Text

– Issuance of Amendment Nos. 302 and 298 Adoption of Tstf-505, Provide Risk Informed Extended Completion Times – RITSTF Initiative 4b
	ML24183A108
Person / Time
Site:	Quad Cities
Issue date:	08/08/2024
From:	Robert Kuntz; Plant Licensing Branch III
To:	Rhoades D; Constellation Energy Generation
	Kuntz R
References
	EPID L-2023-LLA-0084
	Download: ML24183A108 (1)
	v • d • e

August 8, 2024 David P. Rhoades Senior Vice President Constellation Energy Generation, LLC President and Chief Nuclear Officer Constellation Nuclear 4300 Winfield Road Warrenville, IL 60555

SUBJECT:

QUAD CITIES NUCLEAR POWER STATION, UNITS 1 AND 2 - ISSUANCE OF AMENDMENT NOS. 302 AND 298 RE: ADOPTION OF TSTF-505, PROVIDE RISK INFORMED EXTENDED COMPLETION TIMES - RITSTF INITIATIVE 4B AND TSTF-591 REVISE RISK INFORMED COMPLETION TIME (RICT)

PROGRAM (EPID L-2023-LLA-0084)

Dear David Rhoades:

The U.S. Nuclear Regulatory Commission (the Commission) has issued the enclosed Amendment No. 302 to Renewed Facility Operating License No. DPR-29 and Amendment No. 298 to Renewed Facility Operating License No. DPR-30 for the Quad Cities Nuclear Power Station, Units 1 and 2, respectively. The amendments consist of changes to the technical specifications in response to your application dated June 8, 2023, as supplemented by letters dated March 19, 2024, April 5, 2024, May 10, 2024, and June 6, 2024.

The amendments adopt Technical Specifications Task Force (TSTF) Travelers 505 (TSTF-505),

Revision 2, Provide Risk Informed Extended Completion Times - RITSTF Initiative 4b and TSTF-591, Revision 0, Revise Risk Informed Completion Time (RICT) Program.

A copy of the related safety evaluation is also enclosed. The Notice of Issuance will be included in the Commissions monthly Federal Register notice.

Sincerely,

/RA/

Robert Kuntz, Project Manager Plant Licensing Branch III Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket Nos. 50-254 and 50-265

Enclosures:

1. Amendment No. 302 to DPR-29

2. Amendment No. 298 to DPR-30

3. Safety Evaluation cc: Listserv

CONSTELLATION ENERGY GENERATION, LLC AND MIDAMERICAN ENERGY COMPANY DOCKET NO. 50-254 QUAD CITIES NUCLEAR POWER STATION, UNIT 1 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 302 Renewed License No. DPR-29

1.

The U.S. Nuclear Regulatory Commission (the Commission) has found that:

A.

The application for amendment by Constellation Energy Generation, LLC (the licensee) dated June 8, 2023, as supplemented by letters dated March 19, April 5, May 10, and June 6, 2024, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commissions 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 Commissions 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 Commissions regulations and all applicable requirements have been satisfied.

2.

Accordingly, the license is amended by changes to the Technical Specifications as indicated in the attachment to this license amendment and paragraph 3.B. and new paragraph DD. of Renewed Facility Operating License No. DPR-29 are hereby amended to read as follows:

B.

Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 302, are hereby incorporated into this renewed operating license. The licensee shall operate the facility in accordance with the Technical Specifications.

DD.

Adoption of Risk Informed Completion Times TSTF-505, Revision 2, "Provide Risk-Informed Extension Completion Times - RITSTF Initiative 4b" Constellation is approved to implement TSTF-505, Revision 2, modifying the Technical Specifications 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.

Constellation will complete the implementation items listed in of Constellation Letter to the NRC dated June 8, 2023, as modified by Constellation Letter dated March 19, 2024, prior to implementation of the RICT Program. All issues identified in Attachment 5 of Constellation Letter to the NRC dated June 8, 2023, as modified by Constellation Letter dated March 19, 2024, 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 270 days of the date of issuance.

FOR THE NUCLEAR REGULATORY COMMISSION Jeffrey A. Whited, Chief Plant Licensing Branch III Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Attachment:

Changes to the Renewed Facility Operating License and Technical Specifications Date of Issuance: August 8, 2024 Jeffrey A.

Whited Digitally signed by Jeffrey A. Whited Date: 2024.08.08 11:09:11 -04'00'

CONSTELLATION ENERGY GENERATION, LLC AND MIDAMERICAN ENERGY COMPANY DOCKET NO. 50-265 QUAD CITIES NUCLEAR POWER STATION, UNIT 2 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 298 Renewed License No. DPR-30

1.

The U.S. Nuclear Regulatory Commission (the Commission) has found that:

A.

The application for amendment by the Constellation Energy Generation, LLC (the licensee) dated February 3, 2023, as supplemented by letters dated March 19, April 5, May 10, and June 6, 2024, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commissions 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 Commissions 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 Commissions regulations and all applicable requirements have been satisfied.

2.

Accordingly, the license is amended by changes to the Technical Specifications as indicated in the attachment to this license amendment and paragraph 3.B. and new paragraph CC. of Renewed Facility Operating License No. DPR-30 are hereby amended to read as follows:

B.

Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 298, are hereby incorporated into this renewed operating license. The licensee shall operate the facility in accordance with the Technical Specifications.

CC.

Adoption of Risk Informed Completion Times TSTF-505, Revision 2, "Provide Risk-Informed Extension Completion Times - RITSTF Initiative 4b" Constellation is approved to implement TSTF-505, Revision 2, modifying the Technical Specifications 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.

Constellation will complete the implementation items listed in of Constellation Letter to the NRC dated June 8, 2023, as modified by Constellation Letter dated March 19, 2024, prior to implementation of the RICT Program. All issues identified in Attachment 5 of Constellation Letter to the NRC dated June 8, 2023, as modified by Constellation Letter dated March 19, 2024, 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 270 days of the date of issuance.

FOR THE NUCLEAR REGULATORY COMMISSION Jeffery A. Whited, Chief Plant Licensing Branch III Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Attachment:

Changes to the Renewed Facility Operating License and Technical Specifications Date of Issuance: August 8, 2024 Jeffrey A.

Whited Digitally signed by Jeffrey A. Whited Date: 2024.08.08 11:09:49 -04'00'

ATTACHMENT TO LICENSE AMENDMENT NOS. 302 AND 298 RENEWED FACILITY OPERATING LICENSE NOS. DPR-29 AND DPR-30 QUAD CITIES NUCLEAR POWER STATION, UNITS 1 AND 2 DOCKET NOS. 50-254 AND 50-265 Replace the following pages of the Renewed Facility Operating Licenses and Appendix A, Technical Specifications, with the attached pages. The revised pages are identified by amendment number and contain marginal lines indicating the areas of change.

Remove Insert License No. DPR-29 License No. DPR-29 Page 4 Page 4 Page 10 Page 10 Page 11 License No. DPR-30 License No. DPR-30 Page 4 Page 4 Page 10 Page 10 Page 11 TS Page TS Page 1.3-13 1.3-13 1.3-14 3.1.7-1 3.1.7-1 3.3.1.1-1 3.3.1.1-1 3.3.1.1-2 3.3.1.1-2 3.3.1.1-3 3.3.1.1-3 3.3.1.1-4 3.3.1.1-4 3.3.1.1-5 3.3.1.1-5 3.3.1.1-6 3.3.1.1-6 3.3.1.1-7 3.3.1.1-7 3.3.1.1-8 3.3.1.1-8 3.3.1.1-9 3.3.1.1-9 3.3.1.1-10 3.3.1.1-10 3.3.1.1-11 3.3.2.2-1 3.3.2.2-1 3.3.4.1-1 3.3.4.1-1 3.3.4.1-2 3.3.4.1-2 3.3.5.1-1 3.3.5.1-1 3.3.5.1-2 3.3.5.1-2 3.3.5.1-3 3.3.5.1-3 3.3.5.1-4 3.3.5.1-4 3.3.5.1-5 3.3.5.1-5 3.3.5.1-6 3.3.5.1-6 3.3.5.1-7 3.3.5.1-7 3.3.5.1-8 3.3.5.1-8 3.3.5.1-9 3.3.5.1-9 3.3.5.3-1 3.3.5.3-1

Remove Insert TS Page TS Page 3.3.5.3-2 3.3.5.3-2 3.3.5.3-3 3.3.5.3-3 3.3.5.3-4 3.3.5.3-4 3.3.5.3-5 3.3.6.1-1 3.3.6.1-1 3.3.6.1-2 3.3.6.1-2 3.3.6.1-3 3.3.6.1-3 3.3.6.3-1 3.3.6.3-1 3.3.8.1-1 3.3.8.1-1 3.4.3-1 3.4.3-1 3.5.1-1 3.5.1-1 3.5.1-2 3.5.1-2 3.5.1-3 3.5.1-3 3.5.1-4 3.5.1-4 3.5.1-5 3.5.1-5 3.5.1-6 3.5.1-6 3.5.1-7 3.5.3-1 3.5.3-1 3.6.1.2-3 3.6.1.2-3 3.6.1.2-4 3.6.1.2-4 3.6.1.2-5 3.6.1.3-1 3.6.1.3-1 3.6.1.3-2 3.6.1.3-2 3.6.1.3-3 3.6.1.3-3 3.6.1.3-4 3.6.1.3-4 3.6.1.3-5 3.6.1.3-5 3.6.1.6-1 3.6.1.6-1 3.6.1.7-1 3.6.1.7-1 3.6.1.7-2 3.6.1.7-2 3.6.1.7-3 3.6.1.7-3 3.6.1.8-1 3.6.1.8-1 3.6.1.8-2 3.6.1.8-2 3.6.1.8-3 3.6.2.3-1 3.6.2.3-1 3.6.2.6-1 3.6.2.6-1 3.7.1-1 3.7.1-1 3.7.1.2 3.7.1-2 3.7.1-3 3.7.9-1 3.7.9-1 3.7.9-2 3.7.9-2 3.8.1-2 3.8.1-2 3.8.1-3 3.8.1-3 3.8.1-4 3.8.1-4 3.8.1-5 3.8.1-5 3.8.4-1 3.8.4-1 3.8.4-2 3.8.4-2 3.8.4-3 3.8.4-3 3.8.7-1 3.8.7-1 3.8.7-2 3.8.7-2 5.5-14 5.5-14 5.5-15

Remove Insert TS Page TS Page 5.6-5 5.6-5 5.6-6 Renewed License No. DPR-29 Amendment No. 302 B.

Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 302, are hereby incorporated into this renewed operating license. The licensee shall operate the facility in accordance with the Technical Specifications.

C.

The licensee shall maintain the commitments made in response to the March 14, 1983, NUREG-0737 Order, subject to the following provision:

The licensee may make changes to commitments made in response to the March 14, 1983, NUREG-0737 Order without prior approval of the Commission as long as the change would be permitted without NRC approval, pursuant to the requirements of 10 CFR 50.59. Consistent with this regulation, if the change results in an Unreviewed Safety Question, a license amendment shall be submitted to the NRC staff for review and approval prior to implementation of the change.

D.

Equalizer Valve Restriction Three of the four valves in the equalizer piping between the recirculation loops shall be closed at all times during reactor operation with one bypass valve open to allow for thermal expansion of water.

E.

The licensee 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 the authority of 10 CFR 50.90 and 10 CFR 50.54(p). The combined sets of plans1, which contain Safeguards Information protected under 10 CFR 73.21, is entitled: Quad Cities Nuclear Power Station Security Plan, Training and Qualification Plan, and Safeguards Contingency Plan, Revision 2, submitted by letter dated May 17, 2006.

Constellation Energy Generation, LLC 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 CSP was approved by License Amendment No. 249 as modified by License Amendment No. 259.

1 The Training and Qualification Plan and Safeguards Contingency Plan are Appendices to the Security Plan.

Renewed License No. DPR-29 Amendment No. 302 (4)

Ensure that if any inserts are identified as potentially failing the minimum certified Boron-10 areal density criterion, based on correlation of the coupon evaluation or insert service wear evaluation results to inserts, or other abnormal indications, Constellation Energy Generation, LLC will take affected inserts out of service until it can be positively demonstrated that the minimum certified Boron-10 areal density criterion (0.0116 g/cm2) is met for each insert; and, (5)

Submit a report to the NRC, within 90 days following completion of evaluations associated with Item 4 above, that describes the testing results, assessments performed, and interim and long-term corrective actions for abnormal indications.

CC.

Constellation Energy Generation, LLC 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 as described in Constellation's submittal letter dated June 8, 2023, and all its subsequent associated supplements as specified in License Amendment No. 301 dated July 3, 2024 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).

DD.

Adoption of Risk Informed Completion Times TSTF-505, Revision 2, "Provide Risk-Informed Extension Completion Times - RITSTF Initiative 4b" Constellation is approved to implement TSTF-505, Revision 2, modifying the Technical Specifications 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.

Constellation will complete the implementation items listed in Attachment 5 of Constellation Letter to the NRC dated June 8, 2023, as modified by Constellation Letter dated March 19, 2024, prior to implementation of the RICT Program. All issues identified in Attachment 5 of Constellation Letter to the NRC dated June 8, 2023, as modified by Constellation Letter dated March 19, 2024, 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 Renewed License No. DPR-29 Amendment No. 302 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.

4.

This renewed operating license is effective as of the date of issuance and shall expire at midnight on December 14, 2032.

FOR THE NUCLEAR REGULATORY COMMISSION Original Signed By:

J. E. Dyer, Director Office of Nuclear Reactor Regulation Attachments:

1. Appendix A - Technical Specifications

2. Appendix B - Environmental Protection Plan Date of Issuance: October 28, 2004 Renewed License No. DPR-30 Amendment No. 298 B.

Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 298, are hereby incorporated into this renewed operating license. The licensee shall operate the facility in accordance with the Technical Specifications.

C.

The licensee shall maintain the commitments made in response to the March 14, 1983, NUREG-0737 Order, subject to the following provision:

The licensee may make changes to commitments made in response to the March 14, 1983, NUREG-0737 Order without prior approval of the Commission as long as the change would be permitted without NRC approval, pursuant to the requirements of 10 CFR 50.59. Consistent with this regulation, if the change results in an Unreviewed Safety Question, a license amendment shall be submitted to the NRC staff for review and approval prior to implementation of the change.

D.

Equalizer Valve Restriction Three of the four valves in the equalizer piping between the recirculation loops shall be closed at all times during reactor operation with one bypass valve open to allow for thermal expansion of water.

E.

The licensee 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 the authority of 10 CFR 50.90 and 10 CFR 50.54(p). The combined set of plans1, which contain Safeguards Information protected under 10 CFR 73.21, is entitled: Quad Cities Nuclear Power Station Security Plan, Training and Qualification Plan, and Safeguards Contingency Plan, Revision 2, submitted by letter dated May 17, 2006.

Constellation Energy Generation, LLC 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 CSP was approved by License Amendment No. 244 and modified by License Amendment No. 254.

1 The Training and Qualification Plan and Safeguards Contingency Plan are Appendices to the Security Plan.

Renewed License No. DPR-30 Amendment No. 298 (4)

Ensure that if any inserts are identified as potentially failing the minimum certified Boron-10 areal density criterion, based on correlation of the coupon evaluation or insert service wear evaluation results to inserts, or other abnormal indications, Constellation Energy Generation, LLC will take affected inserts out of service until it can be positively demonstrated that the minimum certified Boron-10 areal density criterion (0.0116 g/cm2) is met for each insert; and, (5)

Submit a report to the NRC, within 90 days following completion of evaluations associated with Item 4 above, that describes the testing results, assessments performed, and interim and long-term corrective actions for abnormal indications.

BB.

Constellation Energy Generation, LLC 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 as described in Constellation's submittal letter dated June 8, 2023, and all its subsequent associated supplements as specified in License Amendment No. 297 dated July 3, 2024.

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).

CC.

Adoption of Risk Informed Completion Times TSTF-505, Revision 2, "Provide Risk-Informed Extension Completion Times - RITSTF Initiative 4b" Constellation is approved to implement TSTF-505, Revision 2, modifying the Technical Specifications 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.

Constellation will complete the implementation items listed in Attachment 5 of Constellation Letter to the NRC dated June 8, 2023, as modified by Constellation Letter dated March 19, 2024, prior to implementation of the RICT Program. All issues identified in Attachment 5 of Constellation Letter to the NRC dated June 8, 2023, as modified by Constellation Letter dated March 19, 2024, 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 Renewed License No. DPR-30 Amendment No. 298 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.

4.

This renewed operating license is effective as of the date of issuance and shall expire at midnight on December 14, 2032.

FOR THE NUCLEAR REGULATORY COMMISSION Original Signed By:

J. E. Dyer, Director Office of Nuclear Reactor Regulation Attachments:

1. Appendix A - Technical Specifications

2. Appendix B - Environmental Protection Plan Date of Issuance: October 28, 2004

Completion Times 1.3 Quad Cities 1 and 2 1.3-13 Amendment No. 199/195 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.

EXAMPLE 1.3-8 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One subsystem inoperable.

A.1 Restore subsystem to OPERABLE status.

7 days OR In accordance with the Risk Informed Completion Time Program B.

Required Action and associated Completion Time not met.

B.1 Be in MODE 3.

AND B.2 Be in MODE 4.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 36 hours 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.

(continued) 302/298

Completion Times 1.3 Quad Cities 1 and 2 1.3-14 Amendment No. 199/195 1.3 Completion Times EXAMPLES EXAMPLE 1.3-8 (continued)

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 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 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, Condition A is exited, and therefore, the Required Actions of Condition B may be terminated.

IMMEDIATE When "Immediately" is used as a Completion Time, the COMPLETION TIME Required Action should be pursued without delay and in a controlled manner.

302/298

SLC System 3.1.7 Quad Cities 1 and 2 3.1.7-1 Amendment No. 233/229 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 inoperable.

A.1 Restore SLC subsystem to OPERABLE status.

7 days OR In accordance with the Risk Informed Completion Time Program B.

Two SLC subsystems inoperable.

B.1 Restore one SLC subsystem to OPERABLE status.

8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months C.

Required Action and associated Completion Time not met.

C.1 Be in MODE 3.

AND C.2 Be in MODE 4.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 36 hours 302/298

RPS Instrumentation 3.3.1.1 Quad Cities 1 and 2 3.3.1.1-1 Amendment No. 272/267 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 25% RTP, entry into associated Conditions and Required Actions may be delayed for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months .

CONDITION REQUIRED ACTION COMPLETION TIME A.

One or more required channels inoperable.

A.1 Place channel in trip.

OR 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months OR

NOTE-----

Only applicable when a loss of function has not occurred.

In accordance with the Risk Informed Completion Time Program (continued) 302/298

RPS Instrumentation 3.3.1.1 Quad Cities 1 and 2 3.3.1.1-2 Amendment No. 202/198 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

(continued)

A.2 Place associated trip system in trip.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months OR

NOTE-----

Only applicable when a loss of function has not occurred.

In accordance with the Risk Informed Completion Time Program B.

One or more Functions with one or more required channels inoperable in both trip systems.

B.1 Place channel in one trip system in trip.

OR 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months OR

NOTE-----

Only applicable when a loss of function has not occurred.

In accordance with the Risk Informed Completion Time Program (continued) 302/298

RPS Instrumentation 3.3.1.1 Quad Cities 1 and 2 3.3.1.1-3 Amendment No. 202/198 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B.

(continued)

B.2 Place one trip system in trip.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months OR

NOTE-----

Only applicable when a loss of function has not occurred.

In accordance with the Risk Informed Completion Time Program C.

One or more Functions with RPS trip capability not maintained.

C.1 Restore RPS trip capability.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months D.

Required Action and associated Completion Time of Condition A, B, or C not met.

D.1 Enter the Condition referenced in Table 3.3.1.1-1 for the channel.

Immediately E.

As required by Required Action D.1 and referenced in Table 3.3.1.1-1.

