ML21082A221
ML21082A221 | |
Person / Time | |
---|---|
Site: | Nine Mile Point ![]() |
Issue date: | 04/29/2021 |
From: | Marshall M Plant Licensing Branch 1 |
To: | Rhoades D Exelon Nuclear, Exelon Generation Co |
Marshall M, NRR/DORL/LPL, 415-2871 | |
References | |
EPID L-2019-LLA-0234 | |
Download: ML21082A221 (174) | |
Text
April 29, 2021 Mr. David P. Rhoades Senior Vice President Exelon Generation Company, LLC President and Chief Nuclear Officer Exelon Nuclear 4300 Winfield Road Warrenville, IL 60555
SUBJECT:
NINE MILE POINT NUCLEAR STATION, UNIT 2 - ISSUANCE OF AMENDMENT NO. 186 TO ADOPT TECHNICAL SPECIFICATIONS TASK FORCE TRAVELER TSTF-505, REVISION 2, PROVIDE RISK-INFORMED EXTENDED COMPLETION TIMES - RITSTF INITIATIVE 4B (EPID L-2019-LLA-0234)
Dear Mr. Rhoades:
The U.S. Nuclear Regulatory Commission (the Commission) has issued the enclosed Amendment No. 186 to Renewed Facility Operating License No. NPF-69 for the Nine Mile Point Nuclear Station, Unit No. 2 (Nine Mile Point 2). The amendment consists of changes to the technical specifications in response to your application dated October 31, 2019 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML19304B653), as supplemented by letters dated December 12, 2019, August 28, 2020, October 2, 2020 (two letters), October 22, 2020, and January 7, 2021 (ADAMS Accession Nos. ML19346F427, ML20241A044, ML20276A019, ML20276A020, ML20296A195, and ML21007A019, respectively).
The amendment revises Nine Mile Point 2 technical specification requirements to permit the use of risk-informed completion times for actions to be taken when limiting conditions for operation are not met. The proposed changes are based on Technical Specifications Task Force (TSTF)
Traveler TSTF-505, Revision 2, Provide Risk Informed Extended Completion Times - RITSTF Initiative 4b, dated July 2, 2018 (ADAMS Accession No. ML18183A493).
D. Rhoades A copy of the related Safety Evaluation is also enclosed. Notice of Issuance will be included in the Commissions monthly Federal Register notice.
Sincerely,
/RA/
Michael L. Marshall, Jr., Senior Project Manager Plant Licensing Branch I Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-410
Enclosures:
- 1. Amendment No. 186 to NPF-69
- 2. Safety Evaluation cc: Listserv
NINE MILE POINT NUCLEAR STATION, LLC LONG ISLAND LIGHTING COMPANY EXELON GENERATION COMPANY, LLC DOCKET NO. 50-410 NINE MILE POINT NUCLEAR STATION, UNIT 2 AMENDMENT TO FACILITY OPERATING LICENSE Amendment No. 186 Renewed License No. NPF-69
- 1. The U.S. Nuclear Regulatory Commission (the Commission) has found that:
A. The application for amendment by Exelon Generation Company, LLC (Exelon, the licensee) dated October 31, 2019, as supplemented by letters dated December 12, 2019, August 28, 2020, October 2, 2020 (two letters), October 22, 2020, and January 7, 2021, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act) and the Commission's rules and regulations set forth in 10 CFR Chapter I; B. The facility will operate in conformity with the application, the provisions of the Act, and the rules and regulations of the Commission; C. There is reasonable assurance (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commission's regulations; D. The issuance of this amendment will not be inimical to the common defense and security or to the health and safety of the public; and E. The issuance of this amendment is in accordance with 10 CFR Part 51 of the Commission's regulations and all applicable requirements have been satisfied.
Enclosure 1
- 2. Accordingly, the license is amended by changes to the Technical Specifications as indicated in the attachment to this license amendment, and paragraph 2.C.(2) of Renewed Facility Operating License No. NPF-69 is hereby amended to read as follows:
(2) Technical Specifications and Environmental Protection Plan The Technical Specifications contained in Appendix A and the Environmental Protection Plan contained in Appendix B, both of which are attached hereto, as revised through Amendment No. 186, are hereby incorporated into this license. Exelon Generation shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.
In addition, the license is amended by changes as indicated in the attachment to this license amendment, and new paragraph 2.C.(29) of Renewed Facility Operating License No. NPF-69 will read as follows:
(29) Adoption of Risk Informed Completion Times TSTF-505, Revision 2, Provide Risk-Informed Extension Completion Times -
RITSTF Initiative 4b Exelon is approved to implement TSTF-505, Revision 2, modifying the Technical Specification requirements related to Completion Times (CT) for Required Actions to provide the option to calculate a longer, risk-informed CT (RICT). The methodology for using the new Risk-Informed Completion Time Program is described in NEI 06-09-A, Risk-Informed Technical Specifications Initiative 4b, Risk-Managed Technical Specifications (RMTS) Guidelines, Revision 0, which was approved by the NRC on May 17, 2007.
Exelon will complete the implementation items listed in Attachment 6 of Exelon Letter to the NRC dated October 31, 2019, prior to implementation of the RICT Program. All issues identified in the attachment will be addressed and any associated changes will be made, focused-scope peer reviews will be performed on changes that are PRA upgrades as defined in the PRA standard (ASME/ANS RA-Sa-2009, as endorsed by RG 1.200, Revision 2), and any findings will be resolved and reflected in the PRA of record prior to the implementation of the RICT Program.
- 3. This license amendment is effective as of the date of its issuance and shall be implemented within 180 days or following completion of the probabilistic risk assessment implementation items specified in Attachment 6 to the application dated October 31, 2019, whichever is later.
FOR THE NUCLEAR REGULATORY COMMISSION Digitally signed by Jennifer Jennifer C. Tobin Date: 2021.04.29 C. Tobin 08:12:56 -04'00' James G. Danna, Chief Plant Licensing Branch I Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation
Attachment:
Changes to the Renewed Facility Operating License and Technical Specifications Date of Issuance: April 29, 2021
ATTACHMENT TO LICENSE AMENDMENT NO. 186 NINE MILE POINT NUCLEAR STATION, UNIT 2 RENEWED FACILITY OPERATING LICENSE NO. NPF-69 DOCKET NO. 50-410 Replace the following pages of the Renewed Facility Operating License with the attached revised pages. The revised pages are identified by amendment number and contain marginal lines indicating the areas of change.
Remove Page Insert Page 4 4 15 15 16 16 17 17 18 18 19 19 Replace the following pages of Appendix A, Technical Specifications, with the attached revised pages. The revised pages are identified by amendment number and contain marginal lines indicating the areas of change.
Remove Page Insert Page Remove Page Insert Page 1.3-13 1.3-13 3.3.5.1-5 3.3.5.1-5
-- 1.3-14
-- 1.3-15 3.3.5.1-6 3.3.5.1-6 3.1.7-1 3.1.7-1 3.3.5.1-7 3.3.5.1-7 3.3.1.1-1 3.3.1.1-1 3.3.5.1-8 3.3.5.1-8 3.3.1.1-2 3.3.1.1-2 3.3.5.1-9 3.3.5.1-9 3.3.1.1-3 3.3.1.1-3 3.3.5.1-10 3.3.5.1-10 3.3.1.1-4 3.3.1.1-4 3.3.5.1-11 3.3.5.1-11 3.3.1.1-5 3.3.1.1-5 3.3.5.1-12 3.3.5.1-12 3.3.1.1-6 3.3.1.1-6 3.3.5.1-13 3.3.5.1-13 3.3.1.1-7 3.3.1.1-7 -- 3.3.5.1-14 3.3.1.1-8 3.3.1.1-8 3.3.5.3-1 3.3.5.3-1 3.3.1.1-9 3.3.1.1-9 3.3.5.3-2 3.3.5.3-2 3.3.1.1-10 3.3.1.1-10 3.3.5.3-3 3.3.5.3-3
-- 3.3.1.1-11 3.3.5.3-4 3.3.5.3-4
-- 3.3.1.1-12 -- 3.3.5.3-5 3.3.2.2-1 3.3.2.2-1 3.3.6.1-1 3.3.6.1-1 3.3.4.1-1 3.3.4.1-1 3.3.6.1-2 3.3.6.1-2 3.3.4.1-2 3.3.4.1-2 3.3.6.1-3 3.3.6.1-3 3.3.4.2-1 3.3.4.2-1 3.3.6.1-4 3.3.6.1-4 3.3.4.2-2 3.3.4.2-2 3.3.6.1-5 3.3.6.1-5 3.3.4.2-3 3.3.4.2-3 3.3.6.1-6 3.3.6.1-6
-- 3.3.4.2-4 3.3.6.1-7 3.3.6.1-7 3.3.5.1-3 3.3.5.1-3 3.3.6.1-8 3.3.6.1-8 3.3.5.1-4 3.3.5.1-4 3.3.6.1-9 3.3.6.1-9
Remove Page Insert Page Remove Page Insert Page 3.3.6.1-10 3.3.6.1-10 3.6.1.7-1 3.6.1.7-1
-- 3.3.6.1-11 3.6.2.3-1 3.6.2.3-1 3.3.7.2-1 3.3.7.2-1 3.6.2.4-1 3.6.2.4-1 3.3.7.2-2 3.3.7.2-2 3.7.1-1 3.7.1-1 3.3.7.2-3 3.3.7.2-3 3.7.1-2 3.7.1-2 3.3.8.1-1 3.3.8.1-1 3.7.1-3 3.7.1-3 3.5.1-1 3.5.1-1 3.7.1-4 3.7.1-4 3.5.1-2 3.5.1-2 -- 3.7.1-5 3.5.3-1 3.5.3-1 3.7.5-1 3.7.5-1 3.6.1.2-4 3.6.1.2-4 3.8.1-2 3.8.1-2 3.6.1.3-1 3.6.1.3-1 3.8.1-3 3.8.1-3 3.6.1.3-2 3.6.1.3-2 3.8.1-4 3.8.1-4 3.6.1.3-3 3.6.1.3-3 3.8.4-1 3.8.4-1 3.6.1.3-7 3.6.1.3-7 3.8.7-1 3.8.7-1 3.6.1.3-8 3.6.1.3-8 3.8.8-1 3.8.8-1 3.6.1.3-9 3.6.1.3-9 3.8.8-2 3.8.8-2 3.6.1.6-1 3.6.1.6-1 5.5-13 5.5-13
-- 5.5-14
(1) Maximum Power Level Exelon Generation is authorized to operate the facility at reactor core power levels not in excess of 3988 megawatts thermal (100 percent rated power) in accordance with the conditions specified herein.
(2) Technical Specifications and Environmental Protection Plan The Technical Specifications contained in Appendix A and the Environmental Protection Plan contained in Appendix B, both of which are attached hereto, as revised through Amendment No. 186, are hereby incorporated into this license. Exelon Generation shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.
(3) Fuel Storage and Handling (Section 9.1.SSER 4)*
- a. Fuel assemblies, when stored in their shipping containers, shall be stacked no more than three containers high.
- b. When not in the reactor vessel, no more than three fuel assemblies shall be allowed outside of their shipping containers or storage racks in the New Fuel Vault or Spent Fuel Storage Facility.
- c. The above three fuel assemblies shall maintain a minimum edge-to-edge spacing of twelve (12) inches from the shipping container array and approved storage rack locations.
- d. The New Fuel Storage Vault shall have no more than ten fresh fuel assemblies uncovered at any one time.
(4) Turbine System Maintenance Program (Section 3.5.1.3.10 SER)
The operating licensee shall submit for NRC approval by October 31, 1989, a turbine system maintenance program based on the manufacturers calculations of missile generation probabilities.
(Submitted by NMPC letter dated October 30, 1989 from C.D. Terry and approved by NRC letter dated March 15, 1990 from Robert Martin to Mr.
Lawrence Burkhardt, III).
- The parenthetical notation following the title of many license conditions denotes the section of the Safety Evaluation Report (SER) and/or its supplements wherein the license condition is discussed.
Renewed License No. NPF-69 Amendment 117 through 140, 141, 143, 144, 145, 146, 147, 150, 151, 152, 154, 156, 157, 158, 159, 160, 161, 163, 164, 165, 166, 167, 168, 169, 170, 172, 174, 175, 176, 178, 179, 181, 182, 184, 185, 186
(25) Within 14 days of the license transfers, Exelon Generation shall submit to the NRC the Nuclear Operating Services Agreement reflecting the terms set forth in the application dated August 6, 2013. Section 7.1 of the Nuclear Operating Services Agreement may not be modified in any material respect related to financial arrangements that would adversely impact the ability of the licensee to fund safety-related activities authorized by the license without the prior written consent of the Director of the Office of Nuclear Reactor Regulation.
(26) Within 10 days of the license transfers, Exelon Generation shall submit to the NRC the amended CENG Operating Agreement reflecting the terms set forth in the application dated August 6, 2013. The amended and restated Operating Agreement may not be modified in any material respect concerning decision making authority over safety, security and reliability without the prior written consent of the Director of the Office of Nuclear Reactor Regulation.
(27) At least half the members of the CENG Board of Directors must be U.S. citizens.
(28) The CENG Chief Executive Officer, Chief Nuclear Officer, and Chairman of the CENG Board of Directors must be U.S. citizens. These individuals shall have the responsibility and exclusive authority to ensure and shall ensure that the business and activities of CENG with respect to the facilitys license are at all times conducted in a manner consistent with the public health and safety and common defense and security of the United States.
(29) Adoption of Risk Informed Completion Times TSTF-505, Revision 2, "Provide Risk-Informed Extension Completion Times - RITSTF Initiative 4b" Exelon is approved to implement TSTF-505, Revision 2, modifying the Technical Specification requirements related to Completion Times (CT) for Required Actions to provide the option to calculate a longer, risk-informed CT (RICT). The methodology for using the new Risk-Informed Completion Time Program is described in NEI 06-09-A, "Risk-Informed Technical Specifications Initiative 4b, Risk-Managed Technical Specifications (RMTS) Guidelines," Revision 0, which was approved by the NRC on May 17, 2007.
Exelon will complete the implementation items listed in Attachment 6 of Exelon Letter to the NRC dated October 31, 2019, prior to implementation of the RICT Program. All issues identified in the attachment will be addressed and any associated changes will be made, focused-scope peer reviews will be performed on changes that are PRA upgrades as defined in the PRA standard (ASME/ANS RA-Sa -2009, as endorsed by RG 1.200, Revision 2), and any findings will be resolved and reflected in the PRA of record prior to the implementation of the RICT Program.
Renewed License No. NPF-69 Amendment 140, 144, 183, 186
(30) Exelon is approved to implement 10 CFR 50.69 using the processes for categorization of Risk-Informed Safety Class (RISC)-1, RISC-2, RISC-3, and RISC-4 Structures, Systems, and Components (SSCs) using: Probabilistic Risk Assessment (PRA) models to evaluate risk associated with internal events, including internal flooding, and internal fire; the shutdown safety assessment process to assess shutdown risk; the Arkansas Nuclear One, Unit 2 (ANO-2) passive categorization method to assess passive component risk for Class 2 and Class 3 and non-Class SSCs and their associated supports; the results of the non-PRA evaluations that are based on the IPEEE Screening Assessment for External Hazards updated using the external hazard screening significance process identified in ASME/ANS PRA Standard RA-Sa-2009 for other external hazards except seismic; and the alternative seismic approach described in Exelon's submittal letter dated December 26, 2019, and all its subsequent associated supplements as specified in License Amendment No. 183 dated January 29, 2021.
Exelon will complete the items listed in Attachment 7 of Exelon letter to NRC dated December 26, 2019, prior to implementation of 10 CFR 50.69. All issues identified in the attachment will be addressed and any associated changes will be made, focused-scope peer reviews will be performed on changes that are PRA upgrades as defined in the PRA standard (ASME/ANS RA-Sa-2009, as endorsed by RG 1.200, Revision 2), and any findings will be resolved and reflected in the PRA of record prior to implementation of the 10 CFR 50.69 categorization process.
Prior NRC approval, under 10 CFR 50.90, is required for a change to the categorization process specified above (e.g., change from a seismic margins approach to a seismic probabilistic risk assessment approach).
D. The facility requires exemptions from certain requirements of 10 CFR Part 50 and 10 CFR Part 70.
i) An exemption from the critically alarm requirements of 10 CFR Part 70.24 was granted in the Special Nuclear Materials License No. SNM-1895 dated November 27, 1985. This exemption is described in Section 9.1 of Supplement 4 to the SER. This previously granted exemption is continued in this operating license.
ii) Exemptions to certain requirements of Appendix J to 10 CFR Part 50 are described in Supplements 3, 4, and 5 to the SER. These include (a) (this item left intentionally blank); (b) an exemption from the requirement of Option B of Appendix J, exempting main steam isolation valve measured leakage from the combined leakage rate limit of 0.6 La. (Section 6.2.6 of SSER 5)*; (c) an exemption from Option B of Appendix J, exempting the
- The parenthetical notation following the discussion of each exemption denotes the section of the Safety Evaluation Report (SER) and/or its supplements wherein the safety evaluation of the exemption is discussed.
Renewed License No. NPF-69 Amendment 140, 144, 183, 186
hydraulic control system for the reactor recirculation flow control valves from Type A and Type C leak testing (Section 6.2.6 of SSER 3);
(d) an exemption from Option B of Appendix J, exempting Type C testing on traversing incore probe system shear valves. (Section 6.2.6 SSER 4) iii) An exemption to Appendix A to 10 CFR Part 50 exempting the Control Rod Drive (CRD) hydraulic lines to the reactor recirculation pump seal purge equipment from General Design Criterion (GDC) 55. The CRD hydraulic lines to the reactor recirculation pump seal purge equipment use two simple check valves for the isolation outside containment (one side). (Section 6.2.4, SSER 3) iv) A schedular exemption to GDC 2, Appendix A to 10 CFR Part 50, until the first refueling outage, to demonstrate the adequacy of the downcomer design under the plant faulted condition. This exemption permits additional analysis and/or modifications, as necessary, to be completed by the end of the first refueling outage. (Section 6.2.1.7.4, SSER 3) v) A schedular exemption to GDC 50, Appendix A to 10 CFR Part 50 to allow the operating licensee until start-up following the "mini-outage, which is to occur within 12 months of commencing power operation (entering Operational Condition 1), to install redundant fuses in circuits that use transformers for redundant penetration protection in accordance with their letter of August 29, 1986 (NMP2L 0860). (Section 8.4.2, SSER 5) vi) A schedular exemption to 10 CFR 50.55a(h) for the Neutron Monitoring System until completion of the first refueling outage to allow the operating licensee to provide qualified isolation devices for Class 1 E/non-1E interfaces described in their letters of June 23, 1987 (NMP2L 1057) and June 25, 1987 (NMP2L 1058). (Section 7.2.2.10, SSER 6).
For the schedular exemptions in iv), v), and vi), above, the operating licensee, in accordance with its letter of October 31, 1986, shall certify that all systems, components, and modifications have been completed to meet the requirements of the regulations for which the exemptions have been granted and shall provide a summary description of actions taken to ensure that the regulations have been met. This certification and summary shall be provided 10 days prior to the expiration of each exemption period as described above.
The exemptions set forth in this Section 2.D are authorized by law, will not present an undue risk to public health and safety, and are consistent with the common defense and security. These exemptions are hereby granted. The special circumstances regarding each exemption are identified in the referenced section of the Safety Evaluation Report and the supplements thereto. The exemptions in ii) through vi) are granted pursuant to 10 CFR 50.12.
Renewed License No. NPF-69 Amendment 140, 144, 186
With these exemptions, the facility will operate to the extent authorized herein, in conformity with the application, as amended, the provisions of the Act, and the rules and regulations of the Commission.
E. Exelon Generation shall fully implement and maintain in effect all provisions of the Commission-approved physical security, training and qualification, and safeguards contingency plans, including amendments made pursuant to provisions of the Miscellaneous Amendments and Search Requirements revisions to 10 CFR 73.55 (51 FR 27817 and 27822) and to the authority of 10 CFR 50.90 and 10 CFR 50.54(p). The combined set of plans, which contain Safeguards Information protected under 10 CFR 73.21 is entitled Nine Mile Point Nuclear Station, LLC Physical Security, Safeguards Contingency, and Security Training and Qualification Plan, Revision 1, and was submitted by letter dated April 26, 2006. Changes made in accordance with 10 CFR 73.55 shall be implemented in accordance with the schedule set forth therein.
Exelon Generation shall fully implement and maintain in effect all provisions of the Commission-approved cyber security plan (CSP), including changes made pursuant to the authority of 10 CFR 50.90 and 10 CFR 50.54(p).
The Nine Mile Point Nuclear Stations CSP was approved by License Amendment No. 137 and modified by License Amendment No. 149. The licensee has obtained Commission authorization to use Section 161A preemption authority under 42 U.S.C. 2201a for weapons at its facility.
F. Exelon Generation shall implement and maintain in effect all provisions of the approved fire protection program as described in the Final Safety Analysis Report for the facility through Amendment No. 27 and as described in submittals dated March 25, May 7 and 9, June 10 and 25. July 11 and 16, August 19 and 22, September 5, 12, and 23, October 10, 21, and 22, and December 9, 1986, and April 10 and May 20, 1987, and as approved in the SER dated February 1985 (and Supplements 1 through 6) subject to the following provision:
Exelon Generation may make changes to the approved fire protection program without prior approval of the Commission only if those changes would not adversely affect the ability to achieve and maintain safe shutdown in the event of a fire.
G. The licensees shall have and maintain financial protection of such type and in such amounts as the Commission shall require in accordance with Section 170 of the Atomic Energy Act of 1954, as amended, to cover public liability claims.
H. This license is effective as of the date of issuance and shall expire at midnight on October 31, 2046.
I. The UFSAR supplement, as revised, submitted pursuant to 10 CFR 54.21(d), shall be included in the next scheduled update to the USAR required by 10 CFR 50.71(e)(4) following the issuance of this renewed operating license. Until that update is complete, the licensee may make changes to the programs and activities described in the supplement without prior Commission approval, provided that the Renewed License No. NPF-69 Amendment 140, 144, 149, 154, 186
licensee evaluates such changes pursuant to the criteria set forth in 10 CFR 50.59 and otherwise complies with the requirements in that section.
J. The UFSAR supplement, as revised, describes certain future activities to be completed prior to the period of extended operation. the licensee shall complete these activities in accordance with Appendix A of NUREG-1900, Safety Evaluation Report Related to the License Renewal of Nine Mile Point Nuclear Station, Units 1 and 2, dated September 2006, and shall notify the NRC in writing when implementation of these activities is complete and can be verified by NRC inspection.
K. For the renewed license term, all capsules in the reactor vessel that are removed and tested must meet the test procedures and reporting requirements of the most recent NRC-approved version of the Boiling Water Reactor Vessels and Internals Project (BWRVIP) Integrated Surveillance Program (ISP) appropriate for the configuration of the specimens in the capsule. All capsules placed in storage must be maintained for future insertion. Any changes to storage requirements must be approved by the NRC, as required by 10 CFR Part 50, Appendix H.
FOR THE NUCLEAR REGULATORY COMMISSION Original Signed by J. E. Dyer, Director Office of Nuclear Reactor Regulation
Enclosures:
- 1. Appendix A - Technical Specifications (NUREG-1253)
- 2. Appendix B - Environmental Protection Plan Date of Issuance: October 31, 2006 Renewed License No. NPF-69 Amendment 140, 144, 186
Completion Times 1.3 1.3 Completion Times EXAMPLES EXAMPLE 1.3-7 (continued) is met after Condition B is entered, Condition B is exited and operation may continue in accordance with Condition A, provided the Completion Time for Required Action A.2 has not expired.
IMMEDIATE When "Immediately" is used as a Completion Time, the COMPLETION TIME Required Action should be pursued without delay and in a controlled manner.
(continued)
NMP2 1.3-13 Amendment 91, 186
Completion Times 1.3 1.3 Completion Times EXAMPLES EXAMPLE 1.3-8 (continued)
ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One A.1 Restore subsystem 7 days subsystem to OPERABLE inoperable. status. OR In accordance with the Risk Informed Completion Time Program B. Required B.1 Be in MODE 3. 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> Action and associated AND Completion Time not B.2 Be in MODE 5. 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> met.
When a subsystem is declared inoperable, Condition A is entered. The 7 day Completion Time may be applied as discussed in Example 1.3-2.
However, the licensee may elect to apply the Risk Informed Completion Time Program which permits calculation of a Risk Informed Completion Time (RICT) that may be used to complete the Required Action beyond the 7 day Completion Time. The RICT cannot exceed 30 days. After the 7 day Completion Time has expired, the subsystem must be restored to OPERABLE status within the RICT or Condition B must also be entered.
The Risk Informed Completion Time Program requires recalculation of the RICT to reflect changing plant conditions. For planned changes, the revised RICT must be determined prior to implementation of the change in configuration. For emergent conditions, the revised RICT must be determined within the time limits of the Required Action Completion Time (i.e., not the RICT) or 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after the plant configuration change, whichever is less.
(continued)
NMP2 1.3-14 Amendment 186
Completion Times 1.3 1.3 Completion Times EXAMPLES EXAMPLE 1.3-8 (continued)
If the 7 day Completion Time clock of Condition A has expired and subsequent changes in plant condition result in exiting the applicability of the Risk Informed Completion Time Program without restoring the inoperable subsystem to OPERABLE status, Condition B is also entered and the Completion Time clocks for Required Actions B.1 and B.2 start.
If the RICT expires or is recalculated to be less than the elapsed time since the Condition was entered and the inoperable subsystem has not been restored to OPERABLE status, Condition B is also entered and the Completion Time clocks for Required Actions B.1 and B.2 start. If the inoperable subsystems are restored to OPERABLE status after Condition B is entered, Condition A is exited, and therefore, the Required Actions of Condition B may be terminated.
NMP2 1.3-15 Amendment 186
SLC System 3.1.7 3.1 REACTIVITY CONTROL SYSTEMS 3.1.7 Standby Liquid Control (SLC) System LCO 3.1.7 Two SLC subsystems shall be OPERABLE.
APPLICABILITY: MODES 1, 2, and 3.
ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One SLC subsystem A.1 Restore SLC subsystem 7 days inoperable. to OPERABLE status.
OR In accordance with the Risk Informed Completion Time Program B. Two SLC subsystems B.1 Restore one SLC 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> inoperable. subsystem to OPERABLE status.
C. Required Action and C.1 Be in MODE 3. 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> associated Completion Time not met. AND C.2 Be in MODE 4. 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.1.7.1 Verify available volume of sodium In accordance with pentaborate solution is within the limits the Surveillance of Figure 3.1.7-1. Frequency Control Program (continued)
NMP2 3.1.7-1 Amendment 91, 125, 152, 186
RPS Instrumentation 3.3.1.1 3.3 INSTRUMENTATION 3.3.1.1 Reactor Protection System (RPS) Instrumentation LCO 3.3.1.1 The RPS instrumentation for each Function in Table 3.3.1.1-1 shall be OPERABLE.
APPLICABILITY: According to Table 3.3.1.1-1.
ACTIONS
NOTES ------------------------------------------------------------
- 1. Separate Condition entry is allowed for each channel.
- 2. When Functions 2.b and 2.c channels are inoperable due to the calculated power exceeding the APRM output by more than 2% RTP while operating at 23% RTP, entry into associated Conditions and Required Actions may be delayed for up to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.
CONDITION REQUIRED ACTION COMPLETION TIME A. One or more required A.1 Place channel in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> channels inoperable. trip.
NOTE---------
Not applicable when when trip capability is not maintained.
In accordance with the Risk Informed Completion Time Program (continued)
NMP2 3.3.1.1-1 Amendment 9/1/, 92, 175, 186
RPS Instrumentation 3.3.1.1 ACTIONS (continued)
CONDITION REQUIRED ACTION COMPLETION TIME A. (continued) OR A.2 Place associated trip 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> system in trip.
NOTE---------
Not applicable when when trip capability is not maintained.
In accordance with the Risk Informed Completion Time Program B. --------------NOTE--------------
Not applicable for Functions 2.a, 2.b, 2.c, 2.d, and 2.e.
One or more Functions B.1 Place channel in one 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> with one or more trip system in trip.
required channels OR inoperable in both trip systems. ---------NOTE---------
Not applicable when when trip capability is not maintained.
In accordance with the Risk Informed Completion Time Program (continued)
NMP2 3.3.1.1-2 Amendment 9/1/, 92, 175, 186
RPS Instrumentation 3.3.1.1 ACTIONS (continued)
CONDITION REQUIRED ACTION COMPLETION TIME B. (continued) OR B.2 Place one trip system 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> in trip.
NOTE---------
Not applicable when trip capability is not maintained.
In accordance with the Risk Informed Completion Time Program C. One or more Functions C.1 Restore RPS trip 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> with RPS trip capability.
capability not maintained.
D. Required Action and D.1 Enter the Condition Immediately associated Completion referenced in Time of Condition A, Table 3.3.1.1-1 for the B, or C not met. channel.
E. As required by E.1 Reduce THERMAL POWER to 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> Required Action D.1 < 26% RTP.
and referenced in Table 3.3.1.1-1.
F. As required by F.1 Initiate action to implement the Immediately Required Action D.1 Manual BSP Regions defined and referenced in in the COLR.
Table 3.3.1.1-1.
(continued)
NMP2 3.3.1.1-3 Amendment 9/1/, 92, 175, 186
RPS Instrumentation 3.3.1.1 ACTIONS (continued)
CONDITION REQUIRED ACTION COMPLETION TIME F. (continued) AND F.2 Implement the Automated BSP 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Scram Region using the modified APRM Simulated Thermal Power-High scram setpoints defined in the COLR.
AND F.3 Initiate action in accordance Immediately with Specification 5.6.8.
G. As required by G.1 Be in MODE 2. 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> Required Action D.1 and referenced in Table 3.3.1.1-1.
H. As required by H.1 Be in MODE 3. 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Required Action D.1 and referenced in Table 3.3.1.1-1.
I. As required by I.1 Initiate action to Immediately Required Action D.1 fully insert all and referenced in insertable control Table 3.3.1.1-1. rods in core cells containing one or more fuel assemblies.
J. Required Action and J.1 Initiate action to implement Immediately associated Completion the Manual BSP Regions Time of Condition F not defined in the COLR.
met.
AND J.2 Reduce operation to below 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> the BSP Boundary defined in the COLR.
(continued)
NMP2 3.3.1.1-4 Amendment 91, 92, 140, 151, 186
RPS Instrumentation 3.3.1.1 ACTIONS (continued)
CONDITION REQUIRED ACTION COMPLETION TIME J. (continued) AND J.3 --------------NOTE-------------- 120 days LCO 3.0.4 is not applicable Restore required channel to OPERABLE.
K. Required Action and K.1 Reduce THERMAL POWER 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> associated Completion Time to less than 18% RTP.
of Condition J not met.
NMP2 3.3.1.1-5 Amendment 91, 92, 151, 186
RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS
NOTE -------------------------------------------------------------
- 1. Refer to Table 3.3.1.1-1 to determine which SRs apply for each RPS Function.
- 2. When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> provided the associated Function Maintains RPS trip capability.
SURVEILLANCE FREQUENCY SR 3.3.1.1.1 Perform CHANNEL CHECK. In accordance with the Surveillance Frequency Control Program SR 3.3.1.1.2 Perform CHANNEL CHECK. In accordance with the Surveillance Frequency Control Program SR 3.3.1.1.3 ----------------------------- NOTE------------------------------
Not required to be performed until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after THERMAL POWER 23% RTP.
Verify the calculated power does not exceed the In accordance with average power range monitor (APRM) channels by the Surveillance greater than 2% RTP while operating at Frequency Control 23% RTP. Program SR 3.3.1.1.4 ----------------------------- NOTE------------------------------
For Functions 1.a and 1.b, not required to be performed when entering MODE 2 from MODE 1 until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after entering MODE 2.
Perform CHANNEL FUNCTIONAL TEST. In accordance with the Surveillance Frequency Control Program (continued)
NMP2 3.3.1.1-6 Amendment 91, 92, 123, 140, 151,152, 175, 186
RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS (continued)
SURVEILLANCE FREQUENCY SR 3.3.1.1.5 Verify the source range monitor (SRM) and Prior to fully intermediate range monitor (IRM) channels Withdrawing overlap. SRMs SR 3.3.1.1.6 ----------------------------- NOTE------------------------------
Only required to be met during entry into MODE 2 from MODE 1.
Verify the IRM and APRM channels overlap. In accordance with the Surveillance Frequency Control Program SR 3.3.1.1.7 Calibrate the local power range monitors. In accordance with the Surveillance Frequency Control Program SR 3.3.1.1.8 Perform CHANNEL FUNCTIONAL TEST. In accordance with the Surveillance Frequency Control Program SR 3.3.1.1.9 Calibrate the trip units. In accordance with the Surveillance Frequency Control Program SR 3.3.1.1.10 ---------------------------- NOTES-----------------------------
- 1. For Function 2.a, not required to be performed when entering MODE 2 from MODE 1 until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after entering MODE 2.
- 2. For Function 2.e, the CHANNEL FUNCTIONAL TEST only requires toggling the appropriate outputs of In accordance with the APRM.
the Surveillance Frequency Control Perform CHANNEL FUNCTIONAL TEST.
Program (continued)
NMP2 3.3.1.1-7 Amendment 91, 92, 151, 152, 186
RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS (continued)
SURVEILLANCE FREQUENCY SR 3.3.1.1.11 Perform CHANNEL CALIBRATION In accordance with the Surveillance Frequency Control Program SR 3.3.1.1.12 Perform CHANNEL FUNCTIONAL TEST. In accordance with the Surveillance Frequency Control Program SR 3.3.1.1.13 ---------------------------- NOTES-----------------------------
- 1. Neutron detectors are excluded.
- 2. For Functions 1.a and 2.a, not required to be performed when entering MODE 2 from MODE 1 until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after entering MODE 2.
- 3. For Function 2.e, the CHANNEL CALIBRATION only requires a verification of OPRM-Upscale setpoints in the APRM by the review of the "Show Parameters" display.
Perform CHANNEL CALIBRATION. In accordance with the Surveillance Frequency Control Program SR 3.3.1.1.14 Perform LOGIC SYSTEM FUNCTIONAL TEST. In accordance with the Surveillance Frequency Control Program SR 3.3.1.1.15 Verify Turbine Stop Valve - Closure, and In accordance with Turbine Control Valve Fast Closure, Trip the Surveillance Oil Pressure - Low Functions are not Frequency Control bypassed when THERMAL POWER is 26% RTP. Program (continued)
NMP2 3.3.1.1-8 Amendment 91, 92, 152, 186
RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS (continued)
SURVEILLANCE FREQUENCY SR 3.3.1.1.16 Deleted SR 3.3.1.1.17 ---------------------------- NOTES----------------------------
- 1. Function 2.f digital electronics are excluded.
- 2. For Functions 3 and 4, the sensor response time may be assumed to be the design sensor response time.
- 3. Deleted.
- 4. For Function 9, the RPS RESPONSE TIME is measured from start of turbine control valve fast closure.
Verify the RPS RESPONSE TIME is within limits.
In accordance with the Surveillance Frequency Control Program NMP2 3.3.1.1-9 Amendment 91, 92, 152, 186
RPS Instrumentation 3.3.1.1 Table 3.3.1.1-1 (page 1 of 3)
Reactor Protection System Instrumentation CONDITIONS APPLICABLE REQUIRED REFERENCED MODES OR OTHER CHANNELS FROM SPECIFIED PER TRIP REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS SYSTEM ACTION D.1 REQUIREMENTS VALUE
- a. Neutron Flux Upscale 2 3 H SR 3.3.1.1.1 122/125 SR 3.3.1.1.4 divisions SR 3.3.1.1.5 of full SR 3.3.1.1.6 scale SR 3.3.1.1.13 SR 3.3.1.1.14 5(a) 3 I SR 3.3.1.1.1 122/125 SR 3.3.1.1.4 divisions SR 3.3.1.1.13 of full SR 3.3.1.1.14 scale
- b. Inop 2 3 H SR 3.3.1.1.4 NA SR 3.3.1.1.14 5(a) 3 I SR 3.3.1.1.4 NA SR 3.3.1.1.14
- 2. Average Power Range Monitors
- a. Neutron Flux - Upscale, 2 3 per logic H SR 3.3.1.1.2 20% RTP Setdown channel SR 3.3.1.1.6 SR 3.3.1.1.7 SR 3.3.1.1.10 SR 3.3.1.1.13
- b. Flow Biased Simulated 1 3 per logic G SR 3.3.1.1.2 0.61W +
Thermal Power - Upscale channel SR 3.3.1.1.3 63.4% RTP SR 3.3.1.1.7 and 115.5%
SR 3.3.1.1.10 RTP(b)(e)
SR 3.3.1.1.13(c)(d)
- c. Fixed Neutron 1 3 per logic G SR 3.3.1.1.2 120% RTP Flux - Upscale channel SR 3.3.1.1.3 SR 3.3.1.1.7 SR 3.3.1.1.10 SR 3.3.1.1.13
- d. Inop 1,2 3 per logic H SR 3.3.1.1.7 NA channel SR 3.3.1.1.10 (continued)
(a) With any control rod withdrawn from a core cell containing one or more fuel assemblies.
(b) Allowable Value is .50(W - 5%) + 53.5% RTP when reset for single loop operation per LCO 3.4.1, "Recirculation Loops Operating."
(c) If the As-Found channel setpoint is outside its predefined As-Found tolerances, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service.
(d) The instrument channel setpoint shall be reset to a value within the As-Left tolerance around the nominal trip setpoint at the completion of the surveillance; otherwise, the channel shall be declared inoperable. Setpoints more conservative than the nominal trip setpoint are acceptable provided that the As-Found and As-Left tolerances apply to the actual setpoint implemented in the surveillance procedures to confirm channel performance. The nominal trip setpoint and the methodologies used to determine the As-Found and the As-Left tolerances are specified in the Bases associated with the specified function.
(e) With OPRM Upscale (function 2.e) inoperable, reset the APRM-STP High scram setpoint to the values defined by the COLR to Implement the automated BSP Scram Region in accordance with Action F.2 of this Specification.
NMP2 3.3.1.1-10 Amendment 91, 92, 123, 140, 151, 186
RPS Instrumentation 3.3.1.1 Table 3.3.1.1-1 (page 2 of 3)
Reactor Protection System Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED OTHER CHANNELS FROM SPECIFIED PER TRIP REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS SYSTEM ACTION D.1 REQUIREMENTS VALUE
- 2. Average Power Range Monitors (continued)
- e. OPRM-Upscale 18% RTP(f) 3 per logic F SR 3.3.1.1.2 NA channel SR 3.3.1.1.7 SR 3.3.1.1.10 SR 3.3.1.1.13
- f. 2-Out-Of-4 Voter 1,2 2 H SR 3.3.1.1.2 NA SR 3.3.1.1.10 SR 3.3.1.1.14 SR 3.3.1.1.17
- 3. Reactor Vessel Steam Dome 1,2 2 H SR 3.3.1.1.1 1072 psig Pressure - High SR 3.3.1.1.8 SR 3.3.1.1.9 SR 3.3.1.1.13 SR 3.3.1.1.14 SR 3.3.1.1.17
- 4. Reactor Vessel Water 1,2 2 H SR 3.3.1.1.1 157.8 inches Level - Low, Level 3 SR 3.3.1.1.8 SR 3.3.1.1.9 SR 3.3.1.1.13 SR 3.3.1.1.14 SR 3.3.1.1.17
- 5. Main Steam Isolation 1 8 G SR 3.3.1.1.8 12% closed Valve - Closure SR 3.3.1.1.13 SR 3.3.1.1.14 SR 3.3.1.1.17
- 6. Drywell Pressure - High 1,2 2 H SR 3.3.1.1.1 1.88 psig SR 3.3.1.1.8 SR 3.3.1.1.9 SR 3.3.1.1.13 SR 3.3.1.1.14 (continued)
(f) Following DSS-CD implementation, DSS-CD is not required to be armed while in the DSS-CD Armed Region during the first reactor startup and during the first controlled shutdown that passes completely through the DSS-CD Armed Region. However, DSS-CD is considered OPERABLE and shall be maintained OPERABLE and capable of automatically arming for operation at recirculation drive flow rates above the DSS-CD Armed Region NMP2 3.3.1.1-11 Amendment 91, 92, 123, 140, 151, 186 Corrected Letter Dated 11/23/15
RPS Instrumentation 3.3.1.1 APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCE OTHER CHANNELS D FROM SPECIFIED PER TRIP REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS SYSTEM ACTION D.1 REQUIREMENTS VALUE
- 7. Scram Discharge Volume Water Level - High
- a. Transmitter/Trip Unit 1,2 2 H SR 3.3.1.1.1 49.5 SR 3.3.1.1.8 inches SR 3.3.1.1.9 SR 3.3.1.1.11 SR 3.3.1.1.14 5(a) 2 I SR 3.3.1.1.1 49.5 SR 3.3.1.1.8 Inches SR 3.3.1.1.9 SR 3.3.1.1.11 SR 3.3.1.1.14
- b. Float Switch 1,2 2 H SR 3.3.1.1.8 49.5 SR 3.3.1.1.13 Inches SR 3.3.1.1.14 5(a) 2 I SR 3.3.1.1.8 49.5 SR 3.3.1.1.13 Inches SR 3.3.1.1.14
- 8. Turbine Stop 26% RTP 4 E SR 3.3.1.1.8 7% closed Valve - Closure SR 3.3.1.1.13 SR 3.3.1.1.14 SR 3.3.1.1.15 SR 3.3.1.1.17
- 9. Turbine Control Valve 26% RTP 2 E SR 3.3.1.1.8 465 psig Fast Closure, Trip Oil SR 3.3.1.1.13 Pressure - Low SR 3.3.1.1.14 SR 3.3.1.1.15 SR 3.3.1.1.17
- 10. Reactor Mode 1,2 2 H SR 3.3.1.1.12 NA Switch - Shutdown Position SR 3.3.1.1.14 5(a) 2 I SR 3.3.1.1.12 NA SR 3.3.1.1.14
- 11. Manual Scram 1,2 4 H SR 3.3.1.1.4 NA SR 3.3.1.1.14 5(a) 4 I SR 3.3.1.1.4 NA SR 3.3.1.1.14 (a) With any control rod withdrawn from a core cell containing one or more fuel assemblies.
