of proprietary information pertinent to a particular competitive advantage is potentially as valuable as the total competitive advantage. If competitors acquire components of proprietary information, any one component may be the key to the entire puzzle, thereby depriving Westinghouse of a competitive advantage.
(e)
Unrestricted disclosure would jeopardize the position of prominence of Westinghouse in the world market, and thereby give a market advantage to the competition of those countries.
(f)
The Westinghouse capacity to invest corporate assets in research and development depends upon the success in obtaining and maintaining a competitive advantage.
(iii)
The information is being transmitted to the Commission in confidence and, under the provisions of 10 CFR Section 2.390, it is to be received in confidence by the Commission.
(iv)
The information sought to be protected is not available in public sources or available information has not been previously employed in the same original manner or method to the best of our knowledge and belief.
(v) The proprietary information sought to be withheld in this submittal is that which is appropriately marked in Attachment A to PU3-W-04-153, "Indian Point Nuclear Generating Unit No. 3 Stretch Power Uprate Westinghouse Responses to RAls" (Proprietary) dated November 16, 2004, being transmitted by the Entergy Nuclear Northeast letter and Application for Withholding Proprietary Information from Public Disclosure, to the Document Control Desk. The proprietary information as submitted for use by Westinghouse for the Indian Point Nuclear Generating Unit No. 3 is expected to be applicable for other licensee submittals
5 CAW-04-1 923 in response to certain NRC requirements for justification of Stretch Power Uprate License Amendment Request.
This information is part of that which will enable Westinghouse to:
(a) Provide information in support of plant power uprate licensing submittals.
(b) Provide plant specific calculations.
(c) Provide licensing documentation support for customer submittals.
Further this information has substantial commercial value as follows:
(a)
Westinghouse plans to sell the use of similar information to its customers for purposes of meeting NRC requirements for licensing documentation associated with power uprate licensing submittals.
(b)
Westinghouse can sell support and defense of the technology to its customers in the licensing process.
(c)
The information requested to be withheld reveals the distinguishing aspects of a methodology which was developed by Westinghouse.
Public disclosure of this proprietary information is likely to cause substantial harm to the competitive position of Westinghouse because it would enhance the ability of competitors to provide similar calculations, evaluations, analyses and licensing defense services for commercial power reactors without commensurate expenses.
Also, public disclosure of the information would enable others to use the information to meet NRC requirements for licensing documentation without purchasing the right to use the information.
The development of the technology described in part by the information is the result of applying the results of many years of experience in an intensive Westinghouse effort and the expenditure of a considerable sum of money.
6 CAW-04-1 923 In order for competitors of Westinghouse to duplicate this information, similar technical programs would have to be performed and a significant manpower effort, having the requisite talent and experience, would have to be expended.
Further the deponent sayeth not.
PROPRIETARY INFORMATION NOTICE Transmitted herewith are proprietary and/or non-proprietary versions of documents furnished to the NRC in connection with requests for generic and/or plant-specific review and approval.
In order to conform to the requirements of 10 CFR 2.390 of the Commission's regulations concerning the protection of proprietary information so submitted to the NRC, the information which is proprietary in the proprietary versions is contained within brackets, and where the proprietary information has been deleted in the non-proprietary versions, only the brackets remain (the information that was contained within the brackets in the proprietary versions having been deleted). The justification for claiming the information so designated as proprietary is indicated in both versions by means of lower case letters (a) through (f) located as a superscript immediately following the brackets enclosing each item of information being identified as proprietary or in the margin opposite such information. These lower case letters refer to the types of information Westinghouse customarily holds in confidence identified in Sections (4)(ii)(a) through (4)(ii)(f) of the affidavit accompanying this transmittal pursuant to 10 CFR 2.390(b)(1).
COPYRIGHT NOTICE The reports transmitted herewith each bear a Westinghouse copyright notice. The NRC is permitted to make the number of copies of the information contained in these reports which are necessary for its internal use in connection with generic and plant-specific reviews and approvals as well as the issuance, denial, amendment, transfer, renewal, modification, suspension, revocation, or violation of a license, permit, order, or regulation subject to the requirements of 10 CFR 2.390 regarding restrictions on public disclosure to the extent such information has been identified as proprietary by Westinghouse, copyright protection notwithstanding. With respect to the non-proprietary versions of these reports, the NRC is permitted to make the number of copies beyond those necessary for its internal use which are necessary in order to have one copy available for public viewing in the appropriate docket files in the public document room in Washington, DC and in local public document rooms as may be required by NRC regulations if the number of copies submitted is insufficient for this purpose.
Copies made by the NRC must include the copyright notice in all instances and the proprietary notice if the original was identified as proprietary.