Text

R. E. Ginna Nuclear Power Plant - Issuance of Amendment No. 150 Adopt TSTF-505, Revision 2, Provide Risk-Informed Extended Completion Times - RITSTF Initiative 4B
	ML22119A094
Person / Time
Site:	Ginna
Issue date:	06/21/2022
From:	V Sreenivas; Plant Licensing Branch 1
To:	Rhoades D; Constellation Energy Generation, Constellation Nuclear
	Sreenivas V, NRR/DORL/LPL1, 415-2596
References
	EPID L-2021-LLA-0091
	Download: ML22119A094 (105)
	v • d • e

June 21, 2022 Mr. David P. Rhoades Senior Vice President Constellation Energy Generation, LLC President and Chief Nuclear Officer Constellation Nuclear 4300 Winfield Road Warrenville, IL 60555

SUBJECT:

R. E. GINNA NUCLEAR POWER PLANT - ISSUANCE OF AMENDMENT NO. 150 RE: ADOPT TSTF-505, REVISION 2, PROVIDE RISK-INFORMED EXTENDED COMPLETION TIMES - RITSTF INITIATIVE 4B, (EPID L-2021-LLA-0091)

Dear Mr. Rhoades:

The U.S. Nuclear Regulatory Commission (NRC, the Commission) has issued the enclosed Amendment No. 150 to Renewed Facility Operating License No. DPR-18 for the R. E. Ginna Nuclear Power Plant in response to your application dated May 20, 2021, as supplemented by letters dated October 14, 2021, April 28, 2022, and June 9, 2022 (Agencywide Documents Access and Management System (ADAMS) Accession Nos. ML21140A324, ML21287A006, ML22118B143, and ML22160A411 respectively).

The amendment revised the Technical Specifications to the Renewed Facility Operating License to use risk-informed completion times (RICTs) for actions to be taken when limiting conditions for operation (LCOs) are not met, in accordance with the Technical Specifications Task Force (TSTF) Traveler TSTF-505, Revision 2, Provide Risk-Informed Extended Completion Times -

RITSTF Initiative 4b, dated July 2, 2018 (ADAMS Accession No. ML18183A493).

A copy of our related Safety Evaluation is also enclosed. Notice of Issuance will be included in the Commissions biweekly Federal Register notice.

Sincerely,

/RA/

V. Sreenivas, Project Manager Plant Licensing Branch I Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-244

Enclosures:

1. Amendment No. 150 to Renewed License No. DPR-18

2. Safety Evaluation cc: Listserv

CONSTELLATION GENERATION COMPANY, LLC DOCKET NO. 50-244 R. E. GINNA NUCLEAR POWER PLANT AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 150 Renewed License No. DPR-18

1.

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

The application for amendment by Exelon Generation Company, LLC dated May 20, 2021, as supplemented by the Constellation Energy Generation, LLC letters dated October 14, 2021, April 28, 2022, and June 9, 2022, 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; A.

The facility will operate in conformity with the application, the provisions of the Act, and the rules and regulations of the Commission; B.

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; C.

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 D.

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 as indicated in the attachment to this license amendment, and paragraph 2.C.(2) of Renewed Facility Operating License No. DPR-18 is hereby amended to read as follows:

(2)

Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 150, are hereby incorporated in the renewed license. The licensee shall operate the facility in accordance with the Technical Specifications.

In addition, the license is amended by changes as indicated in the attachment to this license amendment, and paragraph 2.C.(17) of Renewed Facility Operating License No. DPR-18 as follows:

(17)

Constellation Energy Generation, LLC is approved to implement TSTF-505, Revision 2, modifying the Technical Specification requirements related to Completion Times (CT) for Required Actions to provide the option to calculate a longer, Risk-Informed CT (RICT). The methodology for using the new Risk-Informed Completion Time Program is described in NEI 06-09-A, Risk-Informed Technical Specifications Initiative 4b, Risk-Managed Technical Specifications (RMTS) Guidelines, Revision 0, which was approved by the NRC on May 17, 2007.

Constellation Energy Generation, LLC will complete the implementation items listed in Attachment 6 of Exelon Letter to the NRC dated May 20, 2021, prior to implementation of the RICT Program. All issues identified in the attachment will be addressed and any associated changes will be made, focused-scope peer reviews will be performed on changes that are PRA upgrades as defined in the PRA standard (ASME/ANS RA-Sa-2009, as endorsed by RG 1.200, Revision 2), and any findings will be resolved and reflected in the PRA of record prior to the implementation of the RICT Program.

3.

This license amendment is effective as of its date of issuance and shall be implemented within 60 days.

FOR THE NUCLEAR REGULATORY COMMISSION James G. Danna, Chief Plant Licensing Branch I Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Attachment:

Changes to the Renewed Facility Operating License and Technical Specifications Date of Issuance: June 21, 2022 James G.

Danna Digitally signed by James G. Danna Date: 2022.06.21 13:55:34 -04'00'

ATTACHMENT TO LICENSE AMENDMENT NO. 150 TO RENEWED FACILITY OPERATING LICENSE NO. DPR-18 R. E. GINNA NUCLEAR POWER PLANT DOCKET NO. 50-244 Replace the following pages of Renewed Facility Operating License No. DPR-18 with the attached revised pages. The revised pages are identified by amendment number and contain a marginal line indicating the area of change.

Remove Insert 4

4 9

9 10 10 11 Replace the following page of the Appendix A, Technical Specifications, with the attached revised page. The revised page is identified by amendment numbers and marginal lines indicating the area of change.

Remove Insert 1.3-10 1.3-10 1.3-11 3.3.1-1 3.3.1-1 3.3.1-2 3.3.1-2 3.3.1-3 3.3.1-3 3.3.1-4 3.3.1-4 3.3.1-5 3.3.1-5 3.3.1-6 3.3.1-6 3.3.1-7 3.3.1-7 3.3.1-8 3.3.1-8 3.3.1-9 3.3.1-9 3.3.1-10 3.3.1-10 3.3.1-11 3.3.1-11 3.3.1-12 3.3.1-12 3.3.1-13 3.3.1-13 3.3.1-14 3.3.1-14 3.3.1-15 3.3.1-15 3.3.1-16 3.3.1-16 3.3.1-17 3.3.1-17 3.3.1-18 3.3.1-19 3.3.2-1 3.3.2-1 3.3.2-2 3.3.2-2 3.3.2-3 3.3.2-3 3.3.2-4 3.3.2-4 3.3.2-5 3.3.2-5 3.3.2-6 3.3.2-6 3.3.2-7 3.3.2-7 3.3.2-8 3.3.2-8 3.3.2-9 3.3.2-9 3.3.2-10 3.3.2-10 3.3.2-11 3.3.2-12 3.3.4-1 3.3.4-1 3.3.5-1 3.3.5-1 3.3.5-2 3.3.5-2 3.4.11-1 3.4.11-1 3.4.11-2 3.4.11-2 3.4.11-3 3.4.11-3 3.4.11-4 3.5.2-1 3.5.2-1 3.5.2-2 3.5.2-2 3.5.2-3 3.5.2-3 3.5.2-4 3.6.2-3 3.6.2-3 3.6.3-2 3.6.3-2 3.6.3-3 3.6.3-3 3.6.3-4 3.6.3-4 3.6.3-5 3.6.3-5 3.6.6-1 3.6.6-1 3.6.6-2 3.6.6-2 3.6.6-3 3.6.6-3 3.6.6-4 3.7.2-1 3.7.2-1 3.7.5-1 3.7.5-1 3.7.5-2 3.7.5-2 3.7.5-3 3.7.5-3 3.7.5-4 3.7.7-1 3.7.7-1 3.7.7-2 3.7.7-2 3.7.8-1 3.7.8-1 3.8.1-1 3.8.1-1 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 3.8.1-6 3.8.4-1 3.8.4-1 3.8.7-1 3.8.7-1 3.8.7-2 3.8.7-2 3.8.9-1 3.8.9-1 3.8.9-2 3.8.9-2 5.5-13 5.5-13 5.5-14 R. E. Ginna Nuclear Power Plant Amendment No. 150 (2)

Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 150, are hereby incorporated in the renewed license.

Constellation Energy Generation, LLC shall operate the facility in accordance with the Technical Specifications.

(3)

Fire Protection Constellation Energy Generation, LLC shall implement and maintain in effect all provisions of the approved fire protection program that comply with 10 CFR 50.48(a) and 10 CFR 50.48(c), as specified in the licensees amendment request dated March 28, 2013, supplemented by letters dated December 17, 2013; January 29, 2014; February 28, 2014; September 5, 2014; September 24, 2014; December 4, 2014; March 18, 2015; June 11, 2015; August 7, 2015; and as approved in the safety evaluation report dated November 23, 2015. Except where NRC approval for changes or deviations is required by 10 CFR 50.48(c), and provided no other regulation, technical specification, license condition or requirement would require prior NRC approval, the licensee may make changes to the fire protection program without prior approval of the Commission if those changes satisfy the provisions set forth in 10 CFR 50.48(a) and 10 CFR 50.48(c), the change does not require a change to a technical specification or a license condition, and the criteria listed below are satisfied.

(a)

Risk-Informed Changes that May Be Made Without Prior NRC Approval A risk assessment of the change must demonstrate that the acceptance criteria below are met. The risk assessment approach, methods, and data shall be acceptable to the NRC and shall be appropriate for the nature and scope of the change being evaluated; be based on the as-built, as-operated, and maintained plant; and reflect the operating experience at the plant. Acceptable methods to assess the risk of the change may include methods that have been used in the peer-reviewed fire PRA model, methods that have been approved by NRC through a plant-specific license amendment or NRC approval of generic methods specifically for use in NFPA 805 risk assessments, or methods that have been demonstrated to bound the risk impact.

1.

Prior NRC review and approval is not required for changes that clearly result in a decrease in risk. The proposed change must also be consistent with the defense in-depth philosophy and must maintain sufficient safety margins. The change may be implemented following completion of the plant change evaluation.

R. E. Ginna Nuclear Power Plant Amendment No. 150 (17)

Adoption of Risk Informed Completion Times TSTF-505, Revision 2, Provide Risk-Informed Extended Completion Times -RITSTF Initiative 4b Constellation Energy Generation, LLC is approved to implement TSTF-505, Revision 2, modifying the Technical Specification requirements related to Completion Times (CT) for Required Actions to provide the option to calculate a longer, risk-informed CT (RICT). The methodology for using the new Risk-Informed Completion Time Program is described in NEI 06-09-A, Risk-Informed Technical Specifications Initiative 4b, Risk-Managed Technical Specifications (RMTS) Guidelines, Revision 0, which was approved by the NRC on May 17, 2007.

Constellation Energy Generation, LLC will complete the implementation items listed in Attachment 6 of Exelon Letter to the NRC dated May 20, 2021, prior to implementation of the RICT Program. All issues identified in the attachment will be addressed and any associated changes will be made, focused-scope peer reviews will be performed on changes that are PRA upgrades as defined in the PRA standard (ASME/ANS RA-Sa-2009, as endorsed by RG 1.200, Revision 2), and any findings will be resolved and reflected in the PRA of record prior to the implementation of the RICT Program.

(18)

Deleted (19)

Constellation Energy Generation, LLC shall provide to the Director of the Office of Nuclear Reactor Regulation or the Director of the Office of Nuclear Material Safety and Safeguards, as applicable, a copy of any application, at the time it is filed, to transfer (excluding grants of security interests or liens) from Constellation Energy Generation, LLC to its direct or indirect parent, or to any other affiliated company, facilities for the production, transmission, or distribution of electric energy having a depreciated book value exceeding ten percent (10%) of Constellation Energy Generation, LLCs consolidated net utility plant, as recorded on Constellation Energy Generation, LLCs books of account.

D.

The facility requires an exemption from certain requirements of 10 CFR 50.46(a)(1). This includes an exemption from 50.46(a)(1), that emergency core cooling system (ECCS) performance be calculated in accordance with an acceptable calculational model which conforms to the provisions in Appendix K (SER dated April 18, 1978). The exemption will expire upon receipt and approval of revised ECCS calculations. The aforementioned exemption is authorized by law and will not endanger life property or the common defense and security and is otherwise in the public interest. Therefore, the exemption is hereby granted pursuant to 10 CFR 50.12.

- 10 R. E. Ginna Nuclear Power Plant Amendment No. 150 E.

Constellation Energy Generation, LLC 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 27827 and 27822) and to the authority of 10 CFR 50.90 and 10 CFR 50.54(p). The combined set of plans, which contains Safeguards Information protected under 10 CFR 73.21, is entitled: R. E. Ginna Nuclear Power Plant Security Plan, Training and Qualification Plan, and Safeguards Contingency Plan, submitted by letter dated May 15, 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 licensees CSP was approved by License Amendment No. 113 and modified by License Amendment No. 117. The licensee has obtained Commission authorization to use Section 161A preemption authority under 42 U.S.C. 2201a for weapons at its facility.

F.

The Updated Final Safety Analysis Report supplement, submitted pursuant to 10 CFR 54.21 (d), describes certain future activities to be completed prior to the period of extended operation. Ginna LLC shall complete these activities no later than September 18, 2009, and shall notify the Commission in writing when implementation of these activities is complete and can be verified by NRC inspection.

The Updated Final Safety Analysis Report supplement, as revised, shall be included in the next scheduled update to the Updated Final Safety Analysis Report required by 10 CFR 50.71 (e)(4) following issuance of this renewed license. Until that update is complete, the licensee may make changes to the programs and activities described in the supplement without prior Commission approval, provided that the licensee evaluates each such change pursuant to the criteria set forth in 10 CFR 50.59 and otherwise complies with the requirements in that section.