NMP2 3.3.1.1-12 Amendment 91, 92, 123, 140, 151, 186
Feedwater System and Main Turbine High Water Level Trip Instrumentation 3.3.2.2 3.3 INSTRUMENTATION 3.3.2.2 Feedwater System and Main Turbine High Water Level Trip Instrumentation LCO 3.3.2.2 Three channels of feedwater system and main turbine high water level trip instrumentation shall be OPERABLE.
APPLICABILITY: THERMAL POWER 23% RTP.
ACTIONS
NOTE -------------------------------------------------------------
Separate Condition entry is allowed for each channel.
CONDITION REQUIRED ACTION COMPLETION TIME A. One feedwater system A.1 Place channel in 7 days and main turbine high trip.
water level trip OR channel inoperable.
NOTE---------
Not applicable when trip capability is not maintained.
In accordance with the Risk Informed Completion Time Program B. Two or more feedwater B.1 Restore feedwater 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> system and main system and main turbine high water turbine high water level trip channels level trip inoperable. capability.
(continued)
NMP2 3.3.2.2-1 Amendment 91, 140, 186
EOC-RPT Instrumentation 3.3.4.1 3.3 INSTRUMENTATION 3.3.4.1 End of Cycle Recirculation Pump Trip (EOC-RPT) Instrumentation LCO 3.3.4.1 a. Two channels per trip system for each EOC-RPT instrumentation Function listed below shall be OPERABLE:
- 1. Turbine Stop Valve (TSV) - Closure; and
- 2. Turbine Control Valve (TCV) Fast Closure, Trip Oil Pressure - Low.
limits for inoperable EOC-RPT as specified in the COLR are made applicable.
APPLICABILITY: THERMAL POWER 26% RTP with any recirculation pump in fast speed.
ACTIONS
NOTE --------------------------------------------------------------
Separate Condition entry is allowed for each channel.
CONDITION REQUIRED ACTION COMPLETION TIME A. One or more required A.1 Restore channel to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> channels inoperable. OPERABLE status.
OR OR
NOTE---------
Not applicable when trip capability is not maintained.
In accordance with the Risk Informed Completion Time Program (continued)
NMP2 3.3.4.1-1 Amendment 91, 140, 186
EOC-RPT Instrumentation 3.3.4.1 ACTIONS (continued)
COMPLETION CONDITION REQUIRED ACTION TIME A. (continued) A.2 ------------NOTE------------
Not applicable if inoperable channel is the result of an inoperable breaker.
Place channel in 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> trip.
NOTE--------
Not applicable when trip capability is not maintained.
In accordance with the Risk Informed Completion Time Program B. One or more Functions B.1 Restore EOC-RPT trip 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> with EOC-RPT trip capability.
capability not maintained. OR AND B.2 Apply the MCPR limit 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> for inoperable MCPR limit for EOC-RPT as specified inoperable EOC-RPT not in the COLR.
made applicable.
C. Required Action and C.1 Remove the associated 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> associated Completion recirculation pump Time not met. fast speed breaker from service.
OR C.2 Reduce THERMAL POWER 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> to < 26% RTP.
NMP2 3.3.4.1-2 Amendment 91, 140, 186
ATWS-RPT Instrumentation 3.3.4.2 3.3 INSTRUMENTATION 3.3.4.2 Anticipated Transient Without Scram Recirculation Pump Trip (ATWS-RPT) Instrumentation LCO 3.3.4.2 Two channels per trip system for each ATWS - RPT instrumentation Function listed below shall be OPERABLE:
- a. Reactor Vessel Water Level - Low Low, Level 2; and
- b. Reactor Vessel Steam Dome Pressure - High.
APPLICABILITY: MODE 1.
ACTIONS
NOTE -------------------------------------------------------------
Separate Condition entry is allowed for each channel.
CONDITION REQUIRED ACTION COMPLETION TIME A. One or more channels A.1 Restore channel to 14 days inoperable. OPERABLE status.
NOTE---------
Not applicable when trip capability is not maintained.
In accordance with the Risk Informed Completion Time Program (continued)
NMP2 3.3.4.2-1 Amendment 91, 186
ATWS-RPT Instrumentation 3.3.4.2 ACTIONS (continued)
CONDITION REQUIRED ACTION COMPLETION TIME A. (continued) OR A.2 ------------NOTE------------
Not applicable if inoperable channel is the result of an inoperable breaker.
Place channel in 14 days trip.
NOTE---------
Not applicable when trip capability is not maintained.
In accordance with the Risk Informed Completion Time Program B. One Function with B.1 Restore ATWS-RPT trip 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> ATWS-RPT trip capability.
capability not maintained.
C. Both Functions with C.1 Restore ATWS-RPT trip 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> ATWS-RPT trip capability for one capability not Function.
maintained.
D. Required Action and D.1 Remove the associated 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> associated Completion recirculation pump Time not met. breaker(s) from service.
OR D.2 Be in MODE 2. 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> NMP2 3.3.4.2-2 Amendment 91, 152, 186
ATWS-RPT Instrumentation 3.3.4.2 SURVEILLANCE REQUIREMENTS
NOTE -------------------------------------------------------------
When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> provided the associated Function maintains ATWS-RPT trip capability.
SURVEILLANCE FREQUENCY SR 3.3.4.2.1 Perform CHANNEL CHECK. In accordance with the Surveillance Frequency Control Program SR 3.3.4.2.2 Perform CHANNEL FUNCTIONAL TEST. In accordance with the Surveillance Frequency Control Program SR 3.3.4.2.3 Calibrate the analog trip modules. In accordance with the Surveillance Frequency Control Program SR 3.3.4.2.4 Verify, for the Reactor Vessel Steam Dome In accordance Pressure - High Function, the low with the frequency motor generator trip is not Surveillance bypassed for > 29 seconds when THERMAL Frequency POWER is > 5% RTP. Control Program SR 3.3.4.2.5 Perform CHANNEL CALIBRATION. The In accordance Allowable Values shall be: with the Surveillance
- a. Reactor Vessel Water Level - Low Low, Frequency Level 2: 101.8 inches; and Control Program
- b. Reactor Vessel Steam Dome Pressure - High: 1080 psig.
(continued)
NMP2 3.3.4.2-3 Amendment 91, 152, 186
ATWS-RPT Instrumentation 3.3.4.2 SURVEILLANCE REQUIREMENTS (continued)
SURVEILLANCE FREQUENCY SR 3.3.4.2.6 Perform LOGIC SYSTEM FUNCTIONAL TEST, In accordance including breaker actuation. with the Surveillance Frequency Control Program NMP2 3.3.4.2-4 Amendment 91, 152, 186
ECCS Instrumentation 3.3.5.1 ACTIONS (continued)
CONDITION REQUIRED ACTION COMPLETION TIME B. (continued) B.3.1 Place channel in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> for trip. Functions 1.a, 1.d, 2.a, and 2.d AND 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for Functions other than Functions 1.a, 1.d, 2.a, and 2.d OR
NOTE---------
Not applicable when trip capability is not maintained.
In accordance with the Risk Informed Completion Time Program OR B.3.2 ------------NOTE------------
Only applicable for Functions 1.a, 1.d, 2.a, and 2.d.
Isolate the affected 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> flow path(s).
(continued)
NMP2 3.3.5.1-3 Amendment 91, 186
ECCS Instrumentation 3.3.5.1 ACTIONS (continued)
CONDITION REQUIRED ACTION COMPLETION TIME C. As required by C.1 ------------NOTE------------
Required Action A.1 Only applicable and referenced in for Functions Table 3.3.5.1-1. 1.e, 1.f, 1.g, 1.h, 1.i, 1.j, 2.e, 2.f, 2.g, 2.h, and 2.i.
Declare supported 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> from feature(s) inoperable discovery of when its redundant loss of feature ECCS initiation initiation capability capability for is inoperable. feature(s) in both divisions AND C.2 Restore channel to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> OPERABLE status.
NOTE---------
Not applicable when trip capability is not maintained.
In accordance with the Risk Informed Completion Time Program D. As required by D.1 ------------NOTE-------------
Required Action A.1 Only applicable if and referenced in HPCS pump suction is Table 3.3.5.1-1. not aligned to the suppression pool.
(continued)
NMP2 3.3.5.1-4 Amendment 91, 168, 186
ECCS Instrumentation 3.3.5.1 ACTIONS (continued)
CONDITION REQUIRED ACTION COMPLETION TIME D. (continued) Declare HPCS System 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> from inoperable. discovery of loss of HPCS AND initiation capability D.2.1 Place channel in 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> trip.
NOTE---------
Not applicable when trip capability is not maintained.
In accordance with the Risk Informed Completion Time Program D.2.2 Align the HPCS pump 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> suction to the suppression pool.
E. As required by E.1 ------------NOTE------------
Required Action A.1 Only applicable and referenced in for Functions Table 3.3.5.1-1. 1.k, 1.l, and 2.j.
Declare supported 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> from feature(s) inoperable discovery of when its redundant loss of feature ECCS initiation initiation capability capability for is inoperable. feature(s) in both divisions AND (continued)
NMP2 3.3.5.1-5 Amendment 91, 168, 186
ECCS Instrumentation 3.3.5.1 ACTIONS (continued)
CONDITION REQUIRED ACTION COMPLETION TIME E. (continued) E.2 Restore channel to 7 days OPERABLE status.
NOTE---------
Not applicable when trip capability is not maintained.
In accordance with the Risk Informed Completion Time Program F. As required by F.1 Declare Automatic 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> from Required Action A.1 Depressurization discovery of and referenced in System (ADS) valves loss of ADS Table 3.3.5.1-1. inoperable. initiation capability in both trip systems AND F.2 Place channel in 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> or in trip. accordance with the Risk Informed Completion Time Program from discovery of inoperable channel concurrent with HPCS or reactor core isolation cooling (RCIC) inoperable AND (continued)
NMP2 3.3.5.1-6 Amendment 91, 186
ECCS Instrumentation 3.3.5.1 ACTIONS (continued)
CONDITION REQUIRED ACTION COMPLETION TIME F. (continued) 8 days OR
NOTE---------
Not applicable when trip capability is not maintained.
In accordance with the Risk Informed Completion Time Program G. As required by G.1 ------------NOTE------------
Required Action A.1 Only applicable for and referenced in Functions 4.b, 4.d, Table 3.3.5.1-1. 4.e, 5.b, and 5.d.
Declare ADS valves 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> from inoperable. discovery of loss of ADS initiation capability in both trip systems AND G.2 Restore channel to 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> or in OPERABLE status. accordance with the Risk Informed Completion Time Program from discovery of inoperable channel concurrent with HPCS or RCIC inoperable AND (continued)
NMP2 3.3.5.1-7 Amendment 91, 186
ECCS Instrumentation 3.3.5.1 ACTIONS (continued)
CONDITION REQUIRED ACTION COMPLETION TIME G. (continued) 8 days OR
NOTE---------
Not applicable when trip capability is not maintained.
In accordance with the Risk Informed Completion Time Program H. Required Action and H.1 Declare associated Immediately associated Completion supported feature(s)
Time of Condition B, inoperable.
C, D, E, F, or G not met.
NMP2 3.3.5.1-8 Amendment 91, 186
ECCS Instrumentation 3.3.5.1 SURVEILLANCE REQUIREMENTS
NOTES ------------------------------------------------------------
- 1. Refer to Table 3.3.5.1-1 to determine which SRs apply for each ECCS Function.
- 2. When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> provided the associated Function or the redundant Function maintains ECCS initiation capability.
SURVEILLANCE FREQUENCY SR 3.3.5.1.1 Perform CHANNEL CHECK. In accordance with the Surveillance Frequency Control Program SR 3.3.5.1.2 Perform CHANNEL FUNCTIONAL TEST. In accordance with the Surveillance Frequency Control Program*
SR 3.3.5.1.3 Calibrate the trip unit. In accordance with the Surveillance Frequency Control Program SR 3.3.5.1.4 Perform CHANNEL CALIBRATION. In accordance with the Surveillance Frequency Control Program SR 3.3.5.1.5 Perform CHANNEL CALIBRATION. In accordance with the Surveillance Frequency Control Program*
SR 3.3.5.1.6 Perform LOGIC SYSTEM FUNCTIONAL TEST. In accordance with the Surveillance Frequency Control Program*
- Following return to OPERABILITY of the HPCS System, the past due Surveillances will be completed by January 11, 2019.
NMP2 3.3.5.1-9 Amendment 91, 152,168, 174, 186
ECCS Instrumentation 3.3.5.1 Table 3.3.5.1-1 (page 1 of 5)
Emergency Core Cooling System Instrumentation APPLICABLE CONDITIONS MODES OR REFERENCED OTHER REQUIRED FROM SPECIFIED CHANNELS PER REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS FUNCTION ACTION A.1 REQUIREMENTS VALUE
- 1. Low Pressure Coolant Injection-A (LPCI) and Low Pressure Core Spray (LPCS)
Subsystems
- a. Reactor Vessel Water 1,2,3 2 B SR 3.3.5.1.1 157.8 Level - Low, Level 3 SR 3.3.5.1.2 inches SR 3.3.5.1.3 SR 3.3.5.1.5 SR 3.3.5.1.6
- b. Reactor Vessel Water 1,2,3 2(a) B SR 3.3.5.1.1 10.8 inches Level - Low Low Low, SR 3.3.5.1.2 Level 1 SR 3.3.5.1.3 SR 3.3.5.1.5 SR 3.3.5.1.6
- c. Drywell Pressure - High 1,2,3 2(a) B SR 3.3.5.1.1 1.88 psig SR 3.3.5.1.2 SR 3.3.5.1.3 SR 3.3.5.1.5 SR 3.3.5.1 6
- d. Drywell Pressure - High 1,2,3 2 B SR 3.3.5.1.1 1.88 psig (Boundary Isolation) SR 3.3.5.1.2 SR 3.3.5.1.3 SR 3.3.5.1.5 SR 3.3.5.1.6
- e. LPCS Pump Start - Time 1,2,3 1 C SR 3.3.5.1.2 12 seconds Delay Relay (Normal SR 3.3.5.1.5 Power) SR 3.3.5.1.6
- f. LPCI Pump A 1,2,3 1 C SR 3.3.5.1.2 7 seconds Start - Time Delay SR 3.3.5.1.5 Relay (Normal Power) SR 3.3.5.1.6
- g. LPCS Pump Start - Time 1,2,3 1 C SR 3.3.5.1.2 6.75 Delay Relay (Emergency SR 3.3.5.1.5 seconds Power) SR 3.3.5.1.6
- h. LPCI Pump A 1,2,3 1 C SR 3.3.5.1.2 2 seconds Start - Time Delay SR 3.3.5.1.5 Relay (Emergency SR 3.3.5.1.6 Power)
- i. LPCS Differential 1,2,3 1 C SR 3.3.5.1.1 40 psid and Pressure - Low SR 3.3.5.1.2 98 psid (Injection Permissive) SR 3.3.5.1.3 SR 3.3.5.1.5 SR 3.3.5.1.6 (continued)
(a) Also required to initiate the associated diesel generator (DG).
NMP2 3.3.5.1-10 Amendment 91, 168, 186
ECCS Instrumentation 3.3.5.1 Table 3.3.5.1-1 (page 2 of 5)
Emergency Core Cooling System Instrumentation APPLICABLE CONDITIONS MODES OR REFERENCED OTHER REQUIRED FROM SPECIFIED CHANNELS PER REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS FUNCTION ACTION A.1 REQUIREMENTS VALUE
- j. LPCI A Differential 1,2,3 1 C SR 3.3.5.1.1 70 psid and Pressure - Low SR 3.3.5.1.2 150 psid (Injection Permissive) SR 3.3.5.1.3 SR 3.3.5.1.5 SR 3.3.5.1.6
- k. LPCS Pump Discharge 1,2,3 1 E SR 3.3.5.1.1 1000 gpm Flow Low (Bypass) SR 3.3.5.1.2 and SR 3.3.5.1.3 1440 gpm SR 3.3.5.1.5 SR 3.3.5.1.6
- l. LPCI Pump A Discharge 1,2,3 1 E SR 3.3.5.1.1 770 gpm and Flow - Low (Bypass) SR 3.3.5.1.2 930 gpm SR 3.3.5.1.3 SR 3.3.5.1.5 SR 3.3.5.1.6
- m. Manual Initiation 1,2,3 2 C SR 3.3.5.1.6 NA
- a. Reactor Vessel Water 1,2,3 2 B SR 3.3.5.1.1 157.8 Level - Low, Level 3 SR 3.3.5.1.2 inches SR 3.3.5.1.3 SR 3.3.5.1.5 SR 3.3.5.1.6
- b. Reactor Vessel Water 1,2,3 2(a) B SR 3.3.5.1.1 10.8 inches Level - Low Low Low, SR 3.3.5.1.2 Level 1 SR 3.3.5.1.3 SR 3.3.5.1.5 SR 3.3.5.1.6
- c. Drywell Pressure - High 1,2,3 2(a) B SR 3.3.5.1.1 1.88 psig SR 3.3.5.1.2 SR 3.3.5.1.3 SR 3.3.5.1.5 SR 3.3.5.1.6 (continued)
(a) Also required to initiate the associated DG NMP2 3.3.5.1-11 Amendment 91, 168, 186
ECCS Instrumentation 3.3.5.1 Table 3.3.5.1-1 (page 3 of 5)
Emergency Core Cooling System Instrumentation APPLICABLE CONDITIONS MODES OR REFERENCED OTHER REQUIRED FROM SPECIFIED CHANNELS PER REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS FUNCTION ACTION A.1 REQUIREMENTS VALUE
- d. Drywell Pressure - High 1,2,3 2 B SR 3.3.5.1.1 1.88 psig (Boundary Isolation) SR 3.3.5.1.2 SR 3.3.5.1.3 SR 3.3.5.1.5 SR 3.3.5.1.6
- e. LPCI Pump B 1,2,3 1 C SR 3.3.5.1.2 7 seconds Start - Time Delay SR 3.3.5.1.5 Relay (Normal Power) SR 3.3.5.1.6
- f. LPCI Pump C 1,2,3 1 C SR 3.3.5.1.2 12 seconds Start Time Delay SR 3.3.5.1.5 Relay (Normal Power) SR 3.3.5.1.6
- g. LPCI Pump B 1,2,3 1 C SR 3.3.5.1.2 2 second Start - Time Delay SR 3.3.5.1.5 Relay (Emergency SR 3.3.5.1.6 Power)
- h. LPCI Pump C 1,2,3 1 C SR 3.3.5.1.2 7 second Start - Time Delay SR 3.3.5.1.5 Relay (Emergency SR 3.3.5.1.6 Power)
- i. LPCI B and C 1,2,3 1 per valve C SR 3.3.5.1.1 70 psid and Differential SR 3.3.5.1.2 150 psid Pressure - Low SR 3.3.5.1.3 (Injection Permissive) SR 3.3.5.1.5 SR 3.3.5.1.6
- j. LPCI Pump B and LPCI 1,2,3 1 per pump E SR 3.3.5.1.1 770 gpm Pump C Discharge SR 3.3.5.1.2 and Flow - Low (Bypass) SR 3.3.5.1.3 930 gpm SR 3.3.5.1.5 SR 3.3.5.1.6
- k. Manual Initiation 1,2,3 2 C SR 3.3.5.1.6 NA (continued)
NMP2 3.3.5.1-12 Amendment 91, 168, 186
ECCS Instrumentation 3.3.5.1 Table 3.3.5.1-1 (page 4 of 5)
Emergency Core Cooling System Instrumentation APPLICABLE CONDITIONS MODES OR REFERENCED OTHER REQUIRED FROM SPECIFIED CHANNELS PER REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS FUNCTION ACTION A.1 REQUIREMENTS VALUE
- 3. High Pressure Core Spray (HPCS) System
- a. Reactor Vessel Water 1,2,3 4(a) B SR 3.3.5.1.1 101.8 Level - Low Low, SR 3.3.5.1.2 Inches Level 2 SR 3.3.5.1.3 SR 3.3.5.1.5 SR 3.3.5.1.6
- b. Drywell Pressure - High (b) 1,2,3 4(a) B SR 3.3.5.1.1 1.88 psig SR 3.3.5.1.2 SR 3.3.5.1.3 SR 3.3.5.1.5 SR 3.3.5.1.6
- c. Reactor Vessel Water 1,2,3 4 C SR 3.3.5.1.1 209.3 Level - High, Level 8 SR 3.3.5.1.2 inches SR 3.3.5.1.3 SR 3.3.5.1.5 SR 3.3.5.1.6
- d. Pump Suction 1,2,3 2 D SR 3.3.5.1.1 94.5 inches Pressure - Low SR 3.3.5.1.2 H2O SR 3.3.5.1.3 SR 3.3.5.1.5 SR 3.3.5.1.6
- e. Pump Suction 1,2,3 1 D SR 3.3.5.1.2 5.5 seconds Pressure - Timer SR 3.3.5.1.5 SR 3.3.5.1.6
- f. Suppression Pool Water 1,2,3 2 D SR 3.3.5.1.1 200.7 ft Level - High SR 3.3.5.1.2 SR 3.3.5.1.3 SR 3.3.5.1.5 SR 3.3.5.1.6
- g. HPCS Pump Discharge 1,2,3 1 E SR 3.3.5.1.1 220 psig Pressure - High SR 3.3.5.1.2 (Bypass) SR 3.3.5.1.3 SR 3.3.5.1.5 SR 3.3.5.1.6
- h. HPCS System Flow 1,2,3 1 E SR 3.3.5.1.1 580 gpm and Rate - Low (Bypass) SR 3.3.5.1.2 720 gpm SR 3.3.5.1.3 SR 3.3.5.1.5 SR 3.3.5.1.6
- i. Manual Initiation (b) 1,2,3 2 C SR 3.3.5.1.6 NA (continued)
(a) Also required to initiate the associated DG.
(b) The injection functions of Drywell Pressure-High and Manual Initiation are not required to be OPERABLE with reactor steam dome pressure less than 600 psig.
NMP2 3.3.5.1-13 Amendment 160, 168, 186
ECCS Instrumentation 3.3.5.1 Table 3.3.5.1-1 (page 5 of 5)
Emergency Core Cooling System Instrumentation APPLICABLE CONDITIONS MODES OR REFERENCED OTHER REQUIRED FROM SPECIFIED CHANNELS PER REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS FUNCTION ACTION A.1 REQUIREMENTS VALUE
- 4. Automatic Depressurization System (ADS) Trip System A
- a. Reactor Vessel Water 1,2(d),3(d) 2 F SR 3.3.5.1.1 10.8 inches Level - Low Low Low, SR 3.3.5.1.2 Level 1 SR 3.3.5.1.3 SR 3.3.5.1.5 SR 3.3.5.1.6
- b. ADS Initiation Timer 1,2(d),3(d) 1 G SR 3.3.5.1.2 117 seconds SR 3.3.5.1.4 SR 3.3.5.1.6
- c. Reactor Vessel Water 1,2(d),3(d) 1 F SR 3.3.5.1.1 157.8 Level - Low, Level 3 SR 3.3.5.1.2 inches (Permissive) SR 3.3.5.1.3 SR 3.3.5.1.5 SR 3.3.5.1.6
- d. LPCS Pump Discharge 1,2(d),3(d) 2 G SR 3.3.5.1.1 125 psig Pressure - High SR 3.3.5.1.2 and SR 3.3.5.1.3 150 psig SR 3.3.5.1.5 SR 3.3.5.1.6
- e. LPCI Pump A Discharge 1,2(d),3(d) 2 G SR 3.3.5.1.1 115 psig Pressure - High SR 3.3.5.1.2 and SR 3.3.5.1.3 130 psig SR 3.3.5.1.5 SR 3.3.5.1.6
- f. Manual Initiation 1,2(d),3(d) 4 G SR 3.3.5.1.6 NA
- 5. ADS Trip System B
- a. Reactor Vessel Water 1,2(d),3(d) 2 F SR 3.3.5.1.1 10.8 inches Level - Low Low Low, SR 3.3.5.1.2 Level 1 SR 3.3.5.1.3 SR 3.3.5.1.5 SR 3.3.5.1.6
- b. ADS Initiation Timer 1,2(d),3(d) 1 G SR 3.3.5.1.2 117 seconds SR 3.3.5.1.4 SR 3.3.5.1.6
- c. Reactor Vessel Water 1,2(d),3(d) 1 F SR 3.3.5.1.1 157.8 Level - Low, Level 3 SR 3.3.5.1.2 inches (Permissive) SR 3.3.5.1.3 SR 3.3.5.1.5 SR 3.3.5.1.6
- d. LPCI Pumps B & C 1,2(d),3(d) 2 per pump G SR 3.3.5.1.1 115 psig Discharge SR 3.3.5.1.2 and Pressure - High SR 3.3.5.1.3 130 psig SR 3.3.5.1.5 SR 3.3.5.1.6
- e. Manual Initiation 1,2(d),3(d) 4 G SR 3.3.5.1.6 NA (d) With reactor steam dome pressure > 150 psig.
NMP2 3.3.5.1-14 Amendment 91, 186
RCIC System Instrumentation 3.3.5.3 3.3 INSTRUMENTATION 3.3.5.3 Reactor Core Isolation Cooling (RCIC) System Instrumentation LCO 3.3.5.3 The RCIC System instrumentation for each Function in Table 3.3.5.3-1 shall be OPERABLE.
APPLICABILITY:
MODE 1, MODES 2 and 3 with reactor steam dome pressure > 150 psig.
ACTIONS
NOTES ------------------------------------------------------------
- 1. Separate Condition entry is allowed for each channel.
- 2. When the Function 2 channels are placed in an inoperable status solely for performance of SR 3.5.3.4, entry into associated Conditions and Required Actions is not required.
CONDITION REQUIRED ACTION COMPLETION TIME A. One or more channels A.1 Enter the Condition Immediately inoperable. referenced in Table 3.3.5.3-1 for the channel.
B. As required by B.1 Declare RCIC System 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> from Required Action A.1 inoperable. discovery of and referenced in loss of RCIC Table 3.3.5.3-1. initiation capability AND B.2 Place channel in 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> trip.
OR (continued)
NMP2 3.3.5.3-1 Amendment 91, 168, 186
RCIC System Instrumentation 3.3.5.3 ACTIONS (continued)
CONDITION REQUIRED ACTION COMPLETION TIME B. (continued) ---------NOTE---------
Not applicable when trip capability is not maintained.
In accordance with the Risk Informed Completion Time Program C. As required by C.1 Restore channel to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Required Action A.1 OPERABLE status.
and referenced in Table 3.3.5.3-1.
D. As required by D.1 ------------NOTE------------
Required Action A.1 Only applicable if and referenced in RCIC pump suction is Table 3.3.5.3-1. not aligned to the suppression pool.
Declare RCIC System 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> from inoperable. discovery of loss of RCIC initiation capability AND D.2.1 Place channel in 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> trip.
OR OR
NOTE---------
Not applicable when trip capability is not maintained.
In accordance with the Risk Informed Completion Time Program (continued)
NMP2 3.3.5.3-2 Amendment 91, 168, 186
RCIC System Instrumentation 3.3.5.3 ACTIONS (conditions)
CONDITION REQUIRED ACTION COMPLETION TIME D. (continued) D.2.2 Align RCIC pump 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> suction to the suppression pool.
E. Required Action and E.1 Declare RCIC System Immediately associated Completion inoperable.
Time of Condition B, C, or D not met.
NMP2 3.3.5.3-3 Amendment 91, 168, 186
RCIC System Instrumentation 3.3.5.3 SURVEILLANCE REQUIREMENTS
NOTES ------------------------------------------------------------
- 1. Refer to Table 3.3.5.3-1 to determine which SRs apply for each RCIC Function.
- 2. When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed as follows: (a) for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> for Functions 4 and 5; and (b) for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> for Functions 1, 2, and 3 provided the associated Function maintains RCIC initiation capability.
SURVEILLANCE FREQUENCY SR 3.3.5.3.1 Perform CHANNEL CHECK. In accordance with the Surveillance Frequency Control Program SR 3.3.5.3.2 Perform CHANNEL FUNCTIONAL TEST. In accordance with the Surveillance Frequency Control Program SR 3.3.5.3.3 Calibrate the trip units. In accordance with the Surveillance Frequency Control Program SR 3.3.5.3.4 Perform CHANNEL CALIBRATION. In accordance with the Surveillance Frequency Control Program SR 3.3.5.3.5 Perform LOGIC SYSTEM FUNCTIONAL TEST. In accordance with the Surveillance Frequency Control Program NMP2 3.3.5.3-4 Amendment 91, 152, 168, 186
RCIC System Instrumentation 3.3.5.3 Table 3.3.5.3.1 (page 1 of 1)
Reactor Core Isolation Cooling System Instrumentation CONDITIONS REQUIRED REFERENCED CHANNELS PER FROM REQUIRED SURVEILLANCE ALLOWABLE FUNCTION FUNCTION ACTION A.1 REQUIREMENTS VALUE
- 1. Reactor Vessel Water 4 B SR 3.3.5.3.1 101.8 inches Level - Low Low, Level 2 SR 3.3.5.3.2 SR 3.3.5.3.3 SR 3.3.5.3.4 SR 3.3.5.3.5
- 2. Reactor Vessel Water 4 B SR 3.3.5.3.1 209.3 inches Level - High, Level 8 SR 3.3.5.3.2 SR 3.3.5.3.3 SR 3.3.5.3.4 SR 3.3.5.3.5
- 3. Pump Suction 2 D SR 3.3.5.3.1 101 inches Wg Pressure - Low SR 3.3.5.3.2 SR 3.3.5.3.3 SR 3.3.5.3.4 SR 3.3.5.3.5
- 4. Pump Suction 1 D SR 3.3.5.3.2 12.3 seconds Pressure - Timer SR 3.3.5.3.4 SR 3.3.5.3.5
- 5. Manual Initiation (a) 2 C SR 3.3.5.3.5 NA (a) The injection function of Manual Initiation is not required to be OPERABLE with reactor steam dome pressure less than 600 psig.
NMP2 3.3.5.3-5 Amendment 160, 168, 186
Primary Containment Isolation Instrumentation 3.3.6.1 3.3 INSTRUMENTATION 3.3.6.1 Primary Containment Isolation Instrumentation LCO 3.3.6.1 The primary containment isolation instrumentation for each Function in Table 3.3.6.1-1 shall be OPERABLE.
APPLICABILITY: According to Table 3.3.6.1-1.
ACTIONS
NOTE -------------------------------------------------------------
Separate Condition entry is allowed for each channel.
CONDITION REQUIRED ACTION COMPLETION TIME A. One or more channels A.1 Place channel in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> for inoperable. trip. Functions 2.b, 5.b, and 5.c OR
NOTE---------
Not applicable when trip capability is not maintained.
In accordance with the Risk Informed Completion Time Program AND 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for Functions other than Functions 2.b, 5.b, and 5.c OR (continued)
NMP2 3.3.6.1-1 Amendment 91, 186
Primary Containment Isolation Instrumentation 3.3.6.1 ACTIONS (continued)
CONDITION REQUIRED ACTION COMPLETION TIME A. (continued)
NOTE---------
Not applicable when trip capability is not maintained.
In accordance with the Risk Informed Completion Time Program B. One or more automatic B.1 Restore isolation 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Functions with capability.
isolation capability not maintained.
C. Required Action and C.1 Enter the Condition Immediately associated Completion referenced in Time of Condition A Table 3.3.6.1-1 for or B not met. the channel.
D. As required by D.1 Isolate associated 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Required Action C.1 main steam line and referenced in (MSL).
Table 3.3.6.1-1.
OR D.2.1 Be in MODE 3. 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> AND D.2.2 Be in MODE 4. 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> E. As required by E.1 Be in MODE 2. 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> Required Action C.1 and referenced in Table 3.3.6.1-1.
(continued)
NMP2 3.3.6.1-2 Amendment 91, 186
Primary Containment Isolation Instrumentation 3.3.6.1 ACTIONS (continued)
CONDITION REQUIRED ACTION COMPLETION TIME F. As required by F.1 Isolate the affected 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Required Action C.1 penetration flow and referenced in path(s).
Table 3.3.6.1-1.
G. As required by G.1 Isolate the affected 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Required Action C.1 penetration flow and referenced in path(s).
Table 3.3.6.1-1.
H. Required Action and H.1 Be in MODE 3. 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> associated Completion Time of Condition F or AND G not met.
H.2 Be in MODE 4. 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> OR As required by Required Action C.1 and referenced in Table 3.3.6.1-1.
I. As required by I.1 Declare associated 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Required Action C.1 standby liquid and referenced in control (SLC)
Table 3.3.6.1-1. subsystem inoperable.
OR I.2 Isolate the Reactor 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Water Cleanup (RWCU)
System.
J. As required by J.1 Initiate action to Immediately Required Action C.1 restore channel to and referenced in OPERABLE status.
Table 3.3.6.1-1.
OR (continued)
NMP2 3.3.6.1-3 Amendment 91, 186
Primary Containment Isolation Instrumentation 3.3.6.1 ACTIONS (continued)
CONDITION REQUIRED ACTION COMPLETION TIME J. (continued) J.2 Initiate action to Immediately isolate the Residual Heat Removal (RHR)
Shutdown Cooling (SDC) System.
NMP2 3.3.6.1-4 Amendment 91, 186
Primary Containment Isolation Instrumentation 3.3.6.1 SURVEILLANCE REQUIREMENTS
NOTES ------------------------------------------------------------
- 1. Refer to Table 3.3.6.1-1 to determine which SRs apply for each Primary Containment Isolation Function.
- 2. When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> provided the associated Function maintains isolation capability.
SURVEILLANCE FREQUENCY SR 3.3.6.1.1 Perform CHANNEL CHECK. In accordance with the Surveillance Frequency Control Program SR 3.3.6.1.2 Deleted SR 3.3.6.1.3 Perform CHANNEL FUNCTIONAL TEST. In accordance with the Surveillance Frequency Control Program SR 3.3.6.1.4 Calibrate the trip unit. In accordance with the Surveillance Frequency Control Program SR 3.3.6.1.5 Perform CHANNEL CALIBRATION. In accordance with the Surveillance Frequency Control Program SR 3.3.6.1.6 Perform LOGIC SYSTEM FUNCTIONAL TEST. In accordance with the Surveillance Frequency Control Program (continued)
NMP2 3.3.6.1-5 Amendment 91, 147, 152, 186
Primary Containment Isolation Instrumentation 3.3.6.1 SURVEILLANCE REQUIREMENTS (continued)
SURVEILLANCE FREQUENCY SR 3.3.6.1.7 -------------------------------- NOTE------------------------------
The sensor response time may be assumed to be the design sensor response time.
Verify the ISOLATION SYSTEM RESPONSE TIME In accordance with is within limits. the Surveillance Frequency Control Program NMP2 3.3.6.1-6 Amendment 91, 152, 186
Primary Containment Isolation Instrumentation 3.3.6.1 Table 3.3.6.1-1 (page 1 of 5)
Primary Containment Isolation Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED OTHER CHANNELS FROM SPECIFIED PER TRIP REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS SYSTEM ACTION C.1 REQUIREMENTS VALUE
- 1. Main Steam Line Isolation
- a. Reactor Vessel Water 1,2,3 2 D SR 3.3.6.1.1 10.8 inches Level - Low Low Low, SR 3.3.6.1.3 Level 1 SR 3.3.6.1.4 SR 3.3.6.1.5 SR 3.3.6.1.6 SR 3.3.6.1.7
- b. Main Steam Line Pressure 1 2 E SR 3.3.6.1.1 814 psig
- Low SR 3.3.6.1.3 SR 3.3.6.1.4 SR 3.3.6.1.5 SR 3.3.6.1.6 SR 3.3.6.1.7
- c. Main Steam Line 1,2,3 2 per MSL D SR 3.3.6.1.1 184.4 psid Flow - High SR 3.3.6.1.3 SR 3.3.6.1.4 SR 3.3.6.1.5 SR 3.3.6.1.6 SR 3.3.6.1.7
- d. Condenser Vacuum - Low 1,2(a), 2 D SR 3.3.6.1.1 7.6 inches SR 3.3.6.1.3 Hg vacuum SR 3.3.6.1.4 3(a) SR 3.3.6.1.5 SR 3.3.6.1.6
- e. Main Steam Line 1,2,3 2 D SR 3.3.6.1.1 170.6F Tunnel SR 3.3.6.1.3 Temperature - High SR 3.3.6.1.5 SR 3.3.6.1.6
- f. Main Steam Line 1,2,3 2 D SR 3.3.6.1.1 71.7F Tunnel Differential SR 3.3.6.1.3 Temperature - High SR 3.3.6.1.5 SR 3.3.6.1.6
- g. Main Steam Line 1,2,3 2 per area D SR 3.3.6.1.1 175.6F(b)
Tunnel Lead Enclosure SR 3.3.6.1.3 Temperature - High SR 3.3.6.1.5 SR 3.3.6.1.6
- h. Manual Initiation 1,2,3 4 G SR 3.3.6.1.6 NA (continued)
(a) With any turbine stop valve not closed.