E.1 Reduce THERMAL POWER to < 38.5% RTP.

4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months F.

As required by Required Action D.1 and referenced in Table 3.3.1.1-1.

F.1 Be in MODE 2.

8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months (continued) 302/298

RPS Instrumentation 3.3.1.1 Quad Cities 1 and 2 3.3.1.1-4 Amendment No. 272/267 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME G.

As required by Required Action D.1 and referenced in Table 3.3.1.1-1.

G.1 Be in MODE 3.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months H.

As required by Required Action D.1 and referenced in Table 3.3.1.1-1.

H.1 Initiate action to fully insert all insertable control rods in core cells containing one or more fuel assemblies.

Immediately SURVEILLANCE REQUIREMENTS

NOTES ------------------------------------

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 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 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 (continued) 302/298

RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS Quad Cities 1 and 2 3.3.1.1-5 Amendment No. 300/296 SURVEILLANCE FREQUENCY SR 3.3.1.1.2

NOTE-------------------

Not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after THERMAL POWER 25% RTP.

Verify the calculated power does not exceed the average power range monitor (APRM) channels by greater than 2% RTP while operating at 25% RTP.

In accordance with the Surveillance Frequency Control Program SR 3.3.1.1.3 Adjust the channel to conform to a calibrated flow signal.

In accordance with the Surveillance Frequency Control Program SR 3.3.1.1.4

NOTE-------------------

Not required to be performed when entering MODE 2 from MODE 1 until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after entering MODE 2.

Perform CHANNEL FUNCTIONAL TEST.

In accordance with the Surveillance Frequency Control Program SR 3.3.1.1.5 Perform a functional test of each RPS automatic scram contactor.

In accordance with the Surveillance Frequency Control Program SR 3.3.1.1.6 DELETED SR 3.3.1.1.7 DELETED (continued) 302/298

RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS Quad Cities 1 and 2 3.3.1.1-6 Amendment No. 248/243 SURVEILLANCE FREQUENCY 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 local power range monitors.

In accordance with the Surveillance Frequency Control Program SR 3.3.1.1.10 Perform CHANNEL FUNCTIONAL TEST.

In accordance with the Surveillance Frequency Control Program SR 3.3.1.1.11 Calibrate the trip units.

In accordance with the Surveillance Frequency Control Program SR 3.3.1.1.12 Perform CHANNEL CALIBRATION.

In accordance with the Surveillance Frequency Control Program SR 3.3.1.1.13 Verify Turbine Stop ValveClosure and Turbine Control Valve Fast Closure, Trip Oil PressureLow Functions are not bypassed when THERMAL POWER is 38.5% RTP.

In accordance with the Surveillance Frequency Control Program (continued) 302/298

RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS Quad Cities 1 and 2 3.3.1.1-7 Amendment No. 248/243 SURVEILLANCE FREQUENCY SR 3.3.1.1.14

NOTES------------------

1. Neutron detectors are excluded.

2. For Function 2.a, not required to be performed when entering MODE 2 from MODE 1 until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after entering MODE 2.

3. For Function 2.b, not required for the flow portion of the channels.

Perform CHANNEL CALIBRATION.

In accordance with the Surveillance Frequency Control Program SR 3.3.1.1.15 Perform CHANNEL FUNCTIONAL TEST.

In accordance with the Surveillance Frequency Control Program SR 3.3.1.1.16

NOTES------------------

1.

Neutron detectors are excluded.

2.

For Function 1.a, not required to be performed when entering MODE 2 from MODE 1 until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after entering MODE 2.

Perform CHANNEL CALIBRATION.

In accordance with the Surveillance Frequency Control Program SR 3.3.1.1.17 Perform LOGIC SYSTEM FUNCTIONAL TEST.

In accordance with the Surveillance Frequency Control Program continued 302/298

RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS Quad Cities 1 and 2 3.3.1.1-8 Amendment No. 248/243 SURVEILLANCE FREQUENCY SR 3.3.1.1.18

NOTE-------------------

Neutron detectors are excluded.

Verify the RPS RESPONSE TIME is within limits.

In accordance with the Surveillance Frequency Control Program 302/298

RPS Instrumentation 3.3.1.1 Quad Cities 1 and 2 3.3.1.1-9 Amendment No. 300/296 Table 3.3.1.1-1 (page 1 of 3)

Reactor Protection System Instrumentation FUNCTION APPLICABLE MODES OR OTHER SPECIFIED CONDITIONS REQUIRED CHANNELS PER TRIP SYSTEM CONDITIONS REFERENCED FROM REQUIRED ACTION D.1 SURVEILLANCE REQUIREMENTS ALLOWABLE VALUE 1.

Intermediate Range Monitors a.

Neutron FluxHigh 2

3 G

SR 3.3.1.1.1 SR 3.3.1.1.4 SR 3.3.1.1.5 SR 3.3.1.1.16 SR 3.3.1.1.17 121/125 divisions of full scale 5(a) 3 H

SR 3.3.1.1.1 SR 3.3.1.1.4 SR 3.3.1.1.5 SR 3.3.1.1.16 SR 3.3.1.1.17 121/125 divisions of full scale b.

Inop 2

5(a) 3 3

G H

SR 3.3.1.1.4 SR 3.3.1.1.5 SR 3.3.1.1.17 SR 3.3.1.1.4 SR 3.3.1.1.5 SR 3.3.1.1.17 NA NA 2.

Average Power Range Monitors a.

Neutron FluxHigh, Setdown 2

2 G

SR 3.3.1.1.1 SR 3.3.1.1.4 SR 3.3.1.1.5 SR 3.3.1.1.9 SR 3.3.1.1.14 SR 3.3.1.1.17 17.1% RTP b.

Flow Biased Neutron FluxHigh 1

2 F

SR 3.3.1.1.1 SR 3.3.1.1.2 SR 3.3.1.1.3 SR 3.3.1.1.5 SR 3.3.1.1.9 SR 3.3.1.1.10 SR 3.3.1.1.14 SR 3.3.1.1.16 SR 3.3.1.1.17 SR 3.3.1.1.18 0.56 W

+ 67.4% RTP and 122% RTP(b)

(continued)

(a)

With any control rod withdrawn from a core cell containing one or more fuel assemblies.

(b) 0.56 W + 63.2% and 118.4% RTP when reset for single loop operation per LCO 3.4.1, "Recirculation Loops Operating."

302/298

RPS Instrumentation 3.3.1.1 Quad Cities 1 and 2 3.3.1.1-10 Amendment No. 248/243 Table 3.3.1.1-1 (page 2 of 3)

Reactor Protection System Instrumentation FUNCTION APPLICABLE MODES OR OTHER SPECIFIED CONDITIONS REQUIRED CHANNELS PER TRIP SYSTEM CONDITIONS REFERENCED FROM REQUIRED ACTION D.1 SURVEILLANCE REQUIREMENTS ALLOWABLE VALUE 2.

Average Power Range Monitors (continued) c.

Fixed Neutron Flux-High 1

2 F

SR 3.3.1.1.1 SR 3.3.1.1.2 SR 3.3.1.1.5 SR 3.3.1.1.9 SR 3.3.1.1.10 SR 3.3.1.1.14 SR 3.3.1.1.17 SR 3.3.1.1.18 122% RTP d.

Inop 1,2 2

G SR 3.3.1.1.5 SR 3.3.1.1.9 SR 3.3.1.1.10 SR 3.3.1.1.17 NA 3.

Reactor Vessel Steam Dome PressureHigh 1,2 2

G SR 3.3.1.1.1 SR 3.3.1.1.5 SR 3.3.1.1.10 SR 3.3.1.1.11 SR 3.3.1.1.16 SR 3.3.1.1.17 SR 3.3.1.1.18 1050 psig 4.

Reactor Vessel Water LevelLow 1,2 2

G SR 3.3.1.1.1 SR 3.3.1.1.5 SR 3.3.1.1.10 SR 3.3.1.1.11 SR 3.3.1.1.16 SR 3.3.1.1.17 SR 3.3.1.1.18 3.8 inches 5.

Main Steam Isolation ValveClosure 1

8 F

SR 3.3.1.1.5 SR 3.3.1.1.10 SR 3.3.1.1.16 SR 3.3.1.1.17 SR 3.3.1.1.18 9.8% closed 6.

Drywell PressureHigh 1,2 2

G SR 3.3.1.1.5 SR 3.3.1.1.10 SR 3.3.1.1.12 SR 3.3.1.1.17 SR 3.3.1.1.18 2.43 psig (continued) 302/298

RPS Instrumentation 3.3.1.1 Quad Cities 1 and 2 3.3.1.1-11 Amendment No. 248/243 Table 3.3.1.1-1 (page 3 of 3)

Reactor Protection System Instrumentation FUNCTION APPLICABLE MODES OR OTHER SPECIFIED CONDITIONS REQUIRED CHANNELS PER TRIP SYSTEM CONDITIONS REFERENCED FROM REQUIRED ACTION D.1 SURVEILLANCE REQUIREMENTS ALLOWABLE VALUE 7.

Scram Discharge Volume Water LevelHigh a.

Float Switch 1,2 2

G SR 3.3.1.1.5 SR 3.3.1.1.10 SR 3.3.1.1.16 SR 3.3.1.1.17 38.9 gallons 5(a) 2 H

SR 3.3.1.1.5 SR 3.3.1.1.10 SR 3.3.1.1.16 SR 3.3.1.1.17 38.9 gallons b.

Differential Pressure Switch 1,2 2

G SR 3.3.1.1.5 SR 3.3.1.1.10 SR 3.3.1.1.11 SR 3.3.1.1.16 SR 3.3.1.1.17 32.3 gallons 5(a) 2 H

SR 3.3.1.1.5 SR 3.3.1.1.10 SR 3.3.1.1.11 SR 3.3.1.1.16 SR 3.3.1.1.17 32.3 gallons 8.

Turbine Stop Valve-Closure 38.5%

RTP 4

E SR 3.3.1.1.5 SR 3.3.1.1.10 SR 3.3.1.1.13 SR 3.3.1.1.16 SR 3.3.1.1.17 SR 3.3.1.1.18 9.7% closed 9.

Turbine Control Valve Fast Closure, Trip Oil PressureLow 38.5%

RTP 2

E SR 3.3.1.1.5 SR 3.3.1.1.10 SR 3.3.1.1.13 SR 3.3.1.1.16 SR 3.3.1.1.17 SR 3.3.1.1.18 475 psig 10.

Turbine Condenser Vacuum-Low 1

2 F

SR 3.3.1.1.5 SR 3.3.1.1.10 SR 3.3.1.1.12 SR 3.3.1.1.17 SR 3.3.1.1.18 20.6 inches Hg vacuum 11.

Reactor Mode Switch Shutdown Position 1,2 1

G SR 3.3.1.1.15 SR 3.3.1.1.17 NA 5(a) 1 H

SR 3.3.1.1.15 SR 3.3.1.1.17 NA 12.

Manual Scram 1,2 1

G SR 3.3.1.1.8 SR 3.3.1.1.17 NA 5(a) 1 H

SR 3.3.1.1.8 SR 3.3.1.1.17 NA (a)

With any control rod withdrawn from a core cell containing one or more fuel assemblies.

302/298

Feedwater System and Main Turbine High Water Level Trip Instrumentation 3.3.2.2 Quad Cities 1 and 2 3.3.2.2-1 Amendment No. 230/225 3.3 INSTRUMENTATION 3.3.2.2 Feedwater System and Main Turbine High Water Level Trip Instrumentation LCO 3.3.2.2 Four channels of Feedwater System and main turbine high water level trip instrumentation shall be OPERABLE.

APPLICABILITY:

THERMAL POWER 25% RTP.

NOTE--------------------------------------

Separate Condition entry is allowed for each channel.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One or more Feedwater System and main turbine high water level trip channels inoperable.

A.1

NOTE--------

Not applicable if inoperable channel is the result of an inoperable feedwater pump breaker.

Place channel in Trip.

7 days OR In accordance with the Risk Informed Completion Time Program B.

Feedwater System and main turbine high water level trip capability not maintained.

B.1 Restore trip capability.

2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months (continued) 302/298

ATWS-RPT Instrumentation 3.3.4.1 Quad Cities 1 and 2 3.3.4.1-1 Amendment No. 199/195 3.3 INSTRUMENTATION 3.3.4.1 Anticipated Transient Without Scram Recirculation Pump Trip (ATWS-RPT) Instrumentation LCO 3.3.4.1 Two channels per trip system for each ATWS-RPT instrumentation Function listed below shall be OPERABLE:

a.

Reactor Vessel Water LevelLow Low; and b.

Reactor Vessel Steam Dome PressureHigh.

APPLICABILITY:

MODE 1.

ACTIONS

NOTE-------------------------------------

Separate Condition entry is allowed for each channel.

CONDITION REQUIRED ACTION COMPLETION TIME A.

One or more channels inoperable.

A.1 Restore channel to OPERABLE status.

OR 14 days OR In accordance with the Risk Informed Completion Time Program (continued) 302/298

ATWS-RPT Instrumentation 3.3.4.1 Quad Cities 1 and 2 3.3.4.1-2 Amendment No. 199/195 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

(continued)

A.2

NOTE---------

Not applicable if inoperable channel is the result of an inoperable breaker.

Place channel in trip.

14 days OR In accordance with the Risk Informed Completion Time Program B.

One Function with ATWS-RPT trip capability not maintained.

B.1 Restore ATWS-RPT trip capability.

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months C.

Both Functions with ATWS-RPT trip capability not maintained.

C.1 Restore ATWS-RPT trip capability for one Function.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months D.

Required Action and associated Completion Time not met.

D.1 Remove the associated recirculation pump from service.

OR D.2 Be in MODE 2.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 6 hours 302/298

ECCS Instrumentation 3.3.5.1 Quad Cities 1 and 2 3.3.5.1-1 Amendment No. 199/195 3.3 INSTRUMENTATION 3.3.5.1 Emergency Core Cooling System (ECCS) Instrumentation LCO 3.3.5.1 The ECCS instrumentation for each Function in Table 3.3.5.1-1 shall be OPERABLE.

APPLICABILITY:

According to Table 3.3.5.1-1.

ACTIONS

NOTE-------------------------------------

Separate Condition entry is allowed for each channel.

CONDITION REQUIRED ACTION COMPLETION TIME A.

One or more required channels inoperable.

A.1 Enter the Condition referenced in Table 3.3.5.1-1 for the channel.

Immediately B.

As required by Required Action A.1 and referenced in Table 3.3.5.1-1.

B.1

NOTE---------

Only applicable for Functions 1.a, 1.b, 2.a, 2.b, 2.d, and 2.j.

Declare supported feature(s) inoperable when its redundant feature ECCS initiation capability is inoperable.

AND 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months from discovery of loss of initiation capability for feature(s) in both divisions (continued) 302/298

ECCS Instrumentation 3.3.5.1 Quad Cities 1 and 2 3.3.5.1-2 Amendment No. 273/268 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B.

(continued)

B.2

NOTE---------

Only applicable for Functions 3.a and 3.b.

Declare High Pressure Coolant Injection (HPCI) System inoperable.

AND B.3 Place channel in trip.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months from discovery of loss of HPCI initiation capability 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OR

NOTE-----

Only applicable when a loss of function has not occurred.

In accordance with the Risk Informed Completion Time Program (continued) 302/298

ECCS Instrumentation 3.3.5.1 Quad Cities 1 and 2 3.3.5.1-3 Amendment No. 273/268 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C.

As required by Required Action A.1 and referenced in Table 3.3.5.1-1.

C.1

NOTE---------

Only applicable for Functions 1.c, 1.e, 2.c, 2.e, 2.g, 2.h, 2.i, and 2.k.

Declare supported feature(s) inoperable when its redundant feature ECCS initiation capability is inoperable.

AND C.2 Restore channel to OPERABLE status.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months from discovery of loss of initiation capability for feature(s) in both divisions 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OR

NOTE-----

Only applicable when a loss of function has not occurred.

In accordance with the Risk Informed Completion Time Program (continued) 302/298

ECCS Instrumentation 3.3.5.1 Quad Cities 1 and 2 3.3.5.1-4 Amendment No. 199/195 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME D.

As required by Required Action A.1 and referenced in Table 3.3.5.1-1.

D.1

NOTE---------

Only applicable if HPCI pump suction is not aligned to the suppression pool.

Declare HPCI System inoperable.

AND D.2.1 Place channel in trip.

OR D.2.2 Align the HPCI pump suction to the suppression pool.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months from discovery of loss of HPCI initiation capability 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OR

NOTE-----

Only applicable when a loss of function has not occurred.

In accordance with the Risk Informed Completion Time Program 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months (continued) 302/298

ECCS Instrumentation 3.3.5.1 Quad Cities 1 and 2 3.3.5.1-5 Amendment No. 273/268 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME E.

As required by Required Action A.1 and referenced in Table 3.3.5.1-1.

E.1

NOTE---------

Only applicable for Functions 1.d and 2.f.

Declare supported feature(s) inoperable when its redundant feature ECCS initiation capability is inoperable.

AND E.2 Restore channel to OPERABLE status.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months from discovery of loss of initiation capability for subsystems in both divisions 7 days OR

NOTE-----

Only applicable when a loss of function has not occurred.

In accordance with the Risk Informed Completion Time Program (continued) 302/298

ECCS Instrumentation 3.3.5.1 Quad Cities 1 and 2 3.3.5.1-6 Amendment No. 199/195 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME F.

As required by Required Action A.1 and referenced in Table 3.3.5.1-1.

F.1 Declare Automatic Depressurization System (ADS) valves inoperable.

AND F.2 Place channel in trip.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months from discovery of loss of ADS initiation capability in both trip systems 96 hours0.00111 days 0.0267 hours 1.587302e-4 weeks 3.6528e-5 months or in accordance with the Risk Informed Completion Time Program from discovery of inoperable channel concurrent with HPCI or reactor core isolation cooling (RCIC) inoperable AND 8 days OR

NOTE-----

Only applicable when a loss of function has not occurred.

In accordance with the Risk Informed Completion Time Program (continued) 302/298

ECCS Instrumentation 3.3.5.1 Quad Cities 1 and 2 3.3.5.1-7 Amendment No. 199/195 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME G.

As required by Required Action A.1 and referenced in Table 3.3.5.1-1.

G.1 Declare ADS valves inoperable.

AND G.2 Restore channel to OPERABLE status.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months from discovery of loss of ADS initiation capability in both trip systems 96 hours0.00111 days 0.0267 hours 1.587302e-4 weeks 3.6528e-5 months or in accordance with the Risk Informed Completion Time Program from discovery of inoperable channel concurrent with HPCI or RCIC inoperable AND 8 days OR

NOTE-----

Only applicable when a loss of function has not occurred.

In accordance with the Risk Informed Completion Time Program (continued) 302/298

ECCS Instrumentation 3.3.5.1 Quad Cities 1 and 2 3.3.5.1-8 Amendment No. 248/243 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME H.

Required Action and associated Completion Time of Condition B, C, D, E, F, or G not met.

H.1 Declare associated supported feature(s) inoperable.

Immediately 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 as follows: (a) for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months for Functions 3.c, 3.f, and 3.g; and (b) for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months for Functions other than 3.c, 3.f, and 3.g 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 (continued) 302/298

ECCS Instrumentation 3.3.5.1 Quad Cities 1 and 2 3.3.5.1-9 Amendment No. 248/243 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY 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 CHANNEL CALIBRATION.

In accordance with the Surveillance Frequency Control Program SR 3.3.5.1.7 Perform LOGIC SYSTEM FUNCTIONAL TEST.

In accordance with the Surveillance Frequency Control Program 302/298

RCIC System Instrumentation 3.3.5.3 Quad Cities 1 and 2 3.3.5.3-1 Amendment No. 273/268 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

NOTE-------------------------------------

Separate Condition entry is allowed for each channel.