G.

All capsules in the reactor vessel that are removed and tested must meet the test procedures and reporting requirements of ASTM E 185-82 to the extent practicable for the configuration of the specimens in the capsule. Any changes to the capsule withdrawal schedule, including spare capsules, must be approved by the NRC prior to implementation. Any capsules placed in storage must be maintained for future insertion, unless approved by the NRC.

- 11 R. E. Ginna Nuclear Power Plant Amendment No. 150 H.

This renewed license is effective as of the date of issuance and shall expire at midnight on September 18, 2029.

FOR THE NUCLEAR REGULATORY COMMISSION Original Signed By J. E. Dyer, Director Office of Nuclear Reactor Regulation

Attachment:

Appendix A - Technical Specifications Date of Issuance: May 19, 2004

Completion Times 1.3 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 B.1 Be in MODE 3.

AND B.2 Be in MODE 5.

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

R.E. Ginna Nuclear Power Plant 1.3-10 Amendment 150

Completion Times 1.3 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 Required Action COMPLETION should be pursued without delay and in a controlled manner.

TIME R.E. Ginna Nuclear Power Plant 1.3-11 Amendment 150

RTS Instrumentation 3.3.1 3.3 INSTRUMENTATION 3.3.1 Reactor Trip System (RTS) Instrumentation LCO 3.3.1 The RTS instrumentation for each Function in Table 3.3.1-1 shall be OPERABLE.

APPLICABILITY:

According to Table 3.3.1-1.

ACTIONS

- NOTE -

Separate Condition entry is allowed for each Function.

CONDITION REQUIRED ACTION COMPLETION TIME A.

One or more Functions with one channel inoperable.

OR Two source range channels inoperable.

A.1 Enter the Condition referenced in Table 3.3.1-1 for the channel(s).

Immediately B.

As required by Required Action A.1 and referenced by Table 3.3.1-1.

B.1 Restore channel to OPERABLE status.

48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months OR In accordance with the Risk Informed Completion Time Program C.

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

C.1 Be in MODE 3.

AND C.2 Initiate action to fully insert all rods.

AND 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 6 hours R.E. Ginna Nuclear Power Plant 3.3.1-1 Amendment 150

RTS Instrumentation 3.3.1 CONDITION REQUIRED ACTION COMPLETION TIME C.3 Place Control Rod Drive System in a condition incapable of rod withdrawal.

7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months D.

As required by Required Action A.1 and referenced by Table 3.3.1-1.

D.1

- NOTE -

1.

For Functions 2a, 2b, 5, 6, 7b, 8, and 13, one channel may be bypassed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for surveillance testing.

2. The inoperable channel may be bypassed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for surveillance testing of other channels.

Place channel in trip.

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

NOTE-------

Not applicable if there is a loss of function.

In accordance with the Risk Informed Completion Time Program E.

As required by Required Action A.1 and referenced by Table 3.3.1-1.

E.1 Reduce THERMAL POWER to < 5E-11 amps.

OR 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months R.E. Ginna Nuclear Power Plant 3.3.1-2 Amendment 150

RTS Instrumentation 3.3.1 CONDITION REQUIRED ACTION COMPLETION TIME E.2

- NOTE -

Required Action E.2 is not applicable when:

a.

Two channels are inoperable, or b.

THERMAL POWER is

< 5E-11 amps.

Increase THERMAL POWER to 8% RTP.

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

As required by Required Action A.1 and referenced by Table 3.3.1-1.

F.1 Open RTBs and RTBBs upon discovery of two inoperable channels.

AND F.2

- NOTE -

Limited plant cooldown or boron dilution is allowed provided the change is accounted for in the calculated SDM.

Suspend operations involving positive reactivity additions.

AND F.3 Restore channel to OPERABLE status.

Immediately upon discovery of two inoperable channels Immediately 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months R.E. Ginna Nuclear Power Plant 3.3.1-3 Amendment 150

RTS Instrumentation 3.3.1 CONDITION REQUIRED ACTION COMPLETION TIME G.

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

G.1 Be in MODE 3.

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

As required by Required Action A.1 and referenced by Table 3.3.1-1.

H.1 Restore at least one channel to OPERABLE status upon discovery of two inoperable channels.

AND H.2

- NOTE -

Limited plant cooldown or boron dilution is allowed provided the change is accounted for in the calculated SDM.

Suspend operations involving positive reactivity additions.

AND H.3 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 two inoperable channels Immediately 48 Hours I.

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

I.1 Initiate action to fully insert all rods.

AND I.2 Place the Control Rod Drive System in a condition incapable of rod withdrawal.

Immediately 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months R.E. Ginna Nuclear Power Plant 3.3.1-4 Amendment 150

RTS Instrumentation 3.3.1 CONDITION REQUIRED ACTION COMPLETION TIME J.

As required by Required Action A.1 and referenced by Table 3.3.1-1.

J.1

- NOTE -

Plant temperature changes are allowed provided the temperature change is accounted for in the calculated SDM.

Suspend operations involving positive reactivity additions.

AND J.2 Perform SR 3.1.1.1.

Immediately 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months AND Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter K.

As required by Required Action A.1 and referenced by Table 3.3.1-1.

K.1

- NOTE -

1. For Functions 7a and 9b, one channel may be bypassed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for surveillance testing.

2. The inoperable channel may be bypassed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for surveillance testing of other channels.

Place channel in trip.

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

NOTE-------

Not applicable if there is a loss of function.

In accordance with the Risk Informed Completion Time Program R.E. Ginna Nuclear Power Plant 3.3.1-5 Amendment 150

RTS Instrumentation 3.3.1 CONDITION REQUIRED ACTION COMPLETION TIME L.

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

L.1 Reduce THERMAL POWER to < 8.5% RTP.

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

As required by Required Action A.1 and referenced by Table 3.3.1-1.

M.1

- NOTE -

1.

For Function 9a, one channel may be bypassed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for surveillance testing.

2. The inoperable channel may be bypassed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for surveillance testing of other channels.

Place channel in trip.

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 N.

As required by Required Action A.1 and referenced by Table 3.3.1-1.

N.1 Restore channel to OPERABLE status.

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

NOTE-------

Not applicable if there is a loss of function.

In accordance with the Risk Informed Completion Time Program O.

Required Action and associated Completion Time of Condition M or N not met.

O.1 Reduce THERMAL POWER to < 30% RTP.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months R.E. Ginna Nuclear Power Plant 3.3.1-6 Amendment 150

RTS Instrumentation 3.3.1 CONDITION REQUIRED ACTION COMPLETION TIME P.

As required by Required Action A.1 and referenced by Table 3.3.1-1.

P.1

- NOTE -

The inoperable channel may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing of other channels.

Place channel in trip.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months OR In accordance with the Risk Informed Completion Time Program Q.