NMP2 3.3.6.1-7 Amendment 91, 140, 147, 164, 186
Primary Containment Isolation Instrumentation 3.3.6.1 Table 3.3.6.1-1 (page 2 of 5)
Primary Containment Isolation Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED OTHER CHANNELS FROM SPECIFIED PER TRIP REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS SYSTEM ACTION C.1 REQUIREMENTS VALUE
- 2. Primary Containment Isolation
- a. Reactor Vessel Water 1,2,3 2 H SR 3.3.6.1.1 101.8 inches Level - Low Low, SR 3.3.6.1.3 Level 2 SR 3.3.6.1.4 SR 3.3.6.1.5 SR 3.3.6.1.6
- b. Drywell 1,2,3 2 H SR 3.3.6.1.1 1.88 psig Pressure - High SR 3.3.6.1.3 SR 3.3.6.1.4 SR 3.3.6.1.5 SR 3.3.6.1.6
- c. Standby Gas Treatment 1,2,3 1 F SR 3.3.6.1.3 1.0 x 10-2 (SGT) System Exhaust SR 3.3.6.1.5 µCi/cc with Radiation - High SR 3.3.6.1.6 time delay 18.5 seconds
- d. Manual Initiation 1,2,3 4 G SR 3.3.6.1.6 NA
- 3. Reactor Core Isolation Cooling (RCIC) System Isolation
- a. RCIC Steam Line 1,2,3 1 F SR 3.3.6.1.1 175.6 inches Flow - High SR 3.3.6.1.3 water SR 3.3.6.1.4 SR 3.3.6.1.5 SR 3.3.6.1.6
- b. RCIC Steam Line 1,2,3 1 F SR 3.3.6.1.3 13 seconds Flow - Timer SR 3.3.6.1.5 SR 3.3.6.1.6
- c. RCIC Steam Supply 1,2,3 2 F SR 3.3.6.1.1 70 psia Pressure - Low SR 3.3.6.1.3 SR 3.3.6.1.4 SR 3.3.6.1.5 SR 3.3.6.1.6
- d. RCIC Turbine Exhaust 1,2,3 2 F SR 3.3.6.1.1 20 psig Diaphragm SR 3.3.6.1.3 Pressure - High SR 3.3.6.1.4 SR 3.3.6.1.5 SR 3.3.6.1.6
- e. RCIC Equipment Room 1,2,3 1 F SR 3.3.6.1.1 140.5F Area SR 3.3.6.1.3 Temperature - High SR 3.3.6.1.5 SR 3.3.6.1.6
- f. RCIC Steam Line 1,2,3 1 F SR 3.3.6.1.1 140.5F Tunnel SR 3.3.6.1.3 Temperature - High SR 3.3.6.1.5 SR 3.3.6.1.6 (continued)
NMP2 3.3.6.1-8 Amendment 91, 186
Primary Containment Isolation Instrumentation 3.3.6.1 Table 3.3.6.1-1 (page 3 of 5)
Primary Containment Isolation Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED OTHER CHANNELS FROM SPECIFIED PER TRIP REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS SYSTEM ACTION C.1 REQUIREMENTS VALUE
- 3. RCIC System Isolation (continued)
- g. RHR Equipment Room 1,2,3 1 per area F SR 3.3.6.1.1 144.5F Area SR 3.3.6.1.3 Temperature - High SR 3.3.6.1.5 SR 3.3.6.1.6
- h. Reactor Building Pipe 1,2,3 1 per area F SR 3.3.6.1.1 Chase Area SR 3.3.6.1.3 Temperature - High SR 3.3.6.1.5 SR 3.3.6.1.6 El. 319 ft. 144.5F El. 292 ft. 140.5F El. 266 ft. 140.5F El. 227 ft. 140.5F
- i. Reactor Building 1,2,3 1 per area F SR 3.3.6.1.1 134F General Area SR 3.3.6.1.3 Temperature - High SR 3.3.6.1.5 SR 3.3.6.1.6
- j. Area 1,2,3 1 F SR 3.3.6.1.3 1.15 seconds Temperature - Timer SR 3.3.6.1.5 SR 3.3.6.1.6
- k. RCIC/RHR Steam 1,2,3 1 F SR 3.3.6.1.1 40.73 inches Flow - High SR 3.3.6.1.3 water SR 3.3.6.1.4 SR 3.3.6.1.5 SR 3.3.6.1.6
- l. RCIC/RHR Steam 1,2,3 1 F SR 3.3.6.1.3 13 seconds Flow - Timer SR 3.3.6.1.5 SR 3.3.6.1.6
- m. Manual Initiation 1,2,3 1(c) G SR 3.3.6.1.6 NA
- 4. Reactor Water Cleanup (RWCU) System Isolation
- a. Differential 1,2,3 1 F SR 3.3.6.1.1 165.5 gpm Flow - High SR 3.3.6.1.3 SR 3.3.6.1.5 SR 3.3.6.1.6
- b. Differential 1,2,3 1 F SR 3.3.6.1.3 47 seconds Flow - Timer SR 3.3.6.1.5 SR 3.3.6.1.6 (continued)
(c) Only inputs into one of the two trip systems.
NMP2 3.3.6.1-9 Amendment 91, 186
Primary Containment Isolation Instrumentation 3.3.6.1 Table 3.3.6.1-1 (page 4 of 5)
Primary Containment Isolation Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED OTHER CHANNELS FROM SPECIFIED PER TRIP REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS SYSTEM ACTION C.1 REQUIREMENTS VALUE
- 4. RWCU System Isolation (continued)
- c. Heat Exchanger Room 1,2,3 1 F SR 3.3.6.1.1 140.5F Temperature - High SR 3.3.6.1.3 SR 3.3.6.1.5 SR 3.3.6.1.6
- d. Pump Room 1,2,3 1 per room F SR 3.3.6.1.1 Temperature - High SR 3.3.6.1.3 SR 3.3.6.1.5 SR 3.3.6.1.6 Pump Room A 144.5F Pump Room B 159.5F
- e. Reactor Building Pipe 1,2,3 1 per area F SR 3.3.6.1.1 Chase Area SR 3.3.6.1.3 Temperature - High SR 3.3.6.1.5 SR 3.3.6.1.6 El. 319 ft. 144.5F El. 292 ft. 140.5F El. 266 ft. 140.5F El. 227 ft. 140.5F
- f. Reactor Vessel Water 1,2,3 2 F SR 3.3.6.1.1 101.8 inches Level - Low Low, Level SR 3.3.6.1.3 2 SR 3.3.6.1.4 SR 3.3.6.1.5 SR 3.3.6.1.6
- g. SLC System Initiation 1,2 1 I SR 3.3.6.1.6 NA
- h. Manual Initiation 1,2,3 4 G SR 3.3.6.1.6 NA
- a. RHR Equipment Room 3 1 per area F SR 3.3.6.1.1 144.5F Area SR 3.3.6.1.3 Temperature - High SR 3.3.6.1.5 SR 3.3.6.1.6 (continued)
NMP2 3.3.6.1-10 Amendment 91, 186
Primary Containment Isolation Instrumentation 3.3.6.1 Table 3.3.6.1-1 (page 5 of 5)
Primary Containment Isolation Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED OTHER CHANNELS FROM SPECIFIED PER TRIP REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS SYSTEM ACTION C.1 REQUIREMENTS VALUE
- b. Reactor Vessel Water 3 2 J SR 3.3.6.1.1 157.8 inches Level - Low, Level 3 SR 3.3.6.1.3 SR 3.3.6.1.4 SR 3.3.6.1.5 SR 3.3.6.1.6
- c. Reactor Vessel 1,2,3 2 F SR 3.3.6.1.1 148 psig Pressure - High SR 3.3.6.1.3 SR 3.3.6.1.4 SR 3.3.6.1.5 SR 3.3.6.1.6
- d. Reactor Building Pipe 3 1 per area F SR 3.3.6.1.1 Chase Area SR 3.3.6.1.3 Temperature - High SR 3.3.6.1.5 SR 3.3.6.1.6 El. 319 ft. 144.5F El. 292 ft. 140.5F El. 266 ft. 140.5F El. 227 ft. 140.5F
- e. Reactor Building 3 1 per area F SR 3.3.6.1.1 134F General Area SR 3.3.6.1.3 Temperature - High SR 3.3.6.1.5 SR 3.3.6.1.6
- f. Manual Initiation 1,2,3 4 G SR 3.3.6.1.6 NA NMP2 3.3.6.1-11 Amendment 91, 168, 186
Mechanical Vacuum Pump Isolation Instrumentation 3.3.7.2 3.3 INSTRUMENTATION 3.3.7.2 Mechanical Vacuum Pump Isolation Instrumentation LCO 3.3.7.2 Four channels of Main Steam Line Radiation - High Function for the mechanical vacuum pump isolation shall be OPERABLE.
APPLICABILITY: MODES 1 and 2 with any mechanical vacuum pump in service and any main steam line not isolated.
ACTIONS
NOTE -------------------------------------------------------------
Separate Condition entry is allowed for each channel.
CONDITION REQUIRED ACTION COMPLETION TIME A. One or more channels A.1 Restore channel to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> inoperable. OPERABLE status.
NOTE---------
Not applicable when trip capability is not maintained.
In accordance with the Risk Informed Completion Time Program OR A.2 ------------NOTE------------
Not applicable if inoperable channel is the result of an inoperable isolation valve or mechanical vacuum pump breaker.
(continued)
NMP2 3.3.7.2-1 Amendment 91, 186
Mechanical Vacuum Pump Isolation Instrumentation 3.3.7.2 ACTIONS (continued)
CONDITION REQUIRED ACTION COMPLETION TIME A. (continued) Place channel in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> trip.
NOTE---------
Not applicable when trip capability is not maintained.
In accordance with the Risk Informed Completion Time Program B. Mechanical vacuum pump B.1 Restore isolation 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> isolation capability capability.
not maintained.
C. Required Action and C.1 Isolate the 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> associated Completion associated mechanical Time not met. vacuum pump(s).
OR C.2 Remove the associated 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> mechanical vacuum pump breaker(s) from service.
OR C.3 Isolate the main 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> steam lines.
OR C.4 Be in MODE 3. 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> NMP2 3.3.7.2-2 Amendment 91, 152, 186
Mechanical Vacuum Pump Isolation Instrumentation 3.3.7.2 SURVEILLANCE REQUIREMENTS
NOTE -------------------------------------------------------------
When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> provided mechanical vacuum pump isolation capability is maintained.
SURVEILLANCE FREQUENCY SR 3.3.7.2.1 Perform CHANNEL CHECK. In accordance with the Surveillance Frequency Control Program SR 3.3.7.2.2 Perform CHANNEL FUNCTIONAL TEST. In accordance with the Surveillance Frequency Control Program SR 3.3.7.2.3 Perform CHANNEL CALIBRATION. The In accordance Allowable Value shall be 3.6 x full with the power background. Surveillance Frequency Control Program SR 3.3.7.2.4 Perform LOGIC SYSTEM FUNCTIONAL TEST In accordance including isolation valve and mechanical with the vacuum pump breakers actuation. Surveillance Frequency Control Program NMP2 3.3.7.2-3 Amendment 91, 152, 186
LOP Instrumentation 3.3.8.1 3.3 INSTRUMENTATION 3.3.8.1 Loss of Power (LOP) Instrumentation LCO 3.3.8.1 The LOP instrumentation for each Function in Table 3.3.8.1-1 shall be OPERABLE.
APPLICABILITY: MODES 1, 2, and 3, When the associated diesel generator (DG) is required to be OPERABLE by LCO 3.8.2, "AC Sources - Shutdown."
ACTIONS
NOTE -------------------------------------------------------------
Separate Condition entry is allowed for each channel.
CONDITION REQUIRED ACTION COMPLETION TIME A. One or more required A.1 Place channel in 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> channels inoperable. trip.
NOTE---------
Not applicable when trip capability is not maintained.
In accordance with the Risk Informed Completion Time Program B. Required Action and B.1 Declare associated DG Immediately associated Completion inoperable.
Time not met.
NMP2 3.3.8.1-1 Amendment 91, 186
ECCS - Operating 3.5.1 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS), RPV WATER INVENTORY CONTROL, AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM 3.5.1 ECCS - Operating LCO 3.5.1 Each ECCS injection/spray subsystem and the Automatic Depressurization System (ADS) function of six safety/relief valves shall be OPERABLE.
APPLICABILITY: MODE 1, MODES 2 and 3, except ADS valves are not required to be OPERABLE with reactor steam dome pressure 150 psig.
ACTIONS
NOTE --------------------------------------------------------------------
LCO 3.0.4.b is not applicable to HPCS.
CONDITION REQUIRED ACTION COMPLETION TIME A. One low pressure ECCS A.1 Restore low pressure 7 days injection/spray ECCS injection/spray subsystem inoperable. subsystem to OPERABLE OR status.
In accordance with the Risk Informed Completion Time Program B. High Pressure Core B.1 Verify by administrative Immediately Spray (HPCS) System means RCIC System is inoperable. OPERABLE when RCIC is required to be OPERABLE.
AND B.2 Restore HPCS System 14 days to OPERABLE status.
OR In accordance with the Risk Informed Completion Time Program (continued)
NMP2 3.5.1-1 Amendment 91, 109, 168, 174, 186
ECCS - Operating 3.5.1 ACTIONS (continued)
CONDITION REQUIRED ACTION COMPLETION TIME C. Two ECCS injection C.1 Restore one ECCS 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> subsystems inoperable. injection/spray subsystem to OPERABLE OR OR status.
In accordance with One ECCS injection and the Risk Informed one ECCS spray Completion Time subsystem inoperable. Program D. Required Action and D.1 Be in MODE 3. 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> associated Completion Time of Condition A, AND B, or C not met.
D.2 Be in MODE 4. 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> E. One required ADS valve E.1 Restore ADS valve to 14 days inoperable. OPERABLE status.
OR In accordance with the Risk Informed Completion Time Program F. One required ADS valve F.1 Restore ADS valve to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> inoperable. OPERABLE status.
OR AND In accordance with One low pressure ECCS the Risk Informed injection/spray Completion Time subsystem inoperable. Program OR F.2 Restore low pressure 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> ECCS injection/spray subsystem to OPERABLE OR status.
In accordance with the Risk Informed Completion Time Program (continued)
NMP2 3.5.1-2 Amendment 91, 186
RCIC System 3.5.3 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS), RPV WATER INVENTORY CONTROL, AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM 3.5.3 RCIC System LCO 3.5.3 The RCIC System shall be OPERABLE.
APPLICABILITY: MODE 1, MODES 2 and 3 with reactor steam dome pressure > 150 psig.
ACTIONS
NOTE--------------------------------------------------------------------
LCO 3.0.4.b is not applicable to RCIC.
CONDITION REQUIRED ACTION COMPLETION TIME A. RCIC System A.1 Verify by Immediately inoperable. administrative means High Pressure Core Spray System is OPERABLE.
AND A.2 Restore RCIC System 14 days to OPERABLE status.
OR In accordance with the Risk Informed Completion Time Program B. Required Action and B.1 Be in MODE 3. 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> associated Completion Time not met. AND B.2 Reduce reactor steam 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> dome pressure to 150 psig.
NMP2 3.5.3-1 Amendment 91, 109, 168, 186
Primary Containment Air Locks 3.6.1.2 ACTIONS (continued)
CONDITION REQUIRED ACTION COMPLETION TIME C. One or more primary C.1 Initiate action to Immediately containment air locks evaluate primary inoperable for reasons containment overall other than Condition A leakage rate per or B. LCO 3.6.1.1, using current air lock test results.
AND C.2 Verify a door is 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> closed in the affected air lock.
AND C.3 Restore air lock to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> OPERABLE status.
NOTE---------
Not applicable if leakage exceeds limits or if loss of function.
In accordance with the Risk Informed Completion Time Program D. Required Action and D.1 Be in MODE 3. 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> associated Completion Time not met. AND D.2 Be in MODE 4. 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> NMP2 3.6.1.2-4 Amendment 91, 186
PCIVs 3.6.1.3 3.6 CONTAINMENT SYSTEMS 3.6.1.3 Primary Containment Isolation Valves (PCIVs)
LCO 3.6.1.3 Each PCIV and each Secondary Containment Bypass Leakage Valve shall be OPERABLE.
APPLICABILITY: MODES 1, 2, and 3, When associated instrumentation is required to be OPERABLE per LCO 3.3.6.1, "Primary Containment Isolation Instrumentation."
ACTIONS
NOTES ------------------------------------------------------------
- 1. Penetration flow paths may be unisolated intermittently under administrative controls.
- 2. Separate Condition entry is allowed for each penetration flow path.
- 3. Enter applicable Conditions and Required Actions for systems made inoperable by PCIVs.
- 4. Enter applicable Conditions and Required Actions of LCO 3.6.1.1, "Primary Containment," when PCIV leakage results in exceeding overall containment leakage rate acceptance criteria.
CONDITION REQUIRED ACTION COMPLETION TIME A. -------------NOTE-------------- A.1 Isolate the affected 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> except Only applicable to penetration flow path for main steam penetration flow paths by use of at least line with two or more one closed and PCIVs. de-activated OR
automatic valve, closed manual valve, In accordance One or more blind flange, or with the Risk penetration flow paths check valve with flow Informed with one PCIV through the valve Completion Time inoperable except due secured. Program to leakage not within limit. AND (continued)
NMP2 3.6.1.3-1 Amendment 91, 156, 186
PCIVs 3.6.1.3 ACTIONS (continued)
CONDITION REQUIRED ACTION COMPLETION TIME A. (continued) AND 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> for main steam line OR In accordance with the Risk Informed Completion Time Program A.2 -------------NOTES-----------
- 1. Isolation devices in high radiation areas may be verified by use of administrative means.
- 2. Isolation devices that are locked, sealed, or otherwise secured may be verified by use of administrative means.
Verify the affected Once per 31 days penetration flow path following isolation is isolated. for isolation devices outside primary containment AND Prior to entering MODE 2 or 3 from MODE 4 (continued)
NMP2 3.6.1.3-2 Amendment 91, 186
PCIVs 3.6.1.3 ACTIONS (continued)
CONDITION REQUIRED ACTION COMPLETION TIME A. (continued) if primary containment was de-inerted while in MODE 4, if not performed within the previous 92 days, for isolation devices inside primary containment B. -------------NOTE-------------- B.1 Isolate the affected 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Only applicable to penetration flow path penetration flow paths by use of at least with two or more one closed and PCIVs. de-activated
automatic valve, closed manual valve, One or more or blind flange.
penetration flow paths with two or more PCIVs inoperable except due to leakage not within limit.
C. -------------NOTE-------------- C.1 Isolate the affected 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> except Only applicable to penetration flow path for excess flow penetration flow paths by use of at least check valves with only one PCIV. one closed and (EFCVs) and
de-activated penetrations automatic valve, with a closed One or more closed manual valve, system penetration flow paths or blind flange.
with one PCIV AND inoperable except due to leakage not within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> for limit. EFCVs and penetrations with a closed system AND (continued)
NMP2 3.6.1.3-3 Amendment 91, 186
PCIVs 3.6.1.3 ACTIONS (continued)
CONDITION REQUIRED ACTION COMPLETION TIME D. (continued) D.3 Perform SR 3.6.1.3.6 Once per 92 days for the resilient seal purge supply valves closed to comply with Required Action D.1.
E. One or more E.1 Isolate the affected 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> penetration flow paths penetration flow path with one or more by use of at least OR containment purge one closed and exhaust valves not de-activated ---------NOTE---------
within purge valve automatic valve, Not applicable if leakage limits. closed manual valve, there is a loss of or blind flange. function.
AND In accordance with the Risk Informed Completion Time Program (continued)
NMP2 3.6.1.3-7 Amendment 91, 186
PCIVs 3.6.1.3 ACTIONS (continued)
CONDITION REQUIRED ACTION COMPLETION TIME E. (continued) E.2 -----------NOTES----------
- 1. Isolation devices in high radiation areas may be verified by use of administrative means.
- 2. Isolation devices that are locked, sealed, or otherwise secured may be verified by use of administrative means.
Verify the affected Once per 31 days penetration flow path following isolation is isolated. for isolation devices outside containment AND Prior to entering MODE 2 or 3 from MODE 4 if primary containment was de-inerted while in MODE 4, if not performed within the previous 92 days, for isolation devices inside containment AND (continued)
NMP2 3.6.1.3-8 Amendment 91, 186
PCIVs 3.6.1.3 ACTIONS (continued)
CONDITION REQUIRED ACTION COMPLETION TIME E. (continued) E.3 Perform SR 3.6.1.3.6 Once per 92 days for the resilient following isolation seal purge exhaust valves closed to comply with Required Action E.1.
F. Required Action and F.1 Be in MODE 3. 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> associated Completion Time of Condition A, AND B, C, D, or E not met in MODE 1, 2, or 3. F.2 Be in MODE 4. 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> G. Required Action and G.1 Initiate action to Immediately associated Completion restore valve(s) to Time of Condition A, OPERABLE status.
B, C, D, or E not met .
for PCIV(s) required to be OPERABLE during MODE 4 or 5.
NMP2 3.6.1.3-9 Amendment 91, 168, 186
RHR Drywell Spray 3.6.1.6 3.6 CONTAINMENT SYSTEMS 3.6.1.6 Residual Heat Removal (RHR) Drywell Spray System LCO 3.6.1.6 Two RHR drywell spray subsystems shall be OPERABLE.
APPLICABILITY: MODES 1, 2, and 3.
ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One RHR drywell spray A.1 Restore RHR drywell 7 days subsystem inoperable. spray subsystem to OPERABLE status. OR In accordance with the Risk Informed Completion Time Program B. Two RHR drywell spray B.1 Restore one RHR 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> subsystems inoperable. drywell spray subsystem to OPERABLE status.
C. Required Action and C.1 Be in MODE 3. 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> associated Completion Time not met. AND C.2 Be in MODE 4. 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> NMP2 3.6.1.6-1 Amendment 91, 186
Suppression Chamber-to-Drywell Vacuum Breakers 3.6.1.7 3.6 CONTAINMENT SYSTEMS 3.6.1.7 Suppression Chamber-to-Drywell Vacuum Breakers LCO 3.6.1.7 Each suppression chamber-to-drywell vacuum breaker shall be OPERABLE.
APPLICABILITY: MODES 1, 2, and 3.
ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One line with one or A.1 Restore the vacuum 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> more suppression breaker(s) to chamber-to-drywell OPERABLE status. OR vacuum breakers inoperable for In accordance with opening. the Risk Informed Completion Time Program B. -------------NOTE------------- B.1 Close the open vacuum 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Separate Condition breaker.
entry is allowed for each suppression chamber-to-drywell vacuum breaker line.
One or more lines with one suppression chamber-to-drywell vacuum breaker not closed.
(continued)
NMP2 3.6.1.7-1 Amendment 91, 186
RHR Suppression Pool Cooling 3.6.2.3 3.6 CONTAINMENT SYSTEMS 3.6.2.3 Residual Heat Removal (RHR) Suppression Pool Cooling LCO 3.6.2.3 Two RHR suppression pool cooling subsystems shall be OPERABLE.
APPLICABILITY: MODES 1, 2, and 3.
ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One RHR suppression A.1 Restore RHR 7 days pool cooling subsystem suppression pool inoperable. cooling subsystem to OR OPERABLE status.
In accordance with the Risk Informed Completion Time Program B. Two RHR suppression B.1 Restore one RHR 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> pool cooling suppression pool subsystems inoperable. cooling subsystem to OPERABLE status.
C. Required Action and C.1 Be in MODE 3. 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> associated Completion Time not met. AND C.2 Be in MODE 4. 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> NMP2 3.6.2.3-1 Amendment 91, 186
RHR Suppression Pool Spray 3.6.2.4 3.6 CONTAINMENT SYSTEMS 3.6.2.4 Residual Heat Removal (RHR) Suppression Pool Spray LCO 3.6.2.4 Two RHR suppression pool spray subsystems shall be OPERABLE.
APPLICABILITY: MODES 1, 2, and 3.
ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One RHR suppression A.1 Restore RHR 7 days pool spray subsystem suppression pool inoperable. spray subsystem to OR OPERABLE status.
In accordance with the Risk Informed Completion Time Program B. Two RHR suppression B.1 Restore one RHR 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> pool spray subsystems suppression pool inoperable. spray subsystem to OPERABLE status.
C. Required Action and C.1 Be in MODE 3. 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> associated Completion Time not met. AND C.2 Be in MODE 4. 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> NMP2 3.6.2.4-1 Amendment 91, 186
SW System and UHS 3.7.1 3.7 PLANT SYSTEMS 3.7.1 Service Water (SW) System and Ultimate Heat Sink (UHS)
LCO 3.7.1 a. Division 1 and 2 SW subsystems and UHS shall be OPERABLE.
AND b.1 Four OPERABLE SW pumps shall be in operation when water temperature of one or two SW subsystem supply headers is 82°F.
OR b.2 Five OPERABLE SW pumps shall be in operation when water temperature of one or two SW subsystem supply headers is > 82°F and 84°F.
APPLICABILITY: MODES 1, 2, and 3.
ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One SW supply header A.1 Open the SW supply 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> cross connect valve header cross connect inoperable. valve.
AND A.2 Restore the SW supply 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> header cross connect valve to OPERABLE OR status.
In accordance with the Risk Informed Completion Time Program B. One or more non-safety B.1 Isolate the affected 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> related SW flow paths non-safety related SW with one SW isolation flow path(s).
valve inoperable.
(continued)
NMP2 3.7.1-1 Amendment 91, 119, 186
SW System and UHS 3.7.1 ACTIONS (continued)
CONDITION REQUIRED ACTION COMPLETION TIME C. One SW subsystem C.1 Restore SW subsystem 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> inoperable for reasons to OPERABLE status.
other than Conditions OR A and B.
In accordance with the Risk Informed Completion Time Program D. One division of intake D.1 Restore intake deicer 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> deicer heaters heater division to inoperable. OPERABLE status. OR In accordance with the Risk Informed Completion Time Program E. One required SW pump E.1 Restore required SW 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> not in operation. pump to operation.
OR In accordance with the Risk Informed Completion Time Program F. Two or more required F.1 Restore all but one 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> SW pumps not in required SW pump to operation. operation. OR
NOTE---------
Not applicable when loss of function can occur.
In accordance with the Risk Informed Completion Time Program (continued)
NMP2 3.7.1-2 Amendment 91, 119, 186
SW System and UHS 3.7.1 ACTIONS (continued)
CONDITION REQUIRED ACTION COMPLETION TIME G. Required Action and -----------------NOTE------------------
associated Completion Enter applicable Conditions Time of Condition A, and Required Actions of B, C, D, E, or F not LCO 3.4.9, "Residual Heat met. Removal (RHR) Shutdown Cooling System - Hot OR Shutdown," for RHR Shutdown Cooling subsystem(s) made Both SW subsystems inoperable by SW System or inoperable for reasons UHS.
other than --------------------------------------------
Conditions A, B, and C. G.1 Be in MODE 3. 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> OR AND UHS inoperable G.2 Be in MODE 4. 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> for reasons other than Condition D.
NMP2 3.7.1-3 Amendment 91, 119, 186
SW System and UHS 3.7.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.1.1 -------------------------------- NOTE ------------------------------
Not required to be met if SR 3.7.1.5 and SR 3.7.1.8 satisfied.
Verify the water temperature of the intake In accordance with tunnels is 38°F. the Surveillance Frequency Control Program SR 3.7.1.2 Verify the water level in the SW pump In accordance with intake bay is 233.1 ft. the Surveillance Frequency Control Program SR 3.7.1.3 Verify the water temperature of In accordance with each SW subsystem supply header is 84°F. the Surveillance Frequency Control Program AND 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> when supply header water temperature is 78°F SR 3.7.1.4 Verify each required SW pump is in In accordance with operation. the Surveillance Frequency Control Program (continued)
NMP2 3.7.1-4 Amendment 91, 119, 152, 186
SW System and UHS 3.7.1 SURVEILLANCE REQUIREMENTS (continued)
SURVEILLANCE FREQUENCY SR 3.7.1.5 -------------------------------- NOTE ------------------------------
Not required to be met if SR 3.7.1.1 satisfied.
Verify, for each intake deicer heater In accordance with division, the current of each required the Surveillance heater feeder cable is within the limit. Frequency Control Program SR 3.7.1.6 -------------------------------- NOTE ------------------------------
Isolation of flow to individual components does not render SW System inoperable.
Verify each SW subsystem manual, power In accordance with operated, and automatic valve in the flow the Surveillance path servicing safety related systems or Frequency Control components, that is not locked, sealed, or Program otherwise secured in position, is in the correct position.
SR 3.7.1.7 Verify each SW subsystem actuates on an In accordance with actual or simulated initiation signal. the Surveillance Frequency Control Program SR 3.7.1.8 -------------------------------- NOTE ------------------------------
Not required to be met if SR 3.7.1.1 satisfied.
Verify, for each intake deicer heater In accordance with division, the resistance of each required the Surveillance heater feeder cable and associated heater Frequency Control elements is within the limit. Program NMP2 3.7.1-5 Amendment 91, 152, 186
Main Turbine Bypass System 3.7.5 3.7 PLANT SYSTEMS 3.7.5 Main Turbine Bypass System LCO 3.7.5 The Main Turbine Bypass System shall be OPERABLE.
OR LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)," limits for an inoperable Main Turbine Bypass System, as specified in the COLR, are made applicable.
APPLICABILITY: THERMAL POWER 23% RTP.
ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Requirements of the A.1 Satisfy the 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> LCO not met. requirements of the LCO. OR In accordance with the Risk Informed Completion Time Program B. Required Action and B.1 Reduce THERMAL POWER 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> associated Completion to < 23% RTP.
Time not met.
SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.5.1 Perform a system functional test. In accordance with the Surveillance Frequency Control Program SR 3.7.5.2 Verify the TURBINE BYPASS SYSTEM RESPONSE In accordance with TIME is within limits. the Surveillance Frequency Control Program NMP2 3.7.5-1 Amendment 91, 140, 152, 186
AC Sources - Operating 3.8.1 ACTIONS (continued)
CONDITION REQUIRED ACTION COMPLETION TIME A. (continued) A.2 Declare required 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> from feature(s) with no discovery of no offsite power offsite power available inoperable to one division when the redundant concurrent with required feature(s) inoperability are inoperable. of redundant required feature(s)
AND A.3 Restore required 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> offsite circuit to OPERABLE status. OR In accordance with the Risk Informed Completion Time Program AND 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> from discovery of both HPCS and Low Pressure Core Spray (LPCS) Systems with no offsite power OR In accordance with the Risk Informed Completion Time Program B. One required DG B.1 Perform SR 3.8.1.1 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> inoperable. for OPERABLE required offsite circuit(s). AND Once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> thereafter AND (continued)
NMP2 3.8.1-2 Amendment 91, 138, 159, 186
AC Sources - Operating 3.8.1 ACTIONS (continued)
CONDITION REQUIRED ACTION COMPLETION TIME B. (continued) B.2 Declare required 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> from feature(s), supported discovery of by the inoperable DG, Condition B inoperable when the concurrent with redundant required inoperability feature(s) are of redundant inoperable. required feature(s)
AND B.3.1 Determine OPERABLE 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> DG(s) are not inoperable due to common cause failure.
OR B.3.2 Perform SR 3.8.1.2 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for OPERABLE DG(s).
AND B.4 Restore required DG 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> from to OPERABLE status. discovery of an inoperable Division 3 DG OR In accordance with the Risk Informed Completion Time Program AND 14 days OR In accordance with the Risk Informed Completion Time Program (continued)
NMP2 3.8.1-3 Amendment 91, 138, 159, 186
AC Sources - Operating 3.8.1 ACTIONS (continued)
CONDITION REQUIRED ACTION COMPLETION TIME C. Two required offsite C.1 Declare required 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> from circuits inoperable. feature(s) inoperable discovery of when the redundant Condition C required feature(s) concurrent with are inoperable. inoperability of redundant required feature(s)
AND C.2 Restore one required 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> offsite circuit to OPERABLE status. OR In accordance with the Risk Informed Completion Time Program D. One required offsite ------------------NOTE-------------------
circuit inoperable. Enter applicable Conditions and Required Actions of AND LCO 3.8.8, "Distribution Systems - Operating," when One required DG Condition D is entered with inoperable. no AC power source to any division.
D.1 Restore required 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> offsite circuit to OPERABLE status. OR OR In accordance with the Risk Informed Completion Time Program D.2 Restore required DG 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> to OPERABLE status.
OR In accordance with the Risk Informed Completion Time Program (continued)
NMP2 3.8.1-4 Amendment 91, 186
DC Sources - Operating 3.8.4 3.8 ELECTRICAL POWER SYSTEMS 3.8.4 DC Sources - Operating LCO 3.8.4 The Division 1, Division 2, and Division 3 DC electrical power subsystems shall be OPERABLE.
APPLICABILITY: MODES 1, 2, and 3.
ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Division 1 or 2 DC A.1 Restore Division 1 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> electrical power and 2 DC electrical subsystem inoperable. power subsystems to OR OPERABLE status.
In accordance with the Risk Informed Completion Time Program B. Division 3 DC B.1 Declare High Pressure Immediately electrical power Core Spray System subsystem inoperable. inoperable.
C. Required Action and C.1 Be in MODE 3. 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> associated Completion Time not met. AND C.2 Be in MODE 4. 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> NMP2 3.8.4-1 Amendment 91, 186
Inverters - Operating 3.8.7 3.8 ELECTRICAL POWER SYSTEMS 3.8.7 Inverters - Operating LCO 3.8.7 The Division 1 and Division 2 emergency uninterruptible power supply (UPS) inverters shall be OPERABLE.
APPLICABILITY: MODES 1, 2, and 3.
ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One emergency UPS A.1 -----------NOTE--------------
inverter inoperable. Enter applicable Conditions and Required Actions of LCO 3.8.8, Distribution Systems - Operating with any 120 VAC uninterruptible panel de-energized.
Restore emergency UPS 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> inverters to OPERABLE status. OR In accordance with the Risk Informed Completion Time Program B. Required Action and B.1 Be in MODE 3. 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> associated Completion Time not met. AND B.2 Be in MODE 4. 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> NMP2 3.8.7-1 Amendment 91, 186
Distribution Systems - Operating 3.8.8 3.8 ELECTRICAL POWER SYTEMS 3.8.8 Distribution Systems - Operating LCO 3.8.8 The following AC and DC electrical power distribution subsystems shall be OPERABLE:
- a. Division 1 and Division 2 AC electrical power distribution subsystems;
- b. Division 1 and Division 2 120 VAC uninterruptible electrical power distribution subsystems;
- c. Division 1 and Division 2 DC electrical power distribution subsystems; and
APPLICABILITY: MODES 1, 2, and 3.
ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One or both Division 1 A.1 Restore Division 1 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> and 2 AC electrical and 2 AC electrical power distribution power distribution OR subsystems inoperable. subsystem(s) to OPERABLE status. ---------NOTE---------
Not applicable when loss of function can occur.
In accordance with the Risk Informed Completion Time Program (continued)
NMP2 3.8.8-1 Amendment 91, 159, 186
Distribution Systems - Operating 3.8.8 ACTIONS (continued)
CONDITION REQUIRED ACTION COMPLETION TIME B. One or both Division 1 B.1 Restore Division 1 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> and 2 120 VAC and 2 120 VAC uninterruptible uninterruptible OR electrical power electrical power distribution distribution ---------NOTE---------
subsystems inoperable. subsystem(s) to Not applicable when OPERABLE status. loss of function can occur.
In accordance with the Risk Informed Completion Time Program C. One or both Division 1 C.1 Restore Division 1 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and 2 DC electrical and 2 DC electrical power distribution power distribution OR subsystems inoperable. subsystem(s) to OPERABLE status. ---------NOTE---------
Not applicable when loss of function can occur.
In accordance with the Risk Informed Completion Time Program D. Required Action and D.1 Be in MODE 3. 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> associated Completion Time of Condition A, AND B, or C not met.
D.2 Be in MODE 4. 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> E. One or both Division 3 E.1 Declare High Pressure Immediately AC and DC electrical Core Spray System power distribution inoperable.
subsystems inoperable.
(continued)
NMP2 3.8.8-2 Amendment 91, 159, 186
Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.13 Control Room Envelope Habitability Program (continued)
- e. The quantitative limits on unfiltered air inleakage into the CRE. These limits shall be stated in a manner to allow direct comparison to the unfiltered air inleakage measured by the testing described in paragraph c.
The unfiltered air inleakage limit for radiological challenges is the inleakage flow rate assumed in the licensing basis analyses of DBA consequences.
Unfiltered air inleakage limits for hazardous chemicals must ensure that exposure of CRE occupants to these hazards will be within the assumptions in the licensing basis.
- f. The provisions of SR 3.0.2 are applicable to the Frequencies for assessing CRE habitability, determining CRE unfiltered inleakage, and measuring CRE pressure and assessing the CRE boundary as required by paragraphs c and d, respectively.
5.5.14 Surveillance Frequency Control Program This program provides controls for the Surveillance Frequencies. The Program shall ensure that Surveillance Requirements specified in the Technical Specifications are performed at intervals sufficient to assure the associated Limiting Conditions for Operation are met.
- a. The Surveillance Frequency Control Program shall contain a list of Frequencies of the Surveillance Requirements for which the Frequency is controlled by the program.
- b. Changes to the Frequency listed in the Surveillance Frequency Control Program shall be made in accordance with NEI 04-10, Risk-Informed Method for Control of Surveillance Frequency, Revision 1.
- c. The provision of Surveillance Requirements 3.0.2 and 3.0.3 are applicable to the Frequencies established in the Surveillance Frequency Control Program.
(continued)
NMP2 5.5-13 Amendment 126, 152, 186
Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.15 Risk Informed Completion Time Program This program provides controls to calculate a Risk Informed Completion Time (RICT) and must be implemented in accordance with NEI 06-09-A, Revision 0, "Risk-Managed Technical Specifications (RMTS) Guidelines."
The program shall include the following:
- a. The RICT may not exceed 30 days;
- b. A RICT may only be utilized in MODE 1, 2;
- c. When a RICT is being used, any change to the plant configuration, as defined in NEI 06-09-A, Appendix A, must be considered for the effect on the RICT.
- 1. For planned changes, the revised RICT must be determined prior to implementation of the change in configuration.
- 2. For emergent conditions, the revised RICT must be determined within the time limits of the Required Action Completion Time (i.e., not the RICT) or 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after the plant configuration change, whichever is less.
- 3. Revising the RICT is not required if the plant configuration change would lower plant risk and would result in a longer RICT.
- d. For emergent conditions, if the extent of condition evaluation for inoperable structures, systems, or components (SSCs) is not complete prior to exceeding the Completion Time, the RICT shall account for the increased possibility of common cause failure (CCF) by either:
- 2. Risk Management Actions (RMAs) not already credited in the RICT calculation shall be implemented that support redundant or diverse SSCs that perform the function(s) of the inoperable SSCs, and, if practicable, reduce the frequency of initiating events that challenge the function(s) performed by the inoperable SSCs.
- e. The risk assessment approaches and methods shall be acceptable to the NRC. The plant PRA shall be based on the as-built, as-operated, and maintained plant; and reflect the operating experience at the plant, as specified in Regulatory Guide 1.200, Revision 2. Methods to assess the risk from extending the Completion Times must be PRA methods used to support License Amendment No. 186, or other methods approved by the NRC for generic use; and any change in the PRA methods to assess risk that are outside these approval boundaries require prior NRC approval.
NMP2 5.5-14 Amendment 186
SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 186 TO RENEWED FACILITY OPERATING LICENSE NO. NPF-69 NINE MILE POINT NUCLEAR STATION, LLC LONG ISLAND LIGHTING COMPANY EXELON GENERATION COMPANY, LLC.
NINE MILE POINT NUCLEAR STATION, UNIT 2 DOCKET NO. 50-410
1.0 INTRODUCTION
By application dated October 31, 2019 (Reference 1), as supplemented by letters dated December 12, 2019 (Reference 2), August 28, 2020 (Reference 3), October 2, 2020 (two letters) (Reference 4) and (Reference 5), October 22, 2020 (Reference 6), and January 7, 2021 (Reference 7), Exelon Generation Company, LLC (the licensee) submitted a license amendment request (LAR) for Nine Mile Point Nuclear Station Unit 2 (Nine Mile Point 2).
The supplemental letters dated December 12, 2019, August 28, 2020, October 2, 2020 (two letters), October 22, 2020, and January 7, 2021, provided additional information that clarified the application, did not expand the scope of the application as originally noticed, and did not change the U.S. Nuclear Regulatory Commission (NRC or the Commission) staffs initial proposed no significant hazards consideration determination published in the Federal Register on February 11, 2020 (85 FR 7792).
The proposed amendment would revise technical specification (TS) requirements to permit the use of risk-informed completion times (RICTs) for actions to be taken when limiting conditions for operation (LCOs) are not met. The proposed changes are based on Technical Specifications Task Force (TSTF) Traveler TSTF-505, Revision 2, Provide Risk-Informed Extended Completion Times - RITSTF Initiative 4b, dated July 2, 2018 (Reference 8). The NRC issued a final model safety evaluation (SE) approving TSTF-505, Revision 2, on November 21, 2018 (Reference 9). The licensee has proposed variations from the TS changes described in TSTF-505, Revision 2.
During May 2020, the NRC staff and contractors from the Pacific Northwest National Laboratory participated in a regulatory audit. The NRC staff performed the audit to ascertain the information needed to support its review of the application and develop requests for additional information (RAIs), as needed. By electronic mail dated July 30, 2020 (Reference 10),
Enclosure 2
September 2, 2020 (Reference 11), September 28, 2020 (two emails) (Reference 12) and (Reference 13), and December 15, 2020 (Reference 14), the NRC sent the licensee RAIs. By letters dated August 28, 2020, October 2, 2020 (two letters), October 22, 2020, and January 7, 2021, the licensee responded to the RAIs.
2.0 REGULATORY EVALUATION
2.1 DESCRIPTION
OF RISK-INFORMED COMPLETION TIME PROGRAM The TS LCOs are the lowest functional capability or performance levels of equipment required for safe operation of the facility. When an LCO is not met, the licensee must shut down the reactor or follow any remedial or required action (e.g., testing, maintenance, or repair activity) permitted by the TSs until the condition can be met. The remedial actions associated with an LCO contain conditions that typically describe the ways in which the requirements of the LCO can fail to be met. Specified with each stated condition are required action(s) and completion times (CTs). The CTs are referred to as the front stops in the context of this SE. For certain conditions, the TS require exiting the mode of applicability of an LCO (i.e., shut down the reactor).
2.2 DESCRIPTION
OF TS CHANGES The licensees submittal requested approval to add a RICT Program to the Administrative Controls section of the TSs, and modify selected CTs to permit extending the CTs, provided risk is assessed and managed as described in Nuclear Energy Institute (NEI) topical report NEI 06-09, Revision 0-A, Risk-Informed Technical Specifications Initiative 4b: Risk-Managed Technical Specifications (RMTS) Guidelines, dated October 2012 (Reference 15), and the associated final safety evaluation (SE) dated May 17, 2007 (Reference 16). The licensees application for the changes proposed to use NEI 06-09, Revision 0-A, and included documentation regarding the technical adequacy of the probabilistic risk assessment (PRA) models for the RICT Program, consistent with the guidance of Regulatory Guide (RG) 1.200, Revision 2, An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities, dated March 2009 (Reference 17).