CONDITION REQUIRED ACTION COMPLETION TIME A.

One or more required channels inoperable.

A.1 Enter the Condition referenced in Table 3.3.5.3-1 for the channel.

Immediately B.

As required by Required Action A.1 and referenced in Table 3.3.5.3-1.

B.1 Declare RCIC System inoperable.

AND 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months from discovery of loss of RCIC initiation capability (continued) 302/298

RCIC System Instrumentation 3.3.5.3 Quad Cities 1 and 2 3.3.5.3-2 Amendment No. 273/268 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B.

(continued)

B.2 Place channel in trip.

24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OR

NOTE-----

Only applicable when a loss of function has not occurred.

In accordance with the Risk Informed Completion Time Program C.

As required by Required Action A.1 and referenced in Table 3.3.5.3-1.

C.1 Restore channel to OPERABLE status.

24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months (continued) 302/298

RCIC System Instrumentation 3.3.5.3 Quad Cities 1 and 2 3.3.5.3-3 Amendment No. 273/268 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME D.

As required by Required Action A.1 and referenced in Table 3.3.5.3-1.

D.1

NOTE---------

Only applicable if RCIC pump suction is not aligned to the suppression pool.

Declare RCIC System inoperable.

AND D.2.1 Place channel in trip.

OR D.2.2 Align RCIC pump suction to the suppression pool.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months from discovery of loss of RCIC initiation capability 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OR

NOTE-----

Only applicable when a loss of function has not occurred.

In accordance with the Risk Informed Completion Time Program 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months E.

Required Action and associated Completion Time of Condition B, C, or D not met.

E.1 Declare RCIC System inoperable.

Immediately 302/298

RCIC System Instrumentation 3.3.5.3 Quad Cities 1 and 2 3.3.5.3-4 Amendment No. 273/268 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 0.00167 hours 9.920635e-6 weeks 2.283e-6 months for Functions 2 and 5; and (b) for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months for Functions 1, 3, and 4 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 CALIBRATE the trip unit.

In accordance with the Surveillance Frequency Control Program SR 3.3.5.3.3 Perform CHANNEL FUNCTIONAL TEST.

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 302/298

RCIC System Instrumentation 3.3.5.3 Quad Cities 1 and 2 3.3.5.3-5 Amendment No. 273/268 Table 3.3.5.3-1 (page 1 of 1)

Reactor Core Isolation Cooling System Instrumentation FUNCTION REQUIRED CHANNELS PER FUNCTION CONDITIONS REFERENCED FROM REQUIRED ACTION A.1 SURVEILLANCE REQUIREMENTS ALLOWABLE VALUE 1.

Reactor Vessel Water LevelLow Low 4

B SR 3.3.5.3.1 SR 3.3.5.3.2 SR 3.3.5.3.3 SR 3.3.5.3.4 SR 3.3.5.3.5

-55.2 inches 2.

Reactor Vessel Water LevelHigh 2

C SR 3.3.5.3.1 SR 3.3.5.3.2 SR 3.3.5.3.3 SR 3.3.5.3.4 SR 3.3.5.3.5 50.34 inches 3.

Contaminated Condensate Storage Tank (CCST)

Level-Low 2

D SR 3.3.5.3.3 SR 3.3.5.3.4 SR 3.3.5.3.5 598 ft 1 inch 4.

Suppression Pool Water LevelHigh 2

D SR 3.3.5.3.3 SR 3.3.5.3.4 SR 3.3.5.3.5 15 ft 11.25 inches 5.

Manual Initiation 1

C SR 3.3.5.3.5 NA 302/298

Primary Containment Isolation Instrumentation 3.3.6.1 Quad Cities 1 and 2 3.3.6.1-1 Amendment No. 295/291 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

NOTES------------------------------------

1. Penetration flow paths may be unisolated under administrative controls.

2. Separate Condition entry is allowed for each channel.

CONDITION REQUIRED ACTION COMPLETION TIME A.

One or more required channels inoperable.

A.1 Place channel in trip.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for Functions 1.a, 2.a, 2.b, 3.d, 5.b, and 6.b OR In accordance with the Risk Informed Completion Time Program AND (continued) 302/298

Primary Containment Isolation Instrumentation 3.3.6.1 Quad Cities 1 and 2 3.3.6.1-2 Amendment No. 199/195 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

(continued)

A.1 (continued) 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months for Functions other than Functions 1.a, 2.a, 2.b, 3.d, 5.b, and 6.b OR In accordance with the Risk Informed Completion Time Program B.

One or more automatic Functions with isolation capability not maintained.

B.1 Restore isolation capability.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months C.

Required Action and associated Completion Time of Condition A or B not met.

C.1 Enter the Condition referenced in Table 3.3.6.1-1 for the channel.

Immediately D.

As required by Required Action C.1 and referenced in Table 3.3.6.1-1.

D.1 Isolate associated main steam line (MSL).

OR D.2.1 Be in MODE 3.

AND D.2.2 Be in MODE 4.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 12 hours 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months (continued) 302/298

Primary Containment Isolation Instrumentation 3.3.6.1 Quad Cities 1 and 2 3.3.6.1-3 Amendment No. 273/268 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME E.

As required by Required Action C.1 and referenced in Table 3.3.6.1-1.

E.1 Be in MODE 2.

8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months F.

As required by Required Action C.1 and referenced in Table 3.3.6.1-1.

F.1 Isolate the affected penetration flow path(s).

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months G.

Required Action and associated Completion Time for Condition F not met.

OR As required by Required Action C.1 and referenced in Table 3.3.6.1-1.

G.1 Be in MODE 3.

AND G.2 Be in MODE 4.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 36 hours H.

As required by Required Action C.1 and referenced in Table 3.3.6.1-1.

H.1 Declare associated standby liquid control subsystem (SLC) inoperable.

OR H.2 Isolate the Reactor Water Cleanup System.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months 1 hour I.

As required by Required Action C.1 and referenced in Table 3.3.6.1-1.

I.1 Initiate action to restore channel to OPERABLE status.

Immediately 302/298

Relief Valve Instrumentation 3.3.6.3 Quad Cities 1 and 2 3.3.6.3-1 Amendment No. 199/195 3.3 INSTRUMENTATION 3.3.6.3 Relief Valve Instrumentation LCO 3.3.6.3 The relief valve instrumentation for each Function in Table 3.3.6.3-1 shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, and 3.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One relief valve inoperable due to inoperable channel(s).

A.1 Restore channel(s) to OPERABLE status.

14 days OR

NOTE-----

Only applicable when a loss of function has not occurred.

In accordance with the Risk Informed Completion Time Program B.

Required Action and associated Completion Time of Condition A not met.

OR Two or more relief valves inoperable due to inoperable channels.

B.1 Be in MODE 3.

AND B.2 Be in MODE 4.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 36 hours 302/298

LOP Instrumentation 3.3.8.1 Quad Cities 1 and 2 3.3.8.1-1 Amendment No. 287/283 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.

ACTIONS

NOTE------------------------------------

Separate Condition entry is allowed for each channel.

CONDITION REQUIRED ACTION COMPLETION TIME A.

One or more channels inoperable.

A.1 Place channel in trip.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months OR

NOTE-----

Only applicable when a loss of function has not occurred.

In accordance with the Risk Informed Completion Time Program B.

Required Action and associated Completion Time not met.

B.1 Declare associated diesel generator (DG) inoperable.

Immediately 302/298

Safety and Relief Valves 3.4.3 Quad Cities 1 and 2 3.4.3-1 Amendment No. 245/240 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.3 Safety and Relief Valves LCO 3.4.3 The safety function of 9 safety valves shall be OPERABLE.

AND The relief function of 5 relief valves shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, and 3.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One relief valve inoperable.

A.1 Restore the relief valve to OPERABLE status.

14 days OR In accordance with the Risk Informed Completion Time Program B.

Required Action and associated Completion Time of Condition A not met.

NOTE-----------

LCO 3.0.4.a is not applicable when entering MODE 3.

B.1 Be in MODE 3.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months C.

Two or more relief valves inoperable.

OR One or more safety valves inoperable.

C.1 Be in MODE 3.

AND C.2 Be in MODE 4.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 36 hours 302/298

ECCSOperating 3.5.1 Quad Cities 1 and 2 3.5.1-1 Amendment No. 296/292 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS), REACTOR PRESSURE VESSEL (RPV)

WATER INVENTORY CONTROL, AND REACTOR CORE ISOLATION COOLING (RCIC)

SYSTEM 3.5.1 ECCSOperating LCO 3.5.1 Each ECCS injection/spray subsystem and the Automatic Depressurization System (ADS) function of five relief valves shall be OPERABLE.

NOTE---------------------------

Low pressure coolant injection (LPCI) subsystems may be considered OPERABLE during alignment and operation for decay heat removal with reactor steam dome pressure less than the Residual Heat Removal (RHR) cut-in permissive pressure in MODE 3, if capable of being manually realigned and not otherwise inoperable.

APPLICABILITY:

MODE 1, MODES 2 and 3, except high pressure coolant injection (HPCI) and 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 HPCI.

CONDITION REQUIRED ACTION COMPLETION TIME A.

One Low Pressure Coolant Injection (LPCI) pump inoperable.

A.1 Restore LPCI pump to OPERABLE status.

30 days B.

One LPCI subsystem inoperable for reasons other than Condition A.

OR One Core Spray subsystem inoperable.

B.1 Restore low pressure ECCS injection/spray subsystem to OPERABLE status.

7 days OR In accordance with the Risk Informed Completion Time Program (continued) 302/298

ECCSOperating 3.5.1 Quad Cities 1 and 2 3.5.1-2 Amendment No. 296/292 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C.

One LPCI pump in each subsystem inoperable.

C.1 Restore one LPCI pump to OPERABLE status.

7 days OR In accordance with the Risk Informed Completion Time Program D.

Required Action and associated Completion Time of Condition A, B, or C not met.

NOTE-----------

LCO 3.0.4.a is not applicable when entering MODE 3.

D.1 Be in MODE 3.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months E.

Two LPCI subsystems inoperable for reasons other than Condition C.

E.1 Restore one LPCI subsystem to OPERABLE status.

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR In accordance with the Risk Informed Completion Time Program F.

Required Action and associated Completion Time of Condition E not met.

F.1 Be in MODE 3.

AND F.2 Be in MODE 4.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 36 hours (continued) 302/298

ECCSOperating 3.5.1 Quad Cities 1 and 2 3.5.1-3 Amendment No. 296/292 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME G.

HPCI System inoperable.

G.1 Verify by administrative means RCIC System is OPERABLE.

AND G.2 Restore HPCI System to OPERABLE status.

Immediately 14 days OR In accordance with the Risk Informed Completion Time Program H.

One ADS valve inoperable.

H.1 Restore ADS valve to OPERABLE status.

14 days OR In accordance with the Risk Informed Completion Time Program I.

Required Action and associated Completion Time of Condition G or H not met.

NOTE-----------

LCO 3.0.4.a is not applicable when entering MODE 3.

I.1 Be in MODE 3.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months J.

Two or more ADS valves inoperable.

J.1 Be in MODE 3.

AND J.2 Reduce reactor steam dome pressure to

< 150 psig.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 36 hours (continued) 302/298

ECCSOperating 3.5.1 Quad Cities 1 and 2 3.5.1-4 Amendment No. 296/292 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME K.

Two or more low pressure ECCS injection/spray subsystems inoperable for reasons other than Condition C or E.

OR HPCI System and one or more ADS valves inoperable.

OR One or more low pressure ECCS injection/spray subsystems inoperable and one or more ADS valves inoperable.

OR HPCI System inoperable and either one low pressure ECCS injection/spray subsystem is inoperable or Condition C entered.

K.1 Enter LCO 3.0.3 Immediately 302/298

ECCSOperating 3.5.1 Quad Cities 1 and 2 3.5.1-5 Amendment No. 296/292 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.5.1.1 Verify, for each ECCS injection/spray subsystem, locations susceptible to gas accumulation are sufficiently filled with water.

In accordance with the Surveillance Frequency Control Program SR 3.5.1.2

NOTE-------------------

Not required to be met for system vent flow paths opened under administrative control.

Verify each ECCS injection/spray subsystem manual, power operated, and automatic valve in the flow path, that is not locked, sealed, or otherwise secured in position, is in the correct position.

In accordance with the Surveillance Frequency Control Program SR 3.5.1.3 Verify correct breaker alignment to the LPCI swing bus.

In accordance with the Surveillance Frequency Control Program SR 3.5.1.4 Verify each recirculation pump discharge valve cycles through one complete cycle of full travel or is de-energized in the closed position.

In accordance with the INSERVICE TESTING PROGRAM (continued) 302/298

ECCSOperating 3.5.1 Quad Cities 1 and 2 3.5.1-6 Amendment No. 266/261 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.5.1.5 Verify the following ECCS pumps develop the specified flow rate against a test line pressure corresponding to the specified reactor pressure.

TEST LINE PRESSURE NO.

CORRESPONDING OF TO A REACTOR SYSTEM FLOW RATE PUMPS PRESSURE OF Core Spray 4500 gpm 1

90 psig LPCI 9000 gpm 2

20 psig In accordance with the INSERVICE TESTING PROGRAM SR 3.5.1.6

NOTE--------------------

Not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after reactor steam pressure and flow are adequate to perform the test.

Verify, with reactor pressure 1005 and 920 psig, the HPCI pump can develop a flow rate 5000 gpm against a system head corresponding to reactor pressure.

In accordance with the INSERVICE TESTING PROGRAM SR 3.5.1.7

NOTE--------------------

Not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after reactor steam pressure and flow are adequate to perform the test.

Verify, with reactor pressure 180 psig, the HPCI pump can develop a flow rate 5000 gpm against a system head corresponding to reactor pressure.

In accordance with the Surveillance Frequency Control Program (continued) 302/298

ECCSOperating 3.5.1 Quad Cities 1 and 2 3.5.1-7 Amendment No. 290/286 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.5.1.8

NOTE--------------------

Vessel injection/spray may be excluded.

Verify each ECCS injection/spray subsystem actuates on an actual or simulated automatic initiation signal, except for valves that are locked, sealed, or otherwise secured in the actuated position.

In accordance with the Surveillance Frequency Control Program SR 3.5.1.9

NOTE--------------------

Valve actuation may be excluded.

Verify the ADS actuates on an actual or simulated automatic initiation signal.

In accordance with the Surveillance Frequency Control Program SR 3.5.1.10 Verify each ADS valve actuator strokes when manually actuated.

In accordance with the Surveillance Frequency Control Program SR 3.5.1.11 Verify automatic transfer capability of the LPCI swing bus power supply from the normal source to the backup source.

In accordance with the Surveillance Frequency Control Program SR 3.5.1.12 Verify ADS pneumatic supply header pressure is > 80 psig.

In accordance with the Surveillance Frequency Control Program 302/298

RCIC System 3.5.3 Quad Cities 1 and 2 3.5.3-1 Amendment No. 273/268 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS), REACTOR PRESSURE VESSEL (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 inoperable.

A.1 Verify by administrative means High Pressure Coolant Injection System is OPERABLE.

AND A.2 Restore RCIC System to OPERABLE status.

Immediately 14 days OR In accordance with the Risk Informed Completion Time Program B.

Required Action and associated Completion Time not met.

NOTE-----------

LCO 3.0.4.a is not applicable when entering MODE 3.

B.1 Be in MODE 3.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 302/298

Primary Containment Air Lock 3.6.1.2 Quad Cities 1 and 2 3.6.1.2-3 Amendment No. 199/195 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B.

(continued)

B.2 Lock an OPERABLE door closed.

AND B.3

NOTE---------

Air lock doors in high radiation areas or areas with limited access due to inerting may be verified locked closed by administrative means.

Verify an OPERABLE door is locked closed.

24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Once per 31 days C.

Primary containment air lock inoperable for reasons other than Condition A or B.

C.1 Initiate action to evaluate primary containment overall leakage rate per LCO 3.6.1.1, using current air lock test results.

AND C.2 Verify a door is closed.

AND Immediately 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months (continued) 302/298

Primary Containment Air Lock 3.6.1.2 Quad Cities 1 and 2 3.6.1.2-4 Amendment No. 248/243 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C.

(continued)

C.3 Restore air lock to OPERABLE status.

24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OR

NOTE------

Not applicable if leakage exceeds limits or if loss of function has occurred.

In accordance with the Risk Informed Completion Time Program D.

Required Action and associated Completion Time not met.

D.1 Be in MODE 3.

AND D.2 Be in MODE 4.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 36 hours 302/298

Primary Containment Air Lock 3.6.1.2 Quad Cities 1 and 2 3.6.1.2-5 Amendment No. 248/243 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.1.2.1

NOTES------------------

1.

An inoperable air lock door does not invalidate the previous successful performance of the overall air lock leakage test.

2.

Results shall be evaluated against acceptance criteria applicable to SR 3.6.1.1.1.

Perform required primary containment air lock leakage rate testing in accordance with the Primary Containment Leakage Rate Testing Program.

In accordance with the Primary Containment Leakage Rate Testing Program SR 3.6.1.2.2 Verify only one door in the primary containment air lock can be opened at a time.

In accordance with the Surveillance Frequency Control Program 302/298

PCIVs 3.6.1.3 Quad Cities 1 and 2 3.6.1.3-1 Amendment No. 287/283 3.6 CONTAINMENT SYSTEMS 3.6.1.3 Primary Containment Isolation Valves (PCIVs)

LCO 3.6.1.3 Each PCIV, except reactor building-to-suppression chamber vacuum breakers, shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, and 3.

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--------

Only applicable to penetration flow paths with two or more PCIVs.

One or more penetration flow paths with one PCIV inoperable for reasons other than Condition D.

A.1 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.

4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months except for main steam line OR In accordance with the Risk Informed Completion Time Program AND (continued) 302/298

PCIVs 3.6.1.3 Quad Cities 1 and 2 3.6.1.3-2 Amendment No. 199/195 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

(continued)

A.1 (continued)

AND 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 penetration flow path is isolated.

8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months for main steam line OR In accordance with the Risk Informed Completion Time Program Once per 31 days following isolation for isolation devices outside primary containment AND (continued) 302/298

PCIVs 3.6.1.3 Quad Cities 1 and 2 3.6.1.3-3 Amendment No. 199/195 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

(continued)

A.2 (continued)

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 primary containment B.

NOTE---------

Only applicable to penetration flow paths with two or more PCIVs.

One or more penetration flow paths with two or more PCIVs inoperable for reasons other than Condition D.

B.1 Isolate the affected penetration flow path by use of at least one closed and de-activated automatic valve, closed manual valve, or blind flange.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months (continued) 302/298

PCIVs 3.6.1.3 Quad Cities 1 and 2 3.6.1.3-4 Amendment No. 287/283 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C.

NOTE---------

Only applicable to penetration flow paths with only one PCIV.

One or more penetration flow paths with one PCIV inoperable for reasons other than Condition D.

C.1 Isolate the affected penetration flow path by use of at least one closed and de-activated automatic valve, closed manual valve, or blind flange.

AND C.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 penetration flow path is isolated.

4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months except for excess flow check valves (EFCVs) and penetrations with a closed system AND 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months for EFCVs and penetrations with a closed system Once per 31 days following isolation D.

MSIV leakage rate not within limit.

D.1 Restore leakage rate to within limit.

8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months (continued) 302/298

PCIVs 3.6.1.3 Quad Cities 1 and 2 3.6.1.3-5 Amendment No. 273/268 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME E.

Required Action and associated Completion Time of Condition A, B, C, or D not met.

E.1 Be in MODE 3.

AND E.2 Be in MODE 4.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 36 hours SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.1.3.1

NOTE-------------------

Not required to be met when the 18 inch primary containment vent and purge valves are open for inerting, de-inerting, pressure control, ALARA or air quality considerations for personnel entry, or Surveillances that require the valves to be open, provided the drywell vent and purge valves and their associated suppression chamber vent and purge valves are not open simultaneously.