Required Action and Associated Completion Time of Condition P not met.

Q.1 Reduce THERMAL POWER to < 50% RTP.

AND 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Q.2.1 Verify Steam Dump System is OPERABLE.

OR Q.2.2 Reduce THERMAL POWER to < 8% RTP.

7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months 7 hours R.

As required by Required Action A.1 and referenced by Table 3.3.1-1.

R.1

- NOTE -

One train may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing provided the other train is OPERABLE.

Restore train to OPERABLE status.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months OR In accordance with the Risk Informed Completion Time Program R.E. Ginna Nuclear Power Plant 3.3.1-7 Amendment 150

RTS Instrumentation 3.3.1 CONDITION REQUIRED ACTION COMPLETION TIME S.

As required by Required Action A.1 and referenced by Table 3.3.1-1.

S.1

-NOTE-For Functions 16c, 16d, and 16e, one channel may be bypassed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for surveillance testing.

Verify interlock is in required state for existing plant conditions.

OR S.2 Declare associated RTS Function channel(s) inoperable.

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

As required by Required Action A.1 and referenced by Table 3.3.1-1.

T.1

- NOTE -

1.

One train may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing, provided the other train is OPERABLE.

2.

One RTB may be bypassed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months for maintenance on undervoltage or shunt trip mechanisms, provided the other train is OPERABLE.

Restore train to OPERABLE status.

24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OR

NOTE--------

Not applicable if there is a loss of function.

In accordance with the Risk Informed Completion Time Program R.E. Ginna Nuclear Power Plant 3.3.1-8 Amendment 150

RTS Instrumentation 3.3.1 CONDITION REQUIRED ACTION COMPLETION TIME U.

As required by Required Action A.1 and referenced by Table 3.3.1-1.

U.1 Restore at least one trip mechanism to OPERABLE status upon discovery of two RTBs with inoperable trip mechanisms.

AND U.2 Restore trip mechanism to OPERABLE status.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months from discovery of two inoperable trip mechanisms 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months OR In accordance with the Risk Informed Completion Time Program V.

Required Action and associated Completion Time of Condition R, S, T, or U not met.

V.1 Be in MODE 3.

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

As required by Required Action A.1 and referenced by Table 3.3.1-1.

W.1 Restore at least one trip mechanism to OPERABLE status upon discovery of two RTBs with inoperable trip mechanisms.

AND W.2 Restore trip mechanism or train to OPERABLE status.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months from discovery of two inoperable trip mechanisms 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months X.

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

X.1 Initiate action to fully insert all rods.

AND X.2 Place the Control Rod Drive System in a Condition incapable of rod withdrawal.

Immediately 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months R.E. Ginna Nuclear Power Plant 3.3.1-9 Amendment 150

RTS Instrumentation 3.3.1 SURVEILLANCE REQUIREMENTS

- NOTE -

Refer to Table 3.3.1-1 to determine which SRs apply for each RTS Function.

SURVEILLANCE FREQUENCY SR 3.3.1.1 Perform CHANNEL CHECK.

In accordance with the Surveillance Frequency Control Program SR 3.3.1.2

- NOTE -

Required to be performed within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after THERMAL POWER is 50% RTP.

Compare results of calorimetric heat balance calculation to Nuclear Instrumentation System (NIS) channel output and adjust if calorimetric power is

> 2% higher than indicated NIS power.

In accordance with the Surveillance Frequency Control Program SR 3.3.1.3

- NOTE -

1.

Required to be performed within 7 days after THERMAL POWER is 50% RTP but prior to exceeding 90% RTP following each refueling and if the Surveillance has not been performed within the last 31 EFPD.

2.

Performance of SR 3.3.1.6 satisfies this SR.

Compare results of the incore detector measurements to NIS AFD and adjust if absolute difference is 3%.

In accordance with the Surveillance Frequency Control Program R.E. Ginna Nuclear Power Plant 3.3.1-10 Amendment 150

RTS Instrumentation 3.3.1 SURVEILLANCE FREQUENCY SR 3.3.1.4 Perform TADOT.

In accordance with the Surveillance Frequency Control Program SR 3.3.1.5 Perform ACTUATION LOGIC TEST.

In accordance with the Surveillance Frequency Control Program SR 3.3.1.6

- NOTE -

Not required to be performed until 7 days after THERMAL POWER is 50% RTP, but prior to exceeding 90% RTP following each refueling.

Calibrate excore channels to agree with incore detector measurements.

In accordance with the Surveillance Frequency Control Program SR 3.3.1.7

- NOTE -

1.

Not required to be performed for source range instrumentation prior to entering MODE 3 from MODE 2 until 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months after entering MODE 3.

2.

The RTS input relays are excluded from this surveillance for Functions 2a, 5, 6, 7a, 7b, 8, 9a, 9b, and 13.

Perform COT.

In accordance with the Surveillance Frequency Control Program SR 3.3.1.8

- NOTE -

1.

Not required for power range and intermediate range instrumentation until 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months after reducing power < 6% RTP.

2.

Not required for source range instrumentation until 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months after reducing power < 5E-11 amps.

3.

The RTS input relay is excluded from this surveillance for Function 2b.

R.E. Ginna Nuclear Power Plant 3.3.1-11 Amendment 150

RTS Instrumentation 3.3.1 SURVEILLANCE FREQUENCY SR 3.3.1.8 (continued)

Perform COT In accordance with the Surveillance Frequency Control Program SR 3.3.1.9

- NOTE -

Setpoint verification is not required.

Perform TADOT.

In accordance with the Surveillance Frequency Control Program SR 3.3.1.10

- NOTE -

Neutron detectors are excluded.

Perform CHANNEL CALIBRATION.

In accordance with the Surveillance Frequency Control Program SR 3.3.1.11 Perform TADOT.

In accordance with the Surveillance Frequency Control Program SR 3.3.1.12

- NOTE -

Setpoint verification is not required.

Perform TADOT.

Prior to reactor startup if not performed within previous 31 days SR 3.3.1.13

- NOTE -

The RTS permissive input relays are excluded from this surveillance for Functions 16c, 16d, and 16e.

Perform COT.

In accordance with the Surveillance Frequency Control Program R.E. Ginna Nuclear Power Plant 3.3.1-12 Amendment 150

RTS Instrumentation 3.3.1 Table 3.3.1-1 Reactor Trip System Instrumentation APPLICABLE MODES OR LIMITING OTHER SAFETY SPECIFIED REQUIRED SURVEILLANCE SYSTEM FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS SETTINGS(a) 1.

Manual Reactor Trip 1, 2, 3(b), 4(b), 5(b) 2 B,C SR 3.3.1.11 NA 2.

Power Range Neutron Flux a.

High 1, 2 4

D,G SR 3.3.1.1 109.27%

SR 3.3.1.2 RTP SR 3.3.1.7 SR 3.3.1.10 b.