2.2.1 TS 1.0, Use and Application Example 1.3-8, would be added to TS 1.3, Completion Times, and reads as follows:
EXAMPLE 1.3-8 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One A.1 Restore subsystem 7 days subsystem to OPERABLE inoperable. status. OR In accordance with the Risk Informed Completion Time Program B. Required B.1 Be in MODE 3. 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> Action and associated AND Completion Time not B.2 Be in MODE 5. 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.
met.
When a subsystem is declared inoperable, Condition A is entered.
The 7 day Completion Time may be applied as discussed in Example 1.3-2. However, the licensee may elect to apply the Risk Informed Completion Time Program which permits calculation of a Risk Informed Completion Time (RICT) that may be used to complete the Required Action beyond the 7 day Completion Time.
The RICT cannot exceed 30 days. After the 7 day Completion Time has expired, the subsystem must be restored to OPERABLE status within the RICT or Condition B must also be entered.
The Risk Informed Completion Time Program requires recalculation of the RICT to reflect changing plant conditions. For planned changes, the revised RICT must be determined prior to implementation of the change in configuration. For emergent conditions, the revised RICT must be determined within the time limits of the Required Action Completion Time (i.e., not the RICT) or 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after the plant configuration change, whichever is less.
If the 7 day Completion Time clock of Condition A has expired and subsequent changes in plant condition result in exiting the applicability of the Risk Informed Completion Time Program without restoring the inoperable subsystem to OPERABLE status, Condition B is also entered and the Completion Time clocks for Required Actions B.1 and B.2 start.
If the RICT expires or is recalculated to be less than the elapsed time since the Condition was entered and the inoperable subsystem has not been restored to OPERABLE status, Condition B is also entered and the Completion Time clocks for Required Actions B.1 and B.2 start. If the inoperable subsystems are restored to OPERABLE status after Condition B is entered, Conditions A and B are exited, and therefore, the required actions of Condition B may be terminated.
2.2.2 TS 5.5.15, Risk Informed Completion Time Program TS 5.5.15, which describes the RICT Program, would be added to the TS and read as follows:
Risk Informed Completion Time Program This program provides controls to calculate a Risk Informed Completion Time (RICT) and must be implemented in accordance with NEI 06-09, Revision 0-A, Risk-Managed Technical Specifications (RMTS) Guidelines.
The program shall include the following:
- a. The RICT may not exceed 30 days;
- b. A RICT may only be utilized in MODE 1, 2;
- c. When a RICT is being used, any change to the plant configuration, as defined in NEI 06-09-A, Appendix A, must be considered for the effect on the RICT.
- 1. For planned changes, the revised RICT must be determined prior to implementation of the change in configuration.
- 2. For emergent conditions, the revised RICT must be determined within the time limits of the Required Action Completion Time (i.e., not the RICT) or 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after the plant configuration change, whichever is less.
- 3. Revising the RICT is not required if the plant configuration change would lower plant risk and would result in a longer RICT.
- d. For emergent conditions, if the extent of condition evaluation for inoperable structures, systems, or components (SSCs) is not complete prior to exceeding the Completion Time, the RICT shall account for the increased possibility of common cause failure (CCF) by either:
- 2. Risk Management Actions (RMAs) not already credited in the RICT calculation shall be implemented that support redundant or diverse SSCs that perform the function(s) of the inoperable SSCs, and, if
practicable, reduce the frequency of initiating events that challenge the function(s) performed by the inoperable SSCs.
- e. The risk assessment approaches and methods shall be acceptable to the NRC. The plant PRA shall be based on the as-built, as operated, and maintained plant; and reflect the operating experience at the plant, as specified in Regulatory Guide 1.200, Revision 2. Methods to assess the risk from extending the Completion Times must be PRA methods used to support License Amendment No. [186], or other methods approved by the NRC for generic use; and any change in the PRA methods to assess risk that are outside these approval boundaries require prior NRC approval.
2.2.3 Application of the RICT Program to Existing LCOs and Action Statements The typical CT is modified by the application of the RICT Program as shown in the following example. The changed portion is indicated in italics.
ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One subsystem A.1 Restore subsystem 7 days inoperable. to OPERABLE status. OR In accordance with the Risk Informed Completion Time Program Where necessary, conforming changes are made to CTs to make them accurate following use of a RICT. For example, most TSs have requirements to close/isolate containment isolation devices if one or more containment penetrations have inoperable devices. This is followed by a requirement to periodically verify the penetration is isolated. By adding the flexibility to use a RICT to determine a time to isolate the penetration, the periodic verifications must then be based on the time following isolation.
Individual LCO required actions and CTs modified by the proposed change are identified below.
TS 3.1.7 Standby Liquid Control (SLC) System Action A.1 With one SLC subsystem inoperable, restore SLC subsystem to operable status within 7 days or in accordance with the Risk Informed Completion Time Program.
TS 3.5.1 ECCS [Emergency Core Cooling System] - Operating Action A.1 With one low pressure ECCS injection/spray subsystem inoperable, restore low pressure ECCS injection/spray subsystem to operable status within 7 days or in accordance with the Risk Informed Completion Time Program.
Action B.2 With High Pressure Core Spray (HPCS) System inoperable, restore HPCS system to operable status within 14 days or in accordance with the Risk Informed Completion Time Program.
Action C.1 With two ECCS injections subsystems inoperable or one ECCS injection and one ECCS spray subsystem inoperable, restore one ECCS injection/spray subsystem to operable status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or in accordance with the Risk Informed Completion Time Program.
Action E.1 With one required ADS [automatic depressurization system] valve inoperable, restore ADS valve to operable status within 14 days or in accordance with the Risk Informed Completion Time Program.
Action F.1 With one required ADS valve inoperable and one low pressure ECCS injection/spray subsystem inoperable, restore ADS valve to operable status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or in accordance with the Risk Informed Completion Time Program.
Action F.2 Restore low pressure ECCS injection/spray subsystem to operable status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or in accordance with the Risk Informed Completion Time Program.
TS 3.5.3 RCIC [Reactor Core Isolation Cooling] System Action A.2 With RCIC System inoperable, restore RCIC system to operable status within 14 days or in accordance with the Risk Informed Completion Time Program.
TS 3.6.1.2 Primary Containment Air Locks Action C.3 With one or more primary containment air locks inoperable for reasons other than Condition A or B, restore air lock to operable status within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or in accordance with the Risk Informed Completion Time Program.
Note Not applicable if leakage exceeds limits or if loss of function.
TS 3.6.1.3 Primary Containment Isolation Valves (PCIVs)
Action A.1 With one or more penetration flow paths with one PCIV inoperable except due to leakage not within limit, isolate the affected penetration flow path by use of at least one closed and de-activated automatic valve, closed manual valve, blind flange, or check valve with flow through the valve secured within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> except for main steam line or in accordance with
the Risk Informed Completion Time Program, and within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> for main steam line or in accordance with the Risk Informed Completion Time Program.
Action A.2 The CT for the required action to verify the affected penetration flow path is isolated, has been modified by adding the words following isolation after once per 31 days.
Action E.1 With one or more penetration flow paths with one or more containment purge exhaust valves not within purge valve leakage limits, isolate the affected penetration flow path by use of at least one closed and de-activated automatic valve, closed manual valve, or blind flange within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or in accordance with the Risk Informed Completion Time Program.
Note Not applicable if there is a loss of function.
Action E.2 The CT for the required action to verify the affected penetration flow path is isolated, has been modified by adding the words following isolation after once per 31 days.
Action E.3 The CT for the required action to verify the affected penetration flow path is isolated, has been modified by adding the words following isolation after once per 92 days.
TS 3.6.1.6 Residual Heat Removal (RHR) Drywell Spray System Action A.1 With one RHR drywell spray subsystem inoperable, restore RHR drywell spray subsystem to operable status within 7 days or in accordance with the Risk Informed Completion Time Program.
TS 3.6.1.7 Suppression Chamber-to-Drywell Vacuum Breakers Action A.1 With one line with one or more suppression chamber-to-drywell vacuum breakers inoperable for opening, restore the vacuum breaker(s) to operable status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or in accordance with the Risk Informed Completion Time Program.
TS 3.6.2.3 Residual Heat Removal (RHR) Suppression Pool Cooling Action A.1 With one RHR suppression pool cooling subsystem inoperable, restore RHR suppression pool cooling subsystem to operable status within 7 days or in accordance with the Risk Informed Completion Time Program.
TS 3.6.2.4 Residual Heat Removal (RHR) Suppression Pool Spray Action A.1 With one RHR suppression pool spray subsystem inoperable, restore RHR suppression pool spray subsystem to operable status within 7 days or in accordance with the Risk Informed Completion Time Program.
TS 3.7.1 Service Water (SW) System and Ultimate Heat Sink (UHS)
Action C.1 With one SW subsystem inoperable for reasons other than Conditions A and B, restore SW subsystem to operable status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or in accordance with the Risk Informed Completion Time Program.
TS 3.7.5 Main Turbine Bypass System Action A.1 With requirements of the LCO not met, satisfy the requirements of the LCO within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> or in accordance with the Risk Informed Completion Time Program.
TS 3.8.1 AC [Alternating Current] Sources - Operating Action A.3 With one required offsite circuit inoperable, restore required offsite circuit to operable status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or in accordance with the Risk Informed Completion Time Program and within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> from discovery of both HPCS and Low Pressure Core Spray (LPCS) Systems with no offsite power or in accordance with the Risk Informed Completion Time Program.
Action C.2 With two required offsite circuits inoperable, restore one required offsite circuit to operable status within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or in accordance with the Risk Informed Completion Time Program.
Action D.1 With one required offsite circuit inoperable and one required DG [diesel generator] inoperable, restore required offsite circuit to operable status within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> or in accordance with the Risk Informed Completion Time Program.
Action D.2 Restore required DG to operable status within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> or in accordance with the Risk Informed Completion Time Program.
TS 3.8.4 DC [Direct Current] Sources - Operating Action A.1 With a Division 1 or 2 DC electrical power subsystem inoperable, restore Division 1 and 2 DC electrical power subsystems to operable status within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> or in accordance with the Risk Informed Completion Time Program.
TS 3.8.7 Inverters - Operating Action A.1 With one emergency UPS [uninterruptible power supply] inverter inoperable, restore emergency UPS inverters to operable status within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or in accordance with the Risk Informed Completion Time Program.
TS 3.8.8 Distribution Systems - Operating Action A.1 With one or both Division 1 and 2 AC electrical power distribution subsystems inoperable, restore Division 1 and 2 AC electrical power
distribution subsystem(s) to operable status within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> or in accordance with the Risk Informed Completion Time Program.
Note Not applicable when loss of function can occur.
Action B.1 With one or both Division 1 and 2 120 VAC [Volts alternating current]
uninterruptible electrical power distribution subsystems inoperable, restore Division 1 and 2 120 VAC uninterruptible electrical power distribution subsystem(s) to operable status within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> or in accordance with the Risk Informed Completion Time Program.
Note Not applicable when loss of function can occur.
Action C.1 With one or both Division 1 and 2 DC electrical power distribution subsystems inoperable, restore Division 1 and 2 DC electrical power distribution subsystem(s) to operable status within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> or in accordance with the Risk Informed Completion Time Program.
Note Not applicable when loss of function can occur.
2.2.4 Variations from TSTF-505, Revision 2 2.2.4.1 Application of the RICT Program to Modified Action Statements The following Conditions are modified to permit the application of a RICT:
TS 3.3.1.1 Reactor Protection System (RPS) Instrumentation Action A.1 With one or more required channels inoperable, place channel in trip within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> or in accordance with the Risk Informed Completion Time Program.
Note Not applicable when trip capability is not maintained.
Action A.2 Place associated trip system in trip within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> or in accordance with the Risk Informed Completion Time Program.
Note Not applicable when trip capability is not maintained.
Action B.1 With one or more functions with one or more required channels inoperable in both trip systems, place channel in one trip system in trip within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> or in accordance with the Risk Informed Completion Time Program.
Note Not applicable when trip capability is not maintained.
Action B.2 Place one trip system in trip within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> or in accordance with the Risk Informed Completion Time Program.
Note Not applicable when trip capability is not maintained.
TS 3.3.2.2 Feedwater System and Main Turbine High Water Level Trip Instrumentation Action A.1 With one feedwater system and main turbine high water level trip channel inoperable, place channel in trip within 7 days or in accordance with the Risk Informed Completion Time Program.
Note Not applicable when trip capability is not maintained.
TS 3.3.4.1 End of Cycle Recirculation Pump Trip (EOC-RPT) Instrumentation Action A.1 With one or more required channels inoperable, restore channel to operable status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or in accordance with the Risk Informed Completion Time Program.
Note Not applicable when trip capability is not maintained.
Action A.2 Place channel in trip within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or in accordance with the Risk Informed Completion Time Program.
Note Not applicable when trip capability is not maintained.
TS 3.3.4.2 Anticipated Transient Without Scram Recirculation Pump Trip (ATWS-RPT)
Instrumentation Action A.1 With one or more channels inoperable, restore channel to operable status within 14 days or in accordance with the Risk Informed Completion Time Program.
Note Not applicable when trip capability is not maintained.
Action A.2 Place channel in trip within 14 days or in accordance with the Risk Informed Completion Time Program.
Note Not applicable when trip capability is not maintained.
TS 3.3.5.1 ECCS Instrumentation Action B.3.1 As required by Required Action A.1 and referenced in Table 3.3.5.1-1, place channel in trip within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> for Functions 1.a, 1.d, 2.a, and 2.d and within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for Functions other than Functions 1.a, 1.d, 2.a, and 2.d or in accordance with the Risk Informed Completion Time Program Note Not applicable when trip capability is not maintained.
Action C.2 As required by Required Action A.1 and referenced in Table 3.3.5.1-1, restore channel to operable status within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or in accordance with the Risk Informed Completion Time Program.
Note Not applicable when trip capability is not maintained.
Action D.2.1 As required by Required Action A.1 and referenced in Table 3.3.5.1-1, place channel in trip within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or in accordance with the Risk Informed Completion Time Program.
Note Not applicable when trip capability is not maintained.
Action E.2 As required by Required Action A.1 and referenced in Table 3.3.5.1-1, restore channel to operable status within 7 days or in accordance with the Risk Informed Completion Time Program.
Note Not applicable when trip capability is not maintained.
Action F.2 As required by Required Action A.1 and referenced in Table 3.3.5.1-1, place channel in trip within 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> from discovery of inoperable channel concurrent with HPCS or reactor core isolation cooling (RCIC) inoperable or in accordance with the Risk Informed Completion Time Program and
within 8 days or in accordance with the Risk Informed Completion Time Program.
Note Not applicable when trip capability is not maintained.
Action G.2 As required by Required Action A.1 and referenced in Table 3.3.5.1-1, restore channel to operable status within 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> from discovery of inoperable channel concurrent with HPCS or RCIC inoperable or in accordance with the Risk Informed Completion Time Program and within 8 days or in accordance with the Risk Informed Completion Time Program.
Note Not applicable when trip capability is not maintained.
TS 3.3.5.3 Reactor Core Isolation Cooling (RCIC) System Instrumentation Action B.2 As required by Required Action A.1 and referenced in Table 3.3.5.3-1, place channel in trip within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or in accordance with the Risk Informed Completion Time Program.
Note Not applicable when trip capability is not maintained.
Action D.2.1 As required by Required Action A.1 and referenced in Table 3.3.5.3-1, place channel in trip within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or in accordance with the Risk Informed Completion Time Program.
Note Not applicable when trip capability is not maintained.
TS 3.3.6.1 Primary Containment Isolation Instrumentation Action A.1 With one or more channels inoperable, place channel in trip within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> for Functions 2.b, 5.b, and 5.c or in accordance with the Risk Informed Completion Time Program and within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for Functions other than Functions 2.b, 5.b, and 5.c or in accordance with the Risk Informed Completion Time Program.
Note Not applicable when trip capability is not maintained.
TS 3.3.8.1 Loss of Power (LOP) Instrumentation Action A.1 With one or more required channels inoperable, place channel in trip within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> or in accordance with the Risk Informed Completion Time Program.
Note Not applicable when trip capability is not maintained.
TS 3.8.1 AC Sources - Operating Action B.4 With one required DG inoperable, restore required DG to operable status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> from discovery of an inoperable Division 3 DG or in accordance with the Risk Informed Completion Time Program and 14 days or in accordance with the Risk Informed Completion Time Program.
2.2.4.2 Application of the RICT to Additional Actions Requirements The following individual LCO actions and CTs identified below are modified by the proposed change to permit the application of a RICT and are in addition to those included in TSTF-505.
TS 3.3.7.2 Mechanical Vacuum Pump Isolation Instrumentation Action A.1 With one or more channels inoperable, restore channel to operable status within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> or in accordance with the Risk Informed Completion Time Program.
Note Not applicable when trip capability is not maintained.
Action A.2 Place channel in trip within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> or in accordance with the Risk Informed Completion Time Program.
Note Not applicable when trip capability is not maintained.
TS 3.7.1 Service Water (SW) System and Ultimate Heat Sink (UHS)
Action A.2 With one SW supply header cross connect valve inoperable, restore the SW supply header cross connect valve to operable status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or in accordance with the Risk Informed Completion Time Program.
Action D.1 With one division of intake deicer heaters inoperable, restore intake deicer heater division to operable status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or in accordance with the Risk Informed Completion Time Program.
Action E.1 With one required SW pump not in operation, restore required SW pump to operation within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or in accordance with the Risk Informed Completion Time Program.
Action F.1 With two or more required SW pumps not in operation, restore all but one required SW pump to operation within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> or in accordance with the Risk Informed Completion Time Program.
Note Not applicable when loss of function can occur.
2.3 REGULATORY REVIEW 2.3.1 Applicable Regulations The regulation under 10 CFR 50.36(c)(2) requires that TSs contain LCOs, which are the lowest functional capability or performance levels of equipment required for safe operation of the facility. When an LCO of a nuclear reactor is not met, the licensee shall shut down the reactor or follow any remedial action permitted by the TSs until the LCO can be met. Typically, the TSs require restoration of equipment in a timeframe commensurate with its safety significance, along with other engineering considerations. The regulation under 10 CFR 50.36(b) requires that TSs be derived from the analyses and evaluation included in the safety analysis report, and amendments thereto.
In determining whether the proposed TS remedial actions should be granted, the Commission will apply the reasonable assurance standards of 10 CFR 50.40(a) and 50.57(a)(3). The
regulation at 10 CFR 50.40(a) states that in determining whether to grant the licensing request, the Commission will be guided by, among other things, consideration about whether the processes to be performed, the operating procedures, the facility and equipment, the use of the facility, and other TSs, or the proposals, in regard to any of the foregoing collectively provide reasonable assurance that the applicant will comply with the regulations in this chapter, including the regulations in Part 20 of this chapter, and that the health and safety of the public will not be endangered.
The regulation under 10 CFR 50.36(c)(5) states that administrative controls are the provisions relating to organization and management, procedures, recordkeeping, review and audit, and reporting necessary to assure operation of the facility in a safe manner.
The regulation under 10 CFR 50.55a(h), Protection and safety systems, states that protection systems of nuclear power reactors of all types must meet the requirements specified in this paragraph.
Section 10 CFR 50.65, Requirements for monitoring the effectiveness of maintenance at nuclear power plants (i.e., the Maintenance Rule), requires licensees to monitor the performance or condition of SSCs against licensee-established goals in a manner sufficient to provide reasonable assurance that these SSCs are capable of fulfilling their intended functions.
The regulation under 10 CFR 50.65(a)(4) requires the assessment and management of the increase in risk that may result from a proposed maintenance activity.
2.3.2 Applicable Regulatory Guidance Revision 3 of RG 1.174, An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis, January 2018 (Reference 18),
describes an acceptable risk-informed approach for assessing the nature and impact of proposed permanent licensing basis changes by considering engineering issues and applying risk insights. This RG also provides risk acceptance guidelines for evaluating the results of such evaluations.
Revision 1 of RG 1.177, An Approach for Plant-Specific, Risk-Informed Decisionmaking:
Technical Specifications, May 2011 (Reference 19), describes an acceptable risk-informed approach specifically for assessing proposed TS changes. This RG identifies a three-tiered approach for a licensees evaluation of the risk associated with a proposed TS CT change, as follows.
Tier 1 assesses the risk impact of the proposed change in accordance with acceptance guidelines consistent with the Commissions Safety Goal Policy Statement, as documented in RG 1.174 and RG 1.177. The first tier assesses the impact on plant risk as expressed by the change in core damage frequency (CDF) and change in large early release frequency (LERF). It also evaluates plant risk while equipment covered by the proposed CT is out of service, as represented by incremental conditional core damage probability and incremental conditional large early release probability. Tier 1 also addresses PRA acceptability, including the technical adequacy of the licensees plant-specific PRA for the subject application.
Tier 2 identifies and evaluates any potential risk-significant plant equipment outage configurations that could result if equipment, in addition to that associated with the proposed license amendment, is removed from service simultaneously, or if other
risk-significant operational factors, such as concurrent system or equipment testing, are also involved. The purpose of this evaluation is to ensure that there are appropriate restrictions in place such that risk-significant plant equipment outage configurations will not occur when equipment associated with the proposed CT is implemented.
Tier 3 addresses the licensees Configuration Risk Management Program (CRMP) to ensure that adequate programs and procedures are in place for identifying risk-significant plant configurations resulting from maintenance or other operational activities and appropriate compensatory measures are taken to avoid risk-significant configurations that may not have been considered when the Tier 2 evaluation was performed. Compared with Tier 2, Tier 3 provides additional coverage to ensure risk-significant plant equipment outage configurations are identified in a timely manner and that the risk impact of out-of-service equipment is appropriately evaluated prior to performing any maintenance activity over extended periods of plant operation. Tier 3 guidance can be satisfied by the Maintenance Rule, which requires a licensee to assess and manage the increase in risk that may result from activities such as surveillance testing and corrective and preventive maintenance, subject to the guidance provided in RG 1.177, Section 2.3.7.1 and the adequacy of the licensees program and PRA model for this application. The CRMP ensures that equipment removed from service prior to or during the proposed extended CT will be appropriately assessed from a risk perspective.
RG 1.200, Revision 2, describes an acceptable approach for determining whether the PRA acceptability, in total or the parts that are used to support an application, is sufficient to provide confidence in the results, such that the PRA can be used in regulatory decisionmaking for light-water reactors. This RG provides guidance for assessing the technical adequacy of a PRA. Revision 2 of RG 1.200, endorses, with clarifications and qualifications, the use of the American Society of Mechanical Engineers (ASME)/American Nuclear Society (ANS) Standard, ASME/ANS RA-Sa-2009, Addenda to ASME RA-S-2008 Standard for Level 1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications (i.e.,
the PRA Standard) (Reference 20).
As discussed in RG 1.177, Revision 1, and RG 1.174, Revision 3, a risk-informed application should be evaluated to ensure that the proposed changes meet the following key principles:
- 1. The proposed change meets the current regulations unless it is explicitly related to a requested exemption;
- 2. The proposed change is consistent with the defense-in-depth philosophy;
- 3. The proposed change maintains sufficient safety margins;
- 4. When proposed changes result in an increase in risk, the increases should be small and consistent with the intent of the Commissions Safety Goal Policy Statement; and
- 5. The impact of the proposed change should be monitored using performance measurement strategies.
NEI 06-09, Revision 0-A, provides an acceptable methodology for extending existing CTs and thereby delaying exiting the operational mode of applicability or taking required actions if risk is assessed and managed within the limits and programmatic requirements established by a RICT
Program. By letter dated May 17, 2007, the NRC endorsed NEI 06-09, Revision 0-A, as acceptable for referencing by licensees proposing to amend their TS to implement RMTS to the extent specified and under the limitations delineated in the topical report and in the associated NRC staffs SE.
3.0 TECHNICAL EVALUATION
The licensees adoption of TSTF-505, Revision 2, provides for the addition of a RICT Program to the Administrative Controls section of the TS and modifies selected required action CTs to permit extending the CTs, provided risk is assessed and managed as described in NEI 06-09, Revision 0-A. In accordance with NEI 06-09, Revision 0-A, PRA methods are used to justify each extension to a required action CT based on the specific plant configuration that exists at the time of the applicability of the required action and are updated when plant conditions change. The licensees application for the changes proposed in the LAR included documentation regarding the technical adequacy of the PRA models used in the real-time risk model, consistent with the requirements of RG 1.200.
Most TS identify one or more conditions for which the LCO may not be met, to permit a licensee to perform required testing, maintenance, or repair activities. Each condition has an associated required action for restoration of the LCO or for other actions, each with some fixed time interval, referred to as the CT, which identifies the time interval permitted to complete the required action. Upon expiration of the CT, the licensee is required to shut down the reactor or follow the required action(s) stated in the actions requirements. The RICT Program provides the necessary administrative controls to permit extension of CTs and thereby delay reactor shutdown or required actions, if risk is assessed and managed within specified limits and programmatic requirements. The specified safety function or performance level of TS required equipment is unchanged, and the required action(s), including the requirement to shut down the reactor, are also unchanged; only the CTs for the required actions are extended by the RICT Program.
3.1 REVIEW OF KEY PRINCIPLES RG 1.177, Revision 1, and RG 1.174, Revision 3, identify five key safety principles to be applied to risk-informed changes to the TSs. Each of these principles are addressed in NEI 06-09, Revision 0-A. The NRC staffs evaluation of the licensees proposed use of RICTs against these key safety principles is discussed below.
3.1.1 Key Principle 1: Evaluation of Compliance with Current Regulations As stated in 10 CFR 50.36(c)(2):
Limiting conditions for operation are the lowest functional capability or performance levels of equipment required for safe operation of the facility. When a limiting condition for operation of a nuclear reactor is not met, the licensee shall shut down the reactor or follow any remedial action permitted by the technical specifications until the condition can be met.
When the necessary redundancy is not maintained (e.g., one train of a two-train system is inoperable), the TSs permit a limited period of time to restore the inoperable train to operable status and/or take other remedial measures. If these actions are not completed within the CT, the TSs normally require that the plant exit the mode of applicability for the LCO. With one train
of a two-train system inoperable, the TS safety function is accomplished by the remaining operable train. In the current TSs, the CT is specified as a fixed time period (termed the front stop). The addition of the option to determine the CT in accordance with the RICT Program would allow an evaluation to determine a configuration-specific CT. The evaluation would be done in accordance with the methodology prescribed in NEI 06-09, Revision 0-A, and TS 5.5.15. The RICT is limited to a maximum of 30 days (termed the back stop). The CTs in the current TSs were established using experiential data, risk insights, and engineering judgment. The RICT Program provides the necessary administrative controls to permit extension of CTs and thereby delay reactor shutdown or required actions, if risk is assessed and managed appropriately within specified limits and programmatic requirements.
When the necessary redundancy is not maintained, and the system loses the capability to perform its safety function(s) without any further failures (e.g., two trains of a two-train system are inoperable), the plant must exit the mode of applicability for the LCO, or take remedial actions, as specified in the TSs. A configuration-specific RICT may not be used in this condition. With the incorporation of the RICT Program, the required performance levels of equipment specified in LCOs are not changed. Only the required CT for the required actions are modified by the RICT Program.
3.1.1.1 Key Principle 1 Conclusions Based on the discussion provided above, the NRC staff finds that the proposed changes meet the first key safety principle of RG 1.174, Revision 3, and RG 1.177, Revision 1.
3.1.2 Key Principle 2: Evaluation of Defense-in-Depth Defense-in-depth is an approach to designing and operating nuclear facilities that prevents and mitigates accidents that release radiation or hazardous materials. The key is creating multiple independent and redundant layers of defense to compensate for potential human and mechanical failures so that no single layer, no matter how robust, is exclusively relied upon.
Defense-in-depth includes the use of access controls, physical barriers, redundant and diverse key safety functions, and emergency response measures.
As discussed throughout RG 1.174, consistency with the defense-in-depth philosophy is maintained by the following:
Preserve a reasonable balance among the layers of defense Preserve adequate capability of design features without an overreliance on programmatic activities as compensatory measures Preserve system redundancy, independence, and diversity commensurate with the expected frequency and consequences of challenges to the system, including consideration of uncertainty Preserve adequate defense against potential CCFs Maintain multiple fission product barriers Preserve sufficient defense against human errors Continue to meet the intent of the plants design criteria
The proposed change represents a robust technical approach that preserves a reasonable balance among redundant and diverse key safety functions that provide avoidance of core damage, avoidance of containment failure, and consequence mitigation. The three-tiered approach to risk-informed TS CT changes provides additional assurance that defense-in-depth will not be significantly impacted by such changes to the licensing basis. The licensee is proposing no changes to the design of the plant or any operating parameter, no new operating configurations, and no new changes to the design basis in the proposed changes to the TS.
The effect of the proposed changes when implemented will be that the RICT Program will allow CTs to vary based on the risk significance of the given plant configuration (i.e., the equipment out of service at any given time) provided that the system(s) retain(s) the capability to perform the applicable safety function(s) without any further failures (e.g., one train of a two-train system is inoperable). A configuration-specific RICT may not be used if the system has lost the capability to perform its safety function(s). These restrictions on inoperability of all required trains of a system ensure that consistency with the defense-in-depth philosophy is maintained by following existing guidance when the capability to perform TS safety function(s) is lost.
The proposed RICT Program uses plant-specific operating experience for component reliability and availability data. Thus, the allowances permitted by the RICT Program are directly reflective of actual component performance in conjunction with component risk significance. In some cases, the RICT Program may use compensatory actions to reduce calculated risk in some configurations. Where credited in the PRA, these actions are incorporated into station procedures or work instructions and have been modeled using appropriate human reliability considerations. Application of the RICT Program determines the risk significance of plant configurations. It also permits the operator to identify the equipment that has the greatest effect on the existing configuration risk. With this information, the operator can manage the out-of-service duration and determine the consequences of removing additional equipment from service.
The application of the RICT Program places high value on key safety functions and works to ensure they remain a top priority over all plant conditions. The RICT will be applied to extend CTs on key electrical power distribution systems. Failures in electrical power distribution systems can simultaneously affect multiple safety functions; therefore, potential degradation to defense-in-depth during the extended CTs is discussed further below.
3.1.2.1 Use of Compensatory Measures to Retain Defense-in-Depth Application of the RICT Program provides a structure to assist the operator in identifying effective compensatory actions for various plant maintenance configurations to maintain and manage acceptable risk levels. NEI 06-09, Revision 0-A, addresses potential compensatory actions and RMA measures by stating, in generic terms, that compensatory measures may include but are not limited to the following:
Reduce the duration of risk-sensitive activities Remove risk-sensitive activities from the planned work scope Reschedule work activities to avoid high risk-sensitive equipment outages or maintenance states that result in high-risk plant configurations
Accelerate the restoration of out-of-service equipment Determine and establish the safest plant configuration NEI 06-09, Revision 0-A, states that compensatory measures shall be initiated when the PRA calculated RMA time (RMAT) is exceeded, or for preplanned maintenance for which the RMAT is expected to be exceeded, RMAs shall be implemented at the earliest appropriate time.
Therefore, quantitative risk analysis, the qualitative considerations, and the prohibition on loss of all trains of a required system assure a reasonable balance of defense-in-depth is maintained to ensure protection of public health and safety. The NRC staff finds that this proposed change meets the second key safety principle of RG 1.177 and is, therefore, acceptable.
3.1.2.2 Evaluation of Electrical Power Systems According to Revision 22 of the Nine Mile Point 2 Updated Safety Analysis Report, dated February 14, 2017 (USAR) (Reference 21), the plant is designed such that the safety functions are maintained assuming a single failure within the electrical power system. By incorporating an electrical power supply perspective, this concept is further reflected in a number of principal design criteria for Nine Mile Point 2. Single failure requirements are typically suspended for the time that a plant is not meeting an LCO (i.e., in an action statement).
As described in the USAR, Nine Mile Point 2s electric power system provides the power sources for the unit auxiliary and service loads during normal operation of the plant, plant startup and normal shutdown, and for the engineered safety feature (ESF) systems during normal, abnormal, and design-basis accident (DBA) conditions. The electric power system consists of the offsite power system, the onsite AC power system, and the DC power system.
The offsite power system provides a power source for operation of the onsite emergency AC power system under normal, abnormal, or DBA conditions and plant startup and shutdown. The offsite power system also serves as the backup power source for the normal onsite AC power system. The onsite AC power system distributes AC power to the unit auxiliary and service loads and instrumentation and control system loads. The onsite AC power system includes the onsite emergency AC power system which feeds safety-related loads, and the onsite normal or nonsafety-related AC power system which feeds all nonsafety-related loads. The DC power system provides DC power to protective relaying control, instrumentation, and other DC loads.
This system includes the emergency DC power system which feeds safety-related DC loads, and the normal or nonsafety-related DC power system which feeds nonsafety-related DC loads.
In this SE, the NRC staffs review focuses on the offsite power system, the onsite emergency AC power system, the emergency DC power system, and the AC and DC distribution systems that are affected by the proposed changes.
The licensee has requested to use the RICT Program to extend the existing CT for the following TS 3.8, Electrical Power Systems, conditions. The NRC staffs evaluation of the proposed changes considered a number of potential plant conditions allowed by the proposed RICTs.
The staff also considered the available redundant or diverse means to respond to various plant conditions. In these evaluations, the NRC staff examined the safety significance of different plant conditions resulting in both shorter and longer CTs. The plant conditions evaluated are discussed in more detail below.
The NRC staff reviewed information pertaining to the proposed electrical power systems TS conditions in the application, the USAR, TS Bases, and applicable TS LCOs to verify the capability of the affected electrical power systems to perform their safety functions (assuming no
additional failures) is maintained. To achieve that objective, the staff verified whether each proposed TS conditions design success criteria (DSC) reflect the redundant or absolute minimum electrical power source/subsystem/component required to be operable by the LCOs to support the safety functions necessary to mitigate postulated DBAs, safely shut down the reactor, and maintain the reactor in a safe shutdown condition. The NRC staff further reviewed the remaining credited power source/equipment to verify whether the proposed TS condition satisfies its DSC. In conjunction with reviewing the remaining credited power source/equipment, the NRC staff considered supplemental electrical power sources/equipment (not necessarily required by the LCOs and can be either safety or non-safety related) that are/is available at Nine Mile Point 2 and capable of performing the same safety function of the inoperable electrical power source/equipment. In addition, the NRC staff reviewed the proposed RMA examples in 2 of the LAR for reasonable assurance that these RMAs are appropriate to monitor and control risk and to ensure adequate defense-in-depth.
3.1.2.2.1 TS 3.8.1 - AC Sources - Operating 3.1.2.2.1.1 TS 3.8.1 Condition A - One Required Offsite Circuit Inoperable In the LAR, the licensee requested to use the RICT Program to extend the existing CT of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> for TS 3.8.1 Condition A, Required Action A.3. The NRC staff notes that the proposed second CT above is a variation from TSTF-505 Revision 2. In the letter dated August 28, 2020, the licensee stated that the current TS addresses the multiple electrical alignments available for the HPCS system, which is allowed to be aligned to either offsite circuit Line 5 or offsite circuit Line 6. The LPCS can only be aligned to Line 5. Depending on which offsite circuit is lost and the alignment of the HPCS system, either or both systems may be impacted. The 24-hour required CT places the additional restriction into the TS to recognize the potential to lose offsite capability for both injection systems simultaneously. This unique system design characteristic is a variance from the boiling-water reactor (BWR) 4 and BWR6 standard TSs and therefore is a variation to TSTF-505, Revision 2. The licensee further stated that the PRA fully models these alignments and is capable of calculating a RICT in the event the LPCS and HPCS are without AC power.
In Table E1-2 of Enclosure 1 of the LAR, the licensee stated that the RICT estimate for TS 3.8.1.A is 101 hours0.00117 days <br />0.0281 hours <br />1.669974e-4 weeks <br />3.84305e-5 months <br />. According to Table E1-1 in Enclosure 1 of the LAR, the DSC for TS 3.8.1 Condition A is one offsite power source.
As described in the USAR, the offsite power system consists of two 115-kilovolt (kV) circuits from two separate offsite power sources. The circuits terminate at the same switchyard and are connected to two separate reserve station service transformers (SSTs) that feed separate and independent divisions of the onsite emergency power system. The offsite power system provides a reliable source of power for operation of the onsite emergency AC power system under normal, abnormal, or DBA conditions and plant startup and shutdown, and serves as the backup source of power for the normal onsite AC power system. The emergency AC power system is normally energized from offsite power sources via the SSTs or auxiliary boiler transformer. In case of a loss of offsite power (LOOP), this system is energized by the emergency DGs (EDGs). Each offsite power circuit has adequate capacity and capability to supply power to the associated safety-related loads under all conditions of plant operation.
The NRC staff finds that the licensee adequately addressed the variation to TSTF-505, Revision 2, to which the PRA fully models the unique alignments between the offsite circuits and LPCS and HPCS systems and is capable of calculating the RICT in the event the LPCS and
HPCS are without AC power. The staff notes that in this design configuration, during the entry of the RICT Program for TS 3.8.1 Condition A, (i.e., one required offsite circuit is inoperable),
the Nine Mile Point 2 onsite emergency AC power system has the capability to access the remaining offsite circuit. In case of LOOP, the onsite emergency AC power system has the capability to access three EDGs. Thus, the NRC staff finds that the DSC is met and the function of TS 3.8.1, which is to ensure availability of the required AC power to shut down the reactor and maintain it in a safe shutdown condition after an anticipated operational occurrence (AOO) or a postulated DBA, is maintained. The NRC staff reviewed the RMA examples for TS 3.8.1 Condition A and found that these RMAs are consistent with NEI 06-09, Revision 0-A, and that these RMAs are appropriate to monitor and control risk and to ensure adequate defense-in-depth.
3.1.2.2.1.2 TS 3.8.1 Condition B - One Required DG Inoperable The licensee has requested to use the RICT Program to extend the existing CTs of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> (Division 3 DG) and 14 days (Divisions 1 and 2 DGs) for TS 3.8.1 Condition B, Required Action B.4.
In Table E1-2 of Enclosure 1 of the LAR, the licensee stated that the RICT estimate for TS 3.8.1.B is 524 hours0.00606 days <br />0.146 hours <br />8.664021e-4 weeks <br />1.99382e-4 months <br /> and this RICT estimate is applicable to Divisions 1 and 2 EDGs.
According to Table E1-1 of Enclosure 1 of the LAR, the DSC for TS 3.8.1 Condition B is one of two non-HPCS EDGs.
According to the USAR and TS Bases, the EDGs start automatically on receipt of a loss-of-coolant accident (LOCA) signal (i.e., low reactor water level signal; Level 1 for Division 1 and 2 EDGs, Level 2 for Division 3 EDG, or high drywell pressure signal) or an emergency bus degraded voltage or undervoltage signal. The Division 1 EDG starts upon receiving a LPCS or low pressure coolant injection (LPCI) initiation signal from Division 1 ECCS. The Division 2 EDG starts upon receiving an LPCI initiation signal from Division 2 ECCS. The Division 3 DG starts upon receiving an HPCS initiation signal from Division 3 ECCS. The emergency AC power system is normally energized from offsite power sources via the SSTs or auxiliary boiler transformer. In case of LOOP, this system is energized by the EDGs. For Divisions 1 and 2, in case of a LOOP or a LOOP concurrent with a LOCA, all loads on the respective 4.16 kV emergency bus, including the stub bus, are shed (except the 600 volt (V) load centers), and the emergency loads are sequentially started once power is restored. The Division 3 bus has no shedding or sequencing.
Furthermore, Section 8.1.4 of the USAR states, in part, The emergency AC power system is divided into three physically separate and electrically independent divisions designated Divisions I, II, and III. Any two out of these three divisions have the capacity and capability to safely shut down the reactor in case of a LOCA or any other DBA. The NRC staff notes that the DSC for TS 3.8.1.B in the LAR appears not consistent with the USAR. In the letter dated August 28, 2020, the licensee stated that the DSC for TS 3.8.1.B in Table E1-1 is revised to state Any two EDGs instead of one of two Non HPCS EDGs. The licensee further stated that the PRA success criteria for TS 3.8.1.[B] in Table E1-1 is revised to state Same as the HPCS EDG is explicitly credited in the DSC.
The NRC staff notes that in this design configuration, during the entry of the RICT Program for TS 3.8.1 Condition B (i.e., one required DG inoperable), either one of two offsite circuits or two remaining EDGs will be capable of supplying power to the ESF systems required to mitigate DBAs with offsite power available. In the event offsite power is lost concurrent with the DBAs,
the two remaining EDGs will be relied on to power the ESF systems required to mitigate the DBAs. Thus, the NRC staff finds that the DSC is met and the function of TS 3.8.1, which is to ensure availability of the required AC power to shut down the reactor and maintain it in a safe shutdown condition after an AOO or a postulated DBA, is maintained. The NRC staff reviewed the RMA examples for TS 3.8.1 Condition B and found that these RMAs are consistent with NEI 06-09, Revision 0-A, and that these RMAs are appropriate to monitor and control risk and to ensure adequate defense-in-depth.