Verify each 18 inch primary containment vent and purge valve, except for the torus purge valve, is closed.

In accordance with the Surveillance Frequency Control Program (continued) 302/298

Low Set Relief Valves 3.6.1.6 Quad Cities 1 and 2 3.6.1.6-1 Amendment No. 245/240 3.6 CONTAINMENT SYSTEMS 3.6.1.6 Low Set Relief Valves LCO 3.6.1.6 The low set relief function of two relief valves shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, and 3.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One low set relief valve inoperable.

A.1 Restore low set relief valve to OPERABLE status.

14 days OR In accordance with the Risk Informed Completion Time Program B.

Required Action and associated Completion Time of Condition A not met.

NOTE-----------

LCO 3.0.4.a is not applicable when entering MODE 3.

B.1 Be in MODE 3.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months C.

Two low set relief valves inoperable.

C.1 Be in MODE 3.

AND C.2 Be in MODE 4.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 36 hours 302/298

Reactor Building-to-Suppression Chamber Vacuum Breakers 3.6.1.7 Quad Cities 1 and 2 3.6.1.7-1 Amendment No. 199/195 3.6 CONTAINMENT SYSTEMS 3.6.1.7 Reactor Building-to-Suppression Chamber Vacuum Breakers LCO 3.6.1.7 Each reactor building-to-suppression chamber vacuum breaker shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, and 3.

ACTIONS

NOTE-------------------------------------

Separate Condition entry is allowed for each line.

CONDITION REQUIRED ACTION COMPLETION TIME A.

One or more lines with one reactor building-to-suppression chamber vacuum breaker not closed.

A.1 Close the open vacuum breaker.

7 days OR In accordance with the Risk Informed Completion Time Program B.

One or more lines with two reactor building-to-suppression chamber vacuum breakers not closed.

B.1 Close one open vacuum breaker.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months (continued) 302/298

Reactor Building-to-Suppression Chamber Vacuum Breakers 3.6.1.7 Quad Cities 1 and 2 3.6.1.7-2 Amendment No. 248/243 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C.

One line with one or more reactor building-to-suppression chamber vacuum breakers inoperable for opening.

C.1 Restore the vacuum breaker(s) to OPERABLE status.

7 days OR In accordance with the Risk Informed Completion Time Program D. Required Action and Associated Completion Time of Condition C not met.

NOTE-----------

LCO 3.0.4.a is not applicable when entering MODE 3.

D.1 Be in MODE 3.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months E.

Two lines with one or more reactor building-to-suppression chamber vacuum breakers inoperable for opening.

E.1 Restore all vacuum breakers in one line to OPERABLE status.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months F.

Required Action and Associated Completion Time of Conditions A, B or E not met.

F.1 Be in MODE 3.

AND F.2 Be in MODE 4.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 36 hours 302/298

Reactor Building-to-Suppression Chamber Vacuum Breakers 3.6.1.7 Quad Cities 1 and 2 3.6.1.7-3 Amendment No. 248/243 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.1.7.1

NOTES------------------

1.

Not required to be met for vacuum breakers that are open during Surveillances.

2.

Not required to be met for vacuum breakers open when performing their intended function.

Verify each vacuum breaker is closed.

In accordance with the Surveillance Frequency Control Program SR 3.6.1.7.2 Perform a functional test of each vacuum breaker.

In accordance with the Surveillance Frequency Control Program SR 3.6.1.7.3 Verify the opening setpoint of each vacuum breaker is 0.5 psid.

In accordance with the Surveillance Frequency Control Program 302/298

Suppression Chamber-to-Drywell Vacuum Breakers 3.6.1.8 Quad Cities 1 and 2 3.6.1.8-1 Amendment No. 245/240 3.6 CONTAINMENT SYSTEMS 3.6.1.8 Suppression Chamber-to-Drywell Vacuum Breakers LCO 3.6.1.8 Nine suppression chamber-to-drywell vacuum breakers shall be OPERABLE for opening.

AND Twelve suppression chamber-to-drywell vacuum breakers shall be closed.

APPLICABILITY:

MODES 1, 2, and 3.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One required suppression chamber-to-drywell vacuum breaker inoperable for opening.

A.1 Restore one vacuum breaker to OPERABLE status.

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR In accordance with the Risk Informed Completion Time Program B.

Required Action and associated Completion Time of Condition A not met.

NOTE-----------

LCO 3.0.4.a is not applicable when entering MODE 3.

B.1 Be in MODE 3.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months C.

One suppression chamber-to-drywell vacuum breaker not closed.

C.1 Close the open vacuum breaker.

4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months (continued) 302/298

Suppression Chamber-to-Drywell Vacuum Breakers 3.6.1.8 Quad Cities 1 and 2 3.6.1.8-2 Amendment No. 248/243 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME D.

Required Action and associated Completion Time of Condition C not met.

D.1 Be in MODE 3.

AND D.2 Be in MODE 4.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 36 hours SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.1.8.1

NOTES------------------

1.

Not required to be met for vacuum breakers that are open during Surveillances.

2.

Not required to be met for vacuum breakers open when performing their intended function.

Verify each vacuum breaker is closed.

In accordance with the Surveillance Frequency Control Program (continued) 302/298

Suppression Chamber-to-Drywell Vacuum Breakers 3.6.1.8 Quad Cities 1 and 2 3.6.1.8-3 Amendment No. 248/243 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.1.8.2 Perform a functional test of each required vacuum breaker.

In accordance with the Surveillance Frequency Control Program AND Within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after any discharge of steam to the suppression chamber from the relief valves SR 3.6.1.8.3 Verify the opening setpoint of each required vacuum breaker is 0.5 psid.

In accordance with the Surveillance Frequency Control Program 302/298

RHR Suppression Pool Cooling 3.6.2.3 Quad Cities 1 and 2 3.6.2.3-1 Amendment No. 245/240 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 pool cooling subsystem inoperable.

A.1 Restore RHR suppression pool cooling subsystem to OPERABLE status.

7 days OR In accordance with the Risk Informed Completion Time Program B.

Required Action and associated Completion Time of Condition A not met.

NOTE-----------

LCO 3.0.4.a is not applicable when entering MODE 3.

B.1 Be in MODE 3.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months C.

Two RHR suppression pool cooling subsystems inoperable.

C.1 Restore one RHR suppression pool cooling subsystem to OPERABLE status.

8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months D.

Required Action and associated Completion Time of Condition C not met.

D.1 Be in MODE 3.

AND D.2 Be in MODE 4.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 36 hours 302/298

RHR Drywell Spray 3.6.2.6 Quad Cities 1 and 2 3.6.2.6-1 Amendment No. 281/277 3.6 CONTAINMENT SYSTEMS 3.6.2.6 Residual Heat Removal (RHR) Drywell Spray LCO 3.6.2.6 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 subsystem inoperable.

A.1 Restore RHR drywell spray subsystem to OPERABLE status.

7 days OR In accordance with the Risk Informed Completion Time Program B.

Two RHR drywell spray subsystems inoperable.

B.1 Restore one RHR drywell spray subsystem to OPERABLE status.

8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months C.

Required Action and associated Completion Time not met.

C.1 Be in MODE 3.

AND C.2 Be in MODE 4.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 36 hours 302/298

RHRSW System 3.7.1 Quad Cities 1 and 2 3.7.1-1 Amendment No. 199/195 3.7 PLANT SYSTEMS 3.7.1 Residual Heat Removal Service Water (RHRSW) System LCO 3.7.1 Two RHRSW subsystems shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, and 3.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One RHRSW pump inoperable.

A.1 Restore RHRSW pump to OPERABLE status.

30 days B.

One RHRSW pump in each subsystem inoperable.

B.1 Restore one RHRSW pump to OPERABLE status.

7 days OR In accordance with the Risk Informed Completion Time Program (continued) 302/298

RHRSW System 3.7.1 Quad Cities 1 and 2 3.7.1-2 Amendment No. 248/243 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C.

One RHRSW subsystem inoperable for reasons other than Condition A.

C.1

NOTE--------

Enter applicable Conditions and Required Actions of LCO 3.4.7, "Residual Heat Removal (RHR)

Shutdown Cooling SystemHot Shutdown,"

for RHR shutdown cooling subsystem made inoperable by RHRSW System.

Restore RHRSW subsystem to OPERABLE status.

7 days OR In accordance with the Risk Informed Completion Time Program D.

Required Action and associated Completion Time of Conditions A, B, or C not met.

NOTE------------

LCO 3.0.4.a is not applicable when entering MODE 3.

D.1 Be in MODE 3.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months (continued) 302/298

RHRSW System 3.7.1 Quad Cities 1 and 2 3.7.1-3 Amendment No. 248/243 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME E.

Both RHRSW subsystems inoperable for reasons other than Condition B.

E.1

NOTE--------

Enter applicable Conditions and Required Actions of LCO 3.4.7 for RHR shutdown cooling subsystems made inoperable by RHRSW System.

Restore one RHRSW subsystem to OPERABLE status.

8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months F.

Required Action and associated Completion Time of Condition E not met.

F.1 Be in MODE 3.

AND F.2 Be in MODE 4.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 36 hours SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.1.1 Verify each RHRSW manual and power operated valve in the flow path, that is not locked, sealed, or otherwise secured in position, is in the correct position or can be aligned to the correct position.

In accordance with the Surveillance Frequency Control Program 302/298

SSMP System 3.7.9 Quad Cities 1 and 2 3.7.9-1 Amendment No. 248/243 3.7 PLANT SYSTEMS 3.7.9 Safe Shutdown Makeup Pump (SSMP) System LCO 3.7.9 The SSMP System shall be OPERABLE.

APPLICABILITY:

MODE 1, MODES 2 and 3 with reactor steam dome pressure > 150 psig.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

SSMP System inoperable.

A.1 Restore SSMP System to OPERABLE status.

14 days OR In accordance with the Risk Informed Completion Time Program B.

Required Action and associated Completion Time not met.

B.1 Be in MODE 3.

AND B.2 Reduce reactor steam dome pressure to 150 psig.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 36 hours 302/298

SSMP System 3.7.9 Quad Cities 1 and 2 3.7.9-2 Amendment No. 248/243 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.9.1 Verify each SSMP System manual, power operated, and automatic valve in the flow path, that is not locked, sealed, or otherwise secured in position, is in the correct position.

In accordance with the Surveillance Frequency Control Program SR 3.7.9.2 Verify SSMP System pump develops a flow rate 400 gpm against a system head corresponding to reactor pressure

> 1120 psig.

In accordance with the Surveillance Frequency Control Program 302/298

AC SourcesOperating 3.8.1 Quad Cities 1 and 2 3.8.1-2 Amendment No. 275/270 ACTIONS

NOTE-------------------------------------

LCO 3.0.4.b is not applicable to the unit and common DGs, but is applicable to the opposite unit DG.

CONDITION REQUIRED ACTION COMPLETION TIME A.

One required offsite circuit inoperable.

A.1 Perform SR 3.8.1.1 for OPERABLE required offsite circuit.

AND A.2 Declare required feature(s) with no offsite power available inoperable when the redundant required feature(s) are inoperable.

AND A.3 Restore required offsite circuit to OPERABLE status.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months AND Once per 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months thereafter 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months from discovery of no offsite power to one division concurrent with inoperability of redundant required feature(s) 7 days OR In accordance with the Risk Informed Completion Time Program (continued) 302/298

AC SourcesOperating 3.8.1 Quad Cities 1 and 2 3.8.1-3 Amendment No. 298/294 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B.

One required DG inoperable.

B.1 Perform SR 3.8.1.1 for OPERABLE required offsite circuit(s).

AND B.2 Declare required feature(s), supported by the inoperable DG, inoperable when the redundant required feature(s) are inoperable.

AND B.3.1 Determine OPERABLE DG(s) are not inoperable due to common cause failure.

OR B.3.2 Perform SR 3.8.1.2 for OPERABLE DG(s).

AND B.4 Restore required DG to OPERABLE status.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months AND Once per 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months thereafter 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months from discovery of Condition B concurrent with inoperability of redundant required feature(s) 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 24 hours 7 days*

OR In accordance with the Risk Informed Completion Time Program (continued)

Until DG 1 is returned to OPERABLE status, not to exceed 1056 CST on December 25, 2023, the 7 day Completion Time is extended to 14 days. During the extended period, the compensatory actions listed in Attachment 4 of letter RS-23-128 dated December 15, 2023, shall be implemented. If SBO DG-1 becomes unavailable at any time during the extended period, the Required Action is to restore SBO DG-1 within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or enter Condition F.

302/298

AC SourcesOperating 3.8.1 Quad Cities 1 and 2 3.8.1-4 Amendment No. 199/195 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C.

Two required offsite circuits inoperable.

C.1 Declare required feature(s) inoperable when the redundant required feature(s) are inoperable.

AND C.2 Restore one required offsite circuit to OPERABLE status.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months from discovery of Condition C concurrent with inoperability of redundant required feature(s) 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OR In accordance with the Risk Informed Completion Time Program D.

One required offsite circuit inoperable.

AND One required DG inoperable.

NOTE------------

Enter applicable Conditions and Required Actions of LCO 3.8.7, "Distribution SystemsOperating," when Condition D is entered with no AC power source to any division.

D.1 Restore required offsite circuit to OPERABLE status.

OR 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months OR In accordance with the Risk Informed Completion Time Program (continued) 302/298

AC SourcesOperating 3.8.1 Quad Cities 1 and 2 3.8.1-5 Amendment No. 245/240 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME D.

(continued)

D.2 Restore required DG to OPERABLE status.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months OR In accordance with the Risk Informed Completion Time Program E.

Two required DGs inoperable.

E.1 Restore one required DG to OPERABLE status.

2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months F.

Required Action and associated Completion Time of Condition A, B, C, D, or E not met.

NOTE-----------

LCO 3.0.4.a is not applicable when entering MODE 3.

F.1 Be in MODE 3.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months G.

Three or more required AC sources inoperable.

G.1 Enter LCO 3.0.3.

Immediately 302/298

DC SourcesOperating 3.8.4 Quad Cities 1 and 2 3.8.4-1 Amendment No. 199/195 3.8 ELECTRICAL POWER SYSTEMS 3.8.4 DC SourcesOperating LCO 3.8.4 The following DC electrical power subsystems shall be OPERABLE:

a.

Two 250 VDC electrical power subsystems; b.

Division 1 and Division 2 125 VDC electrical power subsystems; and c.

The opposite unit's 125 VDC electrical power subsystem capable of supporting equipment required to be OPERABLE by LCO 3.6.4.3, "Standby Gas Treatment (SGT) System,"

LCO 3.7.4, "Control Room Emergency Ventilation (CREV)

System" (Unit 2 only), LCO 3.7.5 "Control Room Emergency Ventilation Air Conditioning (AC) System" (Unit 2 only),

and LCO 3.8.1, "AC SourcesOperating."

APPLICABILITY:

MODES 1, 2, and 3.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One 250 VDC electrical power subsystem inoperable.

A.1 Restore the 250 VDC electrical power subsystem to OPERABLE status.

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR In accordance with the Risk Informed Completion Time Program (continued) 302/298

DC SourcesOperating 3.8.4 Quad Cities 1 and 2 3.8.4-2 Amendment No. 199/195 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B.

NOTE---------

Only applicable if the opposite unit is in MODE 1, 2, or 3.

Division 1 or 2 125 VDC battery inoperable as a result of maintenance or testing.

B.1 Place associated OPERABLE alternate 125 VDC electrical power subsystem in service.

AND B.2 Restore Division 1 or 2 125 VDC battery to OPERABLE status.

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Prior to exceeding 7 cumulative days per operating cycle of battery inoperability, on a per battery basis, as a result of maintenance or testing C.

NOTE---------

Only applicable if the opposite unit is in MODE 1, 2, or 3.

Division 1 or 2 125 VDC battery inoperable, due to the need to replace the battery, as determined by maintenance or testing.

C.1 Place associated OPERABLE alternate 125 VDC electrical power subsystem in service.

AND C.2 Restore Division 1 or 2 125 VDC battery to OPERABLE status.

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months 7 days OR In accordance with the Risk Informed Completion Time Program (continued) 302/298

DC SourcesOperating 3.8.4 Quad Cities 1 and 2 3.8.4-3 Amendment No. 245/240 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME D.

Division 1 or 2 125 VDC electrical power subsystem inoperable for reasons other than Conditions B or C.

D.1 Restore Division 1 or 2 125 VDC electrical power subsystem to OPERABLE status.

OR D.2

NOTE---------

Only applicable if the opposite unit is not in MODE 1, 2, or 3.

Place associated OPERABLE alternate 125 VDC electrical power subsystem in service.

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR In accordance with the Risk Informed Completion Time Program 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months E.

Opposite unit 125 VDC electrical power subsystem inoperable.

E.1 Restore the opposite unit 125 VDC electrical power subsystem to OPERABLE status.

7 days OR In accordance with the Risk Informed Completion Time Program F.

Required Action and associated Completion Time not met.

NOTE-----------

LCO 3.0.4.a is not applicable when entering MODE 3.

F.1 Be in MODE 3.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 302/298

Distribution SystemsOperating 3.8.7 Quad Cities 1 and 2 3.8.7-1 Amendment No. 275/270 3.8 ELECTRICAL POWER SYSTEMS 3.8.7 Distribution SystemsOperating LCO 3.8.7 The following electrical power distribution subsystems shall be OPERABLE:

a.

Division 1 and Division 2 AC and DC electrical power distribution subsystems; and b.

The portions of the opposite unit's AC and DC electrical power distribution subsystems necessary to support equipment required to be OPERABLE by LCO 3.6.4.3, "Standby Gas Treatment (SGT) System," LCO 3.7.4, "Control Room Emergency Ventilation (CREV) System" (Unit 2 only), LCO 3.7.5, "Control Room Emergency Ventilation Air Conditioning (AC) System" (Unit 2 only),

and LCO 3.8.1, "AC SourcesOperating."

APPLICABILITY:

MODES 1, 2, and 3.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One or more AC electrical power distribution subsystems inoperable.

A.1 Restore AC electrical power distribution subsystems to OPERABLE status.

8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months OR In accordance with the Risk Informed Completion Time Program (continued) 302/298

Distribution SystemsOperating 3.8.7 Quad Cities 1 and 2 3.8.7-2 Amendment No. 275/270 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B.

One or more DC electrical power distribution subsystems inoperable.

B.1 Restore DC electrical power distribution subsystems to OPERABLE status.

2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months OR In accordance with the Risk Informed Completion Time Program C.

One or more required opposite unit AC or DC electrical power distribution subsystems inoperable.

NOTE------------

Enter applicable Condition and Required Actions of LCO 3.8.1 when Condition C results in the inoperability of a required offsite circuit.

C.1 Restore required opposite unit AC and DC electrical power distribution subsystems to OPERABLE status.

7 days OR In accordance with the Risk Informed Completion Time Program D.

Required Action and associated Completion Time of Condition A, B, or C not met.

NOTE-----------

LCO 3.0.4.a is not applicable when entering MODE 3.

D.1 Be in MODE 3.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months E.

Two or more electrical power distribution subsystems inoperable that, in combination, result in a loss of function.

E.1 Enter LCO 3.0.3.

Immediately 302/298

Programs and Manuals 5.5 5.5 Programs and Manuals Quad Cities 1 and 2 5.5-14 Amendment No. 248/243 5.5.14 Surveillance Frequency Control Program This program provides controls for 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 those Surveillance Requirements for which the Frequency is controlled by the program.

b.

Changes to the Frequencies listed in the Surveillance Frequency Control Program shall be made in accordance with NEI 04-10, Risk-Informed Method for Control of Surveillance Frequencies, Revision 1.

c.

The provisions of Surveillance Requirements 3.0.2 and 3.0.3 are applicable to the Frequencies established in the Surveillance Frequency Control Program.

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 and 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 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after the plant configuration change, whichever is less.