Low 1(c), 2 4

D,G SR 3.3.1.1 SR 3.3.1.8 29.28%

RTP SR 3.3.1.10 3.

Intermediate Range Neutron Flux 1(c), 2 2

E,G SR 3.3.1.1 SR 3.3.1.8 (d)

SR 3.3.1.10 4.

Source Range Neutron Flux 2(e) 2 F,G SR 3.3.1.1 SR 3.3.1.8 (d)

SR 3.3.1.10 3(b), 4(b), 5(b) 2 H,I SR 3.3.1.1 SR 3.3.1.7 (d)

SR 3.3.1.10 3(f), 4(f), 5(f) 1 J

SR 3.3.1.1 SR 3.3.1.10 NA 5.

Overtemperature T 1, 2 4

D,G SR 3.3.1.1 Refer to SR 3.3.1.3 Note 1 SR 3.3.1.6 SR 3.3.1.7 SR 3.3.1.10 6.

Overpower T 1, 2 4

D,G SR 3.3.1.1 Refer to SR 3.3.1.7 Note 2 SR 3.3.1.10 R.E. Ginna Nuclear Power Plant 3.3.1-13 Amendment 150

RTS Instrumentation 3.3.1 Table 3.3.1-1 Reactor Trip System Instrumentation FUNCTION APPLICABLE MODES OR OTHER SPECIFIED CONDITIONS REQUIRED CHANNELS CONDITIONS SURVEILLANCE REQUIREMENTS LIMITING SAFETY SYSTEM SETTINGS(a) 7.

Pressurizer Pressure a.

Low 1(g) 4 K,L SR 3.3.1.1 SR 3.3.1.7 1791.3 psig SR 3.3.1.10 b.

High 1, 2 3

D,G SR 3.3.1.1 2396.2 SR 3.3.1.7 psig SR 3.3.1.10 8.

Pressurizer Water 1, 2 3

D,G SR 3.3.1.1 96.47%

Level-High SR 3.3.1.7 SR 3.3.1.10 9.

Reactor Coolant Flow-Low a.

Single Loop 1(h) 3 per loop M,O SR 3.3.1.1 SR 3.3.1.7 89.86%

SR 3.3.1.10 b.

Two Loops 1(i) 3 per loop K,L SR 3.3.1.1 SR 3.3.1.7 89.86%

SR 3.3.1.10 10.

Reactor Coolant Pump (RCP)

Breaker Position a.

Single Loop 1(h) 1 per RCP N,O SR 3.3.1.11 NA b.

Two Loops 1(j) 1 per RCP K,L SR 3.3.1.11 NA 11.

Undervoltage-Bus 11A and 11B 1(g) 2 per bus K,L SR 3.3.1.9 SR 3.3.1.10 (d) 12.

Underfrequency-Bus 11A and 11B 1(g) 2 per bus K,L SR 3.3.1.9 SR 3.3.1.10 57.5 HZ R.E. Ginna Nuclear Power Plant 3.3.1-14 Amendment 150

RTS Instrumentation 3.3.1 Table 3.3.1-1 Reactor Trip System Instrumentation FUNCTION APPLICABLE MODES OR OTHER SPECIFIED CONDITIONS REQUIRED CHANNELS CONDITIONS SURVEILLANCE REQUIREMENTS LIMITING SAFETY SYSTEM SETTINGS(a) 13.

Steam Generator (SG) Water Level-Low Low 1, 2 3 per SG D,G SR 3.3.1.1 SR 3.3.1.7 SR 3.3.1.10 13.88%

14.

Turbine Trip a.

Low Autostop Oil Pressure 1(k)(l) 3 P,Q SR 3.3.1.10 SR 3.3.1.12 (d) b.

Turbine Stop Valve Closure 1(k)(l) 2 P,Q SR 3.3.1.12 NA 15.

Safety Injection (SI) 1, 2 2

R,V SR 3.3.1.11 NA Input from Engineered Safety Feature Actuation System (ESFAS)

R.E. Ginna Nuclear Power Plant 3.3.1-15 Amendment 150

RTS Instrumentation 3.3.1 Table 3.3.1-1 Reactor Trip System Instrumentation APPLICABLE MODES OR LIMITING OTHER SAFETY SPECIFIED REQUIRED SURVEILLANCE SYSTEM FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS SETTINGS(a) 16.

Reactor Trip System Interlocks a.

Intermediate Range 2(e) 2 S,V SR 3.3.1.10 SR 3.3.1.13 5E-11 amp Neutron Flux, P-6 b.

Low Power Reactor Trips 1(g) 4 (power range only)

S,V SR 3.3.1.10 SR 3.3.1.13 8.0% RTP Block, P-7 c.

Power Range Neutron Flux, 1(h) 4 S,V SR 3.3.1.10 SR 3.3.1.13 29.0%

RTP P-8 d.

Power Range Neutron Flux, 1(l) 4 S,V SR 3.3.1.10 SR 3.3.1.13 50.0%

RTP P-9 1(k) 4 S,V SR 3.3.1.10 SR 3.3.1.13 8.0% RTP e.

Power Range Neutron Flux, 1(c), 2 4

S,V SR 3.3.1.10 SR 3.3.1.13 6.0% RTP P-10 17.

Reactor Trip 1, 2 2 trains T,V SR 3.3.1.4 NA Breakers(m) 3(b), 4(b), 5(b) 2 trains W,X SR 3.3.1.4 NA 18.

Reactor Trip 1, 2 1 each per RTB U,V SR 3.3.1.4 NA Breaker Undervoltage and 3(b), 4(b), 5(b) 1 each per RTB W,X SR 3.3.1.4 NA Shunt Trip Mechanisms 19.

Automatic Trip Logic 1, 2 2 trains R,V SR 3.3.1.5 NA 3(b), 4(b), 5(b) 2 trains W,X SR 3.3.1.5 NA R.E. Ginna Nuclear Power Plant 3.3.1-16 Amendment 150

RTS Instrumentation 3.3.1 (a)

A channel is OPERABLE when both of the following conditions are met:

1.

The absolute difference between the as-found Trip Setpoint (TSP) and the previous as-left TSP is within the COT Acceptance Criteria. The COT Acceptance Criteria is defined as:

las-found TSP - previous as-left TSPl COT uncertainty The COT uncertainty shall not include the calibration tolerance.

2.

The as-left TSP is within the established calibration tolerance band about the nominal TSP. The nominal TSP is the desired setting and shall not exceed the Limiting Safety System Setting (LSSS). The LSSS and the established calibration tolerance band are defined in accordance with the Ginna Instrument Setpoint Methodology. The channel is considered operable even if the as-left TSP is non-conservative with respect to the LSSS provided that the as-left TSP is within the established calibration tolerance band.

(b)

With Control Rod Drive (CRD) System capable of rod withdrawal or all rods not fully inserted.

(c)

THERMAL POWER < 6% RTP.