3.1.2.2.1.3 TS 3.8.1 Condition C - Two Required Offsite Circuits Inoperable The licensee has requested to use the RICT Program to extend the existing CT of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for TS 3.8.1 Condition C, Required Action C.2. The proposed CT to restore one required offsite circuit to operable status is 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or in accordance with the RICT Program.
In Table E1-2 of Enclosure 1 of the LAR, the licensee stated that the RICT estimate for TS 3.8.1.C is 145 hours0.00168 days <br />0.0403 hours <br />2.397487e-4 weeks <br />5.51725e-5 months <br />. According to Table E1-1 of Enclosure 1 of the LAR, the DSC for TS 3.8.1 Condition C is one offsite source. The NRC staff notes that during the RICT Program entry for TS 3.8.1.C (i.e., both offsite circuits are inoperable), an offsite circuit would not be an available AC source to provide the necessary power to shut down the reactor and maintain it in safe condition.
According to the USAR, the emergency AC power system is normally energized from offsite power sources via the SSTs or auxiliary boiler transformer. In an event of LOOP, the emergency AC power system is energized by the EDGs. Section 8.3.1 of the USAR states that each EDG is capable of starting and accelerating to rated speed, in the required sequence, all the emergency shutdown loads and the ESF loads connected to it. In case of unavailability of any one EDG, the remaining two EDGs will be capable of feeding all the loads necessary for safe shutdown of the unit in the event of any DBA and LOOP. In the letter dated August 28, 2020, the licensee stated that ESF electrical loads automatically connected to the EDGs.
Regarding the EDG fuel capacity, Section 8.3.1 of the USAR states, Each standby diesel generator fuel oil system has a storage capacity suitable for operating each standby diesel generator for 7 days. Regarding the EDG cooling water capacity, Section 9.5.5.2 of the USAR states, in part, that the capacity of the jacket water system for each EDG adequately maintains the required pumps net positive suction head and makeup water for 7 days of continuous operation of the diesel engine at full load. The NRC staff notes that the 7-day fuel and cooling water supplies for each EDG support the proposed RICT estimate of 6 days.
The NRC staff notes that the Nine Mile Point 2 AC sources include offsite circuits and onsite EDGs. During normal operation, the offsite circuits supply power to the onsite Class 1E power distribution system, and the EDGs are on standby. In this design configuration, during the entry of the RICT Program for TS 3.8.1 Condition C (i.e., both offsite circuits are inoperable), the power for the Class 1E power distribution system is, by design, supplied by any two EDGs.
Thus, the NRC staff finds that the DSC is met and the function of TS 3.8.1, which is to ensure availability of the required power to shut down the reactor and maintain it in a safe shutdown condition after an AOO or a postulated DBA, is maintained. The NRC staff reviewed the RMA examples for TS 3.8.1 Condition C and found that these RMAs are consistent with NEI 06-09, Revision 0-A, and that these RMAs are appropriate to monitor and control risk and to ensure adequate defense-in-depth.
3.1.2.2.1.4 TS 3.8.1 Condition D - One Required Offsite Circuit and One Required DG Inoperable The licensee has requested to use the RICT Program to extend the existing CT of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> for TS 3.8.1 Condition D, Required Actions D.1 and D.2. The proposed CT to restore the required offsite circuit (Required Action D.1) or the required DG (Required Action D.2) to operable status is 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> or in accordance with the RICT Program.
In Table E1-2 of Enclosure 1 of the LAR, the licensee stated that the RICT estimate for TS 3.8.1.D is 17 hours1.967593e-4 days <br />0.00472 hours <br />2.810847e-5 weeks <br />6.4685e-6 months <br />. In Table E1-1 of Enclosure 1 of the LAR, the licensee referenced TS 3.8.1.A and TS 3.8.1.B for TS 3.8.1 Condition Ds DSC. In the letter dated August 28, 2020, the licensee proposed a revision of Table E1-1 of Enclosure 1, in which the DSC for TS 3.8.1.D in Table E1-1 is revised to state one offsite source or any two EDGs instead of See 3.8.1.A and 3.8.1.B.
The NRC staff notes that the Nine Mile Point 2 AC sources include offsite circuits and onsite EDGs. During normal operation, the offsite circuits supply power to the onsite Class 1E power distribution system, and the EDGs are on standby. In this design configuration, during the entry of the RICT Program for TS 3.8.1 Condition D (i.e., one required offsite circuit and one required DG inoperable), either the remaining offsite circuit or the remaining two EDGs will be capable of supplying power to ESF systems required to mitigate DBAs with offsite power. In the event offsite power is lost concurrent with the DBAs, as assumed in the USAR Chapter 15 analysis, the remaining two EDGs will be relied on to power the ESF systems required to mitigate the DBAs. Thus, the NRC staff finds that the DSC is met and the function of TS 3.8.1, which is to ensure availability of the required AC power to shut down the reactor and maintain it in a safe shutdown condition after an AOO or a postulated DBA, is maintained. The NRC staff reviewed the RMA examples for TS 3.8.1 Condition D and found that these RMAs are consistent with NEI 06-09, Revision 0-A, and that these RMAs are appropriate to monitor and control risk and to ensure adequate defense-in-depth.
3.1.2.2.2 TS 3.8.4 - DC Sources - Operating The licensee has requested to use the RICT Program to extend the existing CT of 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> for TS 3.8.4 Condition A, Required Action A.1. The proposed CT to restore the Division 1 and Division 2 DC electrical power subsystems to operable status is 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> or in accordance with the RICT Program.
In Table E1-2 of Enclosure 1 of the LAR, the licensee stated that the RICT estimate for TS 3.8.4.A is 720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br />. According to Table E1-1 of Enclosure 1 of the LAR, the DSC for TS 3.8.4 Condition A is one DC electrical power subsystem.
According to the USAR, the safety-related DC power system consists of the three divisions of the emergency DC power system designated as Divisions 1, 2, and 3, corresponding to the three divisions of the onsite emergency AC power system. Each division of the emergency DC system feeds a separate emergency DC load group through a separate distribution system.
Each division has its own battery, primary and backup battery chargers, DC switchgear and distribution panels. Each battery has two 100-percent capacity battery chargers. Each battery charger is capable of supplying the largest combined demands of the steady-state loads on the battery while recharging the battery from the design minimum charge state to the fully charged state within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
The NRC staff notes that in this design configuration, during the entry of the RICT Program for TS 3.8.4 Condition A (i.e., Division 1 or 2 DC electrical power subsystem inoperable), the remaining DC electrical power subsystem will be capable of providing DC power to the respective emergency load group. Thus, the NRC staff finds that the DSC is met and the function of TS 3.8.4, which is to ensure availability of the required DC power to shut down the reactor and maintain it in a safe shutdown condition after an AOO or a postulated DBA, is maintained. The NRC staff reviewed the RMA examples for TS 3.8.4 Condition A and found that these RMAs are consistent with NEI 06-09, Revision 0-A, and that these RMAs are appropriate to monitor and control risk and to ensure adequate defense-in-depth.
3.1.2.2.3 TS 3.8.7 - Inverters - Operating The licensee has requested to use the RICT Program to extend the existing CT of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for TS 3.8.7 Condition A, Required Action A.1. The proposed CT to restore the emergency UPS inverters to operable status is 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or in accordance with the RICT Program.
In Table E1-2 of Enclosure 1 of the LAR, the licensee stated that the RICT estimate for TS 3.8.7.A is 720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br />. According to Table E1-1 of Enclosure 1 of the LAR, the DSC for TS 3.8.7 Condition A is one of two inverters per division.
As described in the USAR, the emergency UPS system provides 120/208-VAC power to the plant essential instrumentation and control loads and plant computer. The emergency UPS system consists of four UPS units, two for each division (Division 1 and Division 2) and their associated distribution panels and manual transfer switches. For each division, one of the redundant UPS units is normally in service, with the other UPS unit maintained as an energized standby unit with no operating loads. Each UPS unit has a normal AC supply that feeds the UPS, a backup DC supply that feeds the UPS in case of loss of normal AC supply, and an alternate AC supply that will feed the UPS load, in the event of UPS inverter failure or during maintenance mode.
The NRC staff notes that in this design configuration, during the entry of the RICT Program for TS 3.8.7 Condition A, either the remaining UPS inverter of the affected division or one of the two UPS inverters from the other division will be capable of providing the function of supplying the essential instrumentation and control loads. Thus, the NRC staff finds that the DSC is met and the function of TS 3.8.7, which is to ensure availability of the required power to shut down the reactor and maintain it in a safe shutdown condition after an AOO or a postulated DBA, is maintained. The NRC staff reviewed the RMA examples for TS 3.8.7 Condition A and found that these RMAs are consistent with NEI 06-09, Revision 0-A, and that these RMAs are appropriate to monitor and control risk and to ensure adequate defense-in-depth.
3.1.2.2.4 TS 3.8.8 - Distribution Systems - Operating 3.1.2.2.4.1 TS 3.8.8 Condition A - One or Both Division 1 and 2 AC Electrical Power Distribution Subsystems Inoperable The licensee has requested to use the RICT Program to extend the existing CT of 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> for TS 3.8.8 Condition A, Required Action A.1. The proposed CT to restore the Division 1 and 2 AC electrical power distribution subsystem(s) to operable status is 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> or in accordance with the RICT Program.
In Table E1-1 of Enclosure 1 of the LAR, the licensee identified this TS condition as a loss of function (LOF) when both Division 1 and 2 AC electrical power distribution subsystems are inoperable. In the LAR, the licensee proposed to add a note into this TS condition to restrict the use of RICT Program when a LOF occurs.
In Table E1-2 of Enclosure 1 of the LAR, the licensee stated that the RICT estimate for TS 3.8.8.A is 22 hours2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br /> based on the loss of one division of AC electrical power system.
According to Table E1-1 of Enclosure 1 of the LAR, the DSC for TS 3.8.8 Condition A is one of two divisions of distribution subsystems.
As stated in the USAR and TS Bases, the AC and DC electrical power distribution systems are divided by division, for Division 1 and 2, into three independent AC, DC, and 120 VAC uninterruptible electrical power distribution subsystems, and for Division 3, into two independent AC and DC electrical power distribution subsystems. The primary AC distribution system consists of three 4.16 kV emergency buses that are supplied from the transmission system by two physically independent circuits. Each 4.16 kV emergency bus also has a dedicated onsite DG source. The secondary AC distribution system includes 600 V emergency load centers and associated loads, motor control centers, transformers, and distribution panels.
The NRC staff notes that in this design configuration, during the entry of the RICT Program for TS 3.8.8 Condition A and a LOF has not yet occurred, the remaining AC electrical power distribution subsystem will be capable of providing electrical power for the systems required to shut down the reactor and maintain it in a safe condition. The NRC staff also notes that with the proposed NOTE above, the use of the RICT Program for TS 3.8.8 Condition A will be restricted when a LOF occurs. Thus, the NRC staff finds that the DSC is met and the function of TS 3.8.8, which is to ensure availability of the required power to shut down the reactor and maintain it in a safe shutdown condition after an AOO or a postulated DBA, is maintained. The NRC staff reviewed the RMA examples for TS 3.8.8 Condition A and found that these RMAs are consistent with NEI 06-09, Revision 0-A, and that these RMAs are appropriate to monitor and control risk and to ensure adequate defense-in-depth.
3.1.2.2.4.2 TS 3.8.8 Condition B - One or both Division 1 and 2 120-VAC Uninterruptible Electrical Power Distribution Subsystems Inoperable The licensee has requested to use the RICT Program to extend the existing CT of 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> for TS 3.8.8 Condition B, Required Action B.1. The proposed CT to restore the Division 1 and 2 120-VAC uninterruptible electrical power distribution subsystems to operable status is 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> or in accordance with the RICT Program.
In Table E1-2 of Enclosure 1 of the LAR, the licensee stated that the RICT estimate for TS 3.8.8.B is 28 hours3.240741e-4 days <br />0.00778 hours <br />4.62963e-5 weeks <br />1.0654e-5 months <br /> based on the loss of one division of electrical power system. According to Table E1-1 of Enclosure 1 of the LAR, the DSC for TS 3.8.8 Condition B is one of four UPSs.
In Table E1-1 of Enclosure 1 of the LAR, the licensee identified this TS condition as a LOF when both Division 1 and 2 120-VAC uninterruptible electrical power distribution subsystems are inoperable. In the LAR, the licensee proposed to add a note into this TS condition to restrict the use of RICT Program when a LOF occurs.
As stated in the USAR and TS Bases, the AC and DC electrical power distribution systems are divided by division, for Division 1 and 2, into three independent AC, DC, and 120-VAC
uninterruptible electrical power distribution subsystems, and for Division 3, into two independent AC and DC electrical power distribution subsystems. The Division 1 and 2 120-VAC uninterruptible panels are normally powered from their associated emergency UPS inverters (two for each division). The alternate power supply for the uninterruptible panels is a Class 1E regulating transformer powered from the same division as the associated emergency UPS inverter.
The NRC staff notes that in this design configuration, during the entry of the RICT Program for TS 3.8.8 Condition B and a LOF has not yet occurred, the remaining uninterruptible electrical power distribution subsystems will be capable of providing power for the systems required to shut down the reactor and maintain it in a safe condition. The NRC staff also notes that with the proposed NOTE above, the use of RICT Program for TS 3.8.8 Condition B will be restricted when a LOF occurs. Thus, the NRC staff finds that the DSC is met and the function of TS 3.8.8, which is to ensure availability of the required power to shut down the reactor and maintain it in a safe shutdown condition after an AOO or a postulated DBA, is maintained. The NRC staff reviewed the RMA examples for TS 3.8.8 Condition B and found that these RMAs are consistent with NEI 06-09, Revision 0-A, and that these RMAs are appropriate to monitor and control risk and to ensure adequate defense-in-depth.
3.1.2.2.4.3 TS 3.8.8 Condition C - One or Both Division 1 and 2 DC Electrical Power Distribution Subsystems Inoperable The licensee has requested to use the RICT Program to extend the existing CT of 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> for TS 3.8.8 Condition C, Required Action C.1. The proposed CT to restore the Division 1 and 2 DC electrical power distribution subsystem(s) to operable status is 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> or in accordance with the RICT Program.
In Table E1-2 of Enclosure 1 of the LAR, the licensee stated that the RICT estimate for TS 3.8.8.C is 76 hours8.796296e-4 days <br />0.0211 hours <br />1.256614e-4 weeks <br />2.8918e-5 months <br /> based on the loss of one division of electrical power system. According to Table E1-1 of Enclosure 1 of the LAR, the DSC for TS 3.8.8 Condition C is one of two divisions of the DC electrical power distribution subsystems.
In Table E1-1 of Enclosure 1 of the LAR, the licensee identified this TS condition as a LOF when both Division 1 and 2 DC electrical power distribution subsystems inoperable. In the LAR, the licensee proposed to add a note into this TS condition to restrict the use of RICT Program when a LOF occurs.
As stated in the USAR and TS Bases, the AC and DC electrical power distribution systems are divided by division, for Division 1 and 2, into three independent AC, DC, and 120-VAC uninterruptible electrical power distribution subsystems, and for Division 3, into two independent AC and DC electrical power distribution subsystems. There are three independent 125-VDC (Volts direct current) electrical power distribution subsystems. With one or more Division 1 and 2 DC buses inoperable and a LOF has not yet occurred, the remaining DC electrical power distribution subsystems are capable of supporting the minimum safety functions necessary to shut down the reactor and maintain it in a safe shutdown condition.
The NRC staff notes that during the entry of the RICT Program for TS 3.8.8 Condition C and a LOF has not yet occurred, the remaining DC electrical power distribution subsystems will be capable of providing power for the systems required to shut down the reactor and maintain it in a safe condition. The NRC staff also notes that with the proposed NOTE above, the use of RICT Program for TS 3.8.8 Condition C will be restricted when a LOF occurs. Thus, the NRC
staff finds that the DSC is met and the function of TS 3.8.8, which is to ensure availability of the required power to shut down the reactor and maintain it in a safe shutdown condition after an AOO or a postulated DBA, is maintained. The NRC staff reviewed the RMA examples for TS 3.8.8 Condition C and found that these RMAs are consistent with NEI 06-09, Revision 0-A, and that these RMAs are appropriate to monitor and control risk and to ensure adequate defense-in-depth.
3.1.2.2.5 Conclusion of Electrical Power Systems The NRC staff reviewed the proposed changes to Nine Mile Point 2 electrical power systems TS 3.8.1, TS 3.8.4, TS 3.8.7, and TS 3.8.8 conditions and supporting documentation. The proposed changes would add alternate CTs in accordance with the RICT Program for certain required actions of the proposed TSs. Based on the above technical evaluation, the staff find that while the redundancy is not maintained (e.g., one train of a two-train system is inoperable),
the CT extensions in accordance with the RICT Program are acceptable because:
The DSC provided in the LAR and its supplement reflect the LCOs 3.8.1, 3.8.4, 3.8.7, and 3.8.8 minimum requirements to support the associated TS safety functions.
During the entry of the RICT Program for the above TS conditions, the remaining electrical power sources/subsystems are capable of supplying power to mitigate postulated DBAs, safely shut down the reactor, and maintain the reactor in a safe shutdown condition (assuming no additional failures of electrical components). Thus, the capability of the systems to perform their safety functions is maintained.
The licensee has appropriately identified the TS conditions with potential LOF and proposed an adequate restriction on the use of the RICT Program for those TS conditions when a LOF occurs.
The demonstration of identifying and implementing compensatory measures or RMAs, in accordance with the RICT Program, provides reasonable assurance that these RMA examples are appropriate to monitor and control risk and ensure adequate defense-in-depth.
3.1.2.3 Evaluation of Instrumentation and Control Systems The licensee has requested to use the RICT Program to extend the existing CT for the following instrumentation and control (I&C) TS conditions. The NRC staffs evaluation of the proposed changes considered a number of potential plant conditions allowed by the proposed TSs and considered what redundant or diverse means were available to assist in responding to various plant conditions. The plant conditions evaluated are:
LCO 3.3.1.1 RPS Instrumentation LCO 3.3.2.2 Feedwater System and Main Turbine High Water Level Trip Instrumentation LCO 3.3.4.1 EOC-RPT Instrumentation LCO 3.3.4.2 ATWS-RPT Instrumentation LCO 3.3.5.1 ECCS Instrumentation LCO 3.3.5.3 RCIC System Instrumentation LCO 3.3.6.1 Primary Containment Isolation Instrumentation LCO 3.3.7.2 Mechanical Vacuum Pump Isolation Instrumentation LCO 3.3.8.1 Loss of Power (LOP) Instrumentation
Attachment 5 of the LAR provided information supporting the evaluation of the redundancy and diversity of instrumentation included in the TS changes proposed.
The NRC staff followed the guidance in RG 1.174 and further elaborated in RG 1.177 to assess the proposed changes consistency with defense-in-depth criteria. The applicable criteria to the affected I&C systems are:
System redundancy, independence, and diversity are maintained commensurate with the expected frequency and consequences of challenges to the system (e.g., there are no risk outliers)
Defenses against potential CCFs are maintained and the potential for the introduction of new CCF mechanisms is assessed The intent of the plants design criteria is maintained The licensee confirmed, and NRC staff verified, that in accordance with the USAR, in all applicable operating modes, the affected protective feature would perform its intended function by ensuring the ability to detect and mitigate the associated event or accident when the CT of a channel is extended. Therefore, the NRC staff concludes that the intent of the plants design criteria for the I&C functions identified in the LAR is maintained.
The NRC staff finds that while in an LCO condition, the redundancy of the function will be temporarily relaxed, and consequently, the system reliability will be degraded accordingly. The NRC staff examined the design information from the TS, TS Bases, and USAR and the risk-informed LCO conditions for the affected I&C functions. Based on this information, the NRC staff confirmed that under any given DBA evaluated in the USAR, the affected I&C protective features maintain adequate defense-in-depth by either necessary redundancy (e.g.,
at least one redundant channel) and/or necessary diversity (e.g., at least one alternative safety feature).
The licensee confirmed in the LAR that the proposed changes do not alter the I&C system designs. Consequently, the NRC staff concludes that the proposed changes do not alter the ways in which the I&C systems fail, do not introduce new CCF modes, and the system independence is maintained. The NRC staff finds that while some proposed changes allow the time of reduced redundancy (for specific conditions) to be prolonged, this extension may reduce the level of defense against some CCFs; however, the NRC staff finds, as described below, such extension of time of reduced redundancy and defense against CCFs are acceptable due to existing diverse means available to maintain adequate defense-in-depth against a potential single failure during a RICT for the I&C systems.
3.1.2.3.1 LCO 3.3.1.1 RPS Instrumentation The RPS is generally a 2/4 system which is defined as four channels, two trip systems, two channels per trip system arranged in one-out-of-two twice (de-energize to trip) logic (e.g.,
Channel A1 or Channel A2 and Channel B1 or Channel B2). Some functions have more than one instrument per channel.
Within this LCO, Actions A.1, A.2, B.1, and B.2 were proposed to be risk informed (as described in detail above). Condition A is applicable to all functions while Condition B is applicable to all
functions except 2.a, 2.b, 2.c, 2.d, and 2.e. Although both Conditions A and B could include a condition where trip capability is not maintained, the note being added as part of the RICT prohibits the use of a RICT from being applied to a condition where the trip capability is not maintained. Therefore, a RICT is only used to extend the time where certain required redundancy is not maintained. The conditions that have RICT do not reduce independence.
The diversity within the RPS is also not reduced, since the note being added as part of the RICT prohibits the use of a RICT from being applied to a condition where the trip capability is not maintained. In addition, the diversity external to the RPS is also not reduced as described in of the LAR. Furthermore, the diversity described in Attachment 5 was evaluated using the criteria in RG 1.174, RG 1.177, and the model SE, and the diversity was determined to be adequate.
Since system redundancy, independence, and diversity are adequately maintained, the defenses against potential CCFs are maintained and there is no potential for the introduction of new CCF mechanisms.
The intent of the applicable facility design criteria is to ensure adequate redundancy, independence, and diversity, adequate protection against CCF, and ability to perform maintenance without shutting down the facility. Based on the review described above, the NRC staff concludes that the intent of the facility design criteria will be maintained.
3.1.2.3.2 LCO 3.3.2.2 Feedwater System and Main Turbine High Water Level Trip Instrumentation Within this LCO, Action A.1 is proposed to be risk informed (as described in detail above). The Reactor Vessel Water Level (High - Level 8) has three channels with one trip system arranged in a two-out-of-three (energize to initiate) logic (e.g., Channel A and B or Channel A and C or Channel B and C).
The note being added as part of the RICT prohibits the use of a RICT from being applied to a condition where the trip capability is not maintained. Therefore, a RICT is only used to extend the time where certain required redundancy is not maintained. The conditions that have RICTs do not reduce independence.
As described in Attachment 5 to the LAR, there exists a diverse automatic trip function for each event that this function mitigates. There is also an associated manual initiation capability. This diversity was evaluated using the criteria in RG 1.174, RG 1.177, and the model SE, and the diversity was also determined to be adequate.
Since system redundancy, independence, and diversity are adequately maintained, the defenses against potential CCFs are maintained and there is no potential for the introduction of new CCF mechanisms.
The intent of the applicable facility design criterion is to ensure adequate redundancy, independence, and diversity, adequate protection against CCF, and ability to perform maintenance without shutting down the facility. Based on the review described above, the NRC staff concludes that the intent of the facility design criteria will be maintained.
3.1.2.3.3 LCO 3.3.4.1 EOC-RPT Instrumentation This LCO includes two functions (i.e., Turbine Stop Valve Closure and Turbine Control Valve Fast Closure (Trip Oil Pressure - Low), both of which have four channels, arranged in two trip systems (i.e., two channels per trip system in a two-out-of-two once (energize to trip) logic (e.g.,
Channel A and Channel B or Channel C and Channel D).
Within this LCO, Actions A.1 and A.2 were proposed to be risk informed (as described in detail above). Condition A is applicable to both functions included in this LCO.
Although Condition A could include a condition where trip capability is not maintained, the note being added as part of the RICT prohibits the use of a RICT from being applied to a condition where the trip capability is not maintained. Therefore, a RICT is only used to extend the time where certain required redundancy is not maintained. The conditions that have RICTs do not reduce independence.
The diversity means to actuate this function is the capability for manual trip of each function.
This diversity was evaluated using the criteria in RG 1.174, RG 1.177, and the model SE, and the diversity was determined to be adequate.
Since system redundancy, independence, and diversity are adequately maintained, the defenses against potential CCFs are maintained and there is no potential for the introduction of new CCF mechanisms.
The intent of the applicable facility design criteria is to ensure adequate redundancy independence, and diversity, adequate protection against CCF, and ability to perform maintenance without shutting down the facility. Based on the review described above, the NRC staff concludes that the intent of the facility design criteria will be maintained.
3.1.2.3.4 LCO 3.3.4.2 ATWS-RPT Instrumentation The ATWS-RPT LCO includes two functions: Reactor Vessel Water Level (Low Low - Level 2) and Reactor Vessel Steam Dome Pressure (High), both of which include four channels, arranged in two trip systems (i.e., two channels per trip system) in a two-out-of-two once (energize to trip) logic (e.g., Channel 1A and Channel 1B or Channel 2A and Channel 2B).
Within this LCO, Actions A.1 and A.2 were proposed to be risk informed (as described in detail above). Condition A is applicable to both functions. The conditions that have RICT do not reduce independence.
The diversity means to actuate this function is the capability for manual trip of each function.
This diversity was evaluated using the criteria in RG 1.174, RG 1.177, and the model SE, and the diversity was determined to be adequate.
Since system redundancy, independence, and diversity are adequately maintained, the defenses against potential CCFs are maintained and there is no potential for the introduction of new CCF mechanisms.
The intent of the applicable facility design criteria is to ensure adequate redundancy, independence, and diversity, adequate protection against CCF, and ability to perform
maintenance without shutting down the facility. Based on the review described above, the NRC staff concludes that the intent of the facility design criteria will be maintained.
3.1.2.3.5 LCO 3.3.5.1 ECCS Instrumentation The ECCS instrumentation actuates LPCS, LPCI, HPCS, ADS, and the DGs. Within this LCO, Actions B.3.1, C.2, D.2.1, E.2, F.2, and G.2 were proposed to be risk informed (as described in detail above).
The four different subsystems have different levels of redundancy. Although Condition B.3.1, C.2, D.2.1, E.2, F.2, and G.2 are applied to various functions and could include a condition where trip capability is not maintained, the note being added as part of the RICT prohibits the use of a RICT from being applied to a condition where the trip capability is not maintained. The conditions F.2 and G.2 (there are two inserts in these conditions) do not have the same note applied; however, Required Actions F.1 and G.1 are intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within similar ADS trip system functions result in automatic initiation capability being lost for the ADS. Therefore, a RICT is only used to extend the time where certain required redundancy is not maintained. The conditions that have RICT do not reduce independence.
Although the diversity means to actuate each function is the capability for manual trip of each function, the ADS, LPCI, and LPCS systems can be used when the HPCS system is unable to perform its functions. In addition, the LPCI and LPCS are diverse but both actuated by the same conditions. This diversity was evaluated using the criteria in RG 1.174, RG 1.177, and the model SE, and the diversity was determined to be adequate.
Since system redundancy, independence, and diversity are adequately maintained, the defenses against potential CCFs are maintained and there is no potential for the introduction of new CCF mechanisms.
The intent of the applicable facility design criteria is to ensure adequate redundancy, independence, and diversity, adequate protection against CCF, and ability to perform maintenance without shutting down the facility. Based on the review described above, the NRC staff concludes that the intent of the facility design criteria will be maintained.
3.1.2.3.6 LCO 3.3.5.3 RCIC System Instrumentation Within this LCO, Actions B.2 and D.2.1 were proposed to be risk informed (as described in detail above); the note being added as part of the RICT prohibits the use of a RICT from being applied to a condition where the trip capability is not maintained. Therefore, a RICT is only used to extend the time where certain required redundancy is not maintained. The conditions that have RICT do not reduce independence.
The purpose of the RCIC system instrumentation is to initiate actions to ensure adequate core cooling when the reactor vessel is isolated from its primary heat sink (the main condenser) and normal coolant makeup flow from the reactor feedwater system is insufficient or unavailable, such that RCIC system initiation occurs and maintains sufficient reactor water level such that initiation of the low pressure ECCS pumps does not occur.
The diversity means to actuate this function is the capability for manual trip of each function; however, some defense-in-depth is effectively provided by the low pressure ECCS.
Furthermore, this diversity described in Attachment 5 was evaluated using the criteria in RG 1.174, RG 1.177, and the model SE, and the diversity was determined to be adequate.
Since system redundancy, independence, and diversity are adequately maintained, the defenses against potential CCFs are maintained and there is no potential for the introduction of new CCF mechanisms.
The intent of the applicable facility design criteria is to ensure adequate redundancy, independence, and diversity, adequate protection against CCF, and ability to perform maintenance without shutting down the facility. Based on the review described above, the NRC staff concludes that the intent of the facility design criteria will be maintained.
3.1.2.3.7 LCO 3.3.6.1 Primary Containment Isolation Instrumentation Within this LCO, Action A.1 is proposed to be risk informed (as described in detail above); the note being added as part of the RICT prohibits the use of a RICT from being applied to a condition where the trip capability is not maintained. Therefore, a RICT is only used to extend the time where certain required redundancy is not maintained. The conditions that have RICTs do not reduce independence.
The diversity means to actuate this function is the capability for manual trip of each function.
This diversity was evaluated using the criteria in RG 1.174, RG 1.177, and the model SE, and the diversity was determined to be adequate.
Since system redundancy, independence, and diversity are adequately maintained, the defenses against potential CCFs are maintained and there is no potential for the introduction of new CCF mechanisms.
The intent of the applicable facility design criteria is to ensure adequate redundancy, independence, and diversity, adequate protection against CCF, and ability to perform maintenance without shutting down the facility. Based on the review described above, the NRC staff concludes that the intent of the facility design criteria will be maintained.
3.1.2.3.8 LCO 3.3.7.2 Mechanical Vacuum Pump Isolation Instrumentation Within this LCO, Actions A.1 and A.2 are proposed to be risk informed (as described in detail above); the note being added as part of the RICT prohibits the use of a RICT from being applied to a condition where the trip capability is not maintained. Therefore, a RICT is only used to extend the time where certain required redundancy is not maintained. The conditions that have RICTs do not reduce independence.
The diversity means to actuate this function is the capability for manual trip of each function.
This diversity was evaluated using the criteria in RG 1.174, RG 1.177, and the model SE, and the diversity was determined to be adequate.
Since system redundancy, independence, and diversity are adequately maintained, the defenses against potential CCFs are maintained and there is no potential for the introduction of new CCF mechanisms.
The intent of the applicable facility design criteria is to ensure adequate redundancy, independence, and diversity, adequate protection against CCF, and ability to perform
maintenance without shutting down the facility. Based on the review described above, the NRC staff concludes that the intent of the facility design criteria will be maintained.
3.1.2.3.9 LCO 3.3.8.1 Loss of Power Instrumentation Within this LCO, Action A.1 is proposed to be risk informed (as described in detail above); the note being added as part of the RICT prohibits the use of a RICT from being applied to a condition where the trip capability is not maintained. Therefore, a RICT is only used to extend the time where certain required redundancy is not maintained. The conditions that have RICTs do not reduce independence.
Each of the three 4.16 kV emergency buses has its own independent LOP instrumentation and associated trip logic. The voltage for the Division 1, 2, and 3 buses is monitored at two levels, which can be considered as two different undervoltage functions: loss of voltage and degraded voltage. Each Division 1, 2 and 3, 4.16 kV Emergency Bus Loss of Voltage Function and Degraded Voltage Function is monitored by three separate undervoltage relays, one relay per phase. Based on these diverse LOP detection means, the use of RICT does not degrade the available diversity. Furthermore, this diversity described in Attachment 5 was evaluated using the criteria in RG 1.174, RG 1.177, and the model SE, and the diversity was determined to be adequate.
Since system redundancy, independence, and diversity are adequately maintained, the defenses against potential CCFs are maintained and there is no potential for the introduction of new CCF mechanisms.
The intent of the applicable facility design criteria is to ensure adequate redundancy, independence, and diversity, adequate protection against CCF, and ability to perform maintenance without shutting down the facility. Based on the review described above, the NRC staff concludes that the intent of the facility design criteria will be maintained.
3.1.2.3.10 Conclusion of I&C Systems Since the licensee did not propose any changes to the design basis, the independency and the fail-safe principle remain unchanged. The licensee stated in the LAR that the proposed changes did not include any TS LOF conditions. However, it is recognized that while in an Action statement, redundancy of the given protective feature will be temporarily reduced and, accordingly, the system reliability will be reduced. In the LAR, the licensee stated in the description of proposed changes to the I&C systems that at least one redundant or diverse means (e.g., other automatic features or manual action) to accomplish the safety functions (e.g.,
reactor trip, safety injection, or containment isolation) remains available during the use of the RICT. The NRC staff reviewed the licensees proposed TS changes to assess the availability of the redundant or diverse means to accomplish the safety function(s). The NRC staff finds that the availability of the redundant or diverse protective features provides sufficient defense-in-depth to accomplish the safety functions, allowing for the extension of CTs in accordance with the RICT Program. The NRC staff finds that the licensee-proposed RICT Program to the identified I&C systems is in compliance with 10 CFR 50.36(b) and 10 CFR 50.55a(h).
The NRC staff reviewed the licensees proposed TS changes and supporting documentation.
The NRC staff finds that while the I&C redundancy is reduced, the CT extensions implemented in accordance with the RICT Program are acceptable because:
The capability of the I&C systems to perform their safety functions is maintained; At least one redundant or diverse means to accomplish each safety function exists as identified by the licensee; and The licensee will identify and implement RMAs to monitor and control risk in accordance with the RICT Program.
3.1.2.4 Key Principle 2: Conclusions The LAR proposes to modify the TS requirements to permit extending selected CTs using the RICT Program in accordance with NEI 06-09, Revision 0-A. The NRC staff has reviewed the licensees proposed TS changes and supporting documentation. The NRC staff finds that extending the selected CTs with the RICT Program following loss of redundancy, but maintaining the capability of the system to perform its safety function, is an acceptable reduction in defense-in-depth provided that the licensee identifies and implements compensatory measures as appropriate during the extended CT.
As discussed above in this SE, the NRC staff has further evaluated key safety functions in the proposed CT extensions and finds that the proposed changes are consistent with the defense-in-depth philosophy because:
System redundancy (with the exceptions discussed above), independence, and diversity commensurate with the expected frequency and consequences of challenges to the system is preserved Adequate capability of design features without an overreliance on programmatic activities as compensatory measures is preserved The intent of the plants design criteria continues to be met Therefore, NRC staff finds that this proposed change meets the second key safety principle of RG 1.177 and is, therefore, acceptable. Additionally, the NRC staff concludes that the proposed changes are consistent with the defense-in-depth philosophy as described in RG 1.174.
3.1.3 Key Principle 3: Evaluation of Safety Margins Section 2.2.2 of RG 1.177, Revision 1, states, in part, that sufficient safety margins are maintained when:
Codes and standards [] or alternatives approved for use by the NRC are met Safety analysis acceptance criteria in the final safety analysis report are met or proposed revisions provide sufficient margin to account for analysis and data uncertainties
The licensee is not proposing in this application to change any quality standard, material, or operating specification. In the LAR, the licensee proposed to add a new program, Risk Informed Completion Time Program, in Section 5.0, of the TSs, which would require adherence to NEI 06-09, Revision 0-A.
The NRC staff evaluated the effect on safety margins when the RICT is applied to extend the CT up to a backstop of 30 days in a TS condition with sufficient trains remaining operable to fulfill the TS safety function. Although the licensee will be able to have design basis equipment out of service longer than the current TS allow, any increase in unavailability is expected to be insignificant and is addressed by the consideration of the single failure criterion in the design-basis analyses. Acceptance criteria for operability of equipment are not changed and, if sufficient trains remain operable to fulfill the TS safety function, the operability of the remaining train(s) ensures that the current safety margins are maintained. The NRC staff finds that if the specified TS safety function remains operable, sufficient safety margins would be maintained during the extended CT of the RICT Program.
Safety margins are also maintained if PRA functionality is determined for the inoperable train which would result in an increased CT. Credit for PRA functionality, as described in NEI 06-09, Revision 0-A, is limited to the inoperable train, loop, or component. The reduced but available functionality may support a further increase in the CT consistent with the risk of the configuration. During this increased CT, the specified safety function is still being met by the operable train and therefore requires no evaluation of PRA functionality to meet the design-basis success criteria.
3.1.3.1 Key Principle 3 Conclusions As discussed above, the NRC staff finds that the design-basis analyses for Nine Mile Point 2 remain applicable. Although the licensee will be able to have design-basis equipment out of service longer than the current TS allow and the likelihood of successful fulfillment of the function will be decreased when redundant train(s) are not available, the capability to fulfill the function will be retained when the available equipment functions as designed. Any increase in unavailability because less equipment is available for a longer time is included in the RICT evaluation. Therefore, safety margin reductions are minimized by the implementation of the RICT Program. Based on the above, the NRC staff concludes that the proposed change meets the third key safety principle of RG 1.177 and is acceptable.
3.1.4 Key Principle 4: Change in Risk Consistent with the Safety Goal Policy Statement NEI 06-09, Revision 0-A, is a methodology for a licensee to evaluate and manage the risk impact of extensions to TS CTs. Changes to the fixed TS CTs are typically evaluated by using the three-tiered approach described in RG 1.177, Revision 1. This approach addresses the calculated change in risk as measured by the CDF and LERF, as well as the incremental conditional core damage probability and incremental conditional large early release probability; the use of compensatory measures to reduce risk; and the implementation of a CRMP to identify risk-significant plant configurations.
The NRC staff evaluated the licensees processes and methodologies for determining that the change in risk from implementation of RICTs will be small and consistent with the guidance.
The NRC staff evaluated the licensees proposed changes against the three-tiered approach in RG 1.177, Revision 1, for the licensees evaluation of the risk associated with a proposed TS CT change.
3.1.4.1 Tier 1: PRA Capability and Insights The first tier evaluates the impact of the proposed changes on plant operational risk. The Tier 1 review involves two aspects: (1) the technical acceptability of the PRA models and their application to the proposed changes, and (2) a review of the PRA results and insights described in the licensees application.
3.1.4.1.1 PRA Acceptability RG 1.174 states that the scope, level of detail, and technical adequacy of the PRA are to be commensurate with the application for which it is intended and the role the PRA results play in the integrated decision-making process. The NRCs SE as described in NEI 06-09, Revision 0-A, states that the PRA models should conform to the guidance in RG 1.200, Revision 1, An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities, January 2007 (Reference 22). The current version is RG 1.200, Revision 2, which clarifies the current applicable ASME/ANS PRA standard is ASME/ANS RA-Sa-2009.
The NRC staff evaluated the PRA acceptability information provided by the licensee in of its submittal, including industry peer review results and the licensees self-assessment of the PRA models for internal events, including internal flooding, and fire, against the guidance in RG 1.200, Revision 2. The licensee screened out all external hazard events, except for seismic, as insignificant contributors to RICT calculations. The Nine Mile Point 2 PRA model with modifications is used as the CRMP model.
The NRC memorandum dated May 30, 2017 (Reference 23), provides the NRC staffs assessment of the challenges of incorporating diverse and flexible mitigation capability (FLEX) strategies into a PRA model to support risk-informed decisionmaking consistent with the guidance in RG 1.200, Revision 2. The May 30, 2017, memorandum highlights two main areas of uncertainties for crediting FLEX in the PRA: equipment failure probabilities and human reliability analysis (HRA) of the credited operator actions for deploying FLEX. The guidance in NEI 06-09, Revision 0-A, states that sensitivity studies should be performed on the base model prior to initial implementation of the RICT Program on uncertainties that could potentially impact the results of the RICT calculation, and that the insights from the sensitivity studies should be used to develop appropriate compensatory RMAs, including highlighting risk-significant operator actions, confirming availability and operability of important standby equipment, and assessing the presence of severe or unusual environmental conditions. In RAI 14, the NRC staff requested the licensee to discuss if FLEX equipment and mitigating actions are credited in the Nine Mile Point 2 PRA.