(continued) 302/298

Programs and Manuals 5.5 5.5 Programs and Manuals Quad Cities 1 and 2 5.5-15 Amendment No. 248/243 5.5.15 Risk Informed Completion Time Program (continued) 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:

1.

Numerically accounting for the increased possibility of CCF in the RICT calculation; or 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.

A RICT calculation must include the following hazard groups:

internal flood and internal events using a PRA model, internal fires using a PRA model, seismic hazards using penalty factors, and extreme wind and tornado hazards using configuration-specific penalty factors for tornado missiles.

Changes to these means of assessing the hazard groups require prior NRC approval.

f.

The PRA models used to calculate RICT shall be maintained and upgraded in accordance with the processes endorsed in the regulatory positions of Regulatory Guide 1.200, Revision 3, "Acceptability of Probabilistic Risk Assessment Results for Risk-Informed Activities."

g.

A report shall be submitted in accordance with Specification 5.6.7 before a newly developed method is used to calculate a RICT.

302/298

Reporting Requirements 5.6 5.6 Reporting Requirements Quad Cities 1 and 2 5.6-5 Amendment No. 294/290 5.6.5 CORE OPERATING LIMITS REPORT (COLR) (continued)

18. EMF-2292 (P)(A) Revision 0, "ATRIUMTM-10: Appendix K Spray Heat Transfer Coefficients," Siemens Power Corporation, September 2000.

19. ANF-1358(P)(A) Revision 3, "The Loss of Feedwater Heating Transient in Boiling Water Reactors," Framatome ANP, September 2005.

20. EMF-CC-074(P)(A) Volume 4 Revision 0, "BWR Stability Analysis: Assessment of STAIF with Input from MICROBURN-B2," Siemens Power Corporation, August 2000.

21. NEDC-33930P, Revision 0, "GEXL98 Correlation for ATRIUM 10XM Fuel," February 2021, as approved by NRC Staff SE dated December 15, 2022.

22. 006N8642-P, Revision 1, "Justification of PRIME Methodologies for Evaluating TOP and MOP Compliance for non-GNF Fuels," January 2022, as approved by NRC Staff SE dated February 6, 2023.

The COLR will contain the complete identification for each of the TS referenced topical reports used to prepare the COLR (i.e., report number, title, revision, date, and any supplements).

c.

The core operating limits shall be determined such that all applicable limits (e.g., fuel thermal mechanical limits, core thermal hydraulic limits, Emergency Core Cooling Systems (ECCS) limits, nuclear limits such as SDM, transient analysis limits, and accident analysis limits) of the safety analysis are met.

d.

The COLR, including any midcycle revisions or supplements, shall be provided upon issuance for each reload cycle to the NRC.

(continued) 302/298

Reporting Requirements 5.6 5.6 Reporting Requirements Quad Cities 1 and 2 5.6-6 Amendment No. 294/290 5.6.6 Post Accident Monitoring (PAM) Instrumentation Report When a report is required by Condition B or F of LCO 3.3.3.1, "Post Accident Monitoring (PAM) Instrumentation," a report shall be submitted within the following 14 days. The report shall outline the preplanned alternate method of monitoring, the cause of the inoperability, and the plans and schedule for restoring the instrumentation channels of the Function to OPERABLE status.

5.6.7 Risk Informed Completion Time (RICT) Program Upgrade Report A report describing newly developed methods and their implementation must be submitted following a probabilistic risk assessment (PRA) upgrade associated with newly developed methods and prior to the first use of those methods to calculate a RICT.

The report shall include:

a.

The PRA models upgraded to include newly developed methods; b.

A description of the acceptability of the newly developed methods consistent with Section 5.2 of PWROG-19027-NP, Revision 2, "Newly Developed Method Requirements and Peer Review;"

c.

Any open findings from the peer-review of the implementation of the newly developed methods and how those findings were dispositioned; and d.

All changes to key assumptions related to newly developed methods or their implementation.

302/298

SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 302 TO RENEWED FACILITY OPERATING LICENSE NO. DPR-29 AND AMENDMENT NO. 298 TO RENEWED FACILITY OPERATING LICENSE NO. DPR-30 CONSTELLATION ENERGY GENERATION, LLC AND MIDAMERICAN ENERGY COMPANY QUAD CITIES NUCLEAR POWER STATION, UNITS 1 AND 2 DOCKET NOS. 50-254 AND 50-265

1.0 INTRODUCTION

By application dated June 8, 2023 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML23159A249), as supplemented by letters dated March 19, 2024 (ML24079A122), April 5, 2024 (ML24096B782), May 10, 2024 (ML24131A079), and June 6, 2024 (ML24158A301), Constellation Energy Generation, LLC, (Constellation, the licensee) submitted a license amendment request (LAR) for Quad Cities Nuclear Power Station, Units 1 and 2 (QCNPS).

The amendments 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 (ML18183A493). The U.S.

Nuclear Regulatory Commission (NRC or the Commission) issued a final model safety evaluation (SE) approving TSTF-505, Revision 2, on November 21, 2018 (ML18269A041).

Additionally, the licensee requested to adopt associated traveler, TSTF-591, Revision 0, Revise Risk Informed Completion Time (RICT) Program, dated March 22, 2022 (ML22081A224). The U.S. Nuclear Regulatory Commission (NRC or the Commission) issued a safety evaluation (SE) approving TSTF-591 on September 21, 2023 (ML23262B230). TSTF-591 revises the TS section 5.5 requirements regarding changes to the risk assessment and adds a reporting requirement to TS section 5.6.

The licensee has proposed variations from the TS changes described in TSTF-505, Revision 2, which are described in Section 3.2.1 of this SE.

The NRC staff participated in a regulatory audit in January 2023 (the audit plan is located at ML23319A334) to ascertain the information needed to support its review of the application and to develop requests for additional information (RAIs), as needed. On May 28, 2024, the staff issued an audit summary (ML24110A049).

The supplemental letter dated March 19, 2024, provided additional information that clarified the application and expanded the scope of the application as originally noticed, and therefore changed the NRC staffs original proposed no significant hazards consideration determination as published in the Federal Register (FR) on February 21, 2023 (88 FR 10557). Therefore, the NRC staff published an additional notice in the FR on April 16, 2024 (89 FR 26944). The letters dated April 5, 2024, May 10, 2024, and June 6, 2024, provided additional information that clarified the application, as supplemented by the March 19, 2024, letter, did not expand the scope of the application, as supplemented by the March 19, 2024, letter, and therefore did not change the NRC staffs proposed no significant hazards consideration determination published in the FR on April 16, 2024.

2.0 REGULATORY EVALUATION

2.1 Regulatory Review 2.1.1 Applicable Regulations Title 10 of the Code of Federal Regulations (10 CFR) Part 50 provides the general provisions for Domestic Licensing of Production and Utilization Facilities. Under 10 CFR 50.90, whenever a holder of a license wishes to amend the license, including technical specifications in the license, an application for amendment must be filed, fully describing the changes desired. Under 10 CFR 50.92(a), determinations on whether to grant an applied-for license amendment are to be guided by the considerations that govern the issuance of initial licenses or construction permits to the extent applicable and appropriate. Both the common standards in 10 CFR 50.40(a), and those specifically for issuance of operating licenses in 10 CFR 50.57(a)(3), provide that there must be reasonable assurance that the activities at issue will not endanger the health and safety of the public. The following requirements are also appliable to the proposed amendments:

Section 50.36, Technical Specifications, of 10 CFR paragraphs (b), (c)(2), Limiting conditions for operations, and (c)(5), Administrative controls Section 50.55a, Codes and standards, of 10 CFR paragraph (h), Protection and safety systems Section 50.65, Requirements for monitoring the effectiveness of maintenance at nuclear power plants (i.e., the Maintenance Rule) of 10 CFR 2.1.2 Regulatory Guidance NRC Regulatory Guides (RGs) provide one way to ensure that the codified regulations continue to be met. The NRC staff considered the following guidance, and industry guidance endorsed by the NRC, during its review of the proposed changes:

RG 1.200, Revision 2, An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities, dated March 2009 (ML090410014) and RG 1.200, Revision 3, Acceptability of Probabilistic Risk Assessment Results for Risk-Informed Activities, dated December 2020 (ML20238B871).

RG 1.174, An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis, Revision 2, dated May 2011 and Revision 3, dated January 2018 (ML100910006 and ML17317A256, respectively).

RG 1.177, An Approach for Plant-Specific, Risk-Informed Decision making: Technical Specifications, Revision 1, dated May 2011 and Revision 2, dated January 2021 (ML100910008 and ML20164A034, respectively).

NUREG-1855, Revision 1, Guidance on the Treatment of Uncertainties Associated with PRAs [Probabilistic Risk Assessments] in Risk-Informed Decision making, dated March 2017 (ML17062A466).

NUREG-0800, Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants: LWR [Light-Water Reactor] Edition, (SRP) section 16.0, Technical Specifications, dated March 2010 (ML100351425); section 16.1, Risk-Informed Decision Making: Technical Specifications, dated March 2007 (ML070380228); and section 19.2, Review of Risk Information Used to Support Permanent Plant-Specific Changes to the Licensing Basis: General Guidance, dated June 2007 (ML071700658).

Nuclear Energy Institute (NEI) Topical Report (TR) NEI 06-09 Revision 0-A (NEI 06 A), Risk-Informed Technical Specifications Initiative 4b, Risk-Managed Technical Specifications (RMTS) Guidelines, dated October 2012 (ML122860402), provides guidance for risk-informed TSs. The NRC staff issued a final model SE approving NEI 06-09 on May 17, 2007 (ML071200238).

Topical report NEI 17-07, Revision 2, Performance of PRA [Probabilistic Risk Assessment] Peer Reviews Using the ASME/ANS [American Society of Mechanical Engineers/American Nuclear Society] PRA Standard, dated August 2019 (ML19231A182).

Pressurized Water Reactor Owners Group (PWROG) topical report PWROG-19027-NP, Revision 2, Newly Developed Method Requirements and Peer Review, dated July 2020 (ML20213C660).

The licensees submittal cites various revisions of RG 1.200, RG 1.174, and RG 1.177. The RGs have been updated to Revision 3 of RGs 1.200 and 1.174, and Revision 2 for RG 1.177.

The updates do not include any technical changes that would impact the consistency with NEI 06-09-A; therefore, the NRC staff finds the updated revisions to the RGs also applicable for use in the licensees adoption of TSTF-505, Revision 2 and TSTF-591, Revision 0.

2.2 Description of the RICT 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 (i.e., 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 Time(s) (CT). The CTs are referred to as the front stops in the context of this SE. For certain conditions, the TSs require exiting the Mode of Applicability of an LCO (e.g., shut down the reactor).

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 NEI 06-09-A. Consistent with Table 1 of TSTF-505, Revision 2, Conditions Requiring Additional Technical Justification, the LAR provided several plant-specific LCOs and associated Actions for which the licensee proposed to be included in the RICT Program, along with additional justification. The NRC staff review of these variations and the justification is provided in section 3.2.1 of this SE.

The licensee is proposing no changes to the design of the plant or any operating parameter, and no changes to the design basis in the proposed changes to the TSs. The effect of the proposed changes, when implemented, 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). These restrictions on inoperability of all required trains of a system ensure that consistency with the defense-in-depth (DID) 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.

TS 1.0, Use and Application:

The license amendment request, as supplemented, included Example 1.3-8 which will be added to TS 1.3, Completion Times, and will read as follows:

Example 1.3-8 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One subsystem inoperable.

A.1 Restore subsystem to OPERABLE status.

7 days OR In accordance with the Risk Informed Completion Time Program B. Required Action and associated Completion Time not met.

B.1 Be in MODE 3.

AND B.2 Be in MODE 4.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 36 hours 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 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 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 is exited, and therefore, the Required Actions of Condition B may be terminated.

2.3 Description of TSTF-591, Revision 0 In attachment 2 of supplemental letter dated March 19, 2024, the licensee proposed to adopt TSTF-591, Revision 0. The proposed changes would revise TS 5.5.15, Risk Informed Completion Time Program, by updating the reference for RG 1.200 from Revision 2 to Revision

3. The proposed changes would also add a new specification, TS 5.6.7, Risk Informed Completion Time (RICT) Program Upgrade Report, which would require the licensee to submit a report to the NRC before calculating a RICT using a newly developed method.

3.0 TECHNICAL EVALUATION

An acceptable approach for making risk-informed decisions about proposed TS changes, including both permanent and temporary changes, is to demonstrate that the proposed licensing basis (LB) changes meet the five key principles provided in section C of RG 1.174, Revision 3, and the three-tiered approach outlined in section C of RG 1.177, Revision 2. These key principles and tiers are:

Principle 1:

The proposed LB change meets the current regulations unless it is explicitly related to a requested exemption.

Principle 2:

The proposed LB change is consistent with the DID philosophy.

Principle 3:

The proposed LB change maintains sufficient safety margins.

Principle 4:

When the proposed LB change results in an increase in risk, the increase should be small and consistent with the intent of the Commissions policy statement on safety goals for the operations of nuclear power plants.

Tier 1: PRA Capability and Insights Tier 2: Avoidance of Risk-Significant Plant Configurations Tier 3: Risk-Informed Configuration Risk Management Principle 5:

The impact of the proposed LB change should be monitored by using performance measures strategies.

3.1 Method of NRC Staff Review Each of the key principles and tiers are addressed in NEI 06-09-A and approved in the final model SE issued by the NRC for TSTF-505, Revision 2. NEI 06-09-A provides a methodology for extending existing CTs, and to thereby delay 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. The NRC staffs evaluation of the licensees proposed use of RICTs against the key safety principles of RGs 1.174 and 1.177 is discussed below 3.2 Review of Key Principles 3.2.1 Key Principle 1: Evaluation of Compliance with Current Regulations Paragraph 50.36(c)(2) of 10 CFR requires that LCOs 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 TS until the condition can be met.

The CTs in the current TSs were established using experiential data, risk insights, and engineering judgement. 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, and the safety margins and DID remain sufficient. The option to determine the extended CT in accordance with the RICT Program allows the licensee to perform an integrated evaluation in accordance with the methodology prescribed in NEI 06-09-A and proposed TS 5.5.15, Risk Informed Completion Time Program. The RICT is limited to a maximum of 30 days (termed the backstop).

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.

In attachment 1, Description and Assessment; attachment 4, Cross-Reference of TSTF-505 and QCNPS Technical Specifications; and enclosure 1, List of Revised Required Actions to Corresponding PRA Function, to the LAR, as supplemented, the licensee provided a list of the TSs, associated LCOs, and Required Actions for the CTs that included modifications and variations from the approved TSTF-505. The modifications and variations consisted of proposed changes to the Required Actions and CTs. Furthermore, consistent with table 1 of TSTF-505, Revision 2, for QCNPS TS 3.3.2.2, TS 3.3.6.3, TS 3.3.8.1, TS 3.6.1.2, and TS 3.6.1.7 in section 4 of enclosure 1 to the LAR, the licensee included additional technical justification to demonstrate the acceptability for including these TSs in the RICT Program. The NRC staff reviewed the proposed changes to the TSs, associated LCOs, Required Actions, and CTs provided by the licensee for the scope of the RICT Program and concluded, with the incorporation of the RICT Program, that the required performance levels of equipment specified in LCOs are not changed and only the required CTs for the Required Actions are modified, such that 10 CFR 50.36(c)(2) will continue to be met. Based on the discussion provided above, the staff finds that the proposed RICT Program provided in section 2.0 of this SE, LCOs, Required Actions, and CTs meet the first key principle of RGs 1.174 and 1.177.

3.2.2 Key Principle 2: Evaluation of DID In RG 1.174, Revision 2, the NRC identified the following considerations used for evaluation of how the LB change is maintained for the DID philosophy:

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 [Common-Cause Failures].

Maintain multiple fission product barriers.

Preserve sufficient defense against human errors.

Continue to meet the intent of the plants design criteria.

The licensee requested to use the RICT Program to extend the existing CTs for the respective TS LCOs described in the LAR, as supplemented. For the TS LCOs in the LAR, as supplemented, the licensee provided a description and assessment of the redundancy and diversity for the proposed changes. The NRC staffs evaluation of the proposed changes for these LCOs assessed the redundant or diverse means to mitigate accidents to ensure consistency with the QCNPS LB requirements using the guidance in RG 1.174, RG 1.177, and TSTF-505, to ensure adequate DID (for each of the functions) to operate the facility in the proposed manner (i.e., that the changes are consistent with the DID criteria).

to the LAR, as supplemented, provided information supporting the licensees evaluation of the redundancy, diversity, and DID for each TS LCO and TS Required Action as it relates to instrumentation and controls (I&C) and electrical power systems. The NRC staff confirmed that for the following TS LCOs, the above DID criteria were applicable, except for the criteria for maintaining multiple fission product barriers:

3.3.1.1, Reactor Protection System (RPS) Instrumentation 3.3.2.2, Feedwater System and Main Turbine High Water Level Trip Instrumentation 3.3.4.1, Anticipated Transient Without Scram Recirculation Pump Trip (ATWS-RPT)

Instrumentation 3.3.5.1, Emergency Core Cooling System (ECCS) Instrumentation 3.3.5.3, Reactor Core Isolation Cooling (RCIC) System Instrumentation 3.3.6.1, Primary Containment Isolation Instrumentation 3.3.6.3, Relief Valve Instrumentation 3.3.8.1, Loss of Power (LOP) Instrumentation 3.8.1, AC [Alternating Current] Sources - Operating 3.8.4, DC [Direct Current] Sources - Operating 3.8.7, Distribution Systems - Operating For the TS LCOs specific to I&C (i.e., TS 3.3, Instrumentation, specifically: 3.3.1.1, 3.3.2.2, 3.3.4.1, 3.3.5.1, 3.3.5.3, 3.3.6.1, 3.3.6.3, 3.3.8.1), the NRC staff reviewed the specific trip logic arrangements, redundancy, backup systems, manual actions, and diverse trips specified for each of the protective safety functions and associated instrumentation, as described in the associated Updated Final Safety Analysis Report (UFSAR) (ML23293A285) sections, and as reflected in the LAR, as supplemented. The NRC staff verified that, in accordance with the QCNPS UFSAR and equipment and actions credited in enclosure 1 to the LAR, as supplemented, 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.

Furthermore, the staff concludes that there is sufficient redundancy, diversity, and DID, to protect against CCFs and potential single failure for the QCNPS instrumentation systems evaluated in LAR enclosure 1, as supplemented, during a RICT. There is at least one diverse means specified by the licensee for initiating mitigating action for each accident event, thus providing DID against a failure of instrumentation during the RICT for each TS LCO. The NRC staff confirmed that the DID specified by the licensee does not overly rely on manual actions as the diverse means: therefore, there is not over-reliance of programmatic activities as compensatory measures. Therefore, the NRC staff finds that the intent of the plants design criteria (e.g., safety functions) for the above TS LCOs related to I&C are maintained.

QCNPS is a dual-unit plant with its two units sharing the alternating current (AC) and direct current (DC) electrical power systems between them. In the supplement dated March 19, 2024 (in response to EEEB RAI-01 and EEEB RAI-03), the licensee explained that sharing of the AC and DC systems and how the single-failure criteria was applicable. In response to other EEEB RAIs related to design success criteria (DSC) and loss of function (LOF), the licensee provided necessary clarifications and an update to the LAR Table E1-1 In-Scope TS/LCO Conditions to Corresponding PRA Functions.