(d)

UFSAR Table 7.2-3.

(e)

Both Intermediate Range channels < 5E-11 amps.

(f)

With CRD System incapable of withdrawal and all rods fully inserted. In this condition, the Source Range Neutron Flux function does not provide a reactor trip, only indication.

(g)

THERMAL POWER 8.5% RTP.

(h)

THERMAL POWER 30% RTP.

(i)

THERMAL POWER 8.5% RTP and Reactor Coolant Flow-Low (Single Loop) trip Function blocked.

(j)

THERMAL POWER 8.5% RTP and RCP Breaker Position (Single Loop) trip Function blocked.

(k)

THERMAL POWER > 8% RTP, and either no circulating water pump breakers closed, or condenser vacuum 20".

(l)

THERMAL POWER 50% RTP, 1 of 2 circulating water pump breakers closed, and condenser vacuum > 20".

(m)

Including any reactor trip bypass breakers that are racked in and closed for bypassing an RTB.

R.E. Ginna Nuclear Power Plant 3.3.1-17 Amendment 150

RTS Instrumentation 3.3.1 Table 3.3.1-1 (Note 1)

Overtemperature T

- NOTE -

The Overtemperature T Function Limiting Safety System Setting is defined by:

Overtemperature T T0 {K1 + K2 (P-P') - K3 (T-T') [(1+1s) / (1+2s)] - f1(I)}

Where:

T is measured RCS T, F.

T0 is the indicated T at RTP, F.

s is the Laplace transform operator, sec-1.

T is the measured RCS average temperature, F.

T' is the nominal Tavg at RTP, F.

P is the measured pressurizer pressure, psig.

P' is the nominal RCS operating pressure, psig.

K1 is the Overtemperature T reactor trip setpoint, [*].

K2 is the Overtemperature T reactor trip depressurization setpoint penalty coefficient, [*]/psi.

K3 is the Overtemperature T reactor trip heatup setpoint penalty coefficient, [*]/F.

1 is the measured lead time constant, [*] seconds.

2 is the measured lag time constant, [*] seconds.

f(I) is a function of the indicated difference between the top and bottom detectors of the Power Range Neutron Flux channels where qt and qb are the percent power in the top and bottom halves of the core, respectively, and qt + qb is the total THERMAL POWER in percent RTP.

f1(I) = [*] {[*] - (qt - qb)}

when qt - qb [*]% RTP f1(I) = 0% of RTP when [*] % RTP < qt - qb [*]% RTP f1(I) = [*] {(qt - qb) - [*]}

when qt - qb > [*]% RTP

These values denoted with [*] are specified in the COLR.

R.E. Ginna Nuclear Power Plant 3.3.1-18 Amendment 150

RTS Instrumentation 3.3.1 Table 3.3.1-1 (Note 2)

Overpower T

- NOTE -

The Overpower T Function Limiting Safety System Setting is defined by:

Overpower T T0 {K4 - K5 (T-T') - K6 [(3sT) / (3s+1)] - f2(I)}

Where:

T is measured RCS T, F.

T0 is the indicated T at RTP, F.

s is the Laplace transform operator, sec-1.

T is the measured RCS average temperature, F.

T' is the nominal Tavg at RTP, F.

K4 is the Overpower T reactor trip setpoint, [*].

K5 is the Overpower T reactor trip heatup setpoint penalty coefficient which is:

[*]/F for T < T' and;

[*]/F for T T'.

K6 is the Overpower T reactor trip thermal time delay setpoint penalty which is:

[*]/F for increasing T and;

[*]/F for decreasing T.

3 is the measured impulse/lag time constant, [*] seconds.

f2(I) = [*]

These values denoted with [*] are specified in the COLR.

R.E. Ginna Nuclear Power Plant 3.3.1-19 Amendment 150

ESFAS Instrumentation 3.3.2 3.3 INSTRUMENTATION 3.3.2 Engineered Safety Feature Actuation System (ESFAS) Instrumentation LCO 3.3.2 The ESFAS instrumentation for each Function in Table 3.3.2-1 shall be OPERABLE.

APPLICABILITY:

According to Table 3.3.2-1.

ACTIONS

- NOTE -

Separate Condition entry is allowed for each Function.

CONDITION REQUIRED ACTION COMPLETION TIME A.

One or more Functions with one channel or train inoperable.

A.1 Enter the Condition referenced in Table 3.3.2-1 for the channel or train.

Immediately B.

As required by Required Action A.1 and referenced by Table 3.3.2-1.

B.1 Restore channel to OPERABLE status.

48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months OR

NOTE-------

Not applicable if there is a loss of function.

In accordance with the Risk Informed Completion Time Program C.

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

C.1 Be in MODE 2.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months R.E. Ginna Nuclear Power Plant 3.3.2-1 Amendment 150

ESFAS Instrumentation 3.3.2 CONDITION REQUIRED ACTION COMPLETION TIME D.

As required by Required Action A.1 and referenced by Table 3.3.2-1.

D.1 Restore channel to OPERABLE status.

48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months OR In accordance with the Risk Informed Completion Time Program E.

As required by Required Action A.1 and referenced by Table 3.3.2-1.

E.1 Restore train to OPERABLE status.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months OR In accordance with the Risk Informed Completion Time Program F.

As required by Required Action A.1 and referenced by Table 3.3.2-1.

F.1

- NOTE -

1.

For Functions 4c, 5b, and 6c, one channel may be bypassed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for surveillance testing.

2. The inoperable channel may be bypassed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for surveillance testing of the other channels.

Place channel in trip.

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 G.

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

G.1 Be in MODE 3.

AND G.2 Be in MODE 4.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 12 hours R.E. Ginna Nuclear Power Plant 3.3.2-2 Amendment 150

ESFAS Instrumentation 3.3.2 CONDITION REQUIRED ACTION COMPLETION TIME H.

As required by Required Action A.1 and referenced by Table 3.3.2-1.

H.1 Restore channel to K.1 OPERABLE status.

K.2 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months OR

NOTE-------

Not applicable if there is a loss of function.

In accordance with the Risk Informed Completion Time Program I.

As required by Required Action A.1 and referenced by Table 3.3.2-1.

K.3 I.1 Restore train to OPERABLE status.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months OR In accordance with the Risk Informed Completion Time Program J.

As required by Required Action A.1 and referenced by Table 3.3.2-1.

J.1

- NOTE -

1.

For Functions 1c, one channel may be bypassed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for surveillance testing.

2. The inoperable channel may be bypassed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for surveillance testing of the other channels.

K.4 Place channel in trip.

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 R.E. Ginna Nuclear Power Plant 3.3.2-3 Amendment 150

ESFAS Instrumentation 3.3.2 CONDITION REQUIRED ACTION COMPLETION TIME K.

Required Action and associated Completion Time of Condition H, I, or J not met.

K.5 K.1 Be in MODE 3.