In its October 2, 2020, response to RAI 14.a and b (Reference 5), the licensee explained that three FLEX capabilities were credited in the internal events (including internal flooding) and fire PRAs:
Use of portable FLEX DGs to provide DC power and power for long-term Nitrogen makeup to the Safety Relief Valves (SRVs)
Use of portable FLEX diesel-driven pumps for injection of cooling water from the UHS into Reactor Pressure Vessel Use of the Hardened Containment Vent System, permanently installed With regard to equipment reliability, the licensee stated in response to RAI 14.c that the FLEX DGs are similar to industry DGs presented in NUREG/CR-6928, Industry-Average Performance for Components and Initiating Events at U.S. Commercial Nuclear Power Plants, dated February 2007 (Reference 24), such as the Station Blackout DGs and the FLEX diesel-driven pumps are also similar to industry diesel-driven fire pumps. However, the licensee acknowledged that FLEX DGs and diesel-driven pumps are portable, and therefore, sufficient industry failure data does not yet exist to support a PRA. The licensee stated that the failure rate for FLEX equipment was assumed to be a factor of two times the failure rate for similar equipment listed in NUREG/CR-6928 to account for uncertainty. The licensee explained it compared these assumed values to failure rates presented in an analysis of limited industry FLEX equipment failures presented in PWROG-18043-P, Revision 0, FLEX Equipment Data Collection and Analysis, February 2020 (Reference 25), and found them to be consistent. The licensee also reviewed its plant-specific FLEX equipment failure data (which includes data since January 2015) and calculated preliminary plant-specific failures rates for the DGs and diesel-driven pumps. The NRC staff notes that these preliminary values provided in the response are in some cases higher (i.e., the failure to start rates) than the assumed rates used in the PRA models and in some cases the failure rates are lower (i.e., the run time rates). The licensee explained that these preliminary values are based on limited experience and that the FLEX program is still evolving as improvements have been made to the program (e.g., changes were made to the battery charging connections). The licensee stated that it does not consider this early data to represent any outlier events.
With respect to the HRA of the credited operator actions, Section 7.5 of NEI 16-06, Crediting Mitigating Strategies in Risk-Informed Decision Making (Reference 23), recognizes that the current HRA methods do not translate directly to human actions required for implementing mitigating strategies. Sections 7.5.4 and 7.5.5 of NEI 16-06 describe such actions to which the current HRA methods cannot be directly applied, such as debris removal; transportation of portable equipment; installation of equipment at a staging location; routing of cables and hoses; and those complex actions that require many steps over an extended period, multiple personnel and locations, evolving command and control, and extended time delays. In response to RAI 14.d, the licensee identified three credited operator actions that contain the type of activities for which existing HRA approaches are not explicitly applicable.
The licensee provided the results of a composite sensitivity study in which the failure rates used from NUREG/CR-6928 were increased by a factor of five and all FLEX operator errors were set to their 95th percentile values for the plant configurations associated with eight different TS LCOs whose risk could be impacted by this treatment. The licensee clarified that for the joint human error probability (HEP) a minimum value of 1E-06 was used regardless of the recalculated joint HEP using the 95th percentile values. The sensitivity study results showed
that the impact of crediting FLEX equipment and action on the RICT calculations is small. The licensee also explained that based on the sensitivity study results that no specific global RMAs were identified to address the uncertainty associated with crediting FLEX equipment and actions. The licensee stated, however, that if FLEX actions were identified as important by the real time risk (RTR) model for a RICT, then configuration-specific RMAs would be identified.
In response to RAI 14.e, the licensee described its evaluation of the modeling performed to incorporate FLEX into the PRA against the definition of a PRA upgrade provided in the ASME/ANS RA-Sa-2009 PRA standard using guidance from RG 1.200, Revision 2. The NRC staff is unable to unequivocally conclude that the licensees implementation of FLEX credit does not constitute an upgrade. However, given the results of the sensitivity studies conducted by the licensee that showed a small impact on CDF and LERF, the NRC staff finds that the licensees treatment of FLEX in the PRA is acceptable for this application. Future changes to the PRA will be captured by the PRA maintenance process, consistent with the guidance in NEI 06-09, Revision 0-A. As described later in this SE, the licensee has procedures for maintaining the PRA to reasonably reflect the as-built and as-operated plant. Therefore, any future plant and industry operating experience affecting the FLEX equipment failure rates and HEPs is expected to be captured by the PRA maintenance process. Also, the guidance in NEI 06-09, Revision 0-A, discusses use of RMAs. If FLEX actions are identified important by the RTR model for a RICT, the licensee confirmed that configuration-specific RMAs would be identified.
3.1.4.1.1.1 Internal Events PRA (Including Internal Flooding)
The NRC staff reviewed the peer review history for the Nine Mile Point 2 internal events and internal flooding PRAs as described in LAR Enclosure 2. A full-scope peer review of the internal events PRA was performed in July 2009 using NEI 05-04, Revision 2, Process for Performing Internal Events PRA Peer Reviews Using the ASME/ANS PRA Standard, dated November 2008 (Reference 26), and the guidance in the ASME/ANS RA-Sa-2009 PRA Standard and RG 1.200, Revision 2. A fact and observation (F&O) closure review was performed in February 2019 on all the internal events (including internal flooding) findings.
It was performed by an independent assessment (IA) team, consistent with guidance in Appendix X of NEI 05-04 and clarifications in the NRCs acceptance letter dated May 3, 2017 (Reference 27).
Additionally, concurrent with the 2019 F&O closure review, a focused-scope peer review was performed on the incorporation of support system initiating event fault trees. This focused-scope peer review resulted in three F&Os (i.e., F&O 5-1, 8-1, and 8-2) associated with surveillance requirements (SRs) that were found not to be met. The NRC staff reviewed these F&Os along with dispositions for this application. The F&O dispositions refer to the licensees proposed implementation item in LAR Attachment 6 (i.e., one of six implementation items related to PRA modeling updates) to resolve these F&Os prior to implementation of the RICT Program. In its October 2, 2020, response to RAI 6 (Reference 5), the licensee described the modeling updates associated with these F&Os and stated that they are now closed in the latest PRA model via the 2020 F&O Closure Review. The licensee stated all other findings were closed during the February 2019 F&O closure review.
In its October 2, 2020, response to RAI 7.a (Reference 5), the licensee provided a summary of the internal events PRA model changes made since July 2009 full-scope peer review and justification for why each change did or did not meet the definition of a PRA upgrade using the definition in the ASME/ANS R-Sa-2009 PRA Standard. The licensee indicated that one PRA
change was determined to be a PRA upgrade, related to a change from a cognitive reliability HRA model to an accident sequence evaluation program (ASEP) time reliability HRA model). In response to PRA 7.b, the licensee stated that a focused-scope peer review was performed in 2020 on this HRA PRA upgrade. This focused-scope peer review led to three additional F&Os (i.e., F&O 20-1, 20-2, and 20-2) for which the licensee provided dispositions in the RAI response. The NRC staff reviewed the dispositions for these new F&Os and concluded that they do not impact the application, as follows. For F&O 20-1, the resolution involves documentation of a reasonableness check that has already been performed. For F&O 20-2, the resolution involves correcting HRA documentation for post-initiator actions execution errors in which the ASEP method was erroneously referenced. For F&O 20-2, the resolution involves updating the HRA calculator database to be consistent with the modeling performed in the calculator and update of the HRA documentation to clarify the timelines for ASEP calculations.
Based on its review, the NRC staff finds that the internal events and internal flooding PRA has been adequately peer reviewed against the current version of the PRA standard and RG 1.200, and that the licensee has adequately dispositioned the F&Os to support the technical adequacy of the internal events PRA for the Nine Mile Point 2 RICT Program.
3.1.4.1.1.2 Fire PRA The NRC staffs review of the Nine Mile Point 2 fire PRA was based on the results of a full-scope peer review of the fire PRA, the associated F&Os closure review described in LAR , and a focused-scope peer review performed in 2020 after the LAR was submitted.
The full-scope peer review of the fire PRA was performed in June 2018 using the NEI 07-12, Final Revision of Appendix X to NEI 05-04/07-12/12-16 Close Out Facts and Observations, November 2008 (Reference 28), process and the guidance in the ASME/ANS RA-Sa-2009 PRA Standard and RG 1.200, Revision 2. The Nine Mile Point 2 fire PRA F&O closure review was performed in February 2019 by an independent assessment team on SRs with finding-level F&Os from the 2018 full-scope review. The February 2019 F&O closure process for the Nine Mile Point 2 fire PRA was performed consistent with guidance in Appendix X of NEI 07-12 and clarifications in the NRCs acceptance letter dated May 3, 2017. The F&O closure review closed out all open finding-level F&Os. The licensee performed a self-assessment of whether the resolution of a finding could constitute an upgrade of the PRA as defined by the ASME/ANS RA-Sa-2009 PRA standard and found that these determinations were reviewed by the independent assessment team. The licensee stated that a focused-scope peer review performed in 2020 after the LAR was submitted encompassed SRs associated with the fire scenario selection (FSS) and analysis technical element to address updated fire modeling of the main control room (MCR). The disposition to the one-finding level F&O from that review for the fire PRA is found to be acceptable for the application because it appropriately addressed the technical concern raised in the finding.
RG 1.200 states NRC reviewers, [will] focus their review on key assumptions and areas identified by peer reviewers as being of concern and relevant to the application. The NRC staff evaluates the acceptability of the PRA for each new risk-informed application and, as discussed in RG 1.174, recognizes that the acceptable technical adequacy of risk analyses necessary to support regulatory decisionmaking may vary with the relative weight given to the risk assessment element of the decision-making process. The NRC staff notes that the calculated results of the PRA are used directly to calculate a RICT which subsequently determines how long SSCs (both individual SSCs and multiple, unrelated SSCs) controlled by TSs can remain inoperable.
In RAI 18 (Reference 11), the NRC requested information about use of fire PRA methods that deviate from guidance provided in NUREG/CR-6850, Volume 2, EPRI [Electric Power Research Institute]/NRC-RES Fire PRA Methodology for Nuclear Power Facilities, Detailed Methodology, dated September 2005 (Reference 29), or other acceptable guidance (e.g.,
frequently asked questions (FAQs), NUREGs, or interim guidance documents). In its October 2, 2020, response to RAI 18 (Reference 5), the licensee stated that [n]o methods were used in developing the Nine Mile Point 2 fire PRA that deviated from acceptable guidance.
In RAI 19, NRC requested information about use of reduced transient fire heat release rates (HRRs) below those prescribed in NUREG/CR-6850 and justification if reduced HRRs were used. In response to RAI 19, the licensee explained that only the 98th percentile HRR of 317 kilowatts from NUREG/CR-6850, Volume 2, was used in developing transient fire scenarios for the fire PRA, and therefore, no reduced HRR rates were credited. NRC staffs review finds the licensees use of the HRR for transient fires to be acceptable for this application because reduced HRRs were not used.
In RAI 20, NRC staff requested description of the licensees treatment of sensitive electronics and explanation of whether its treatment is consistent with the guidance in FAQ 13-0004, Clarifications on Treatment of Sensitive Electronics, dated December 13, 2013 (Reference 30), including the caveats about configurations that can invalidate the approach (i.e., sensitive electronics mounted on the surface of cabinets and the presence of louver or vents). In response to RAI 20, the licensee explained that its treatment of sensitive electronics is based on the guidance provided in FAQ 13-0004 in which the damage threshold for thermoset cable is used for sensitive electronics within an electrical cabinet. The licensee explained that as part of its screening process configurations were identified with the potential to expose sensitive electronics to radiant heat due to being mounted on the surface of the cabinet or due to the locations of ventilation openings. The licensee explained that for those configurations, the lower damage threshold for sensitive electronics from NUREG/CR-6850, Volume 2 was applied rather than the damage threshold allowed using the FAQ 13-0004 approach for those sensitive electronics interior to the cabinet. NRC staffs review finds that the licensees treatment of sensitive electronics is acceptable for this application because it is consistent with the guidance in FAQ 13-0004 and NUREG/CR-6850, Volume 2.
In RAI 21, NRC staff cited sources of guidance on HRA and cited statements concerning minimum joint HEP values. NUREG-1921, EPRI/NRC-RES Fire Human Reliability Analysis Guidelines - Final Report, dated July 2012 (Reference 31), discusses the need to consider a minimum value for the joint probability of HFEs. NUREG-1921 refers to Table 2-1 of NUREG-1792, Good Practices for Implementing Human Reliability Analysis (HRA), dated April 2005 (Reference 32), which recommends that joint HEP values should not be below 1E-5.
Table 4-4 of EPRI TR 1021081, Establishing Minimum Acceptable Values for Probabilities of Human Failure Events, provides a lower limiting value of 1E-6 for sequences with a very low level of dependence. In the RAI, the NRC staff stated that the guidance in NUREG-1921 allows for assigning joint HEPs that are less than 1E-5, but only through assigning proper levels of dependency. Accordingly, the NRC staff requested explanation about the minimum joint HEP values used in the internal events and fire PRAs and whether the values used in the internal events PRA are less than 1E-6 and whether the values used for the fire PRA are less than 1E-5.
In response to RAI 21, the licensee explained that for the internal events PRA the minimum joint HEP values are set at 1E-6 except for HEP combination that includes an action associated with long-term heat removal. The licensee sets the minimum joint HEP for this lower dependency HEP combination to 9.5E-7. The NRC staff notes that per the guidance in Figure 6-1 of NUREG-1921 when an operator action is performed by a different crew this leads to Low
Dependency for even high stress scenarios, and therefore, according to Table 6-1 of NUREG-1921, the credit taken by the licensee for joint HEPs that include a long-term action is justified. Concerning the fire PRA, the licensee explained it was updated in 2020 (after the LAR submittal) to use the same minimum joint HEP values as used in the internal events PRA. The licensee stated that this meets the guidance provided in Section 6.2 of NUREG-1921 to apply the same minimum joint HEP values in the fire PRA as in the internal events PRA. In addition, the licensee provided the results of a sensitivity study for the fire PRA in which the minimum joint HEP values were increased to 1E-5 for all HEP combinations. The results show that the impact of this change in the minimum joint HEP only increased the total fire CDF and LERF by less than 2 percent. The NRC staff notes that this result is not apt to change significantly in the future, in part since FLEX actions are already included in the PRA models. The NRC staff finds the licensees use of minimum joint HEP values acceptable for this application because it meets the intent of applicable guidance to establish an appropriate minimum joint HEP; and even though the minimum joint HEP value for the fire PRA is set at 1E-6 opposed to 1E-5, the licensee shows through a conservatively performed sensitivity study that setting the minimum joint HEP for the fire PRA to 1E-5 rather than 1E-6 has a minimal impact on fire PRA risk.
In RAI 22, the NRC staff requested information about whether obstructed plume modeling was used and if it was used how it was modeled. Beside containing peak HRRs, NUREG-2178, Volume 1, Peak Heat Release Rates and Effect of Obstructed Plume, dated December 2015 (Reference 33), provides guidance on obstructed plume modeling and indicates that an obstructed plume model is not applicable to cabinets in which the fire is modeled at elevations of less than one-half of the cabinet. In response to RAI 22, the licensee confirmed that obstructed plume modeling was used in the fire PRA consistent with NRC guidance. The licensee explained that for modeling all panels the base on the fire was assumed to be located above half the panel height. The licensee explained that the base of the fire was generally modeled to be one foot below the top of the panel consistent with FAQ 08-0043, Location of Fire within Electrical Cabinets, dated August 4, 2009 (Reference 34). The NRC staff finds the licensees treatment of obstructed plume modeling to be acceptable for this application because it is in alignment with NRC guidance in NUREG-2178, Volume 1, and FAQ 08-0043.
In RAI 23, NRC staff requested information about how well-sealed cabinets were treated in the fire PRA including how fire propagation outside of well-sealed motor control center (MCC) cabinets at greater than 440 V was evaluated and whether well-sealed cabinets at less than 440 V are included in the Bin 15 count of ignition sources. The NRC staff noted that guidance in fire PRA FAQ 14-0009, Treatment of Well-Sealed MCC Electrical Panels Greater than 440 V, dated April 29, 2015 (Reference 35), provides the technique for evaluating fire damage from MCC cabinets having a voltage greater than 440 V. The NRC staff also noted guidance for cabinets at below 440 V as it regards the Bin 15 count in FAQ 08-0042 from NUREG/CR-6850, Volume 2, which clarifies the meaning of well-sealed and robustly secured. In response to RAI 23, the licensee explained that it applied the methodology provided in FAQ 14-0009 to fire scenario development for well-sealed and robustly secured MCCs equal to or greater than 440 V including applicable propagation of fire outside the cabinet enclosure. The licensee also explained that well-sealed and robustly secured cabinets less than 440 V were not included in the Bin 15 ignition source count. The licensee explained that it reevaluated several electrical cabinets in the Bin 15 ignition source count whose voltage levels were in question and determined that these panels did not meet the definition of well-sealed and robustly secured.
The NRC staff finds the licensees treatment of well-sealed and robustly secured MCCs equal to or greater than 440 V acceptable for this application because it is consistent with fire PRA FAQ-14-0009. The NRC staff finds the licensees treatment of well-sealed and robustly secured MCCs less than 440 V acceptable for this application because these cabinets were not included
in the Bin 15 ignition source count per the guidance in Chapter 6 of NUREG/CR-6850, Volume 2, using the definition of well-sealed and robustly secured in NUREG/CR-6850, Supplement 1.
In RAI 24 (Reference 11), the NRC staff requested information about how transient and hot work fire influence factors were assigned and whether the treatment was performed using guidance from FAQ 12-0064, Hot Work/Transient Fire Frequency Influence Factors, dated January 17, 2013 (Reference 36), or Section 6 of NUREG/CR-6850.
In response to RAI 24 (Reference 5), the licensee explained that influence factors were applied using the guidance in FAQ 12-0064 by an informal expert panel. The licensee explained that credit for administrative controls was not applied to reduce any transient fire frequencies, and therefore, any violations of transient combustible administrative controls are not applicable to assignment of influence factors. The licensee stated that an influence factor of 0 was not assigned for maintenance, occupancy, or hot work for any PAU. However, an influence factor of 0 for storage was assigned to the suppression pool and hydrogen storage PAUs.
In RAI 27 (Reference 14), the NRC staff requested further explanation regarding the 0 storage influence factor assigned to the suppression pool and hydrogen storage PAUs, and why a value of 50 was not assigned to any PAU. In its January 7, 2021, response to RAI 27 (Reference 7),
the licensee explained that a 0 influence factor for storage for the suppression pool was assigned because the suppression pool atmosphere is inerted nearly all of the time that the reactor is at power. The licensee further stated that there are no fixed ignition sources or fire probabilistic risk assessment (FPRA) targets in the suppression pool PAU, and that increasing the influence factor in this PAU would decrease the applicable transient bin frequencies in other PAUs. The NRC staff finds that using an influence factor of 0 within the suppression pool PAU is acceptable for this application because the suppression pool PAU is almost always inerted at power and there are no FPRA targets in the PAU. Therefore, the NRC staff agrees that assigning a value of 0 for the storage weighting factor for the suppression pool PAU will have an unimportant effect on this application.
Concerning the hydrogen storage PAU, the licensee explained that it consists of a fenced combustible exclusion zone, and that there are no FPRA targets in the PAU. The licensee further stated that increasing the influence factor in this PAU would decrease the applicable transient bin frequencies in other PAUs. The NRC staff finds that using an influence factor of 0 within the hydrogen storage PAU is acceptable for this application because the PAU consists of a fenced combustible exclusion zone and there are no FPRA targets in the PAU. Therefore, the NRC staff concludes that assigning a value of 0 for the storage weighting factor in this PAU will have an unimportant effect on this application.
The NRC staff also requested justification that an influence factor of 50 was not used in determining the frequency of transient fires in any location within the plant. The licensee indicated that an expert panel was performed and relied upon historical knowledge, plant experience, and FAQ 12-0064 guidance to assign the relative rankings. A review of work orders was not explicitly performed. The licensee indicated that materials are staged on the turbine deck (TB-50C) prior to an outage, but that location did not warrant a value of 50 for maintenance or hot work influence factors which affect the frequency of transient fires. The licensee indicated that analysis of location TB-50C assumed burnout of the location, and still is not a significant contributor to fire risk. Also, the licensee indicated that increasing an influence factor in this PAU will decrease the applicable transient bin frequency in other PAUs within the turbine building generic location. The NRC staff finds that not using an influence factor of 50
within the plant is acceptable for this application because: (1) an expert panel relying on historical knowledge, plant experience, and the NRC staffs latest guidance on influence factors for transient work fires, was used, and (2) because the location likely to require a factor of 50 was analyzed as PAU burnout and still was not risk significant. Therefore, the NRC staff concludes that not assigning a value of 50 to the turbine deck PAU will have an unimportant effect on this application.
In RAI 25 (Reference 11), the NRC staff requested information about whether Main Control Board (MCB) in the MCR and the panels behind constitute a single enclosure and whether this configuration was evaluated in accordance with NRC guidance. Fire PRA FAQ 14-0008, Main Control Board Treatment, dated July 22, 2014 (Reference 37), clarifies the definition of an MCB and effectively provides guidance for when to include the cabinets on the back side of the MCB as part of the MCB for fire PRA. It is important to distinguish between MCB and non-MCB cabinets because misinterpretation of the configuration of these cabinets can lead to incomplete or incorrect fire scenario development. In response to RAI 25 (Reference 5), the licensee explained that the MCB consists of a collection of relatively small console type panels that with minor exceptions have no controls on the rear side and no walk-through elements features.
Based on this description, the NRC staff finds that the MCB at Nine Mile Point 2 does not constitute a single enclosure with a walk-through feature with controls on the rear side that can be affected by fire that spans the walkway, and is therefore, not subject to the guidance in FAQ 14-0008.
In response to RAI 16 (Reference 5), the licensee confirmed that the implementation items identified in LAR Attachment 6 to update the PRA models prior to implementation of the RICT Program apply to both the internal events and fire PRAs.
In RAI 12f, the NRC staff indicated that the uncertainty analysis report identified the modeling associated with MCR abandonment due to loss of control (LOC) as a source of modeling uncertainty. The NRC staff indicated that the licensees report explains that no credit was taken for MCR abandonment due to LOC and concludes this conservative treatment has only a small impact on the application. The NRC staff noted in the RAI that conservatisms in the model can mask the delta risk associated with taking certain components out of service and, therefore, can lead to underestimation of the delta risk and overestimation of a RICT. The NRC staff also noted that the fire risk contribution from MCR abandonment scenarios due to LOC may be significant.
In its response to RAI 12f, the licensee indicated that prior to the 2020 update of the Nine Mile Point 2 fire PRA, LOC abandonment was identified as a source of uncertainty due primarily to the contribution of a single MCB fire (P852) to the overall fire risk. The licensee stated that this scenario contributed 12 percent to the fire CDF and 26 percent to the fire LERF making it the second most risk-significant CDF and top LERF scenario. The only other potential LOC candidate with a similar lack of available success paths is an MCB fire in P601. The licensee indicated that given the challenges associated with crediting LOC abandonment, treatment of MCB fire scenarios using NUREG-2178, Volume 2, was subsequently incorporated into the 2020 update of the Nine Mile Point 2 fire PRA in order to improve realism in the determination of fire risk. The licensee indicated that its updated treatment utilizes an MCB event tree which resulted in a more comprehensive and realistic treatment of fires originating in the MCB.
The licensee indicated that the decision to abandon for LOC requires development of a unique HEP in addition to the execution steps associated with transferring control to the remote shutdown panel. Further, it stated that for LOC abandonment, the HEP applicable to Nine Mile
Point 2 for the decision to abandon may range from 6.0E-2 to 1.0 based on the guidance in NUREG-1921, Supplement 2. For P852-LOC, the licensee stated that the conditional core damage probability may be conservatively assumed to correspond to the HEP for the decision to abandon, which is assumed to be 0.2 based on a review of plant procedures and an assumption about training conditions.
The licensee indicated that with its revised uncertainty analysis, the potential credit is estimated to be only slightly above 1 percent of the total fire CDF. Accordingly, the licensee indicated that not crediting LOC abandonment in the NUREG-2178, Volume 2 event tree approach is now a minor conservatism and no longer considered a significant source of uncertainty. Thus, the potential credit from LOC abandonment in the fire PRA would have no impact on the delta risk calculations for RICT. The licensee further indicated that the updated MCB treatment was subject to a focused-scope peer review and the results from that review have been addressed in the applicable FPRA notebook.
The NRC staff inquired in RAI 28 (Reference 14), on whether the focused-scope peer review covered both NUREG-2178, Volume 2 on the MCB and the use of NUREG-1921, Supplement 2 on MCR abandonment due to LOC. The staff also asked whether any F&Os were generated by the focused-scope peer review and if so, whether these F&Os were closed by an F&O closure review or by another peer review. In response to RAI 28, the licensee indicated that the scope of the focused-scope peer review included an FSS review in the fire PRA on the MCB event tree approach for fire PRA in NUREG-2178, Volume 2. The licensee indicated that there was one finding-level F&O related to the FSS scope involving documentation of the fire modeling tools.
The FSS supporting requirement was considered met, but the F&O was generated to correct two inconsistencies between the description and the actual model application. In both cases, the text was updated to match the model. The licensee stated that the F&O was not closed using the NEI 07-12 Appendix X process for F&O closure. With regards to the peer review on NUREG-1921, Supplement 2, the licensee indicated that The [focused-scope peer review] did not address NUREG-1921 Supplement 2 since the approach was not applied.
The NRC staff finds the licensees treatment of MCB fires leading to abandonment due to LOC acceptable for this application since the MCB event tree from NUREG-2178, Volume 2, was used and peer reviewed. The staff finds that the licensee does not need to close the documentation F&O cited in its RAI response to make a conclusion on this LAR, as the F&O has no technical consequence on the LAR. With regards to the peer review of the licensees use of NUREG-1921, Supplement 2, the NRC staff finds that neither a peer review of its implementation nor a NRC staff finding on the acceptability of the use of NUREG-1921, Supplement 2, in the licensees fire PRA is necessary because the licensee clearly stated that the approach from NUREG-1921, Supplement 2 was not applied.
Based on its review, the NRC staff finds that the fire PRA has been adequately peer reviewed against the version of the PRA Standard endorsed in RG 1.200, Revision 2 and the fire PRA F&Os have been closed or adequately resolved for the application. Based on these findings, the fire PRA is technically acceptable to support the RICT Program, including RICT calculations, once the implementation items to update the fire PRA listed in the license condition are completed.
3.1.4.1.1.3 PRA Technical Adequacy Conclusions LAR Attachment 6 identifies two implementation items associated with PRA technical adequacy that will be completed prior to the implementation of the RICT Program:
The internal flooding PRA model will be updated to incorporate the new pipe rupture frequencies using the pipe length approach per the latest revision of EPRI TR 1013141, Revision 3, Pipe Rupture Frequencies for Internal Flooding Probabilistic Risk Assessments, dated December 2008 (Reference 38).
The internal flooding PRA model will be updated to incorporate resolutions to F&Os 5-1, 8-1, and 8-2 from the focused-scope peer review of the internal events PRA regarding support system initiating event fault tree modeling. However, the response to RAI 6 stated that since the LAR submittal, an F&O closure review was performed in 2020 that closed out these F&Os. Therefore, this implementation item is already complete.
Based on its review of the licensees submittal and assessments, the NRC staff concludes that the Nine Mile Point 2 PRA models for internal events, including internal flooding, and for fire events used to implement the RICT Program satisfy the guidance of RG 1.200, Revision 2. The NRC staff based this conclusion on the findings that the PRA models conform sufficiently to the applicable industry PRA standards for internal events, including internal flooding, and for fire events at an appropriate capability category, considering the licensees acceptable disposition of the peer review F&Os, the proposed implementation items, and the NRC staff review.
Based on the review of the provided information, the Nine Mile Point 2 PRA models were determined to be of sufficient technical adequacy to support implementation of the RICT Program. Therefore, the NRC staff finds that the licensee has satisfied the intent of Sections 2.3.1, 2.3.2, and 2.3.3 of RG 1.177, Revision 1, and Sections 2.3 and 2.5 of RG 1.174, Revision 3, and that the Nine Mile Point 2 PRA acceptability, once the implementation items are satisfactorily implemented, will be sufficient to implement RMTS in accordance with NEI 06-09, Revision 0-A.
3.1.4.1.1.4 PRA Update Process In the LAR, the term RTR model and CRMP model are both used and refer to the same model.
The licensee has established a periodic update and review process for the PRAs that are used in the RTR model, which is described in Enclosure 7 of the LAR. The NRC staff reviewed the licensees PRA model update process to assess if the PRA models that support the RICT Program are maintained consistent with the as-built, as-operated, and maintained plant.
The licensee explained that its process is consistent with NEI 06-09, Revision 0-A. The licensee explains in Section 2 of LAR Enclosure 7 that its PRA update requirements include:
review of plant changes and discovered conditions for potential impact on the PRA models and the CRMP model including risk calculation to support the RICT Program (e.g., plant changes, plant or industry operational experience, and errors or limitations identified in the modeling) review of plant changes that meet the plant procedure criteria for updating the PRA models before the periodic update
periodic update of the PRA models at least every two refueling outages performance of interim risk analyses or implementation of administrative restrictions on use of the RICT Program, if significant plant changes or discovered conditions cannot be implemented immediately Section 2.3.4 of NEI 06-09, Revision 0-A, specifies that criteria shall exist in PRA configuration risk management to require PRA model updates concurrent with implementation of facility changes that significantly impact RICT calculations. LAR Enclosure 7 states that if, a plant change or a discovered condition is identified that has a significant impact on the RICT Program calculations [], an unscheduled update of the PRA models will be implemented. In RAI 8, the NRC staff requested explanation of the conditions that must exist and criteria that would be used to require a PRA update, including what is meant by the term significant impact to the RICT Program calculations. In the response to RAI 8, the licensee explained that the internal events and fire PRA update procedures require evaluation of plant changes or discovered conditions against set criteria. The evaluation to determine whether the PRA models are adequate to support risk-informed applications is performed by either qualitative screening or quantitative criteria. The quantitative criteria include relative or absolute change in CDF or LERF, as well as changes in significant sequences and configuration risk. The NRC staff finds the licensees process for determining when an unscheduled PRA update is needed acceptable because it is capable of identifying changes that could impact the RICT Program.
The NRC staff concludes the licensees PRA model update process is consistent with RG 1.200 and consistent with the guidance in NEI 06-09, Revision 0-A, and is therefore acceptable.
3.1.4.1.1.5 Risk Assessment Approaches and Methods Changes to the PRA are expected to occur over time to reflect changes in PRA methods, and changes to the as-built, as-operated, and maintained plant to reflect the operating experience at the plant as specified in RG 1.200, Revision 2. Changes in PRA methods are addressed by proposed TS Section 5.5.15e:
The risk assessment approaches and methods shall be acceptable to the NRC.
The plant PRA shall be based on the as-built, as-operated, and maintained plant; and reflect the operating experience at the plant, as specified in Regulatory Guide 1.200, Revision 2. Methods to assess the risk from extending the completion times must be PRA methods approved for use with this program in Amendment Nos. [XXX/YYY], or other methods approved by the NRC for generic use; and any change in the PRA methods to assess risk that are outside these approval boundaries require prior NRC approval.
The NRC staff finds that this proposed TS change is acceptable because it adequately implements the RICT Program using models, methods, and approaches consistent with applicable guidance that are acceptable to the NRC.
3.1.4.1.1.6 PRA Acceptability Conclusion The licensee has reviewed the PRA using endorsed guidance and adequately addressed or will address all identified issues, has established a periodic update and review process to update the PRA and associated CRMP model to incorporate changes made to the plant and PRA methods and data consistent with the RICT Program, and will calculate RICTs using
NRC-accepted PRA methods. Therefore, the NRC staff concludes that the licensee has and will maintain a PRA that is technically adequate to support implementation of the RICT Program.
3.1.4.1.2 Scope of the PRA The NRC staff's SE in NEI 06-09, Revision 0-A, states that sources of risk besides internal events and internal fires (i.e., seismic and other external events) must be quantitatively assessed if they contribute significantly to configuration-specific risk. The SE further states that bounding analyses or other conservative quantitative evaluations are permitted where realistic PRA models are unavailable. In addition, the SE concludes that if sources of risk can be shown to be insignificant contributors to configuration risk, then they may be excluded from the RMTS.
The Nine Mile Point 2 PRA models that will be used for the RICT Program include contributions from internal events, including internal flooding, and internal fire events. In addition, the licensee provided a bounding estimate of the seismic CDF and LERF and will add those CDF and LERF values into the change in risk used to calculate RICTs consistent with the guidance in NEI 06-09, Revision 0-A. The LAR refers to this approach as applying a seismic risk penalty factor. In LAR Enclosure 4, the licensee describes its process, which includes hazard screening, for determining that other external hazards have an insignificant impact on configuration risk including extreme winds and external flooding.
3.1.4.1.2.1 Seismic Hazard Contribution to the RICT The licensee explained in LAR Enclosure 4 that RICT calculations will include a risk contribution from seismic events using a seismic penalty approach. The seismic penalty, commonly used in the RICT, is an estimation of seismic core damage frequency (SCDF) performed by a mathematical convolution of seismic hazard curves. A seismic penalty also exists for seismic large early release frequency (SLERF) and is obtained by multiplying the calculated SCDF by an average seismic conditional large early release probability. The licensees approach for including the seismic risk contribution in the RICT calculation is to add a constant SCDF and SLERF to each calculation for Nine Mile Point 2. Section 3.3.5 of NEI 06-09, Revision 0-A, states that for stations without external events PRAs, the station should apply one of three acceptable methods to determine external event risk. The second, often used, method is a reasonable bounding analysis which must be case-specific, technically verifiable, and shown to be conservative from the perspective of RICT determination.
The seismic penalty is different depending on whether the containment is inerted or de-inerted.
To estimate a RICT when the containment is inerted, the licensee proposed to add an SCDF contribution of 6.4E-7/year and an SLERF contribution of 3.2E-7/year to the configuration specific delta risk contribution from internal events (including internal flooding) and internal fire events. To estimate a RICT when the containment is de-inerted, the licensee proposed to add the same SCDF penalty of 6.4E-7/year but an increased delta SLERF penalty of 6.4E-7/year (i.e., conditional large early release probability equal to 1.0).
The baseline SCDF and SLERF estimates were derived using a bounding analysis approach based on an updated seismic hazard as described by the licensee in Section 3 of LAR . In response to the NRC request pursuant to 10 CFR 50.54(f) that licensees reevaluate the seismic hazard at sites against the current NRC requirements and guidance, the licensee completed a site-specific Nine Mile Point 2 hazard analysis dated March 31, 2014 (Reference 39), using EPRI guidance in the Seismic Evaluation Guidance: Screening, Prioritization and Implementation Details (SPID), dated February 2013 (Reference 40). The
probabilistic hazard analysis also used information and guidance from the Central and Eastern United States (CEUS) for Nuclear Facilities report dated January 2012 (Reference 41), and the EPRI Ground Motion Model for the CEUS report dated June 2013 (Reference 42). Using the updated seismic hazard for Nine Mile Point 2, the licensee determined the SCDF and SLERF for Nine Mile Point 2 by applying the method to estimate a plant-level fragility. The NRC staff finds this approach consistent with the approach used in the NRC report on Generic Issue 199 (GI-199), Implications of Updated Probabilistic Seismic Hazard Estimates in Central and Eastern United States on Existing Plants, dated August 2010 (Reference 43).
In Section 3 of LAR Enclosure 4, the licensee explains that it used a plant-level fragility based on the 0.5 g high confidence of low probability of failure (HCLPF). The same plant-level fragility value was used in its individual plant examination of external events (IPEEE) seismic margins analysis (SMA) consistent with its review level earthquake. This is higher than the 0.3 g screening value recommended by NUREG-1407, Procedural and Submittal Guidance for the Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities, dated June 1991 (Reference 44). The HCLPF is the capacity representing 95 percent confidence that the conditional probability of failure of an SSC is 5 percent or less. For the IPEEE, the SMA HCLPF of 0.5 g was the 84th percentile. For this application, the licensee stated that the 50th percentile HCLPF of 0.42 g was used. The one exception to the applicability of this plant-level fragility was to the fragility of the nonsafety-related high-pressure nitrogen bottle supply to the SRVs. However, the high-pressure nitrogen bottle supply is credited after 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> when emergency depressurization is needed, so it does not impact CDF or LERF.
The uncertainty parameter for seismic capacity was represented by a combined beta factor of 0.46. The analysis used the hazard curve for peak ground acceleration (PGA) to determine the SCDF estimate of 6.4E-7/year. The NRC staff finds that this approach is consistent with the approach used in the NRC report on GI-199.
In RAI 26 (Reference 13), the NRC staff noted that IPEEE HCLPF value of 0.42 g was used rather than the HCLPF value of 0.23 g presented in Table C-2 of the GI-199 report and requested explanation for use of the higher capacity value. The NRC staff also noted reference in the LAR to sensitivity studies that were performed on the risk impact of changing the seismic hazard intervals and ground motion frequencies, and therefore, requested description of the sensitivity study results and how the results were used. In response to RAI 26 (Reference 6),
the licensee explained that the 0.23 g PGA HCLPF value cited from the 2010 GI-199 report is the same value reported in the 1995 Nine Mile Point 2 IPEEE submittal and applies to the lowest calculated HCLPF of any SSC in the Nine Mile Point 2 IPEEE seismic safe shutdown success paths. The licensee explained that this SSC was the nonsafety-related (non-seismic qualified) high pressure nitrogen supply used to keep the SRVs open in the long term (i.e., after 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />). The licensee explained there are also two redundant success paths available that provide an alternative to emergency depressurization and low-pressure injection. The licensee explained that because this fragility is not important to seismic risk, the higher HCLFP value of 0.42 g could be used for the plant to represent the plant-level capacity (from which the 50th percentile HCLFP of 0.5 g was designated for this application).
Also, in response to RAI 26, the licensee described the seismic interval and ground motion frequency studies cited in the LAR. The licensee explained that in three sensitivity cases, different adjustments were made to the eight baseline hazard intervals which resulted in an 8 percent, 2 percent, and negligible increase in SCDF. The fourth sensitivity case, in which the number of hazard intervals was increased to 18 intervals (using all the data points in the PGA hazard curve) resulted in the same CDF as the baseline case (i.e., 6.4E-7/year). Accordingly, the NRC staff finds that the impact of how the seismic hazard intervals were defined has
minimal impact on seismic risk and, therefore, on the application. The licensee explained in another sensitivity case where the 2.5 Hertz spectral frequency was used instead of the PGA there was a significant decrease in SCDF. However, the NRC staff notes that the PGA is the most common metric used in nuclear power plant SPRAs and that using the PGA is conservative compared to the results of the sensitivity study, and therefore, is acceptable for this application.
The bounding SLERF penalty was determined using the estimated bounding SCDF and multiplying it by an average seismic CLERP. The licensee stated that the average seismic CLERP used was based on information from the Nine Mile Point 2 SPRA that was performed during the licensees IPEEE, although not required but performed in order to provide a quantitative perspective of the SMA, and the results from quantification of the Nine Mile Point 2 full power internal events PRA model. The licensee presented the dominant seismic accident sequences and from those scenarios calculated an average seismic CLERP of 0.32. The NRC staff notes that these accident sequences represent nearly all of the seismic risk. Also, to account for potential uncertainties, the licensee stated that a conservative CLERP value of 0.5 was used to determine the SLERF penalty of 3.2E-7/year for the RICT calculation. The use of this increased value provides additional safety margin. The seismic penalty of 3.2E-7/year will be used when the containment is inerted. The licensee stated that for determining the SLERF penalty for when the containment is de-inerted, insights from the internal events Level 2 PRA model were used. The Nine Mile Point 2 Level 2 PRA model indicates that, when the containment is de-inerted, the Nine Mile Point 2 Level 2 full power internal events PRA credits steam inerting in the primary containment to mitigate hydrogen deflagration with a 0.5 failure probability. Accordingly, the licensee conservatively assumed that, when the containment is de-inerted, the seismic CLERP is equal to 1.0. Therefore, the seismic penalty that will be used when the containment is de-inerted is 6.4E-7/year.
The NRC staff notes that, during application of a RICT, the component is taken out of service which potentially increases the SCDF and SLERF. It is not certain to the NRC staff that the SCDF and SLERF penalties proposed by the licensee bound all possible RICT configurations.
However, the NRC staff also notes that seismically induced failures of equipment are highly correlated (i.e., for a given seismic event if one SSC fails, then the redundant SSCs also fail).
Accordingly, the increase associated with taking an SSC out of service is non-existent or small and therefore bounded by the SCDF and SLERF penalties applied to the RICT calculations.