The NRC staff reviewed the electrical power systems design for a potential LOF for each proposed electrical RICT based on TSTF-505 and did not identify a LOF for any electrical power system for the proposed RICTs. The NRC staff reviewed the LAR and the supplement dated March 19, 2024, to verify each affected electrical LCO condition can be entered voluntarily or involuntarily based on NEI 06-09-A, and to evaluate if the affected electrical power systems for those LCO conditions could perform their safety functions (assuming no additional failures other than those considered in the applicable RICT condition) for proposed RICTs. Based on its evaluation to verify no LOF for any electrical proposed RICT, the NRC staff finds that the QCNPS electrical power systems would function as intended for the proposed TS changes. The NRC staff verified that the design success criteria in LAR table E1-1, In Scope TS/LCO Conditions to Corresponding PRA Functions, (as updated in supplement dated March 19, 2024) for each of the electrical TS 3.8 LCO conditions reflect the minimum operable electrical power sources to support their safety functions to mitigate postulated design-basis accidents, safely shutdown the reactor, and maintain the reactor in a safe shutdown condition. The NRC staff also finds that RICT estimates are provided for each of those TS 3.8 LCO Conditions in LAR table E1-2, In Scope TS/LCO Conditions RICT Estimate, "consistent with NEI 06-09-A.

Based on the above evaluation, the NRC staff finds that the QCNPS electrical power systems would continue to provide safety functions as intended with the proposed TS changes.

In enclosure 12, Risk Management Action Examples, to the LAR, the licensee provided examples of risk management actions (RMAs) that are representative of actual RMAs that may be considered during a RICT Program entry for any of the proposed changes to TS 3.8 LCO Conditions to reduce the risk impact and ensure adequate DID. The NRC staff reviewed the RMA examples related to the electrical power systems provided in enclosure 12, section 4, which included electrical related examples for TS 3.8.1.A, one required offsite circuit inoperable, TS 3.8.1.B, one required DG inoperable, TS 3.8.1.D, one required offsite circuit inoperable AND one required DG inoperable, and TS 3.8.4.D, Division 1 or 2 125 VDC electrical power subsystem inoperable for reasons other than Conditions B or C. The NRC staff determined the RMAs had the required level of detail that would reduce the risk impact and ensure adequate DID. Based on that review, the NRC staff determined that those examples provide reasonable assurance that the actual RMAs implemented to monitor and control risk for each LCO (for specific structures, systems, and component(s) (SSC(s)) will be of similar quality and specific to that LCO.

The NRC staff reviewed the licensees proposed electrical TS LCO changes and supporting documentation. Based on the evaluations above, the staff finds that given redundancy in various LCO conditions, the CT extensions as allowed by the RICT Program, are acceptable because the capacity and capability of the remaining operable electrical systems to perform their safety functions (assuming no additional failures) would remain adequate, and the licensees identification and implementation of RMAs as compensatory measures, in accordance with the RICT Program, would provide adequate DID.

Considering that the CT extensions will be implemented in accordance with the NEI 06-09-A guidance, which also considers RMAs and the redundancy of the offsite and onsite power system, the NRC staff finds that the plant will maintain adequate DID. Therefore, the staff finds that the TS LCOs proposed by the licensee in attachment 2 to the LAR, as supplemented, are acceptable for the RICT Program.

Based on the above, the NRC staff finds that the licensees proposed changes are consistent with the NRC-endorsed guidance described in NEI 06-09-A and satisfy the second key principle in RGs 1.177 and 1.174. Additionally, the staff concludes that the changes are consistent with the DID philosophy as described in RG 1.174.

3.2.3 Key Principle 3: Evaluation of Safety Margins Paragraph 50.55a(h) of 10 CFR requires in part, that [p]rotection systems of nuclear power reactors of all types must meet the requirements specified in this paragraph. Section 2.2.2, Technical Specification Change Maintains Sufficient Safety Margin (Principle 3), of RG 1.177 states, in part, that sufficient safety margins are maintained when:

a.

Codes and standards or alternatives approved for use by the NRC are met.

b.

Safety analysis acceptance criteria in the final safety analysis report (FSAR) are met or proposed revisions provide sufficient margin to account for analysis and data uncertainties.

The licensee is not proposing to change any quality standard, material, or operating specification in this application. In the LAR, the licensee proposed to add a new program, Risk Informed Completion Time Program, in section 5.5, Programs and Manuals, of the QCNPS TSs, which requires adherence to NEI 06-09-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 TSs 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 A, is limited to the inoperable train, loss-of-offsite power (LOOP), or component. Based on the above, the NRC staff finds that the design-basis analyses for QCNPS remain applicable and unchanged, that sufficient safety margins would be maintained during the extended CT, and that the proposed changes to the TSs do not include any change in the standards applied or the safety analysis acceptance criteria. The NRC staff concludes that the proposed changes meet 10 CFR 50.55a(h) and, therefore, the third key principle of RGs 1.177 and 1.174.

3.2.4 Key Principle 4: Change in Risk Consistent with the Safety Goal Policy Statement Proposed TS section 5.5.15, states, in part, that the RICT must be implemented in accordance with NEI 06-09-A, Revision 0, Risk-Managed Technical Specifications (RMTS) Guidelines.

NEI 06-09-A provides a methodology for a licensee to evaluate and manage the risk impact of extensions to TS CTs. Permanent changes to the fixed TS CTs are typically evaluated by using the three-tiered approach described in SRP section 16.1; RG 1.177, Revision 2; and RG 1.174, Revision 3. This approach addresses the calculated change in risk as measured by the change in core damage frequency (CDF) and large early release frequency (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 configuration risk management program (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 would be small and consistent with the intent of the Commissions Safety Goal Policy Statement1. In addition, the staff evaluated the licensees proposed changes against the three-tiered approach in RG 1.177, Revision 2, for the licensees evaluation of the risk associated with a proposed TS CT change. The results of the NRC staffs review are discussed below.

3.2.4.1 Tier 1: PRA Capability and Insights Tier 1 evaluates the impact of the proposed changes on plant operational risk. The Tier 1 review involves two aspects: (1) scope and 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.

1 Commissions Safety Goal Policy Statement, Safety Goals for the Operations of Nuclear Power Plants; Policy Statement, published in the Federal Register on August 4, 1986 (51 FR 28044), as corrected, and republished, on August 21, 1986 (51 FR 30028).

In enclosure 2, Information Supporting Consistency with Regulatory Guide 1.200, Revision 2, and enclosure 4, Information Supporting Justification of Excluding Sources of Risk Not Addressed by the PRA Models, to the LAR, the licensee identified the following modeled hazards and alternate methodologies that the licensee proposed to be used in the QCNPS RICT Program to assess the risk contribution for extending the CT of a TS LCO:

Internal Events PRA (IEPRA) model (includes internal floods),

Internal Fire Events PRA (FPRA) model.

Seismic Hazard: a CDF penalty of 4.31 x 10-6 per year, and a LERF penalty of 1.98 x 10-6 per year (inerted containment) and 4.31 x 10-6 per year (de-inerted containment)

Extreme Winds and Tornado Missile Hazards: Tornado missile CDF penalty of 1x10-5 per year and a tornado missile LERF penalty of 5x10-7 per year for all plant configurations associated with LCOs to be included in the RICT Program, Other External Hazards: screened out from RICT Program based on appendix 6A of the ASME/ANS RA-Sa-2009, Addenda to ASME/ANS RA-S 2008, Standard for Level 1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications (ASME/ANS RA-SA-2009 PRA Standard).

PRA Scope The guidance in RG 1.174, Revision 3, states that [t]he 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 process. The NRCs SE for NEI 06-09-A states that the PRA models should conform to the guidance in RG 1.200, Revision 1. The current version is RG 1.200, Revision 3, which clarifies the current applicable ASME/ANS PRA 3.2.4.1.2 Evaluation of PRA Acceptability for Internal Events and Internal Fires Standard is ASME/ANS RA-Sa-2009. RG 1.200, Revision 3, is a recent update that does not include any technical challenges that would impact the plants consistency with NEI 06-09-A; therefore, both RG 1.200, Revisions 2 and 3 are acceptable for the implementation of the RICT Program. For external hazards for which a PRA is not available, the guidance in NEI 06-09-A allows for the use of bounding analysis of the risk contribution of the hazard for incorporation into the RICT calculation or justification for why the hazard is not significant to the RICT calculation.

The NRC staff evaluated the PRA acceptability information provided by the licensee in enclosure 2 to the LAR, 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 and extreme winds and tornado missile, as described later in this section, as insignificant contributors to the RICT calculations. The QCNPS PRA model with modifications is used as the CRMP model, as described later in this section. In addition, the licensee provided a bounding estimate of the seismic and tornado missile CDFs and LERFs and will include those CDF and LERF values, per sections 3.9 and 4.2 of enclosure 4 to the LAR, in the change-in-risk used to calculate RICTs consistent with the guidance in NEI 06-09-A.

The NRC staff finds that the QCNPS scope of modeled PRA hazards, and those hazards for which a modeled PRA is not available where the licensee has proposed use of alternative methods, are commensurate with the RICT application for use in the integrated decision-making process, consistent with RG 1.174, Revision 3.

Evaluation of PRA Acceptability for Internal Events and Internal Fires Internal Events PRA (Includes Internal Flooding)

In section 3 of enclosure 2, to the June 8, 2023, submittal the licensee explains that the internal events PRA model was subjected to a full-scope peer review in April 2017 against RG 1.200, Revision 2.

Subsequently, the licensee conducted an Independent Assessments in February/March of 2021 to close the finding-level F&Os using the Appendix X process documented in the NEI letter to the NRC Final Revision of Appendix X to NEI 05-04/07-12/12-16, 'Close-out of Facts and Observations, dated February 21, 2017 (ML17086A431). All finding-level F&Os were reviewed and closed using this NRC-accepted process. Hence, the LAR does not identify any open finding-level F&Os.

The NRC staff finds that the QCNPS IEPRA (that includes internal flooding) was appropriately peer reviewed consistent with RG 1.200, Revision 2, and that all finding-level F&Os have been closed consistent with the Appendix X process guidance, as accepted, with conditions by the NRC staff. Therefore, the NRC staff concludes that the IEPRA (that includes internal flooding) is acceptable for use in the RICT Program.

Internal Fire (FPRA)

In enclosure 2, section 4 to the LAR, the licensee confirmed that the QCNPS internal FPRA model received a full-scope peer review in June 2013 using the ASME/ANS RA-Sa-2009 PRA Standard, and RG 1.200, Revision 2. Subsequent to the peer review, focused-scope peer reviews were conducted in February and May 2021. Subsequent independent assessment for closure of F&Os using the Appendix X process, as accepted, with conditions by the NRC staff, was performed in March and May 2021, which resulted in closure of all but one finding-level F&O, F&O 9-1. In response to APLB RAI-11 provided in the March 19, 2024, LAR supplement, the licensee provided the peer review description of the finding and recommended actions to close out the finding. Based on the information provided the NRC staff concluded that the open F&O 9-1 does not impact on this application since the remedy required updating documentation and required no PRA model updating.

In recent years the industry has submitted multiple fire PRAs for NRC staff review. During this period both the industry and NRC staff determined that updated guidance, methods, and data would be needed for a licensee to develop a more realistic fire model. To ensure that FPRA models not previously evaluated by staff are in alignment with updated guidance, methods, and data, the NRC staff provided a series of APLB RAI questions to ascertain the status of the QCNPS fire model. The licensees responses to APLB RAIs-01,-02,-03,-05,-06,-07,-08,-09, and-10 provided in the March 19, 2023, LAR supplement demonstrated that the QCNPS fire model has incorporated all of the updated guidance, methods, and data that are applicable to QCNPS.

The NRC staff finds that the QCNPS FPRA was appropriately peer reviewed consistent with RG 1.200, Revision 2, and that all finding-level F&Os have been closed consistent with the Appendix X process guidance, as accepted, with conditions by the staff. Therefore, the NRC staff concludes that the FPRA is acceptable for use in the RICT Program.

Evaluation of PRA External Hazards Modeled Evaluation of Seismic Hazard The licensees approach for including the seismic risk contribution in the RICT calculation is to add a seismic CDF and a seismic LERF penalty to each RICT calculation. The proposed seismic CDF penalty estimate was based on using the plant-specific mean seismic hazard curve developed in response to the Near-Term Task Force recommendation 2.1 (ML14090A526), and a plant-level mean high confidence of low probability of failure (HCLPF) capacity of 0.24g referenced to peak ground acceleration (PGA). The uncertainty parameter for seismic capacity was represented by a composite beta factor (c) of 0.4. The calculated seismic CDF penalty is 4.31x10-6 per year based on PGA, which is conservative as compared with a typical average of four frequencies, namely, PGA (100), 10, 5, and 1 Hz. The staffs review finds the method to determine the baseline seismic CDF acceptable for this application because it is consistent with the approach used in NRC Generic Issue 199 (GI-199) Implications of Updated Probabilistic Seismic Hazard Estimates in Central and Eastern United States on Existing Plants (ML100270582). For this application, the NRC staff convolved the input parameters identified by the licensee to confirm the proposed seismic CDF penalty estimate.

Concerning the proposed seismic LERF penalty estimate, the licensee explained in the LAR that an estimate of the seismic LERF was obtained by multiplying the estimated seismic CDF (as described above) by an average seismic conditional large early release probability (SCLERP). An estimate of the average SCLERP was calculated using 1) an estimation of the breakdown of seismic core damage frequency (SCDF) by accident sequence type and 2) PRA accident sequence progression information from the quantification results of the current QCNPS full power internal events (FPIE) PRA model of record adjusted to reflect the influence of seismic-induced failures. Information from industry SPRAs was used to inform the selection of key SSC fragilities. A convolution calculation of the seismic hazard curve and the fragility value for each SCDF sequence type category was performed to calculate the sequence weighted average SCLERP of 0.46. The calculated seismic LERF is 1.98x10-6 per year for an inerted containment. For the de-inerted containment, the penalty assumes that the seismic LERF estimate is equal to seismic CDF estimate and therefore, 4.31x10-6 per year. The NRC staff finds the licensees approach to determining a seismic LERF penalty estimate to be acceptable for this application because the lower range of seismic capacity is assigned to force higher fractional contributions to those accident sequence types with higher CLERPs which is conservative for the inerted containment and because the approach for de-inerted containment assumes a CLERP of 1.0.

The licensee stated in the LAR that the QCNPS seismic penalty calculation addresses the risk of seismically-induced LOOP by conservatively including very low magnitude seismic events (as low as 0.0005g PGA), which is a very small fraction of the QCNPS Safe Shutdown Earthquake (SSE), in the SCDF and seismic large early release frequency (SLERF) convolution calculations. The 24-hr non-recovered seismic-induced LOOP frequency is a very small percentage (approximately 1 percent for seismic events up to the SSE) of the frequency of such challenges already captured in the FPIE PRA such that it will not significantly impact the RICT Program calculations and therefore, has been omitted from explicit analysis in the RICT calculations. The NRC staff finds that this evaluation adequately addresses the impact of seismically induced LOOP for very low magnitude seismic events and has an insignificant impact on the RICT program calculations.

In summary, the NRC staffs review finds the licensees proposal to use the seismic CDF penalty of 4.31x10-6 per year, and a seismic LERF penalty of 1.98x10-6 per year for an inerted containment and 4.31x10-6 per year for a de-inerted containment to be acceptable for the licensees RICT Program for the QCNPS, because (1) the licensee used the most current site-specific seismic hazard information for the QCNPS, (2) the licensee used an acceptably low plant HCLPF value of 0.24g and a combined beta factor of 0.4 consistent with the information for the QCNPS in the GI-199 evaluation to develop the conservative seismic CDF penalty, (3) the licensee used an acceptably conservative sequence weighted average SCLERP of 0.46 to estimate a conservative seismic LERF, and (4) adding baseline seismic annual risk to RICT calculations, which assumes fully correlated failures, is conservative for this application.

Evaluation of Extreme Winds and Tornado Hazards Section 4.1 of enclosure 4 to the LAR discusses the licensees evaluation of extreme wind on this application. Tornado wind speed hazard curve information for Quad Cites is provided in Table 6-1 of NUREG/CR-4461, Tornado Climatology of the Contiguous United States, Revision 2 (ML070810400). Based on the EF scale, the wind speed for the 10-6 annual exceedance probability is 202 mph. Comparable 1,000,000 year Mean Recurrence Interval (MRI) tornado wind speeds from the American Society of Civil Engineers (ASCE) ASCE 7 Hazard Tool1 are less than 200 mph. The licensee concluded that the extreme winds pressure can generally be screened from consideration for the TSTF-505 application because the frequency of tornadoes having wind speeds that exceed the design basis of 300 miles per hour is much less than 10-6 per year, and the frequency of winds that could cause the failure of the concrete chimney are also less that 10-6 per year. In addition, tropical storms such as hurricanes are not a concern for QCNPS given its inland location, and the risk from straight winds is bounded by that from tornadoes.

Section 4.2 of enclosure 4 to the LAR discusses the licensees evaluation of tornado missile impact on this application. The licensee determined that for certain maintenance LCO configurations, tornado missiles could not be screened for the TSTF-505 application, necessitating a tornado missile penalty factor to be established for RICT calculations. Tornado missile failure probabilities for potentially vulnerable SSCs are based on the methodology provided in NEI 17-02 Tornado Missile Risk Evaluator (TMRE) Industry Guidance Document, Revision 1, September 2017 (ML17268A036). To develop the penalty factors, the tornado missile risk model was quantified for all LCO configurations proposed to be included within the RICT Program and for several risk significant combinations of LCO configurations. Based on its evaluations, to encompass all the plant configurations associated with LCOs to be included in the RICT Program, the licensee proposed a bounding tornado missile CDF penalty of 1x10-5 per year. Similarly, for all plant configurations associated with LCOs to be included in the RICT Program, the licensee proposed a tornado missile LERF penalty of 5x10-7 per year, which was determined by the licensee to be bounding for all LCOs and plant configurations.

The NRC staff reviewed the licensees evaluation provided in Section 4 of Enclosure 4, and finds the licensees determination of CDF and LERF tornado missile risk penalties acceptable for this application because (1) the tornado missile risk is calculated using a conservative approach for tornado strike frequencies, (2) recovery or mitigation are conservatively not 1 The ASCE 7 Hazard Tool can be accessed at https://asce7hazardtool.online/.

credited for these scenarios, although there are potential mitigation paths available using either installed equipment and/or FLEX, (3) the penalties bound the results of a tornado missile risk assessment for all LCOs encompassed by the RICT Program, and (4) the estimated LCO-specific tornado missile penalty factors would be added in their entirety to the delta-risk calculations for RICT determinations.

Evaluation of External Flooding Hazard QCNPS justified screening out the external flooding hazard for their TSTF-505 LAR by modifying the height of certain flood barriers around the power block, performing engineering calculations to justify the reduction in risk due to these modifications, and changing flood hazard procedures and training to accommodate these modifications. Through these changes, QCNPS was able to reduce their external flooding risk below the screening criteria as discussed below.

The post-Fukushima external flooding analysis required licensees to update their external flooding hazard curves and to evaluate for all applicable external flooding mechanisms that are beyond design basis, such as local intense precipitation (LIP) and combined effects river flooding. The QCNPS Flood Hazard Reevaluation Report (FHRR) (ML13081A037) determined that LIP and Combined Effects Flooding (which includes the Probable Maximum Flood (PMF),

upstream dam failure, and coincident wind/wave action) were not bounded by the current design basis. The NRC issued its staff assessment of the FHRR on November 18, 2016 (ML16323A343). The staff concluded that the results in the FHRR were appropriately evaluated and should serve as input to the Integrated Assessment (IA).

The QCNPS Flooding IA (non-public) was submitted to the NRC on June 29, 2018. This assessment demonstrated a complex approach to mitigate LIP and combined effects flooding which included the shutdown of both plants, removal of shield plugs along with the drywell and reactor vessel heads, filling the condensate storage tanks including the reactor cavities and dryer pools, removal of the gates that separate the units fuel storage pools, and finally opening the reactor building (RB) plant doors to allow the flood waters to enter the building. The updated analysis also demonstrated the need for QCNPS to install LIP barriers, namely metal stop logs, door panel installations, and hinged gates with inflatable seals, in the early response to either LIP or combined effect flooding events as they developed. The staff concluded in its staff assessment (ML19168A196) of the QCNPS IA that the UFSAR and LIP barrier measures appropriately addressed plant vulnerabilities to external flooding.