K.6 K.7 AND K.2 Be in MODE 5.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 36 hours L.

As required by Required Action A.1 and referenced by Table 3.3.2-1.

L.1

- NOTE -

1. For Functions 1d and 1e, one channel may be bypassed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for surveillance testing.

2. The inoperable channel may be bypassed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for surveillance testing of the other channels.

Place channel in trip.

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 M.

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

M.1 Be in MODE 3.

AND M.2 Reduce pressurizer pressure to < 2000 psig.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 12 hours N.

As required by Required Action A.1 and referenced by Table 3.3.2-1.

N.1 Declare associated Auxiliary Feedwater pump inoperable and enter applicable condition(s) of LCO 3.7.5, "Auxiliary Feedwater (AFW)

System."

Immediately R.E. Ginna Nuclear Power Plant 3.3.2-4 Amendment 150

ESFAS Instrumentation 3.3.2 SURVEILLANCE REQUIREMENTS

- NOTE -

Refer to Table 3.3.2-1 to determine which SRs apply for each ESFAS Function.

SURVEILLANCE FREQUENCY SR 3.3.2.1 Perform CHANNEL CHECK In accordance with the surveillance Frequency Control Program SR 3.3.2.2

- NOTE-The ESFAS input relays are excluded from this surveillance for Functions 1c, 1d, 1e, 4c, 5b, and 6c.

Perform COT.

In accordance with the Surveillance Frequency Control Program SR 3.3.2.3

- NOTE -

Verification of relay setpoints not required.

Perform TADOT.

In accordance with the Surveillance Frequency Control Program SR 3.3.2.4

- NOTE -

Verification of relay setpoints not required.

Perform TADOT.

In accordance with the Surveillance Frequency Control Program SR 3.3.2.5 Perform CHANNEL CALIBRATION In accordance with the Surveillance Frequency Control Program R.E. Ginna Nuclear Power Plant 3.3.2-5 Amendment 150

ESFAS Instrumentation 3.3.2 SURVEILLANCE FREQUENCY SR 3.3.2.6 Verify the Pressurizer Pressure-Low and Steam Line Pressure-Low Functions are not bypassed when pressurizer pressure > 2000 psig.

In accordance with the Surveillance Frequency Control Program SR 3.3.2.7 Perform ACTUATION LOGIC TEST.

In accordance with the Surveillance Frequency Control Program R.E. Ginna Nuclear Power Plant 3.3.2-6 Amendment 150

ESFAS Instrumentation 3.3.2 Table 3.3.2-1 Engineered Safety Feature Actuation System Instrumentation FUNCTION APPLICABLE MODES OR OTHER SPECIFIED CONDITIONS REQUIRED CHANNELS CONDITIONS SURVEILLANCE REQUIREMENTS LIMITING SAFETY SYSTEM SETTINGS(a) 1.

Safety Injection R.E. Ginna Nuclear Power Plant 3.3.2-7 Amendment a.

Manual Initiation 1,2,3,4 2

H,K SR 3.3.2.4 NA b.

Automatic 1,2,3,4 2 trains I,K SR 3.3.2.7 NA Actuation Logic and Actuation Relays c.

Containment 1,2,3,4 3

J,K SR 3.3.2.1 4.61 psig Pressure-High SR 3.3.2.2 SR 3.3.2.5 d.

Pressurizer Pressure-Low 1,2,3(b) 3 L,M SR 3.3.2.1 SR 3.3.2.2 1729.8 psig SR 3.3.2.5 SR 3.3.2.6 e.

Steam Line Pressure-Low 1,2,3(b) 3 per steam line L,M SR 3.3.2.1 SR 3.3.2.2 393.8 psig SR 3.3.2.5 SR 3.3.2.6 150

ESFAS Instrumentation 3.3.2 Table 3.3.2-1 Engineered Safety Feature Actuation System Instrumentation FUNCTION APPLICABLE MODES OR OTHER SPECIFIED CONDITIONS REQUIRED CHANNELS CONDITIONS SURVEILLANCE REQUIREMENTS LIMITING SAFETY SYSTEM SETTINGS(a) 2.

Containment Spray a.

Manual Initiation Left pushbutton 1,2,3,4 1

H,K SR 3.3.2.4 NA Right pushbutton 1,2,3,4 1

H,K SR 3.3.2.4 NA b.

Automatic Actuation Logic and Actuation Relays 1,2,3,4 2 trains I,K SR 3.3.2.7 NA c.

Containment Pressure-High High 1,2,3,4 3 per set J,K SR 3.3.2.1 SR 3.3.2.2 SR 3.3.2.5 32.11 psig (narrow range) 29.6 psig (wide range) 3.

Containment Isolation a.

Manual Initiation 1,2,3,4,(c) 2 H,K SR 3.3.2.4 NA b.

Automatic Actuation Logic and Actuation Relays 1,2,3,4 2 trains I,K SR 3.3.2.7 NA c.

Safety Injection Refer to Function 1 (Safety Injection) for all automatic initiation functions and requirements.

R.E. Ginna Nuclear Power Plant 3.3.2-8 Amendment 150

ESFAS Instrumentation 3.3.2 Table 3.3.2-1 Engineered Safety Feature Actuation System Instrumentation FUNCTION APPLICABLE MODES OR OTHER SPECIFIED CONDITIONS REQUIRED CHANNELS CONDITIONS SURVEILLANCE REQUIREMENTS LIMITING SAFETY SYSTEM SETTINGS(a) 4.

Steam Line Isolation a.

Manual Initiation 1,2(d),3(d) 1 per loop D,G SR 3.3.2.4 NA b.

Automatic Actuation 1,2(d),3(d) 2 trains E,G SR 3.3.2.7 NA Logic and Actuation Relays c.

Containment Pressure-High 1,2(d),3(d) 3 F,G SR 3.3.2.1 SR 3.3.2.2 18.0 psig High SR 3.3.2.5 d.

High Steam Flow 1,2(d),3(d) 2 per steam line F,G SR 3.3.2.1 SR 3.3.2.2 1.30E6 lbm/hr SR 3.3.2.5

@ 1005 psig Coincident with Safety Injection Refer to Function 1 (Safety Injection) for all initiation functions and requirements.

and Coincident with Tavg-Low 1,2(d),3(d) 2 per loop F,G SR 3.3.2.1 SR 3.3.2.2 SR 3.3.2.5 544.0F e.

High-High Steam Flow 1,2(d),3(d) 2 per steam line F,G SR 3.3.2.1 SR 3.3.2.2 SR 3.3.2.5 4.53E6 lbm/hr

@ 785 psig Coincident with Safety Injection Refer to Function 1 (Safety Injection) for all initiation functions and requirements.