The NRC staff finds that, during RICTs for SSCs credited in the design basis to mitigate seismic events, the licensee's proposed methodology captures the risk associated with seismically induced failures of redundant SSCs because such SSCs are assumed to be fully correlated. By assuming full correlation, the seismic risk for those RICTs will not increase if one of the redundant SSCs is unavailable because simultaneous failure of all redundant trains would be assumed in an SPRA. During RICTs for SSCs not credited in the design-basis seismic event, but which could be used when credited SSCs fail, the proposed methodology for considering seismic risk contributions may be non-conservative. The basis for this statement is that the seismically induced failure of such SSCs during the RICT may not be included in the risk increase. However, the occurrence and degree of non-conservatism depends on the plant HCLPF value used for the RICT calculations, as compared to the HCLPF values for such SSCs.
The degree of non-conservatism will be low or nonexistent if the plant HCLPF value is lower than most or all SSCs impacted by a seismic event. During RICTs for SSCs that are not used to mitigate a seismic event, the proposed methodology for considering seismic risk contributions is conservative because the seismically induced failure of such SSCs would not result in a risk
increase associated with the plant configuration during the RICT, but the baseline seismic risk is still included in the calculation.
The licensee also calculated the seismically induced LOOP frequency of 1.4E-5/year for Nine Mile Point 2, which is approximately 1.8 percent of the total unrecovered LOOP frequency in the internal events PRA for Nine Mile Point 2. The NRC staff evaluated the analysis and finds that the analysis adequately addresses the impact of seismically induced LOOP and has an insignificant impact on the RICT Program calculations.
In summary, the NRC staffs review finds the licensees proposal to use the SCDF contributions of 6.4E-7/year and a SLERF contribution of 3.2E-7/year as an addition to the configuration-specific delta CDF and delta LERF from the internal events (including internal flooding) and internal fire initiating events, acceptable for the licensees RICT Program for Nine Mile Point 2 because:
The licensee used the most current site-specific seismic hazard information for Nine Mile Point 2 The licensee used an acceptably low plant HCLPF value of 0.42 g consistent with the information for Nine Mile Point 2 in the GI-199 evaluation to determine the seismic CDF penalty The licensee determined a seismic LERF penalty based on its seismic CDF estimate combined with a conservative estimate of the seismic CLERP Adding baseline seismic risk to RICT calculations, which assumes the fully correlated failures, is conservative for SSCs credited in seismic events, while any potential non-conservative results for SSCs that are not credited in seismic events is small or nonexistent, as discussed above 3.1.4.1.2.2 Extreme Winds and Tornado Hazards Section 4 of Enclosure 4 to the LAR discusses the licensees evaluation of the extreme winds and tornadoes impact on this application. Table E4-8 of the same enclosure discusses the basis for the insignificant impact of extreme winds and tornadoes (including tornado-generated missiles) for this application and relies on the design of SSCs and a tornado missile analysis.
In Section 4 of LAR Enclosure 4, the licensee stated that key equipment and structures are designed to withstand tornadoes with a maximum rotational velocity of 290 miles per hour (mph)
(plus an additional transitional velocity of 70 mph, a maximum pressure drop of 3 pounds per square inch (psi), and a maximum rate of pressure drop of 2 psi per second that equate to a resultant wind speed velocity of 360 mph). The licensee stated that the results of its IPEEE tornado missile risk evaluation indicate that the tornado missile CDF is less than 1E-7/year and that the tornado frequencies used in the IPEEE bound the more current tornado wind speeds presented in NUREG/CR-4461, Revision 2, Tornado Climatology of the Contiguous United States, dated February 2007 (Reference 45). Additionally, the licensee explained that it performed a more current evaluation of tornado missile protection at Nine Mile Point 2 in response to Regulatory Issue Summary 2015-16, Tornado Missile Protection, dated June 10, 2015 (Reference 46). The tornado missile protection evaluation identified components that may be directly or indirectly impacted by tornado missiles and determined these potential vulnerabilities meet Nine Mile Point 2 design and licensing bases per the Nine Mile Point 2
USAR. However, the licensee also stated that these potentially vulnerable SSCs could, nonetheless, contribute to tornado risk. Therefore, as documented in the LAR, the licensee performed an evaluation showing that probability of tornado strike on an unprotected SSC was much less than 1E-6/year.
In summary, the NRC staff finds that the extreme winds and tornadoes, including tornado missiles, have an insignificant contribution to configuration risk and can be excluded from the calculation of the proposed RICTs.
3.1.4.1.2.3 External Flooding In Section 5 of LAR Enclosure 4, the licensee evaluated the risk from external flooding hazard.
The licensees conclusions of the insignificant impact of the external flooding hazard on this application are based on the results documented in the licensees flood hazard reevaluation report (FHRR) dated March 12, 2013 (Reference 47), for Nine Mile Point 2.
The Nine Mile Point 2 FHRR concluded that the results of all flood causing mechanisms, except local intense precipitation (LIP), are bounded by the current licensing basis and do not pose a challenge to the plant. The licensee stated that a reevaluation of LIP found that LIP produced a water surface elevation less than the current licensing basis water surface elevation of 262.5 feet at Nine Mile Point 2. Additionally, because the flood duration was estimated in the FHRR to be 52.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> opposed to the 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br /> assumed in the current licensing basis, the impact of the increased duration was evaluated in a plant report. This reevaluation considered flood inundation time, in-leakage, and building drainage features and did not credit temporary barriers or repositioning of doors. The licensees LIP reevaluation concluded that a LIP event will not cause enough water to enter and accumulate in buildings to affect safety-related SSCs.
The licensee also stated that as a defense-in-depth measure, mitigating strategies assessment for flooding confirms that FLEX will remain deployable during a LIP with installation of temporary flood barriers. The NRC staffs assessment of the licensees LIP evaluation is documented in a letter dated September 20, 2017 (Reference 48).
The NRC staffs evaluation of the licensees consideration of external flooding hazards for Nine Mile Point 2 finds that the external flooding hazard has an insignificant contribution to configuration risk and can be excluded from the calculation of the proposed RICTs because the reevaluated flood hazard in the FHRR is either bounded by the design basis flood elevation or has adequate physical margin against flood water intrusion for relevant SSCs, and includes conservatism in the analysis.
3.4.1.1.2.4 Other External Hazards Besides the external flooding and high winds and tornadoes discussed above, the licensee provided rationale for the insignificant impact of non-seismic external hazards and other hazards for Nine Mile Point 2 in Table E4-8 of Enclosure 4 to the LAR. In Enclosure 4, the licensee stated that this assessment is based on an update of the Nine Mile Point 2 IPEEE external hazard screening evaluation. The licensee stated that non-mandatory Appendix 6-A of the ASME/ANS PRA Standard provides a guide for identification of most of the possible external events for a plant site. The NRC staff notes that this list is essentially the same list of hazards as presented in Table 4-1 of NUREG-1855, Revision 1, Guidance on the Treatment of
Uncertainties Associated with PRAs in Risk-Informed Decisionmaking, dated March 2017 (Reference 49). According to the LAR, the licensee evaluated the following external hazards:
Aircraft Impacts Avalanche Biological Events Coastal Erosion Drought External Flooding (discussed above)
Extreme Wind or Tornado (including generated missiles, discussed above)
Fog Forest or Range Fire Frost Hail High Summer Temperature High Tide, Lake Level or River Stage Hurricane Ice Cover Industrial or Military Facility Accident Internal Fires (evaluated in an internal fire PRA)
Internal Flooding (evaluated in the internal events PRA)
Landslide Lightning Low Lake Level or River Stage Low Winter Temperature Meteorite or Satellite Impact Pipeline Accident Release of Chemicals in Onsite Storage River Diversion Sand or Dust storm Seiche Seismic Activity (treated by adding the bounding seismic risk to the RICT calculations, discussed above)
Snow Soil Shrink-Swell Storm Surge Toxic Gas Transportation Accidents Tsunami Turbine-Generated Missiles Volcanic Activity Waves Section 2 of Enclosure 4 to the LAR states that the overall process for addressing external hazards considers two aspects of the external hazard contribution to risk.
The first is the contribution from the occurrence of beyond design basis conditions (e.g., winds greater than design, seismic events greater than
design-basis earthquake). These beyond design basis conditions challenge the capability of the SSCs to maintain functionality and support safe shutdown of the plant.
The second aspect addressed are the challenges caused by external conditions that are within the design basis, but still require some plant response to assure safe shutdown (e.g., high winds or seismic events causing a LOOP). While the plant design basis assures that the safety-related equipment necessary to respond to these challenges is protected, the occurrence of these conditions nevertheless cause a demand on these systems that presents a risk.
In LAR Table E4-8, the licensee provided a disposition for each non-seismic external hazard as well as other hazards and concludes that no unique PRA model for these hazards is required in order to assess configuration risk for the RICT Program, with the exception of internal flooding and internal fire, which are addressed by a PRA.
The NRC staff notes that the preliminary screening criteria and progressive screening criteria presented in LAR Table E4-9 are the same criteria presented in Supporting Requirements EXT-B1 and EXT-C1 of the ASME/ANS PRA Standard for screening external hazards in the 2009 ASME/ANS PRA Standard, as endorsed by RG 1.200, Revision 2.
The basis for exclusion of certain hazards from consideration in the determination of RICTs due to their insignificance to the calculation of configuration risk was also provided in Enclosure 4 of the LAR. The licensee stated that its IPEEE external screening evaluation was updated to support this LAR. External hazards considered by the licensee were listed in Table E4-8 of to the LAR. The NRC staff finds that the list of external hazards considered by the licensee is consistent with the hazards listed in Appendix 6-A of the ASME/ANS RA-Sa-2009 PRA Standard, which is endorsed in RG 1.200, Revision 2.
The NRC staffs review of the information in the submittal finds that the contributions from the other external hazards have an insignificant contribution to configuration risk and can be excluded from the calculation of the proposed RICTs for Nine Mile Point 2 because they either do not challenge the plant or they are bounded by the external hazards analyzed for the plant.
3.4.1.1.2.5 External Hazards Conclusion The NRC staff concludes that the licensee's approach for considering the impact of seismic events, non-seismic external hazards, and other hazards for Nine Mile Point 2 in the RICT calculations, is acceptable because the licensee included a technically acceptable quantitative assessment of the seismic risk for Nine Mile Point 2 consistent with the guidance in NEI 06-09, Revision 0-A, and demonstrated the insignificant contribution to configuration risk from other external hazards on the proposed RICTs.
3.1.4.1.2.6 Shutdown Risk Shutdown risk is not applicable to this LAR since the LAR only applies to Modes 1 and 2.
3.1.4.1.2.7 PRA Scope Conclusions According to the LAR, the proposed RICT Program is only applicable to Modes 1 and 2; therefore, risk evaluations for Modes 3, 4, and 5 are not relevant to the proposed change.
Based on the above, the NRC staff finds that the licensee has satisfied the intent of Section 2.3.2 of RG 1.177, Revision 1, and Sections 2.3 and 2.5 of RG 1.174, Revision 3, and that the scope of the PRA model and the use of a bounding analysis for seismic events is appropriate for this application.
3.1.4.1.3 PRA Modeling Section 3.2.2 of NEI 06-09, Revision 0-A, specifies that to evaluate a RICT for a given required action, the specific systems or components involved should be directly modeled in the PRA or, if not directly modeled, the functions directly correlated to the specific systems or components are modeled in the PRA. TSTF-505, Revision 2 also states that required actions for systems that do not affect CDF or LERF or for which a RICT cannot be quantitatively determined are not in scope of the program. The licensee identified, for each TS LCO required actions for which the RICT Program is proposed to apply, the following:
The SSCs are included within the scope of the PRA models, or surrogate SSC or operator errors modeling that bounds the functions of the TS SSCs; The success criteria parameters used to determine PRA functional determination are the same as the design-basis success criteria parameters or, if different, plant-specific analyses that were used to support the PRA are justified Commitments to update the PRA models to include the SSCs covered by the TS The licensee stated that CCFs are appropriately addressed, the CRMP provides the capability to select the system as out of service in order to calculate a RICT, and the CRMP is maintained consistent with the baseline PRA model.
3.1.4.1.3.1 System and Surrogate Modeling The NRC SE to NEI 06-09, Revision 0-A, and TSTF-505, Revision 2, specify that the LAR is to provide a comparison of the TS functions to the PRA modeled functions and that justification be provided to show that the scope of the PRA model is consistent with the licensing basis assumptions. Table E1-1 in Enclosure 1 to the LAR, as supplemented by the licensee in its letter dated August 28, 2020:
Identifies each TS LCO condition in scope of the RICT Program and, the SSCs covered by the LCO, as applicable Indicates whether the SSC is modeled in the PRA For the cases in which the SSCs are not explicitly modeled, an explanation of how the PRA uses surrogate events that bound the function(s) of the TS LCO SCC(s) or identification of commitments to update the PRA models to include the SSCs In response to RAI 15 (Reference 5), the licensee provided additional information on I&C modeling in the Nine Mile Point 2 PRA. The licensee explained that some I&C components are modeled explicitly in the PRA, while others assumed to be included within the boundary of main components (e.g., instrument air compressor boundary includes the compressor, motor, local
circuit breaker, and local I&C circuitry). The licensee stated that for I&C functions not explicitly modeled, a surrogate is identified and is mapped for use in the PRA used in the RICT Program.
The licensee presented a table listing the system functions encompassed by TS in the RICT Program and instrumentation failures modeled in the PRAs. This list included sensors (e.g.,
pressure, flow, and level transmitters), switches, and relays, as well as proposed surrogates for I&C not explicitly modeled in the PRA. The NRC staff notes the surrogate component failures reflect or bound the impact of the failures of the unmodeled I&C. The NRC staff finds the licensees modeling of analog I&C systems is acceptable for the application, because either the I&C system is explicitly modeled or an appropriate component failure is used as a surrogate.
With regards to modeling digital I&C, the licensee stated in response to RAI 15 that a digital feedwater level control system was installed at Nine Mile Point 2 during the most recent outage, but it has not yet been modeled in the PRAs. The licensee explained, however, that a bounding sensitivity study was performed. The results of the sensitivity study for 11 LCOs whose RICTs could be affected indicate that RICT remained unchanged.
LAR Table E1-1 of Enclosure 1 states that for TS LCO Condition 3.3.5.1 (ECCS Instrumentation) Condition C (ECCS Actuation instrumentation), HPCS discharge instrumentation is not modeled and failure of the HPCS minimum flow valve will be used as a surrogate for HPCS discharge instrumentation failure. In response to RAI 9.c, the licensee justified the proposed surrogate. The licensee explained that the minimum discharge flow instruments are provided to protect the HPCS pump from overheating during operation when the associated injection valve (which provides ECCS flow during transients and accidents) is not sufficiently open. The NRC staff notes that the HPCS pump overheat protection will trip the HPCS pump and therefore result in no HPCS flow, which is the same result as failure of the HPCS instrumentation to initiate flow. The NRC staff finds that the licensees surrogate modeling of the HPCS instrumentation is sufficient to reflect LCO 3.3.5.1.
3.1.4.1.3.2 Success Criteria The NRCs May 17, 2007, SE to NEI 06-09, Revision 0-A, specifies that the LAR is to provide a comparison of the TS functions to the PRA modeled functions and that sufficient justification is to be provided to show that the scope of the PRA model, including applicable success criteria, is consistent with the licensing basis assumptions. Table E1-1 in Enclosure 1 to the LAR summarizes how the PRA success criteria differs from the design-basis success criteria.
For TS LCO Condition 3.6.1.7.A (Suppression Chamber-to-Drywell Vacuum Breakers), the licensee proposed an implementation item that PRA modeling will be incorporated to include the associated failure prior to exercising the RICT Program. In response to RAI 9.a (Reference 5),
the licensee explained that internal events and fire PRA models have been updated to include the failure of the suppression chamber-to-drywell vacuum breakers to open. The licensee stated that the success criteria used is consistent with the design-basis success criteria. The NRC staff notes that Table E1-1 of the LAR indicates that there are four lines with two vacuum breakers in series per line and three lines are required for successful vacuum relief for the drywell.
For TS LCO Condition 3.7.1 (SW System and UHS) Condition C (One SW subsystem inoperable for reasons other than Condition A and B), LAR Table E1-1 of Enclosure 1, and an associated implementation item in LAR Attachment 6, state that the success criteria are consistent with the design basis except when UHS temperature is > 82°F and that the PRA model will be updated to include this condition prior to exercising the RICT Program. In the
response to RAI 9.b and RAI 16, the licensee explained that the internal events and fire PRA models have been or will be updated to incorporate SW system alignment and success criteria modeling when the UHS is greater than 82 degrees Fahrenheit (F). The licensee explained that when the UHS is greater than 82 F, five SW pumps are assumed to be in-service and that the success criteria is four successful pumps for a LOCA without a LOOP, consistent with the design-basis success criteria (i.e., so an additional SW pump is needed to compensate for the warmer temperatures). The licensee explained that the UHS temperature will be tracked explicitly in the RTR tool or a conservative assumption for the configuration will be used. The NRC staff finds that the licensees PRA model is sufficient to reflect LCO 3.7.1.C and that UHS temperature will be monitored to know when the additional SW pump is required.
In RAI 9.d, the NRC staff noted that the PRA success criterion used to model systems associated with TS LCO Condition 3.5.1.A (Low Pressure ECCS Injection/Spray) Condition A (One low pressure ECCS injection/spray subsystem inoperable) is different from the design-basis success criterion indicated in LAR Table E1-1 of Enclosure 1. The NRC staff requested justification for why the PRA success criterion (i.e., One of four subsystems) is less restrictive than the design-basis success criterion (i.e., Two of four subsystems). In response to RAI 9.d, the licensee explained that the PRA success criteria is based on EPRI Modular Accident Analysis Program calculations for a large LOCA scenario, which is the bounding scenario for low pressure ECCS injection or spray. Furthermore, the licensee explained that sensitivity studies using the more restrictive low pressure core injection success criteria (i.e.,
two of four subsystems) demonstrate that the RICT calculations are not sensitive to this PRA model assumption. The NRC staff finds that the licensees PRA model is sufficient to reflect TS LCO 3.5.1.A.
For TS LCO Condition 3.3.7.2 (Mechanical Vacuum Pump Isolation Instrumentation)
Condition A (One or more channels inoperable), LAR Table E1-1 of Enclosure 1, and the associated implementation item in LAR Attachment 6 state that the PRA models will be updated to include these SSCs prior to exercising the RICT Program. In RAI 9.e, the NRC staff noted the same wording was used in the corresponding implementation item presented in LAR and requested a description of the modeling that will be incorporated to reflect TS LCO 3.3.7.2.A to calculate a RICT. The NRC staff also requested explanation of how inoperability of the mechanical vacuum pump isolation instrumentation impacts CDF and LERF.
In response to RAI 9.e, the licensee explained that for LOCAs outside of containment, in scenarios where the main condenser pressure boundary remains intact, the failure to isolate the condenser vacuum pump pathway can lead to a large early release. The licensee stated, as augmented by its response to RAI 16, that the trip of the main condenser mechanical vacuum pumps and actuation of the associated isolation valve are or will be modeled in internal events and fire PRAs using the same success criteria as the design-basis success criteria. The NRC staff finds that the licensees PRA model is sufficient to reflect TS LCO 3.3.7.2.A.
For TS LCO Condition 3.7.1.D (One division of intake deicer heaters inoperable), LAR Table E1-1 of Enclosure 1, and associated implementation item in LAR Attachment 6, state that the PRA models will be updated to include this condition prior to exercising the RICT Program.
In RAI 9.f, the NRC staff requested a description of the modeling that will be incorporated to reflect TS LCO 3.7.1.D to calculate a RICT. The NRC staff also requested an explanation of how inoperability of the deicers impacts CDF or LERF. In response to RAI 9.f, the licensee explained that failure of both divisions of deicers, in conjunction with lake temperatures cold enough to require needing the deicers (i.e., 38 F), is assumed to fail the SW system. The licensee stated, as augmented by its response to RAI 16, that intake deicer heater failures are now modeled in internal events and fire PRAs using the same success criteria as the
design-basis success criteria, and therefore, can be used to reflect this LCO. The NRC staff finds that the licensees PRA model is sufficient to reflect TS LCO 3.7.1.D.
In RAI 9.g, the NRC staff noted that the PRA success criterion used to model systems associated with TS LCO Condition 3.7.5 (Main Turbine Bypass) Condition A (Main Turbine Bypass System - Requirements of the LCO not met) is different from the design-basis success criterion indicated in LAR Table E1-1 of Enclosure 1. The LAR states that the PRA success criteria (i.e., three-of-five turbine bypass valves) is based on the minimum number of valves required to prevent major demands on the suppression pool, and indicates that the design-basis success criteria (i.e., five-of-five turbine bypass valves) is based on the need to control steam pressure when reactor steam exceeds turbine requirements during unit startup, sudden load rejection, and cooldown. In the RAI, the NRC staff stated that it was not clear whether these two functions were equivalent and whether the design-basis function was being met for this LCO using the PRA success criteria. Therefore, the NRC staff requested explanation of the PRA modeling of the turbine bypass system and the impact of its failure on CDF and LERF and justification that three turbine bypass valves are sufficient to fulfill the safety function for TS LCO 3.7.5.A in the accident scenarios modeled in the PRAs. In response to RAI 9.g, the licensee explained that for all non-ATWS scenarios, that turbine bypass flow through three out-of-five valves is sufficient to address decay heat removal requirements, with margin, and requiring minimal SRV actuations and a minimal related suppression pool heat-up challenge.
The licensee also explained given an ATWS event, the suppression pool will experience heat-up challenges regardless of the number of turbine bypass valves open. The licensee explained that the emergency operating procedure response is designed to bring the reactor to 4 percent of rated full power which is also well within the capacity of the flow provided by three bypass valves.
3.1.4.1.3.3 Common-Cause Modeling Section 3.3.6 of NEI 06-09, Revision 0-A, states that for all RICT assessments of planned configurations, the treatment of CCFs in the quantitative configuration risk management tools may be performed by considering only the removal of the planned equipment and not adjusting CCFs terms. RG 1.177 states that when a component is rendered inoperable in order to perform preventive maintenance, the CCF contributions in the remaining operable components should be modified to remove the inoperable component and to only include CCF of the remaining components.
In LAR Enclosure 8, Section 2, the licensee explained that CCF events are calculated using common-cause alpha factors and by placing the basic event in the appropriate location in the fault tree. The licensee stated that adjustments to the CCF grouping or CCF probabilities are not necessary when a component is taken out of service for preventive maintenance. The licensee explained that in a two-train system, its approach is conservative because the CCF term is retained even though one of the trains is removed from service (i.e., unavailable). In general, the NRC staff notes that the CCF contribution from the out-of-service component is conservatively retained in the following ways:
The independent failure rate used in the PRA models includes both independent and dependent failure events (i.e., the dependent failures should be subtracted from the total population of failures to calculate the independent failure rate)
The CCF event probabilities that include the out-of-service component are retained
The NRC staff also notes that this simplification produces both conservative and non-conservative effects. The CCF probability estimates are very uncertain and retaining precision in the calculation of these estimates using a more refined approach will not necessarily improve the accuracy of the results. Therefore, the staff concludes that the licensees method is acceptable because the calculations reasonably include CCFs after removing one train for maintenance consistent with the accuracy of the estimates.
RG 1.177 also states that when a component is rendered inoperable because it fails, the CCF probability for the remaining redundant components should be increased to represent the conditional failure probability due to CCF of these components, in order to account for the possibility that the first failure was caused by a CCF mechanism. Concerning entering TSs for emergent conditions, consistent with TSTF-505 Revision 2, the administrative TS requirement (TS 5.5.15, item d) specifies that in an emergent condition, if the extent of condition for the inoperable SSC is not complete prior to exceeding the allowed outage time, then the RICT Program will account for the increased possibility of CCF by either (1) numerically accounting for the increased possibility of CCF in the RICT calculation or (2) implementing RMAs, not already credited in the RICT calculation, that support redundant or diverse SSCs that perform the function(s) of the inoperable SSCs, and, if practicable, reduce the frequency of initiating events that challenge the function(s) performed by the inoperable SSCs. The licensee explained in LAR Enclosure 8 that if a numeric adjustment is performed, the RICT calculation shall be adjusted to numerically account for the increased possibility of CCF in accordance with RG 1.177, as specified in Appendix A, Section A-1.3.2.1.
3.1.4.1.3.4 CRMP Model The PRA model serves as the model used by the RTR tool, which is used to perform the RICT calculations. The licensee refers to the CRMP in the LAR as the RTR model. The tool used to perform the RICT calculations provides a user interface which supports the RICT Program by providing a method to evaluate the plant configuration.
In LAR Enclosure 8, the licensee described the necessary changes to the peer-reviewed baseline PRA models for use in the configuration risk software to support RICT calculations that preserves the CDF and LERF quantitative results; maintains the quality of the peer-reviewed PRA models; and correctly accommodates changes in risk due to configuration-specific considerations.
In Enclosure 8 of the LAR, the licensee explained that the peer-reviewed internal events, including internal flooding, PRA model, and the fire events PRA model are maintained as separate models. However, for RICT Program implementation, these baseline models are incorporated into the RTR tool software and modified or adjusted as follows for use in configuration risk calculations:
The unit availability factor is set to 1.0 (unit available)
Maintenance unavailability is set to zero or false unless unavailable due to the configuration Mutually exclusive combinations, including normally disallowed maintenance combinations, are adjusted to allow accurate analysis of the configuration
For systems where some trains are in service and some in standby, the RTR model addresses the actual configuration of the plant including defining in-service trains as needed These adjustments are the same as those used for the evaluation of risk under the Maintenance Rule program (i.e., 10 CFR 50.65(a)(4)). The RTR software is designed to quantify the unit-specific configuration for both internal events, including internal flooding, and fire events, and includes the seismic risk contribution when calculating the RMAT and RICT.
The licensee explained that adjustment for the impact of outdoor temperatures for seasonal service equipment and changes in success criteria to reflect the time-in-the-core operating cycle were not needed. In RAI 10 (Reference 11), the NRC staff noted the guidance in NEI 06-09, Revision 0-A, stating:
If the PRA model is constructed using data points or basic events that change as a result of time of year or time of cycle (examples include moderator temperature coefficient, summer versus winter alignments for heating ventilation and air condition, seasonal alignments for SW), then the RICT calculation shall either
- 1) use the more conservative assumption at all time, or 2) be adjusted appropriately to reflect the current (e.g., seasonal or time of cycle) configuration for the feature as modeled in the PRA.
In response to RAI 10, the licensee explained that the success criteria of the SW system when the UHS is greater than 82 F and (2) the intake deicer heaters when the UHS is less than 38 F are adjusted for seasonal variation. The licensee explained that the UHS temperature will be tracked in its RTR tool or a conservative assumption will be made. The licensee further provided discussion of possible RMAs for low and high UHS temperatures. The NRC staff finds that the licensees treatment of seasonal variations is acceptable because impact of seasonal variations was explicitly modeled when possible in the PRAs or RMAs will be used to reduce risk.
The licensee further explained that the PRA models may be optimized to improve performance speed, but that these changes are verified to provide the same results as the baseline models.
The licensee explained that when quantifying the RTR model, a full quantification will be performed for each configuration limiting the use of pre-solved cutsets to specific configurations.
The licensee also discussed other attributes to the RTR model, such as when and how to treat CCFs and modeling requirements for emergent conditions.
The licensee also discussed administrative controls for the RTR model such as quality and updated requirements. The licensee explained that every PRA model of record update requires an update to the RTR model in accordance with plant procedures. The licensee explained that an acceptance test is performed after every configuration risk model update to verify proper mapping of changes to RTR model.
The NRC staff concludes that the RTR (or CRMP) model used to calculate the RICTs is acceptable because the underlying PRA models will remain acceptable and the acceptance test will verify the RTR model is consistent with the underlying baseline PRA.
3.1.4.1.3.5 PRA Modeling Conclusions The NRC staff reviewed the information provided by the licensee and concluded that the PRA modeling used to support the RICT Program can appropriately model alignments of components during periods when the RICT will be calculated. Therefore, the NRC staff finds that the licensee has satisfied the intent of Section 2.3.3 of RG 1.177, Revision 1, Section 2.3 of RG 1.174, Revision 3, and that the PRA modeling is appropriate for the application of the RICT Program.
3.1.4.1.4 Key Assumptions and Sensitivity and Uncertainty Analyses Using PRAs to evaluate TS changes requires consideration of the assumptions made within the PRA that can have a significant influence on the ultimate acceptability of the proposed changes.
Risk-informed analyses of TS changes can be affected by uncertainties regarding the assumptions made during the PRA models development and application. In general, the risk resulting from TS CT changes is expected to be relatively insensitive to most uncertainties because the uncertainties tend to affect similarly both the base case and the case with the TS equipment unavailable. The licensee considered PRA modeling uncertainties and their potential impact on the RICT Program and identified, as necessary, applicable RMAs to limit the impact of these uncertainties. In Enclosure 9 of the LAR, the licensee discussed key assumptions and sources of uncertainty.
In LAR Enclosure 9, Section 3, the licensee stated that the internal events PRA uncertainty analysis was performed based on guidance from NUREG-1855, Revision 1. The licensee explained that the three sources of uncertainty defined in NUREG-1855 are considered in the RICT Program: parametric uncertainties, modeling uncertainties, and completeness uncertainties. Parametric uncertainties are specifically addressed in the PRA quantification to develop probability distributions for CDF and LERF and determine mean estimates for the risk values. The licensee explained that the fire PRA uncertainties were organized by the fire PRA topics presented in NUREG/CR-6850. The licensee cited definitions from NUREG-1855, Revision 1, for the terms credible assumption and consensus model, and explained that it has used consensus modeling approaches to develop the fire PRA and, besides NUREG/CR-6850, it used guidance from more recently issued NUREGs pertaining to fire PRA and fire PRA FAQs. The licensee stated that there are no systems conservatively assumed failed for all fire PRA scenarios. The NRC staff reviewed the licensees dispositions provided in LAR Table E9-1 to the identified key assumptions and sources of modeling uncertainty.
In response to RAI 11 (Reference 5), the licensee further explained the process for reviewing key assumptions and sources of uncertainty. The licensee explained that consistent with Steps E-1.1 and E-1.2 of NUREG-1855, Revision 1, generic sources of uncertainty were identified for the internal events PRA from the EPRI TR-1016737, Treatment of Parameter and Model Uncertainty for Probabilistic Risk Assessments, dated December 2008 (Reference 50), and for the fire PRA and Level 2 PRA from EPRI TR-1026511, Practical Guidance of the Use of Probabilistic Risk Assessment in Risk-informed Applications with a Focus on the Treatment of Uncertainty, dated December 2012 (Reference 51). The licensee also indicated that it reviewed the internal events and fire PRA documentation for unique plant-specific sources of uncertainty. The licensee explained that the considerations for screening the initial
comprehensive list of uncertainties down to the list presented in the LAR were based on whether:
A consensus model as defined by NUREG-1855, Revision 1, was used The uncertainty had an impact on the PRA results There was a reasonable alternative to the assumption Treatment of the uncertainty had a conservative bias impacting the risk results For the assumptions and sources of uncertainty that were not screened, the licensee shows in of the LAR, as discussed below, that its evaluation did not identify the need for additional sensitivity analyses for this application. The licensee stated that consistent with the guidance in NUREG-1855, if sources of uncertainty were identified that contribute to challenging the acceptance guidelines, then appropriate compensatory measures or performance monitoring should be identified to help minimize the risk. The licensee stated that for the RICT Program, appropriate compensatory RMAs will be implemented prior to exceeding the RMAT.
In LAR Enclosure 9, Table E9-1, the licensee dispositioned key assumptions and sources of uncertainty associated with the internal events PRA. For most uncertainties, the licensee stated that the approach represents a best estimate or consensus industry practice. For many of these cases, the licensee stated that its treatment was also somewhat conservative and/or the treatment would have minimal impact on a RICT calculation with one exception. In LAR Table E9-1, the licensee indicated that the internal flooding PRA model will be updated with new pipe break frequencies using the pipe length approach presented in the most recent version of EPRI TR-1013141, Revision 3, Pipe Rupture Frequencies for Internal Flooding Probabilistic Risk Assessments, to remove this uncertainty prior to implementation of the RICT Program at Nine Mile Point 2.
In LAR Enclosure 9, Table E9-1, the licensee stated that treatment of suppression pool strainers performance is a modeling uncertainty. The disposition to this modeling uncertainty stated that any potential extended unavailability via RICT is not relevant because suction strainer failures impact all ECCS systems as a common-mode failure. In response to RAI 12.a, the licensee provided further justification of the conclusion that the uncertainty associated with suppression pool strainer performance cannot have an impact on the RICT calculations. The licensee explained that failure of the suppression pool strainer is strongly dominated by the common-cause failure of all suction strainers, independent of the unavailability of individual strainers. However, the licensee also stated that strainer failure can impact the reliability of RCIC and high-pressure core spray, and therefore, it performed a sensitivity study on TS conditions included in the RICT Program that could be affected. The sensitivity study results showed that calculated RICTs were not impacted. Therefore, the NRC staff finds that the uncertainty associated with the CCF of suppression pool strainers has an inconsequential impact on the RICT Program.
In LAR Enclosure 9, Table E9-1, the licensee stated that Nine Mile Point 2 assumes that a single LPCI pump is adequate, and there is no real evidence yet that this is not acceptable to prevent core melt. In response to RAI 12.b, the licensee provided further justification for disposition of this uncertainty. The licensee first explained that in the baseline PRA model, one LPCI train is assumed to be successful to prevent core damage for a below-core large LOCA.
The licensee explained that it performed a sensitivity in which the success criteria for the
number of LPCI trains required to prevent core damage ranged across three cases (i.e. 0-of-3, 2-of-3, and 3-of-3 trains). The licensee showed that the difference in the change in risk from the sensitivity cases compared to the baseline case was very small (i.e., less than 3E-10 per year CDF and 6E-11 per year LERF in all cases). Therefore, the NRC staff finds that the uncertainty associated with LPCI pump success criteria for a very large break LOCA has an inconsequential impact on the RICT Program.
In LAR Enclosure 9, Table E9-3, the licensee dispositioned the fire PRA modeling uncertainties stating they do not present a significant impact on the Nine Mile Point 2 RICT calculations. The NRC staff reviewed the licensees dispositions provided in LAR Table E9-1 to the identified key assumptions and sources of modeling uncertainty, and in a few cases, requested additional information when it was not clear that the uncertainty could not impact the RICT calculations.
In LAR Enclosure 9, Table E3-1, the licensee identified detailed circuit analysis as a source of fire PRA modeling uncertainty because of conservatisms in the approach. In response to RAI 12.c, the licensee provided further justification for this uncertainty. The licensee explained that detailed circuit failure analysis was not limited to risk-significant scenarios but was applied to basic events throughout the model. The licensee explained that the conservatism referred to in the LAR is for aggregating the circuit failure probabilities for different failure modes (i.e.,
intra-cable hot shorts, inter-cable hot shorts, or ground equivalent hot shorts) into one failure probability. The NRC staff notes that the licensees treatment was applied throughout the model and has a comparable impact in the RICT calculation on the results of the baseline case (i.e., all equipment required by the TS is available) as on the results of the unavailability cases (i.e., cases in which equipment is unavailable). Because the treatment is conservative, impacts both the baseline case and unavailability cases, and the licensee performed detailed circuit failure analysis through the model, the NRC staff finds that the modeling uncertainty associated with circuit likelihood analyses has an inconsequential impact on the RICT Program.
In RAI 12.d, the NRC staff noted a source of uncertainty identified by the licensee as important in an uncertainty analysis report. The source of modeling uncertainty concerned plugging of the intake from the lake (i.e., UHS) to the SW system due to the existence of Zebra Mussels, frazil ice, high winds, and algae. Though the licensee stated that the treatment of the uncertainty was conservative, the NRC staff noted that modeling conservatisms can mask risk for certain plant configurations leading to the underestimation of the change in risk associated with a RICT calculation and the underestimation of the RICT. Therefore, the NRC staff requested justification for the treatment of the uncertainty for TS LCO 3.7.1 associated with the SW system and other LCOs whose risk could be affected by having a dependency on SW. In response to RAI 12.d, the licensee explained that plugging of the intake from the lake is assumed to result in failure of the entire SW system so is independent of the unavailability of SW trains, functions, or components. This is true for TS LCO 3.7.1.A, LCO 3.7.1.C, LCO 3.7.1.E, and LCO 3.7.1.F whose risk can be impacted by this intake plugging failure because all divisions of SW will be failed regardless of plant configuration. For this reason, the NRC staff finds that the modeling uncertainty associated with plugging of the intake from the UHS to the SW has an inconsequential impact on the RICT Program.
In RAI 12.e, the NRC staff noted a source of uncertainty identified by the licensee in an uncertainty analysis report associated with special data variables that were developed for non-typical equipment and appeared to rely on judgment. Therefore, the NRC staff requested a description of this equipment and the approach used to develop failure probabilities for this equipment, and justification that use of probabilities based on judgment would not impact the RICT calculations. In response to RAI 12.e, the licensee explained that special data variables
were developed for non-typical equipment for which there is little data and for which surveillance testing is difficult. The licensee explained that in these cases, engineering judgment was applied. The licensee cited and discussed two examples, FLEX equipment and bar rack heaters (i.e., deicers). For FLEX equipment, failure rates for similar equipment was used and multiplied by an uncertainty factor. For the bar rack heaters, a failure of 1E-6 is assumed per demand for each of the two divisions which is similar to the 2E-7 per year developed for a lake intake initiating event. The licensee explained that a study was performed in which the top cutsets were sorted by Fussell-Vesely (F-V) values and the cutsets with special variables were reviewed down to a F-V value of 10 percent. This study concluded that non-typical equipment failure probabilities developed using judgment will have no impact on the RICT Program since none of the components are proposed to be included in the RICT Program.
In RAI 13 (Reference 11), the NRC staff noted regulatory guidance that applies to PRA quantification performed in support of RICT calculations. RG 1.174 clarifies that, because of the way the acceptance guidelines in RG 1.174 have been developed, the appropriate numerical measures to use when comparing the PRA results with the risk acceptance guidelines are mean values. The risk management thresholds values for the RICT Program have been developed based on RG 1.174 and, therefore, the most appropriate measures with which to make a comparison are also mean values. Point estimates are the most commonly calculated and reported PRA results. Point estimates do not account for the state-of-knowledge correlation (SOKC) between nominally independent basic event probabilities, but they can be quickly and simply calculated. Mean values do reflect the SOKC and are always larger than point estimates but require longer and more complex calculations. NUREG-1855, Revision 1, provides guidance on evaluating how the uncertainty arising from the propagation of the uncertainty in parameter values of the PRA inputs impacts the comparison of the PRA results with the guideline values. Therefore, the NRC staff requested summarization of how SOKC is considered in the PRA models that support the RICT application.
In response to RAI 13 (Reference 5), the licensee explained that the impact of the SOKC uncertainty on RICT estimates is considered negligible, and therefore, point estimate values are adequate to perform its RICT calculations (i.e., to determine the change in risk associated with CT extensions). The licensee presented the results of a sensitivity study for the internal events and fire PRA models that shows the change in risk calculated using mean values versus the change in risk calculated using point estimates for three plant configurations (i.e., the unavailability of RCIC, the unavailability of an EDG, and the unavailability of an RHR train).
The sensitivity study results indicate that the increase in the change in risk based determined using mean values opposed to point estimate values ranged from 0.3 percent to 2.5 percent.
Also, the NRC staff notes that the impact of SOKC is spread across many different failure modes and has a comparable impact on the results of the baseline case (i.e., all equipment required by the TS is available) as the result of the unavailability cases (i.e., cases in which equipment is unavailable). For this reason, and demonstration by the licensees sensitivity study that the impact of the SOKC is small, the NRC staff finds the licensees treatment of the SOKC for the RICT application acceptable.
Given the licensees process for identifying internal event key assumption and sources of uncertainty and the licensees evaluation of those uncertainties provided in LAR Table E9-1, Table E9-3, and in response to RAI 12, the NRC staff finds that the licensees analysis of key assumptions and sources of uncertainty is consistent with guidance in NUREG-1855, Revision 1.
The NRC staffs review indicates the licensee performed an adequate assessment to identify the potential sources of uncertainty, and the identification of the key assumptions and sources of uncertainty was appropriate and consistent with the guidance in NUREG-1855 and associated EPRI TR-1016737 and EPRI TR-1026511. Therefore, the NRC staff finds that the licensee has satisfied the guidance in Sections 2.3.4 and 2.3.5 of RG 1.177, Revision 1, Section 2.2.2 of RG 1.174, Revision 3, and that the identification of assumptions and treatment of model uncertainties for risk evaluation of extended CTs is appropriate for this application and consistent with the guidance identified in NEI 06-09, Revision 0-A.
3.1.4.1.5 PRA Results and Insights The proposed change implements a process to determine TS RICTs rather than specific changes to individual TS CTs. NEI 06-09, Revision 0-A, states that periodic assessment of the risk incurred due to operation beyond the front stop CTs due to implementation of a RICT Program and comparison to the guidance of RG 1.174, Revision 3, for small increases in risk.