More specifically the FHRR found that extreme precipitation could cause flooding above ground floor elevation (595 feet). QCNPS has 14 credited flood barriers around the power block to keep LIP flood waters from entering the buildings. These barriers are listed in Table E4-12 of the LAR. Seven of the barriers are temporary and require manual installation. The remaining barriers are permanently installed exterior doors or plates that do not require manual action to perform their function. All exterior credited flood barriers were evaluated in the IA. In the TSTF-505 LAR, the licensee provided that the installation of the seven temporary barriers is governed by QCOA 0010-22, Local Intense Precipitation Response Procedure, which includes rainfall monitoring and action triggers. The LAR also states that the longest barrier installation takes approximately 45 minutes, and all seven can be done concurrently with eight equipment operators in approximately 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . In the IA, the licensee stated that there are no direct external flooding impacts from a LIP once the LIP barriers are installed. The IA provided the justification that the timeline is well defined, the entry conditions are provided in the procedures, and training is provided, such that QCNPS demonstrated the response to the LIP is adequate. For the TSTF-505 LAR, the licensee screened out the LIP Hazard using preliminary screening Criterion 1 Event damage potential is less than events for which the plant is designed.

For the combined effects floods, a Probabilistic Flood Hazard Assessment (PFHA) was performed in 2021 to characterize the frequency of floods exceeding plant grade and the LIP barriers. The PFHA showed that for the combined effects flood, the frequency of water exceeding the ground floor elevation of 595.0 feet is approximately 2x10-6/yr, as shown in Figure E4-3 of the TSTF-505 LAR. To lower the risk of the combined effects flood hazard, the licensee determined that certain LIP barriers could be modified to protect the plant up to the height of 599.0 feet, which equates to an exceedance frequency less than 1x10-6 per year. In the LAR, the licensee estimated that the Human Error Probabilities (HEP) to install each of the seven LIP barriers to the 599.0 feet level to be 5x10-02 for an overall HEP of 3x10-1. The licensee assumed no credit for additional mitigation capability leading to the CCDP to be estimated at 3x10-1, which is equal to the HEP of installing all the flood barriers. The licensee combined the CCDP with the frequency of flood waters exceeding plant grade and then topping the LIP barriers to estimate the mean CDF at 6x10-7/yr.

QCNPS has not yet completed updating this new mitigation strategy credited in the consideration of external flooding risk for this application and, therefore, provided an implementation item in Table A5-1 of Attachment 5 of the TSTF-505 LAR to complete the associated engineering change (EC) 636914 prior to implementing the RICT program. The staff noted that changes to EC 636912, as well as changes to plant emergency procedure QCOA 0010-16 also appeared incomplete. In its March 19, 2024, response to APLC RAI-02, the licensee stated that updates to procedural guidance in QCOA-0010-16 and QCOA-0010-22 are included in EC 636912 and EC 636914 directly cross-referenced EC 636912 so only EC 636914 was originally listed as an implementation item. For clarity, the licensee stated in the same RAI response that TSTF-505 LAR Attachment 5, Table A5-1 implementation item will be revised with additional specificity. The NRC staff determined that the updated implementation item provides adequate assurance that the required updates support this application and will be completed prior to implementing the RICT program.

The external flood hazard screening analysis that is provided in Section 5 in Enclosure 4 of the TSTF-505 LAR does not credit some the UFSAR external flooding mitigations steps used by the licensee in their External Flooding IA and evaluated by the NRC staff in their staff assessment.

In response to APLC RAI-01 regarding credit for the Darley pump, and APLC RAI-05 regarding the RB crane, in its March 19, 2024, supplement, the licensee clarified that the use of the Darley pump to fill the condensate storage tanks including the reactor cavities and dryer pools and use of the RB crane to remove the shield plugs and the drywell and reactor vessel heads are not credited in the TSTF-505 conservative estimate of external flooding risk.

In its March 19, 2024, response to APLC RAI-06 requesting justification for the continued validity of the conclusions of the staffs IA assessment in light of the external flooding modifications to the plant, the licensee provided that steps 1 through 11 of the UFSAR strategy described in the licensees IA are still part of the plants design safety analysis and would still be performed in the event of a severe external flooding event. The response further stated that the addition of the higher LIP barriers is a risk reduction measure that does not impact the completion of any of the other LB actions or mitigation capabilities and explained that it reduces the probability that the event progresses to the last step in the UFSAR strategy. Based on its review, the NRC staff finds that the updated external flooding mitigation strategy described in the LAR does not change the plants design safety analysis for external flooding.

The NRC staff noted in APLC RAI-03 that the analysis provided in Enclosure 4 regarding the CCDP for LIP barrier installation appeared to require an extensive number of operators given there are several barriers to be installed, lack of specificity regarding training and timing validation, and concerns of the robustness and maintenance of the barriers. In response to APLC RAI-03 in its March 19, 2024, supplement, the licensee stated that their analysis regarding LIP barrier installation requires 8 plant personnel, that the longest install time for a single barrier requires 45 minutes, the barriers could be installed in parallel or in series as the operators would have a 96-hour time completion, and that each of the operators would initially be trained during their on-the-job training/task performance evaluation with continuing training performed quadrennially for licensed operator requalification training and biennially for end of cycle. The licensee further stated that the barriers are stored at each of the installation locations (right next to the opening or physically attached to the wall for hinged barriers), that the barriers are designed to withstand four times the amount of pressure required to screen the scenario, and that the licensee has implemented a program which provides augmented quality assurance measures, therefore, the structural failure of the barrier is a much lower probability than the failure to manually install which supports the estimated conditional core damage probability (CCDP) value of 3x10-1. The NRC staffs review determined that the training requirements for LIP barrier installation is consistent with industry standards and that the LIP barriers themselves are adequate to address external floods.

The NRC staff, in APLC RAI-04, requested information to support the licensees assertion that the LIP barrier installation HEP values provided in the TSTF-LAR are conservative, and consistent with the guidance in NEI-06-09-A, as well as NUREG-1792 Good Practices for Implementing Human Reliability Analysis (ML051160213). In its March 19, 2024, supplement response, the licensee performed more detailed analyses of the manual actions utilizing the NRC developed Integrated Human Event Analysis System for Event and Condition Assessment (IDHEAS-ECA) methodology. Using this methodology, the licensee estimated that the total HEP for installing all seven barriers is 1.1x10-2. The IDHEAS methodology identified "Understanding" as the main driver of failure probability to the human response of the river flood. In response to RAI-04, the licensee stated that a dependency analysis (DA) was not conducted on the operator actions associated with the external flooding mitigation strategy given these actions can extend the 24-hour PRA analysis window and that the operators have 96 hours0.00111 days 0.0267 hours 1.587302e-4 weeks 3.6528e-5 months to install, verify installation, and correct any errors well within the time provided. Furthermore, while the licensees updated HEP analysis estimated a lower value, their response stated that their estimate of external flooding risk will continue to use the more conservative value of 3x10-1 for the failure to install all seven barriers. The NRC staff finds that (1) the licensees updated human reliability analysis is consistent with the NRC developed IDHEAS-ECA methodology, (2)

QCNPS personnel have adequate time to enter the procedure, diagnose the scenario, and ensure proper installation of the LIP barriers, and (3) the HEP value of 3x10-1 used in the analysis is demonstrably conservative.

The licensees PFHA for the QCNPS and the surrounding Mississippi River basin characterized the frequency of floods exceeding the plant grade. The NRC staff provided requests for additional information in order for the staff to gain a better understanding of the PFHA methodologies, data sources, and uncertainty. Regarding data sources and modeling, the licensee stated that the Mississippi River basin upstream to QCNPS was subdivided into ten subbasins in order that the appropriate weather gages are assigned to each subbasin and that the subbasin is considered to have homogeneous weather characteristics. The selection of the 49 weather stations used for data input were based on the station having the longest duration of reporting, to provide the appropriate spatial representation of north to south and east to west, that all historical extreme events were captured by at least one of the stations, and any median missing data represented less than one percent of the data required for the analysis.

The QCNPS PFHA utilizes the R Multi-Sites Auto regressive Weather GENerator (RMAWGEN) model. The RMAWGEN utilizes vector autoregression (VAR) process that capture the relationship between multiple station data as they change over time. In addition, the RMAWGEN utilizes generalized additive models (GAMs) that are typically used to model daily precipitation data in order to determine complex space-time relationships within the data. The candidate RMAWGEN models for different time-lags and estimation methods were tested for normality and seriality of residuals, from which the best models were selected for temperature and precipitation, respectively. The model-simulated outputs were compared to actual events, and it was determined that each of the stations correlation values were greater than 98 percent.

Regarding the potential impacts of an extreme weather event the RMAWGEN model employs the Wilks approach to model the correlation among precipitation occurrences at selected gauging stations.

Regarding concerns about climate change the licensee stated that the Intergovernmental Panel on Climate Change (IPCC) fifth assessment report that utilizes the Coupled Model Intercomparison Project Phase 5 (CMIP5) Shared Socioeconomic Pathways (SSP) 4.5 and 8.5 were incorporated in their PFHA. The licensee noted in their RAI response that the IPCC has recently issued an update, CMIP6, which was not available when the PFHA was performed. The licensees PFHA contractor, Applied Weather Associates (AWA), has completed (apart from this PFHA study) more than 70 climate change studies using both the CMIP5 and CIMP6 reports.

Based on this experience AWA assesses that the CMIP5 reports results in higher variability for daily, monthly, and annual precipitation frequency results than those of the CMIP6 report for similar locations and therefore the QCNPS PFHA using the CHIP5 data should be considered to have greater variability and, consequently, larger uncertainty (more conservative) in estimating flood frequency when compared to current information (CHIP 6).

To address uncertainties in the methods and data sources, the licensee performed multiple sensitivity analyses and described the uncertainties either quantitatively (as applicable) or qualitatively in its PFHA report. For the effects of climate change on flooding, the licensee compared normal scenarios (without climate change) to temperature-based climate change scenarios. They concluded that the normal weather scenario is conservative and used it for further flooding risk analyses. However, many previous studies suggest that climate change could increase the magnitude and frequency of precipitation, leading to higher flooding levels.

Currently, NRC regulatory guidelines do not provide acceptance criteria for including climate change in flooding hazard analyses. Nevertheless, the staff determined that the flood frequency curve in Figure E4-3 of the LAR enclosure 4 represents a median hazard curve. This decision is based on the risk insights from the 2016 Integrated Assessment flood frequency analyses and the staffs independent confirmatory frequency analysis.

In summary, the NRC staff determined that the approach used in the QCNPS PFHA report is generally acceptable for this application based on: (1) utilization of methods that are commonly used in climate modeling, (2) the selection of data sources are of the highest quality, (3) results of the modeling demonstrated a reasonable fidelity with observed weather events, and (4) uncertainties were addressed qualitatively or quantitatively by performing several sensitivities.

The NRC staffs review of the external flood hazard risk finds that the licensee has appropriately considered the risk from external flooding in the proposed RICTs, that the estimated mean CDF of 6x10-7 is demonstrably conservative and can support the screening of this external hazard.

Furthermore, this estimate of risk conservatively does not credit additional mitigation equipment such as the Darley pump and RB crane, as well as other mitigation steps for external flooding.

Therefore, the external flooding hazard is not a significant contribution to configuration risk and can be excluded from the calculation of the proposed RICTs.

Evaluation of Other External Hazards Besides seismic, extreme winds and tornado missiles, and external flooding hazards discussed above, the licensee confirmed that other external hazards for QCNPS have an insignificant contribution and proposed these hazards be screened out from the RICT program. The licensee provided their rationale for the insignificant impact of other external hazards for the QCNPS in Table E4-16 of enclosure 4 to the LAR. The licensee further stated that this assessment included consideration of configuration-specific conditions. For all other external hazards, the NRC staffs review of the information in the submittal and supplement finds that the contributions from other external hazards have an insignificant contribution to configuration risk and can be excluded from the calculation of the proposed RICTs because they either do not challenge the plant or they are bounded by the external hazards analyzed for the plant. The NRC staffs review notes that the preliminary screening criteria and progressive screening criteria used and presented in LAR Table E4-17 is the same criteria presented in supporting requirements for screening external hazards EXT-B1, EXT-B2, and EXT-C1 of the ASME/ANS PRA Standard.

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-A delineates that periodic assessment be performed of the risk incurred due to operation beyond the front stop CTs resulting from implementation of the RICT Program and comparison to the guidance of RG 1.174, Revision 3, for small increases in risk. In enclosure 5, Baseline Core Damage Frequency (CDF) and Large Early Release Frequency (LERF), to the LAR, the licensee provided the estimated total CDF and LERF to demonstrate that they meet the 1E-4/year CDF and 1E-5/year LERF criteria of RG 1.174 consistent with the guidance in NEI 06-09-A, and that these guidelines will be satisfied for implementation of a RICT.

The licensee has incorporated NEI 06-09-A into the new proposed TS 5.5.15. The estimated current total CDF and LERF for QCNPS PRAs meet the RG 1.174, Revision 3 guidelines; therefore, the NRC staff finds that the PRA results and insights to be used by the licensee in the RICT Program will continue to be consistent with NEI 06-09-A.

Key Assumptions and Uncertainty Analyses The licensee considered PRA modeling uncertainties and their potential impact on the RICT program and identified, as necessary, the applicable RMAs to limit the impact of these uncertainties. In enclosure 9 of the June 8, 2023, submittal the licensee discussed the identification of key assumptions and sources of uncertainty along with providing the dispositions for impact on the risk-informed application of applicable sensitivities. The licensee evaluated the QCNPS PRA model to identify the key assumptions and sources of uncertainty for this application consistent with the RG 1.200, Revision 2, definitions, using sensitivity and importance analyses to place bounds on uncertain processes, to identify alternate modeling strategies, and to provide information to users of the PRA.

In response to APLA RAI-01 in the March 19, 2024, LAR supplement, the licensee provided clarification on the sensitivity study conducted related to the data uncertainty of digital components, specifically the QCNPS digital feedwater control system (DFWCS). The PRA model basic events used in the study represented all of the failure modes, reactor vessel overflow and loss of flow, of the DFWCS. The NRC staff determined that the sensitivity study performed by the licensee related to the DFWCS appropriately bounded the uncertainty and that the insights from the sensitivity study reasonably shows that this source of uncertainty does not impact this application.

In response to APLA RAI-02 in the March 19, 2024, LAR supplement, the licensee provided an updated sensitivity study regarding the uncertainty related to successful core cooling following containment failure where the original sensitivity demonstrated an impact ranging from 33 to 81 percent on CDF or LERF. The licensee stated that the original sensitivity was overly conservative in that the likelihood of unsuccessful core cooling was increased by a factor of ten.

The updated sensitivity provided in response used a factor of two increase. The results of the study demonstrated that this source of uncertainty did not significantly impact the large majority of RICT calculations. The NRC staff determined increasing the probability of failure by a factor of two was reasonable given in part the QCNPS PRA model probability is a conservative value based on industry studies. However, the results of the updated sensitivity showed that TS LCO 3.5.1 Condition B regarding the inoperability of either one low pressure coolant injection (LPCI) or core spray (CS) subsystem, was significantly impacted by 31.7 percent. Based on these results the NRC staff considers this a potentially significant source of uncertainty for this application. The licensees response did not identify any remediation to this source of uncertainty as required by Section 2.3.4 of NEI 06-09 and therefore requested additional clarification from the licensee by email dated May 13, 2024 (ML24135A018).

In its response dated June 6, 2024, the licensee stated that the uncertainties in TS LCO 3.5.1 Condition B will be compensated for by using a variety of RMAs. RMAs may include (but are not limited to), deferring planned maintenance or testing that affects the reliability of safety systems that provide defense-in-depth such as drywell or torus venting, minimizing activities on the switchyard, service water, and residual heat removal service water systems, and briefing the on-shift operations crew concerning restoring balance of plant support, diesel generator alignment and AC bus crossties, and containment high pressure scenarios. The staff finds that the inclusion of RMAs adequately addresses the uncertainties in TS LCO 3.5.1, Condition B.

In response to APLA RAI-07 in the March 19, 2024, LAR supplement the licensee provided details on how the QCNPS PRA modeling of FLEX addresses the NRC staff uncertainty concerns regarding the modeling of FLEX listed in the May 6, 2022, NRC memorandum (ML22014A084). Constellation provided the results of a sensitivity study that removed all FLEX credit from the QCNPS PRA models used to calculate RICTs. The results of the study demonstrate that modeling of FLEX has a minimal impact on any of requested TS LCO RICTs.

The NRC staff determined that the uncertainties associated with FLEX does not impact this application.

In response to APLB RAI-04 in the March 19, 2024, LAR supplement Constellation provided the results of a sensitivity study that addressed the use of a 1 x 10-6 floor value for joint human error probabilities in the QCNPS FPRA model used to calculate RICTs when a value of 1 x 10-5 is recommended. The results of the study, that applied the 1 x 10-5 floor value demonstrated that the JHEP floor value of 1 x 10-6 has a minimal impact on any of requested TS LCO RICTs.

Therefore, based on the results of the sensitivity study the NRC staff determined that the use of the 1 x 10-6 JHEP floor value does not impact this application.

Based on the NRC staffs review of the licensees dispositions provided in enclosure 9 to the LAR, as supplemented, the staff finds that the licensee performed an adequate assessment to identify the potential sources of uncertainty, and that the identification of the key assumptions and sources of uncertainty was appropriate and consistent with the guidance in NUREG-1855, Revision 1 and associated Electric Power Research Institute (EPRI) TR-1016737, Treatment of Parameter and Model Uncertainty for Probabilistic Risk Assessments, December 2008 and EPRI TR-1026511, Practical Guidance of the Use on Probabilistic Risk Assessment in the Risk-informed Treatment of Uncertainty, December 2012. Therefore, the NRC staff finds the licensee has satisfied the guidance in RG 1.177, Revision 2, and RG 1.174, Revision 3, and that the identification and treatment of assumptions and treatment of model uncertainties for risk evaluation of extended CTs is appropriate for this application and is consistent with the guidance in NEI 06-09-A and therefore acceptable.

PRA Scope and Acceptability Conclusions As stated in enclosure 2 to the LAR, the licensee has subjected the PRA models to the peer review processes and submitted the results of the peer review. The NRC staff reviewed the peer-review history, which included the results and findings, the licensees resolutions of peer review findings, and the identification and disposition of key assumptions and sources of uncertainty. The NRC staff concludes that: (1) the licensees PRA models are acceptable to support the RICT Program, and (2) the key assumptions for the PRAs have been identified consistent with the guidance in RG 1.200, Revision 2 and NUREG-1855, Revision 1.

Additionally, the staff finds that the licensees approach for considering the impact of seismic events, non-seismic external hazards and other hazards using alternative methods is acceptable.

Application of PRA Models in the RICT Program The QCNPS base PRA models (that are determined to be acceptable previously in this SE) will be modified as an application-specific PRA model (i.e., CRMP tool), that will be used to analyze the risk for an extended CT. The CRMP model produces results (i.e., risk metrics) that are consistent with the NEI 06-09-A guidance. Throughout the entirety of the LAR and associated supplements as discussed below, and specifically Table E1-1, the licensee provided all information to support the requested LCO actions proposed for the QCNPS RICT Program consistent with all the Limitations and Conditions prescribed in Section 4.0 of NEI 06-09-A.

In LAR enclosure 8, Attributes of the Real-Time Risk Model, section 2, Translation of Baseline PRA Model for Use in Configuration Risk, the licensee explains that the CRMP model credits systems that are shared between units. In response to APLA RAI-03 in the March 19, 2024, LAR supplement the licensee identified and described all credited shared systems and equipment and described the PRA modeling for a dual unit event. They included the service water, fire protection, safe shutdown makeup, residual heat removal service water, instrument and system air, AC power, and 125-and 250-volt DC systems. The licensee stated that CRMP model accurately represents the availability of each of these systems based on the configuration specific input to the model and therefore each unit does not over credit the availability of these shared systems. The NRC staff finds that the modeling of these shared systems in the CRMP model is acceptable because the calculated RICTs are not significantly impacted by over-crediting them in dual unit events.

In LAR enclosure 8, section 2, the licensee identifies several specific modifications that are made to the baseline PRA model to produce the CRMP model, or the real time risk (RTR) tool, that is used to make the RICT calculations. In response to APLA RAI-04 in the March 19, 2024, LAR supplement, the licensee provided additional details on how adjustments to the CRMP model are made to reflect changing conditions that could affect the model and associated RICT calculations, such as seasonal variations that could impact success criteria. The licensee stated that there are seasonal variations that currently need to be accounted for in the CRMP model and that the CRMP model does have settings for various emergent weather-related conditions that can be adjusted in real-time if needed, and that plant operators are trained to make these adjustments. The NRC staff finds that the licensees CRMP model is in accordance with NEI 06-09-A with respect to the treatment of changing plant conditions, such as the weather and seasonal variations, because it is capable of being adjusted in real-time to account for changing plant conditions or assesses these conditions conservatively for the RICT calculations.

In LAR enclosure 1, Table E1-1 identifies each TS LCO proposed for the RICT program, describes whether the systems and components involved in the TS LCO are implicitly or explicitly modeled in the PRA, and compares the design basis and PRA success criteria. For certain TS LCO conditions, the table explains that the associated SSCs are not modelled in the PRAs but will be represented using a surrogate event that fails the function performed by the SSC.

In response to APLA RAI-06a in the March 19, 2024, LAR supplement, the licensee provided additional clarification for the LCO for TS LCO 3.3.5.1, emergency core cooling system (ECCS) actuation for CS, LPCI, high pressure core injection (HPCI), and emergency diesels (EDGs),

Condition B Functions 3.a and 3.b. The licensee clarified that Functions 3.a and 3.b are associated with the HPCI system initiation either due to reactor vessel water level low-low or drywell pressure high signals and that PRA model surrogate for this instrumentation is the modeled HPCI pump. The NRC staff finds that the HPCI pump surrogate bounds the function of the actuation instruments related to Functions 3.a and 3.b of TS LCO 3.3.5.1.B and is consistent with the guidance of NEI 06-09-A.

In response to APLA RAI-06b in the March 19, 2024, LAR supplement, the licensee provided additional clarification for the LCO for TS LCO 3.3.5.1, emergency core cooling system (ECCS) actuation for CS, LPCI, HPCI, and EDGs, Condition B Functions 3.c and 3.g. The licensee clarified that Functions 3.c and 3.g are associated with the HPCI system initiation due to reactor vessel water level high signals and that PRA model surrogate for this instrumentation is the modeled HPCI pump. The NRC staff finds that the HPCI pump surrogate bounds the function of the actuation instruments related to Functions 3.c and 3.g of TS LCO 3.3.5.1.B and is consistent with the guidance of NEI 06-09-A.

In response to APLA RAI-06c in the March 19, 2024, LAR supplement, the licensee provided additional clarification for the LCO for TS LCO 3.6.1.2, primary containment airlock, Condition C. The licensee clarified that PRA model surrogate for the inoperability of a primary containment airlock is the modeled large pre-existing containment failure that leads to containment bypass. The NRC staff finds that the large pre-existing containment failure surrogate bounds the function of the primary containment airlocks and is consistent with the guidance of NEI 06-09-A.

In response to APLA RAI-06d in the March 19, 2024, LAR supplement, the licensee provided additional clarification for the LCO for TS LCO 3.6.1.3, primary containment isolation valves, Condition A. The licensee clarified that PRA model surrogate for the inoperability of a primary containment isolation valves is the modeled large pre-existing containment failure that leads to containment bypass. The NRC staff finds that the large pre-existing containment failure surrogate bounds the function of the primary containment isolation valves and is consistent with the guidance of NEI 06-09-A.

For emergent conditions in which the extent of condition evaluation for inoperable SSCs is not complete prior to exceeding the CT, the requirement in TSTF-505, Revision 2, is to either (a) numerically account for the increased probability of CCF or (b) to implement RMAs not already credited in the RICT calculation 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. The NRC staff finds that numerically accounting for an increased probability of failure, in accordance with RG 1.177, Revision 2, 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 staff finds that both methods minimize the impact of CCF because they 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.

For planned conditions, the licensee states in LAR enclosure 8, section 6, that adjustments to CCF grouping and associated probabilities (QCNPS uses alpha factors to calculate CCFs) are not necessary when a component is taken out of service for preventive maintenance because (1) [t]he component is not out-of-service for reasons subject to a potential CCF and (2) the net failure probability for the in-service components includes the CCF contribution of the out-of-service component. The licensee also states, in part, that the CCF events that are related to the out-of-service component are retained and that this is conservative.

Section 3.3.6, Common Cause Failure Consideration, of NEI 06-09-A states, in part, 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 CCF terms. However, RG 1.177 states that when a component is rendered inoperable in order to perform preventative 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. The NRC staff finds that the CCF contribution from the out-of-service component is conservatively retained in the following ways: (1) 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) and (2) the CCF event probabilities that include the out-of-service component are retained. The NRC staff also finds; however, that this simplification produces both conservative and non-conservative effects.

The CCF probability estimates are 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 finds that the licensees method is acceptable because, consistent with NEI 06-09-A, the calculations reasonably include CCFs after removing one train for maintenance consistent with the accuracy of the estimates.

The NRC staff did not identify any insufficiencies in the information or the CRMP tool (RTR model) as described in the LAR, as supplemented. Furthermore, as stated in attachment 1 to the LAR, regarding the QCNPS design criteria, the licensee stated that [t]he proposed change does not change the design, configuration, or method of operation of the plant. The NRC staff finds that the QCNPS PRA models and CRMP tool used will continue to reflect the as-built, as-operated plant consistent with RG 1.200, Revision 2, for ensuring PRA acceptability is maintained. Therefore, the staff finds that the proposed application of the QCPNS RICT Program is appropriate for use in the adoption of TSTF-505 for performing RICT calculations.

Tier 1 Conclusions Based on the above conclusions, the NRC staff finds that the licensee has satisfied the intent of tier 1 in RG 1.177 and RG 1.174, for determining the PRA acceptable, and that the scope of the PRA models (i.e., IEPRA, FPRA) evaluated PRA hazards, high winds hazards, other external hazards, and seismic methodology is appropriate for this application.

3.2.4.2 Tier 2: Avoidance of Risk-Significant Plant Configurations As described in RG 1.177, Revision 2, the second tier evaluates the capability of the licensee to recognize and avoid risk-significant plant configurations that could result if equipment, in addition to that associated with the proposed change, is taken out of service simultaneously or if other risk-significant operational factors, such as concurrent system or equipment testing, are also involved. The limits established for entry into a RICT and for RMA implementation are consistent with the NEI guidance of Nuclear Management and Resources Council (NUMARC) 93-01, Revision 4F (ML18120A069), endorsed by RG 1.160, Revision 4 (ML18220B281), as applicable to plant maintenance activities.

In response to APLA RAI-05 in the March 19, 2024, LAR supplement the licensee stated that the QCNPS Maintenance Rule monitoring program incorporates the use of performance criteria to evaluate SSC performance as described in NEI 18-10, Monitoring the Effectiveness of Nuclear Power Plant Maintenance. The NRC staff has previously evaluated this methodology in monitoring SSC performance and had determined its use for TSTF-505 applications to be acceptable.

Based on the licensees incorporation of NEI 06-09-A in the TSs as discussed in LAR attachment 1, the use of RMAs as discussed in LAR enclosure 12, and because the proposed changes are consistent with the Tier 2 guidance of RG 1.177, Revision 2, the NRC staff finds the licensees RICT Program requirements and criteria are consistent with the principle of Tier 2 to avoid risk-significant configurations and, therefore, that their Tier 2 program is acceptable and supports the proposed implementation of the RICT Program.

3.2.4.3 Tier 3: Risk Informed Configuration Risk Management Tier 3 of RG 1.177, Revision 2, 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.

The proposed RICT Program establishes a CRMP, or RTR model, based on the underlying PRA models. In enclosure 8 to the LAR, the licensee explains the adjustments to PRA models (e.g., adjustments to maintenance unavailability) to ensure the proper use of models in the RTR model calculations. The RTR model is then used to evaluate configuration-specific risk for planned activities associated with the RMTS extended CT and emergent conditions that may arise during an extended CT. This required assessment of configuration risk, along with the implementation of compensatory measures and RMAs, is consistent with the principle of Tier 3 for assessing and managing the risk impact of out-of-service equipment.

In enclosure 8 to the LAR, the licensee confirmed that future changes made to the baseline PRA models and changes made to the online model (i.e., RTR) are controlled and documented by plant procedures. In enclosure 10, Program Implementation, to the LAR, the licensee identified the attributes that the RICT Program procedures will address, which are consistent with NEI 06-09-A. The NRC staff finds that the licensee has identified appropriate administrative controls consistent with NEI 06-09-A and 10 CFR 50.36(c)(5).

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-A.

Therefore, the staff finds that the licensee has proposed acceptable administrative controls for the PRA and personnel implementing the RICT Program and will establish appropriate programmatic and procedural controls for its RICT Program, consistent with the guidance of NEI 06-09-A, section 3.2.1, RMTS Process Control and Responsibilities.

Based on the licensees incorporation of NEI 06-09-A in the TSs, as discussed in LAR attachment 1; use of RMAs, as discussed in LAR enclosure 12; and because the proposed changes are consistent with the Tier 3 guidance of RG 1.177, Revision 2, the NRC staff finds that the licensees Tier 3 program is acceptable and supports the proposed implementation of the RICT Program.

3.2.4.4 Key Principle 4 Conclusions The licensee has demonstrated the technical acceptability and scope of its PRA models and alternative methods, this includes considering the impact of seismic events, non-seismic external hazards, and other hazards, and that the models can support implementation of the RICT Program for determining extensions to 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-A and the acceptance guidance in RG 1.177 and RG 1.174. The RICT Program will be controlled administratively through plant procedures and training and follows the NRC approved methodology in NEI 06-09-A. The NRC staff concludes that the RICT Program satisfies the fourth key principle of RG 1.177 and is, therefore, acceptable.

3.2.5 Key Principle 5: Performance Measurement Strategies - Implementation and Monitoring RG 1.177, Revision 2 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 availability of SSCs impacted by the change. Revision 3 of RG 1.174 states, in part, 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. Enclosure 11 of the June 8, 2023, submittal states, the SSCs in the scope of the RICT Program are also in the scope of 10 CFR 50.65 for the Maintenance Rule. The Maintenance Rule monitoring programs will provide for evaluation and disposition of unavailability impacts which may be incurred from implementation of the RICT program.

NEI 06-09-A specifies that the cumulative risk associated with the use of RMTS beyond the front-stop for equipment out of service is to be monitored. In enclosure 11 to the LAR, the licensee states that the cumulative risk is calculated at least every refueling cycle, not to exceed 24 months. The NRC staff finds that this periodicity is consistent with NEI 06-09-A.

The NRC staff concludes that the RICT Program satisfies the fifth key principle of RG 1.177 and RG 1.174 because: (1) as described in enclosure 11 to the LAR, the RICT Program will monitor the average annual cumulative risk increase as described in NEI 06-09-A, and use this average annual increase to ensure that the program, as implemented, meets RG 1.174 guidance for small risk increases: and (2) all affected SSCs are within the Maintenance Rule program, which is used to monitor changes to the reliability and availability of these SSCs.

3.3 Adoption of TSTF-591, Revision 0 The NRC staff compared the licensees proposed TS changes in section 2.3 of this SE against the changes approved in TSTF-591. The NRC staff finds that the licensees proposed changes to the QCNPS TSs described in section 2.3 of this SE are consistent with those found acceptable in TSTF-591.

In the SE approving traveler TSTF-591, the NRC staff concluded that the TSTF-591 proposed changes to STS 5.5.15, Risk Informed Completion Time Program, and the proposed addition of STS 5.6.7, Risk Informed Completion Time (RICT) Program Upgrade Report, were acceptable. These modifications were acceptable because, as discussed in that SE, they continued to ensure the PRA models used to calculate a RICT are maintained and upgraded by the licensees appropriate use of endorsed guidance (i.e., the ASME/ANS PRA Standard requirements, and specific industry guidance that the NRC staff has determined are sufficient for determining the acceptability of PRA models and newly developed methods for use in the RICT program). Furthermore, as discussed in the traveler SE, the addition of reporting requirements does not preclude any NRC staff oversight of PRA changes performed to ensure the PRA model(s) continue to be maintained and upgraded consistent with RG 1.200, Revision

3. Therefore, the NRC staff found that the proposed changes to the RICT Program and addition of the RICT Program Upgrade Report requirements were acceptable because they continued to meet the requirements of 10 CFR 50.36(c)(5) by providing administrative controls necessary to assure operation of the facility in a safe manner. For these same reasons, the NRC staff concludes that the corresponding proposed changes to the QCNPS TSs in section 2.3 of this SE continue to meet the requirements of 10 CFR 50.36(c)(5).

3.4 Correction of TS 3.6.2.6, Condition C On June 26, 2020, the NRC issued Amendment No. 281 to Renewed Facility Operating License No. DPR-29 and Amendment No. 277 to Renewed Facility Operating License No. DPR-30 for QCNPS, Units 1 and 2, respectively (ML20150A328). The amendments revised the combined main steam isolation valve (MSIV) leakage rate limit for all four steam lines in TS 3.6.1.3, Primary Containment Isolation Valves (PCIVs), Surveillance Requirement (SR) 3.6.1.3.10; added a new TS 3.6.2.6, Residual Heat Removal (RHR) Drywell Spray; and revised TS 3.6.4.1, Secondary Containment, SR 3.6.4.1.1.

The amendment request submitted on March 5, 2019, proposed a required action C.1 of Be in MODE 3. with a NOTE that stated LCO 3.0.4.a is not applicable when entering MODE 3 for CONDITION C. Required Action and Associated Completion Time not met with a completion time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . The licensees supplement to the amendment request dated May 23, 2019 (ML19143A347) proposed to revise Condition C, to include require action C.1 to be in Mode 3 with a completion time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and required action C.2 to be in mode 4 with a completion time of 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The amendments issued on June 26, 2020, reflected Condition C with the associated required action, note, and completion time from the March 5, 2019, submittal and therefore did not appropriately reflect the revised Condition provided in the May 23, 2019, supplement. Further, the NRC staff safety evaluation dated June 26, 2020, as discussed in Section 2.2.2, TS 3.6.2.6, Residual Heat Removal (RHR) Drywell Spray, the staff evaluated Condition C as proposed in the May 23, 2019, supplement.

The NRC staff concludes that the error was introduced during the preparation of the license amendments and is entirely editorial in nature. The proposed correction does not change any of the conclusions in the safety evaluation associated with the amendments referenced above and does not affect the associated notices to the public. The TS pages included in this amendment reflect this change to TS 3.6.2.6, Condition C.

3.5 Technical Conclusion The NRC staff has evaluated the proposed changes against each of the five key principles in RG 1.177, Revision 2 and RG 1.174, Revision 3, and evaluated the optional variations from the approved TSTF-505 discussed in section 3.2.1 of this SE. The staff concludes that the changes proposed by the licensee satisfy the key principles of risk-informed decision-making identified in RG 1.174, and RG 1.177 and; therefore, the requested adoption of the proposed changes to the TSs and associated guidance are acceptable to assure the regulatory requirements of 10 CFR Part 50 identified in section 2.1 of this SE will continue to be met.

4.0 ADDITIONAL CHANGES TO OPERATING LICENSES In its letter dated June 8, 2023, the licensee proposed amendments to the Renewed Facility Operation Licenses for QCNPS by adding the follow proposed license condition:

Adoption of Risk Informed Completion Times TSTF-505, Revision 2, "Provide Risk-Informed Extension Completion Times - RITSTF Initiative 4b" Constellation is approved to implement TSTF-505, Revision 2, modifying the Technical Specifications 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.

Constellation will complete the implementation items listed in Attachment 5 of Constellation Letter to the NRC dated June 8, 2023, prior to implementation of the RICT Program. All issues identified in Attachment 5 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.

Subsequently, by letter dated March 19, 2024, the licensee modified Table A5-1, which was included in Attachment 5 of the licensees June 8, 2023, letter. As noted in the March 19, 2024, letter, the revised Table A5-1 supersedes the originally submitted Table A5-1 in its entirety. The March 19, 2024, letter revised Table A5-1 by adding an implementation requirement to complete engineering calculation EC 63912. This modification to Table A5-1 is discussed in Section 3.2.4.1 of this SE. Therefore, the licenses for QCNPS will be modified consistent with the licensees proposed amendments and by including reference to the March 19, 2024, letter. The NRC staff finds that the proposed license condition is acceptable because it explicitly states that prior to implementation, the QCNPS RICT program and PRAs will: (1) be consistent with NEI 06-09-A, and (2) address all changes consistent with RG 1.200, Revision 2.

5.0 STATE CONSULTATION

In accordance with the Commission's regulations on, the Illinois State official was notified of the proposed issuance of the amendment on June 28, 2024. The State official had no comments.

6.0 ENVIRONMENTAL CONSIDERATION

The amendments change the requirements with respect to installation or use of a facilitys components located within the restricted area as defined in 10 CFR Part 20. The NRC staff has determined that the amendments involve 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 amendments involve no significant hazards consideration, and there has been no public comment on such finding (88 FR 53537 and 89 FR 26944). Accordingly, the amendments meet 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 amendments.

7.0 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 amendments will not be inimical to the common defense and security or to the health and safety of the public.

Principal Contributors: April Pulvirenti, NRR Naeem Iqbal, NRR Keith Tetter, NRR Stacey Rosenberg, NRR Edmund Kleeh, NRR Vijay Goel, NRR Ming Li, NRR Hosun Ahn, NRR Nageswara Karipineni, NRR Khadijah West, NRR Date of Issuance: August 8, 2024

ML24183A108 OFFICE NRR/DORL/LPL3/PM NRR/DORL/LPL3/LA NRR/DSS/STSB/BC NRR/DSS/SCPB/BC NAME RKuntz SRohrer (SLent for)

SMehta MValentin DATE 6/28/24 7/2/24 7/3/24 7/3/24 OFFICE NRR/DSS/SNSB/BC NRR/DRA/APLA/BC NRR/DRA/APLB/BC NRR/DRA/APLC/BC NAME PSahd RPascarelli RRodriguez (A)

SVasavada SRosenberg for DATE 7/5/24 7/2/24 7/3/24 7/2/24 OFFICE NRR/DEX/EEEB/BC NRR/DEX/EICB/BC NRR/DEX/EXHB/BC OGC NLO w/comments NAME WMorton FSacko BHayes PLom DATE 7/2/24 7/3/24 7/2/24 8/1/24 OFFICE NRR/DORL/LPL3/BC NRR/DORL/LPL3/PM NAME JWhited RKuntz DATE 8/8/24 8/8/24

v t e Letter Sequence Approval
EPID:L-2023-LLA-0084, TSTF-505 (Approved, Closed)
Initiation Request Acceptance Administration Questions Answers 19 March 2024 5 April 2024 10 May 2024 6 June 2024 Results Approval Other: ML23319A334, ML24110A049
MONTHYEAR2024-04-05 [Table View]

ML24183A108

Text

SUBJECT:

Dear David Rhoades:

Enclosures:

Attachment:

Attachment:

1.0 INTRODUCTION

2.0 REGULATORY EVALUATION

3.0 TECHNICAL EVALUATION

5.0 STATE CONSULTATION

6.0 ENVIRONMENTAL CONSIDERATION

7.0 CONCLUSION

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