As with other unique risk-informed applications, supplemental risk acceptance guidelines that complement the RG 1.174 guidance are appropriate. NEI 06-09, Revision 0-A, states that configuration risk be assessed to determine the RICT and establishes the criteria for incremental core damage probability (ICDP) and incremental large early release probability (ILERP) on which to base the RICT. An ICDP of 1E-5 and an ILERP of 1E-6 are used as the risk measures for calculating individual RICTs.
NEI 06-09, Revision 0-A, as modified by the limitations and conditions in the associated SE, states that the cumulative impact of implementation of an RMTS be periodically assessed and shown to result in a total risk impact below 1E-5/year for changes to CDF, a total risk impact below 1E-6/year for changes to LERF, and the total CDF and total LERF must be reasonably shown to be less than 1E-4/year and 1E-5/year, respectively. The licensee indicated in of the LAR that the estimated total CDF and LERF meet the 1E-4/year CDF and 1E-5/year LERF criteria of RG 1.174, consistent with the guidance in NEI 06-09, Revision 0-A, and that these guidelines be satisfied whenever a RICT is implemented.
The licensee has incorporated NEI 06-09, Revision 0-A, in the RICT Program of TS 5.5.15, and therefore can calculate the RICT consistently with its criteria and assesses the RICT Program to assure any risk increases are small per the guidance of RG 1.174, Revision 3, and intent of RG 1.177, Revision 1. Also, the estimate of the current total CDF and LERF meets the intent of the acceptance guidelines of RG 1.174, Revision 3. Therefore, the NRC staff finds that the licensees RICT Program is consistent with NEI 06-09, Revision 0-A, guidance and is acceptable.
3.1.4.1.6 Implementation of the RICT Program Because NEI 06-09, Revision 0-A, involves the real-time application of PRA results and insights by the licensee, the NRC staff reviewed the licensees description of programs and procedures associated with implementation of the RICT Program in Enclosure 10 of its submittal. The administrative controls on the PRA, and on changes to the PRA, should provide confidence that the PRA results are reasonable, and the administrative controls on the plant personnel using the RICT should provide confidence that the RICT Program will be appropriately applied.
The means for demonstrating the technical acceptability of the PRA models include assessment against the ASME/ANS PRA standards and RG 1.200, which includes guidance for performing
peer reviews and focused-scope peer reviews. The technical adequacy of the PRA models is discussed in Enclosure 2, Information Supporting Consistency with Regulatory Guide 1.200, Revision 2 and Enclosure 7, PRA Model Update Process, of the submittal. According to , Attributes of the Real-Time Risk Model, future changes made to the baseline PRA model, changes made to the baseline PRA model for translation to the online model, and changes made to the online model configuration files are controlled and documented by plant procedures.
NEI 06-09, Revision 0-A, specifies that the RMTS risk assessment process should be integrated into station-wide work control processes and defines the necessary attributes of the RMTS program structure. In the conduct of RMTS, procedural guidance is required for conducting and using the results of the risk assessment. These procedures should specify the station functional organizations and personnel, including operations, engineering, work management and PRA personnel, responsible for each step of the procedures. The procedures should also clearly specify the process for calculating the applicable RICT, implementing RMAs, conducting, reviewing, and approving decisions to exceed the front-stop CT and remove equipment from service.
LAR Enclosure 10, Program Implementation, describes the implementing programs and procedures and the associated personnel training. The licensee explained that a RICT Program description and implementing procedures will be developed. The program description will establish the management responsibilities and general requirements for risk management, training, implementation, and monitoring of the RICT Program. More detailed procedures will provide specific responsibilities, limitations, and instructions for implementing the RICT Program. The program description and implementing procedures will incorporate the programmatic requirements for RMTS included in NEI 06-09, Revision 0-A. The program will be integrated with the existing online work control process. Entry into the RICT Program will require management approval prior to pre-planned activities and as soon as practicable following emergent conditions. These and other attributes that will be addressed in the RICT Program are identified in the LAR.
The NRC staff found that the licensee will establish appropriate programmatic and procedural controls for its RICT Program, consistent with the guidance of NEI 06-09, Revision 0-A, Section 3.2.1.
NEI 06-09, Revision 0-A, specifies that stations implementing an RMTS program shall provide training in the programmatic requirements associated with the RMTS program and of the individual RICT evaluations to personnel responsible for determining TS operability decisions or conducting RICT assessments. Training of plant personnel shall be provided for those organizations with functional responsibilities for performing or administering the CRMP (or RTR) commensurate with each positions responsibilities, in accordance with 10 CFR 50.120(b)(3) and other applicable regulations, within the RICT Program, as described in NEI 06-09, Revision 0-A.
In LAR Enclosure 10, the licensee described its program for providing training to its staff. The licensee identifies the attributes that the RICT Program procedures will address, which are consistent with NEI 06-09, Revision 0-A. The licensee also identified the categories of plant personnel that will be trained and the different types of training that the different categories of plant personnel receive. This includes detailed or Level 1 training for individuals who will be directly involved in the implementation of the RICT Program, Level 2 training for plant management positions with authority to approve entry into the RICT Program and other
management and personnel who closely support the RICT Program, and Level 3 training for personnel that need basic knowledge of RICT Program requirements and procedures.
The NRC staff reviewed the description of the training program provided in the LAR and concluded that the program is consistent with the training requirements set forth in NEI 06-09, Revision 0-A, Section 2.3.3. Therefore, the NRC staff finds that the licensee has proposed acceptable administrative controls on the PRA and on the personnel that will use the RICT Program.
3.1.4.2 Tier 2: Avoidance of Risk-Significant Plant Configurations The second tier provides that a licensee should provide reasonable assurance that risk-significant plant equipment outage configurations will not occur when specific plant equipment is taken out of service in accordance with the proposed TS change.
The guidance in NEI 06-09, Revision 0-A, does not permit voluntary entry into high-risk configurations, which would exceed instantaneous CDF and LERF limits of 1E-3/year and 1E-4/year, respectively. The guidance in NEI 06-09, Revision 0-A, specifies that if the instantaneous CDF and LERF limits are exceeded for emergent conditions, then implementation of RMAs is required. It further states that implementation of RMAs when the actual or anticipated risk accumulation during a RICT will exceed one-tenth of the ICDP or ILERP limit (the RMAT). Such RMAs may include rescheduling planned activities to lower risk periods or implementing risk-reduction measures. The limits established for entry into a RICT and for RMA implementation are consistent with the guidance of NUMARC 93-01, Revision 4A, Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, dated April 2011 (Reference 52), endorsed by RG 1.160, Revision 3, Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, dated May 2012 (Reference 53), as applicable to plant maintenance activities. The RICT Program requirements and criteria are consistent with the principle of Tier 2 to avoid risk-significant configurations.
Consistent with NEI 06-09, Revision 0-A, Enclosure 12 of the LAR identifies three categories of RMAs (i.e., actions to provide increased risk awareness and control, actions to reduce the duration of maintenance activities, and actions to minimize the magnitude of the risk increase).
LAR Enclosure 12 also provides examples of RMAs. The licensee explained that determination of RMAs is performed using plant procedures and involves both qualitative and quantitative considerations for specific plant configurations and the consideration of the practical means available to manage risk. The licensee stated that development of RMAs is performed in a graded manner and considers RMAs developed for the Maintenance Rule, 10 CFR 50.65(a)(4) program. The licensee also stated it uses general, configuration-specific, and common-cause RMAs. The licensee stated that general RMAs include:
Consideration of rescheduling maintenance to reduce risk Discussion of RICT in pre-job briefs Consideration of proactive return-to-service of other equipment Efficient execution of maintenance
The licensee stated that configuration-specific RMAs are also developed based on the RTR tool to identify candidates to manage the risk associated with internal events, internal flooding, and fire events. These actions include:
Identification of important equipment or trains for protection Identification of important operator actions for briefings Identification of key fire initiators and fire zones for RMAs in accordance with the site fire RMA process Identification of dominant initiating events and actions to minimize potential for initiators Consideration of insights from PRA model cutsets, through comparison of importance Further, the licensee stated that common-cause RMA candidates include:
Performance of non-intrusive inspections on alternate trains Confidence runs performed for standby SSCs Increased monitoring for running components Expansion of monitoring for running components Deferring maintenance and testing activities that could generate an initiating event which would require operation of potentially affected SSCs Readiness of operators and maintenance to respond to additional failures Shift briefs or standing orders which focus on initiating event response or loss of potentially affected SSCs The LAR stated that if an emergent condition occurs for which an extent of condition was not assessed prior to entering into the RMATs or the extent of condition assessment cannot rule out the potential for CCF, then RMAs are expected to be implemented to mitigate CCF and its impact. The licensee also stated that these RMAs can include pre-identified RMAs as described above as well as system-specific RMAs. The NRC staff concludes the licensees process for developing RMAs is in accordance with NEI 06-09, Revision 0-A, because it utilizes configuration-specific risk insights and specifically considers the potential for CCFs in emergent conditions.
Based on the licensees incorporation of NEI 06-09, Revision 0-A, in the TS as discussed in LAR Attachment 1 and use of RMAs as discussed in LAR Enclosure 12, Risk Management Actions, and because the proposed changes are consistent with the guidance of RG 1.174, Revision 3, and RG 1.177, Revision 1, the NRC staff finds the licensees Tier 2 program is acceptable and supports the proposed implementation of the RICT Program.
3.1.4.3 Tier 3: Risk-Informed Configuration Risk Management The third tier provides that a licensee should develop a program that ensures that the risk impact of out-of-service equipment is appropriately evaluated prior to performing any maintenance activity.
NEI 06-09, Revision 0-A, addresses Tier 3 guidance by specifying an assessment of the RICT to be based on the plant configuration of all SSCs that might impact the RICT, including safety-related and nonsafety-related SSCs. If a risk-significant plant configuration exists, based on the expectation of exceeding a threshold of one-tenth of the risk on which the RICT is based, compensatory measures and RMAs are required to be implemented. Thus, the RICT Program provides an acceptable methodology to assess and address risk-significant configurations.
Further, reassessment of any plant configuration changes is also required to be completed in a timely manner, based on the more restrictive limit of any applicable TS action requirement or a maximum of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after the configuration change occurs.
Based on the licensees incorporation of NEI 06-09, Revision 0-A, in the TS, as discussed in LAR Attachment 1 and use of RMAs as discussed in LAR Enclosure 12, Risk Management Actions, and because the proposed changes are consistent with the Tier 3 guidance of RG 1.177, Revision 1, the NRC staff finds that the proposed changes are acceptable.
3.1.4.4 Key Principle 4 Conclusions The licensee has demonstrated the technical acceptability and scope of its PRA models, and that the models can support implementation of the RICT Program for determining CTs. The licensee has made proper consideration of key assumptions and sources of uncertainty. The risk metrics are consistent with the approved methodology of NEI 06-09, Revision 0-A, and the acceptance guidance in RG 1.177 and RG 1.174. The RICT Program is controlled administratively through plant procedures and training. The RICT Program follows the NRC-approved methodology in NEI 06-09, Revision 0-A. The NRC staff concludes that the RICT Program satisfies the fourth key safety principle of RG 1.177 and is, therefore, acceptable.
3.1.5 Key Principle 5: Performance Measurement Strategies - Implementation and Monitoring Program RG 1.177, Revision 1, and RG 1.174, Revision 3, establish the need for an implementation and monitoring program to ensure that extensions to TS CTs do not degrade operational safety over time and that no adverse degradation occurs due to unanticipated degradation or common-cause mechanisms. An implementation and monitoring program is intended to ensure that the impact of the proposed TS change continues to reflect the reliability and availability of SSCs impacted by the change. Revision 3 of RG 1.174 states that monitoring performed in conformance with the Maintenance Rule, 10 CFR 50.65, can be used when the monitoring performed is sufficient for the SSCs affected by the risk-informed application. According to LAR 1, the SSCs in the scope of the RICT Program are also in the scope of the Maintenance Rule. In response to RAI 17 (Reference 6), the licensee described the approach and methods used for SSC performance monitoring as described in Regulatory Position C.3.2 referenced in RG 1.177 for meeting the fifth key safety principle. The NRC staff concludes that the licensees Maintenance Rule monitoring programs will provide for evaluation and disposition of unavailability impacts which may be incurred from implementation of the RICT Program.
Section 3.3.3 of NEI 06-09, Revision 0-A, instructs the licensee to track the risk associated with all entries beyond the front stop CT, and Section 2.3.1 provides a requirement for assessing cumulative risk, including a periodic evaluation of any increase in risk due to the use of the RMTS program to extend the CTs. According to LAR Enclosure 11, the licensee calculates cumulative risk at least every refueling cycle, but the recalculation period does not exceed 24 months, which is consistent with NEI 06-09, Revision 0-A. The licensee converts the cumulative ICDP and the ILERP into average annual values which are then compared to the
acceptance guidelines of RG 1.174. If any acceptance guidelines are exceeded, corrective actions are taken to ensure that future plant operational risk is within the acceptance guidelines.
This evaluation assures that RMTS program implementation meets RG 1.174 guidance for small risk increases.
The NRC staff concludes that the RICT Program satisfies the fifth key safety principle of RG 1.177, Revision 1, and RG 1.174 by, in part, monitoring the average annual cumulative risk increase as described in NEI 06-09, Revision 0-A, and using this average annual increase to ensure the program as implemented meets RG 1.174 guidance for small risk increases and is therefore, acceptable. Additionally, the NRC staff concludes that the RICT Program satisfies the fifth key safety principle of RG 1.177, Revision 1, and RG 1.174 because, in part, all the affected SSCs are within the Maintenance Rule program, which can be used to monitor changes to the reliability and availability of these SSCs.
3.2 VARIATIONS FROM TSTF-505 The NRC staff evaluated the proposed use of RICTs in the variations stated above in Section 2.2.4 of this SE in conjunction with evaluating the proposed use of RICTs in each of the individual LCO actions and CTs stated above in Section 2.2.3 of this SE. The NRC staffs evaluation of the licensees proposed use of RICTs in the variations against the key safety principles is discussed above in Sections 3.1.1 through 3.1.5 of this SE. Based on the above Sections 3.1.1 through 3.1.5, the NRC staff finds that each of the five key principles in RG 1.177, Revision 1, and RG 1.174, Revision 3, have been met and concludes that the proposed variations are acceptable.
In addition to the variations discussed above, the licensee proposed deleting a footnote for a one-time change to the completion time for LCO 3.5.1B. The action and completion time described in the footnote expired on December 31, 2018. Removal of the footnote is acceptable, because the period during which the footnote was applicable has expired and deleting the footnote does not affect the remaining requirements in the Nine Mile Point 2 TSs.
3.3 TECHNICAL SPECIFICATION ADMINISTRATIVE CONTROLS The NRC staff reviewed the licensees proposed addition of a new program, the RICT Program, to the administrative controls section of the TS. The NRC staff evaluated the elements of the new program to ensure alignment with the requirements in 10 CFR 50.36(c)(5) and to ensure the programmatic controls are consistent with the RICT Program described in NEI 06-09, Revision 0-A.
The proposed TS 5.5.15 requires that the RICT Program be implemented in accordance with NEI 06-09, Revision 0-A. This is acceptable because NEI 06-09, Revision 0-A, establishes an appropriate framework for an acceptable RICT Program. This proposed TS section is consistent with NEI 06-09-A.
The proposed TS 5.5.15 states that a RICT may not exceed 30 days. The NRC staff determined that 30-day limit is appropriate because it allows sufficient time to restore SSCs to operable status while avoiding excessive out-of-service times for TS SSCs.
The proposed TS 5.5.15 states that the RICT may only be used in Modes 1 and 2. This provision ensures that the RICT is only used for determination of CDF and LERF for modes of operation modeled in the PRA.
The proposed TS 5.5.15 requires that while in a RICT, any change in plant configuration as defined in NEI 06-09, Revision 0-A, must be considered for the effect on the RICT. The TS also specifies time limits for determining the effect on the RICT. These time limitations are consistent with those specified in NEI 06-09, Revision 0-A.
The proposed TS 5.5.15 contains requirements for the treatment of CCFs for emergent conditions in which the common-cause evaluation is not complete. The proposed requirements are to either numerically account for the increased probability of CCF or to implement RMAs that support redundant or diverse SSCs that perform the functions of the inoperable SSCs and, if practicable, reduce the frequency of initiating events that challenge the function(s) performed by the inoperable SSCs. Key Principle 2 of risk-informed decisionmaking is to assure that the change is consistent with defense-in-depth philosophy. The seven considerations supporting the evaluation of the impact of the change on defense-in-depth are discussed in RG 1.174, including one to preserve adequate defense against potential CCF. The NRC staff finds that numerically accounting for an increased probability of failure will shorten the estimated RICT based on the particular SSCs involved, thereby limiting the time when a CCF could affect risk.
Alternatively, implementing actions that can increase the availability of other mitigating SSCs or decrease the frequency of demand on the affected SSCs will decrease the likelihood that a CCF could affect risk. The NRC staff concludes that both the quantitative and the qualitative actions minimize the impact of CCF and therefore support meeting Key Principle 2 as described in RG 1.174. These methods either limit the exposure time, help ensure the availability of alternate SSCs, or decrease the probability of plant conditions requiring the safety function to be performed. The NRC staff finds that these methods contribute to maintaining defense-in-depth because the methods limit the exposure time or ensure the availability of alternate SSCs.
The proposed TS 5.5.15 contains a provision that risk assessment approaches and methods used shall be acceptable to the NRC. The plant PRA shall be based on the as-built, as-operated, and maintained plant; and reflect the operating experience at the plant, as specified in RG 1.200, Revision 2. Methods to assess the risk from extending the CTs must be PRA methods used to support this LAR, or other methods approved by the NRC for generic use. As stated in the NRC staffs SE of NEI 06-09, Revision 0-A:
TR NEI 06-09, Revision 0, requires an evaluation of the PRA model used to support the RMTS against the requirements of RG 1.200, Revision 1, and ASME RA-S-2002, Standard for Probabilistic Risk Assessment for Nuclear Power Plant Applications, for capability Category II. This assures that the PRA model is technically adequate for use in the assessment of configuration risk. This capability category of PRA is sufficient to support the evaluation of risk associated with out of service SSCs and establishing risk-informed CTs.
Proposed TS 5.5.15 appropriately requires the licensee to utilize the risk assessment approaches and methods previously approved by the NRC or incorporated in the RICT Program and requires prior NRC approval for any change in PRA methods to assess risk that are outside those approval boundaries. The NRC staff finds that this requirement is appropriately reflected in the administrative controls section of the Nine Mile Point 2 TS.
The regulations in 10 CFR 50.36(c)(5) require the TS to contain administrative controls providing provisions relating to organization and management, procedures, recordkeeping, review and audit, and reporting necessary to assure operation of the facility in a safe manner.
The NRC staff has determined that the administrative controls section of the TS will assure
operation of the facility in a safe manner when the facility uses the RICT Program. Therefore, the NRC staff has determined that the requirements of 10 CFR 50.36(c)(5) are satisfied.
4.0 ADDITIONAL CHANGES TO THE OPERATING LICENSE In the LAR, the licensee proposed the following license condition to be added to the Operating License:
Adoption of Risk Informed Completion Times TSTF-505, Revision 2, "Provide Risk-Informed Extended Completion Times-RITSTF Initiative 4b" Exelon is approved to implement TSTF-505, Revision 2, modifying the Technical Specification requirements related to completion times (CT) for required actions to provide the option to calculate a longer, risk-informed CT (RICT). The methodology for using the new Risk-Informed Completion Time Program is described in NEI 06-09, Revision 0-A, Risk-Informed Technical Specifications Initiative 4b, Risk-Managed Technical Specifications (RMTS) Guidelines, Revision 0, which was approved by the NRC on May 17, 2007.
Exelon will complete the implementation items listed in Attachment 6 of Exelon letter to the NRC dated October 31, 2019, prior to implementation of the RICT Program. All issues identified in the attachment will be addressed and any associated changes will be made, focused-scope peer reviews will be performed on changes that are PRA upgrades as defined in the PRA standard (ASME/ANS RA-Sa-2009, as endorsed by RG 1.200, Revision 2), and any findings will be resolved and reflected in the PRA of record prior to implementation of the RICT Program.
LAR Attachment 6 identifies the following six implementation items that will be completed prior to the implementation of the RICT Program:
For Mechanical Vacuum Pump Isolation instrumentation: The PRA model will be updated to includes these SSCs prior to exercising the RICT Program for this TS.
The PRA success criteria will match the design success criteria.
For Suppression Chamber-to-Drywell Vacuum Breakers inoperable for opening:
The PRA model will be updated to include this failure mode prior to exercising the RICT Program for this TS. The PRA success criteria will match the design success criteria.
For SW subsystem inoperable: The success criteria are consistent with design basis except when UHS temperature is >82 F. The PRA model is being updated to include this condition prior to exercising the RICT Program for this TS.
For Intake Deicer Heaters inoperable: The PRA model will be updated to explicitly include these components prior to its use with RICT for this TS.
For frequency of floods of various magnitudes in the Internal Flooding Analysis:
The PRA model will be updated to incorporate the new pipe rupture frequencies using the pipe length approach per the latest revision of EPRI TR-1013141.
For PRA Fact and Observation Independent Assessment and Focused Scope Peer Review: All open issues identified in Report 032405-RPT-01 will be addressed prior to exercising the RICT Program.
Based on its evaluation in this SE, the NRC staff finds that the proposed license condition and its implementation items are acceptable because they adequately implement the RICT Program using models, methods, and approaches consistent with the applicable guidance that has previously been endorsed as acceptable by the NRC.
5.0
SUMMARY
5.1 NRC STAFF FINDINGS AND CONCLUSIONS The NRC staff finds that the licensees proposed implementation of the RICT Program for the identified scope of required actions is consistent with the guidance of NEI 06-09, Revision 0-A.
The licensees methodology for assessing the risk impact of extended CTs, including the individual CT extension impacts in terms of ICDP and ILERP, and the overall program impact in terms of CDF and LERF, is accomplished using PRA models of sufficient scope and technical adequacy based on consistency with the guidance of RG 1.200, Revision 2. For seismic hazards, which does not have a PRA model, the licensee will use bounding analyses in accordance with NEI 06-09, Revision 0-A, guidance, proposed Administrative Control TS, and the proposed license condition. The RICT calculation uses the PRA model as translated into the RTR tool, and the licensee has an acceptable process in place to ensure the quality of the translation. In addition, the NRC staff finds that the proposed implementation of the RICT Program addresses the RG 1.177 defense-in-depth philosophy and safety margins to ensure that they are adequately maintained and includes adequate administrative controls as well as performance monitoring programs.
5.2 TECHNICAL EVALUATION
CONCLUSIONS The NRC staff has evaluated the proposed changes against each of the five key principles in RG 1.177, Revision 1, and RG 1.174, Revision 3.
The proposed changes to the LCO conditions and the CTs for remedial actions are acceptable and will continue to meet 10 CFR 50.36(c)(2), 10 CFR 50.57(a)(2), and 10 CFR 50.57(a)(6).
Therefore, the NRC staff concludes that the proposed change meets Key Principle 1.
For LCO conditions in the existing TS, some reduction in defense-in-depth has already been evaluated and accepted for a limited period of time during the current CT, and the RICT Program provides solely a risk-informed extension for operating in that plant condition.
Therefore, the NRC staff concludes that the proposed change meets Key Principle 2.
Implementation of the methodology as described in TS 5.5.15 provides confidence that the CTs can be extended without any unanalyzed reductions in safety margins because the design-basis success criteria parameters will be at the same level and provided by the same equipment as has been currently accepted. Therefore, the NRC staff concludes that the proposed change meets Key Principle 3.
The LAR has demonstrated the technical acceptability and scope of the PRA models and that the models can support implementation of the RICT Program for determining the identified CTs.
The licensee has considered the impacts of seismic events, non-seismic external hazards, and
other hazards in the RICT calculations. In accordance with NEI 06-09, Revision 0-A, the licensee will include a conservative penalty for seismic risk in the RICT calculations. The risk metrics will be consistent with the NRC-approved methodology of NEI 06-09, Revision 0-A; RG 1.174, Revision 3; and RG 1.177, Revision 1; and the RICT Program is controlled administratively through plant procedures and training. Therefore, the NRC staff concludes that the proposed change meets Key Principle 4.
The licensees PRA model takes the sum of the contributors to risk associated with each application of the RICT Program, and that change in CDF or LERF above the zero maintenance baseline levels is converted into average annual values which are then compared to the limits of RG 1.174. If any limits are exceeded, corrective actions are taken to ensure future plant operational risk is within the acceptance guidance. The SSCs in the scope of the RICT Program that have their CTs extended by entry into the RICT Program are monitored to ensure their safety performance is not degraded because the SSCs in the scope of the RICT Program are also in the scope of the Maintenance Rule. Revision 3 of RG 1.174 states that monitoring performed in conformance with the Maintenance Rule, 10 CFR 50.65, can be used when the monitoring performed is sufficient for the SSCs affected by the risk-informed application. The NRC staff, therefore, concludes that the proposed change meets Key Principle 5.
The NRC staff concludes that the proposed changes satisfy the key principles of risk-informed decisionmaking identified in RG 1.174, Revision 3, and RG 1.177, Revision 1, and, therefore, the requested adoption of the proposed changes to the TSs, implementation items, and associated guidance is acceptable.
6.0 STATE CONSULTATION
In accordance with the Commissions regulations, the New York State official was notified of the proposed issuance of the amendment on April 2, 2021. The State official had no comments.
7.0 ENVIRONMENTAL CONSIDERATION
The amendment changes a requirement with respect to installation or use of a facility component located within the restricted area as defined in 10 CFR Part 20. The NRC staff has determined that the amendment involves no significant increase in the amounts, and no significant change in the types, of any effluents that may be released offsite, and that there is no significant increase in individual or cumulative occupational radiation exposure. The Commission has previously issued a proposed finding that the amendment involves no significant hazards consideration, and there has been no public comment on such finding (85 FR 7792). Accordingly, the amendment meets the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9). Pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the issuance of the amendment.
8.0 CONCLUSION
The Commission has concluded, based on the considerations discussed above, that: (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) there is reasonable assurance that such activities will be conducted in compliance with the Commissions regulations, and (3) the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public.
9.0 REFERENCES
1 Grudger, David, T., Exelon Generation, letter to U.S. Nuclear Regulatory Commission, "Nine Mile Point Nuclear Station, Unit 2 - Licensee Amendment Request to Revise Technical Specifications to Adopt Risk Informed Completion Times TSTF-505, Revision 2,"
October 31, 2019 (ADAMS Accession No. ML19304B653).
2 Rafferty-Czincila, Shannon, Exelon Generation, letter to U.S. Nuclear Regulatory Commission, "Supplemental Information No.1 for Nine Mile Point Nuclear Station, Unit 2, to Adopt TSTF-505," December 12, 2019 (ADAMS Accession No. ML19346F427).
3 Gudger, David T., Exelon Generation, letter to U.S. Nuclear Regulatory Commission, "Nine Mile Point Nuclear Station, Unit 2 - Request for Additional Information for Nine Mile Point Nuclear Station, Unit 2, to Adopt TSTF-505," August 28, 2020 (ADAMS Accession No. ML20241A044).
4 Grudger, David, T., Exelon Generation, letter to U.S. Nuclear Regulatory Commission, "Supplemental Information for Nine Mile Point Nuclear Station, Unit 2, to Adopt TSTF-505,"
October 2, 2020 (ADAMS Accesion No. ML20276A019).
5 Grudger, David, T., Exelon Generation, letter to U.S. Nuclear Regulatory Commission, "Request for Additional Information for Nine Mile Point Nuclear Station, Unit 2, to Adopt TSTF-505," October 2, 2020 (ADAMS Accession No. ML20276A020).
6 Grudger, David, T., Exelon Generation, letter to U.S. Nuclear Regulatory Commission, "Response to Request for Additional Information Questions 17 and 26 for Nine Mile Point Nuclear Station, Unit 2, to Adopt TSTF-505," October 22, 2020 (ADAMS Accesion No.
7 Grudger, David, T., Exelon Generation, letter to U.S. Nuclear Regulatory Commission, "Responses to Request for Additional Information Questions 27 and 28 for Nine Mile Point Nuclear Station, Unit 2, to Adopt TSTF-505," January 7, 2021 (ADAMS Accesion No.
8 U.S. Nuclear Regulatory Commission, "TSTF-505, Revision 2, TSTF Comments on Draft Safety Evaluation for Traveler TSTF-505, Provide Risk-Informed Extended Completion Times and Submittal of TSTF-505, Revision 2," July 2, 2018 (ADAMS Package Accession No. ML18183A493).
9 U.S. Nuclear Regulatory Commission, "Final Revised Model Safety Evaluation of Traveler TSTF-505, Revision 2, Provide Risk Informed Extended Completion Times - RITSTF Initiative 4B," November 21, 2018 (ADAMS Package Accession No. ML18269A041).
10 U.S. Nuclear Regulatory Commission, "Nine Mile Point Nuclear Station, Unit 2 - Request for Additional Information Re: Review of License Amendment Request to Revise Technical Specifications to Adopt Risk Informed Completion Times," July 30, 2020 (ADAMS Accession No. ML20213A935).
11 U.S. Nuclear Regulatory Commission, "Nine Mile Point Nuclear Station, Unit 2 - Request for Additional Information to Support Review of License Amendment Request to Revise Technical Specifications to Adopt Risk Informed Completion Times," September 2, 2020 (ADAMS Accession No. ML20246G636).
12 U.S. Nuclear Regulatory Commission, "Nine Mile Point Nuclear Station, Unit 2 - Withdrawal and Replacement of Request for Additional Information to Support Review of License Amendment Request to Revise Technical Specifications to Adopt Risk-Informed Completion Times," September 28, 2020 (ADAMS Accession No. ML20272A280).
13 U.S. Nuclear Regulatory Commission, "Nine Mile Point Nuclear Station, Unit 2 - Request for Additional Information Re: Review of License Amendment Request to Revise Technical
Specifications to Adopt Risk Informed Completion Times," September 28, 2020 (ADAMS Accession No. ML20273A237).
14 U.S. Nuclear Regulatory Commission, "Nine Mile Point Nuclear Station, Unit 2 - Request for Additional Information Re: Review of License Amendment Request to Revise Technical Specifications to Adopt Risk Informed Completion Times," December 15, 2020 (ADAMS Accession No. ML20351A164).
15 Nuclear Energy Institute, "Risk-Informed Technical Specifications Initiative 4b: Risk-Managed Technical Specification (RMTS)," Topical Report NEI 06-09, Revision 0-A, October 2012 (ADAMS Package Accession No. ML122860402).
16 Golder, Jennifer, M., U.S. Nuclear Regulatory Commission, letter to Bradley, Biff, Nuclear Energy Institute, "Final Safety Evaluation For Nuclear Energy Institute (NEI) Topical Report (TR) NEI 06 09, Risk-Informed Technical Specifications Initiative 4b, Risk-Managed Technical Specifications (RMTS) Guidelines," May 17, 2007 (ADAMS Accession No. ML071200238).
17 U.S. Nuclear Regulatory Commission, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities," Regulatory Guide 1.200, Revision 2, March 2009 (ADAMS Accession No. ML090410014).
18 U.S. Nuclear Regulatory Commission, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis,"
Regulatory Guide 1.174, Revision 3, January 2018 (ADAMS Accession No. ML17317A256).
19 U.S. Nuclear Regulatory Commission, "An Approach for Plant-Specific, Risk-Informed Decisionmaking: Technical Specifications," Regulatory Guide 1.177, Revision 1, May 2011 (ADAMS Accession No. ML100910008).
20 American Society of Mechanical Engineers/American Nuclear Society (ASME/ANS),
"Standard for Level 1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications," Addendum A to RA-S-2008, PRA Standard ASME/ANS RA-Sa-2009, June 2005.
21 "Nine Mile Point Nuclear Station, Unit 2, Submittal of Revision 22 to the Updated Safety Analysis Report (USAR) and Reference Figures, 10 CFR 50.59 Evaluation Summary Report, Technical Specifications Bases Changes, and 10 CFR 54.37 Aging Management Review," February 14, 2017 (ADAMS Package Accession No. ML16309A376).
22 U.S. Nuclear Regulatory Commission, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities," Regulatory Guide 1.200, Revision 1, January 2007 (ADAMS Accession No. ML070240001).
23 U.S. Nuclear Regulatory Commission, "Assessment of the NEI 16-06, Crediting Mitigating Strategies in Risk-Informed Decision Making, Guidance for Risk-informed Changes to Plants Licensing Basis," May 30, 2017 (ADAMS Accession No. ML17031A269).
24 U.S. Nuclear Regulatory Commission, "Industry-Average Performance for Components and Initiating Events at U.S. Commercial Nuclear Power Plants," NUREG/CR-6928, February 2007 (ADAMS Accession No. ML070650650).
25 Pressurized Water Reactor Owners Group, "FLEX Equipment Data Collection and Analysis," PWROG-18043 P, Revision 0, February 2020 (not-publicly available).
26 Nuclear Energy Institute, "Process for Performing Internal Events PRA Peer Reviews Using the ASME/ANS PRA Standard," NEI 05-04, Revision 2, November 2008 (ADAMS Accession No. ML083430462).
27 U.S. Nuclear Regulatory Commission, letter to Nuclear Energy Institute, "U.S. Nuclear Regulatory Commission Acceptance on Nuclear Energy Institute Appendix X to Guidance
05-04, 07-12, and 12-13, Close-Out of Facts and Observations (F&Os)," May 3, 2017 (ADAMS Accession No. ML17079A427).
28 Nuclear Energy Institute, "Final Revision Of Appendix X to NEI 05-04/07-12/12-16 Close Out Facts and Observations," NEI 07-12, November 2008 (ADAMS Package Accession No. ML17086A431).
29 U.S. Nuclear Regulatory Commission, Electric Power Research Institute, "EPRI/NRC-RES Fire PRA Methodology for Nuclear Power Facilities, Volume 2: Detailed Methodology,"
NUREG/CR-6850, Volume 2, September 2005 (ADAMS Accession No. ML052580118).
30 U.S. Nuclear Regulatory Commission, "Close-Out of Fire Probabilistic Risk Assessment Frequently Asked Question 13-0004 on Clarifications Regarding Treatment of Sensitive Electronics," December 13, 2013 (ADAMS Accession No. ML13322A085).
31 U.S. Nuclear Regulatory Commission, Electric Power Research Institute, "EPRI/NRC-RES Fire Human Reliability Analysis Guidelines, Final Report," NUREG-1921, July 2012 (ADAMS Accession No. ML12216A104).
32 U.S. Nuclear Regulatory Commission, "Good Practices for Implementing Human Reliability Analysis (HRA), Final Report," NUREG-1792, April 2005 (ADAMS Accession No. ML051160213).
33 U.S. Nuclear Regulatory Commission, "Refining and Characterizing Heat Release Rates from Electrical Enclosures During Fire (RACHELLE -FIRE) Volume 1: Peak Heat Release Rates and Effect of Obstructed Plume," NUREG-2178, Volume 1, December 2015 (ADAMS Accession No. ML16110A140).
34 U.S. Nuclear Regulatory Commission, "Closure of National Fire Protection Association 805 Frequently Asked Question 08-0043 Electrical Cabinet Fire Location," August 4, 2009 (ADAMS Accession No. ML092120448).
35 U.S. Nuclear Regulatory Commission, "Close-Out of Fire Probabilistic Risk Assessment Frequently Asked Question 14-0009," April 29, 2015 (ADAMS Package Accession No. ML15119A176).
36 U.S. Nuclear Regulatory Commission, "Close-Out of National Fire Protection Association 805 Frequently Asked Question 12-0064 on Hot Work/Transient Fire Frequency Influence Factors," January 17, 2013 (ADAMS Accession No. ML12346A488).
37 U.S. Nuclear Regulatory Commission, "Close-Out of Fire Probabilistic Risk Assessment Frequently Asked Question 14-0008 on Main Control Board Treatment FPRA FAQ 14-0008, Main Control Board Treatment," July 22, 2014 (ADAMS Accession No. ML14190B307).
38 Electric Power Research Institute, "Pipe Ruptures Frequencies for Internal Flooding Probabilistic Risk Assessments," EPRI TR 1013141, Revision 3, December 2008.
39 Korsnick, Mary, G., Constellation Energy Nuclear Group, LLC, letter to U.S. Nuclear Regulatory Commission, "Seismic Hazard and Screening Report (CEUS) Sites, Response to NRC Request for Information Pursuant to 10 CFR 50.54(f) Regarding Recommendation 2.1 of the Near-Term Task Force Review of Insights from the Fukushima Daichi Accident,"
March 31, 2014 (ADAMS Accession No. ML14099A196).
40 Electric Power Research Institute, "Seismic Evaluation Guidance: Screening, Prioritization and Implementation Details (SPID) for the Resolution of Fukushima Near-Term Task Force Recommendation 2.1: Seismic," Final Report 1025287, February 2013.
41 U.S. Nuclear Regulatory Commission, "Central and Eastern United States Seismic Source Characterization for Nuclear Facilities," NUREG-2115, Volumes 1-6, January 2012 (ADAMS Package Accession No. ML12048A776).
42 Electric Power Research Institute, "Ground-Motion Model (GMM) Review Project," EPRI TR 30020000717, June 2013.
43 U.S. Nuclear Regulatory Commission, "Generic Issue 199 (GI-199) - Implications of Updated Probabilistic Seismic Hazard Estimates in Central and Eastern United States on Existing Plants - Safety/Risk Assessment," August 31, 2010 (ADAMS Accession No. ML100270639).
44 U.S. Nuclear Regulatory Commission, "Procedural and Submittal Guidance for the Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities," NUREG-1407, June 1991 (ADAMS Accession No. ML063550238).
45 Pacific Northwest National Laboratory, prepared for U.S. Nuclear Regulatory Commission, "Tornado Climatology of the Contiguous United States," NUREG/CR-4461, Rev. 2, February 2007 (ADAMS Accession No. ML070810400).
46 U.S. Nuclear Regulatory Commission, "Tornado Missile Protection," Regulatory Issue Summary 2015-06, June 10, 2015 (ADAMS Accession No. ML15020A419).
47 Korsnick, Mary, G., Constellation Energy Nuclear Group, LLC, letter to U.S. Nuclear Regulatory Commission, "Nine Mile Point Nuclear Station, Units 1 and 2, Transmittal of Flood Hazard Reevaluation Report," March 12, 2013 (ADAMS Accession No. ML13074A032).
48 U.S. Nuclear Regulatory Commission letter to Exelon Generation Company, LLC, "Nine Mile Point Nuclear Station, Units 1 and 2 - Staff Assessment of Flooding Focused Evaluation," September 20, 2017 (ADAMS Accession No. ML17251A045).
49 U.S. Nuclear Regulatory Commission, "Guidance on the Treatment of Uncertainties Associated with PRAs in Risk-Informed Decisionmaking Final Report," NUREG-1855, Revision 1, March 2017 (ADAMS Accession No. ML17062A466).
50 Electric Power Research Institute, "Treatment of Parameter and Model Uncertainty for Probabilistic Risk Assessments," EPRI TR 1016737, December 2008.
51 Electric Power Research Institute, "Practical Guidance of the Use of Probabilistic Risk Assessment in Risk-informed Applications with a Focus on the Treatment of Uncertainty,"
EPRI TR 1026511, December 2012.
52 Nuclear Energy Institute, "Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," NUMARC 93-01, Revision 4A, April 2011 (ADAMS Accession No. ML11116A198).
53 U.S. Nuclear Regulatory Commission, "Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," Regulatory Guide 1.160, Revision 3, May 2012 (ADAMS Accession No. ML113610098).
Principal Contributors: A. Russell, A. Sallman, B. Lee, C. Moulton, J. Hyslop, J. Patel, K. Nguyen, K. Tetter, M. Biro M. Valentin-Olmeda, N. Carte, S. Haider, Z. Coffman Date: April 29, 2021
ML21082A221 *by e-mail OFFICE NRR/DORL/LPL1/PM NRR/DORL/LPL1/LA NRR/DEX/EEEB/BC* NRR/DEX/EICB/BC*
NAME MMarshall JBurkhardt BTitus MWaters DATE 03/30/2021 03/30/2021 03/24/2021 02/25/2021 OFFICE NRR/DRA/APLA/BC* NRR/DRA/APLB/BC(A)* NRR/DRA/APLC/BC* NRR/DSS/SCPB/BC*
SVasavada for NAME RPascarelli SVasavada BWittick SRosenberg DATE 3/24/2021 3/24/2021 4/1/2021 3/27/2021 OFFICE NRR/DSS/SNSB/BC* NRR/DSS/STSB/BC* OGC (NLO)* NRR/DORL/LPL1/BC*
NAME SKrepel VCusumano KGamin JDanna (JTobin for)
DATE 03/23/2021 03/26/2021 04/22/2021 04/29/2021 OFFICE NRR/DORL/LPL1/PM*
NAME MMarshall DATE 04/29/2021