R.E. Ginna Nuclear Power Plant 3.3.2-9 Amendment 150

ESFAS Instrumentation 3.3.2 Table 3.3.2-1 Engineered Safety Feature Actuation System Instrumentation FUNCTION APPLICABLE MODES OR OTHER SPECIFIED CONDITIONS REQUIRED CHANNELS CONDITIONS SURVEILLANCE REQUIREMENTS LIMITING SAFETY SYSTEM SETTINGS(a) 5.

Feedwater Isolation a.

Automatic Actuation Logic and Actuation Relays 1,2(e),3(e) 2 trains E,G SR 3.3.2.7 NA b.

SG Water Level-High 1,2(e),3(e) 3 per SG F,G SR 3.3.2.1 SR 3.3.2.2 SR 3.3.2.5 91.15%

c.

Safety Injection Refer to Function 1 (Safety Injection) for all initiation functions and requirements.

R.E. Ginna Nuclear Power Plant 3.3.2-10 Amendment 150

ESFAS Instrumentation 3.3.2 Table 3.3.2-1 Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR LIMITING OTHER SAFETY SPECIFIED REQUIRED SURVEILLANCE SYSTEM FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS SETTINGS(a) 6.

Auxiliary Feedwater (AFW) a.

Manual Initiation AFW 1,2,3 1 per pump N

SR 3.3.2.4 NA Standby AFW 1,2,3 1 per pump N

SR 3.3.2.4 NA b.

Automatic Actuation Logic and Actuation Relays 1,2,3 2 trains E,G SR 3.3.2.7 NA c.

SG Water Level-Low Low 1,2,3 3 per SG F,G SR 3.3.2.1 SR 3.3.2.2 SR 3.3.2.5 13.88%

d.

Safety Injection (Motor driven pumps only)

Refer to Function 1 (Safety Injection) for all initiation functions and requirements.

e.

Undervoltage -

Bus 11A and 11B (Turbine driven pump only) 1,2,3 2 per bus D,G SR 3.3.2.3 SR 3.3.2.5 2597 V with 3.6 sec time delay f.

Trip of Both Main Feedwater Pumps (Motor driven pumps only) 1 2 per MFW pump B,C SR 3.3.2.4 NA R.E. Ginna Nuclear Power Plant 3.3.2-11 Amendment 150

ESFAS Instrumentation 3.3.2 (a)

A channel is OPERABLE when both of the following conditions are met:

1.

The absolute difference between the as-found Trip Setpoint (TSP) and the previous as-left TSP is within the COT Acceptance Criteria. The COT Acceptance Criteria is defined as:

las-found TSP - previous as-left TSPl COT uncertainty The COT uncertainty shall not include the calibration tolerance.

2.

The as-left TSP is within the established calibration tolerance band about the nominal TSP. The nominal TSP is the desired setting and shall not exceed the Limiting Safety System Setting (LSSS). The LSSS and the established calibration tolerance band are defined in accordance with the Ginna Instrument Setpoint Methodology. The channel is considered operable even if the as-left TSP is non-conservative with respect to the LSSS provided that the as-left TSP is within the established calibration tolerance band.

(b)

Pressurizer Pressure 2000 psig.

(c)

During CORE ALTERATIONS and movement of irradiated fuel assemblies within containment.

(d)

Except when both MSIVs are closed and de-activated.

(e)

Except when all Main Feedwater Regulating and associated bypass valves are closed and de-activated or isolated by a closed manual valve.

R.E. Ginna Nuclear Power Plant 3.3.2-12 Amendment 150

LOP DG Start Instrumentation 3.3.4 3.3 INSTRUMENTATION 3.3.4 Loss of Power (LOP) Diesel Generator (DG) Start Instrumentation LCO 3.3.4 Each 480 V safeguards bus shall have two OPERABLE channels of LOP DG Start Instrumentation.

APPLICABILITY:

MODES 1, 2, 3, and 4, When associated DG is required to be OPERABLE by LCO 3.8.2, "AC Sources - MODES 5 and 6."

ACTIONS

- NOTE -

Separate Condition entry is allowed for each 480 V safeguards bus.

CONDITION REQUIRED ACTION COMPLETION TIME A.

One or more 480 V bus(es) with one channel inoperable.

A.1 Place channel(s) in trip.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months OR In accordance with the Risk Informed Completion Time Program B.

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

OR One or more 480 V bus(es) with two channels inoperable.

B.1 Enter applicable Condition(s) and Required Action(s) for the associated DG made inoperable by LOP DG start instrumentation.

Immediately R.E. Ginna Nuclear Power Plant 3.3.4-1 Amendment 150

Containment Ventilation Isolation Instrumentation 3.3.5 3.3 INSTRUMENTATION 3.3.5 Containment Ventilation Isolation Instrumentation LCO 3.3.5 The Containment Ventilation Isolation instrumentation for each Function in Table 3.3.5-1 shall be OPERABLE.

APPLICABILITY:

According to Table 3.3.5-1.

ACTIONS

- NOTE -

Separate Condition entry is allowed for each Function.

CONDITION REQUIRED ACTION COMPLETION TIME A.

One radiation monitoring channel inoperable.

A.1 Restore the affected channel to OPERABLE status.

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

NOTE------

Not applicable if there is a loss of function.

In accordance with the Risk Informed Completion Time Program B.

- NOTE -

Only applicable in MODE 1, 2, 3, or 4.

One or more Functions with one or more manual or automatic actuation trains inoperable.

OR B.1 Enter applicable Conditions and Required Actions of LCO 3.6.3, "Containment Isolation Boundaries," for containment mini-purge isolation valves made inoperable by isolation instrumentation.

Immediately R.E. Ginna Nuclear Power Plant 3.3.5-1 Amendment 150

Containment Ventilation Isolation Instrumentation 3.3.5 CONDITION REQUIRED ACTION COMPLETION TIME Both radiation monitoring channels inoperable.

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

C.

- NOTE -

Only applicable during CORE ALTERATIONS or movement of irradiated fuel assemblies within containment.

One or more Functions with one or more manual or automatic actuation trains inoperable.

OR Both radiation monitoring channels inoperable.

OR Required Action and associated Completion Time for Condition A not met.

C.1 Place and maintain containment purge and exhaust valves in closed position.

OR C.2 Enter applicable Conditions and Required Actions of LCO 3.9.3, "Containment Penetrations," for containment purge and exhaust isolation valves made inoperable by isolation instrumentation.

Immediately Immediately R.E. Ginna Nuclear Power Plant 3.3.5-2 Amendment 150

Pressurizer PORVs 3.4.11 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.11 Pressurizer Power Operated Relief Valves (PORVs)

LCO 3.4.11 Each PORV and associated block valve shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, and 3.

ACTIONS

- NOTE -

1.

Separate entry into Condition A is allowed for each PORV.

2.

Separate entry into Condition C is allowed for each block valve.

CONDITION REQUIRED ACTION COMPLETION TIME A.

One or both PORVs OPERABLE and not capable of being automatically controlled.

A.1 Close and maintain power to associated block valve.

OR A.2 Place associated PORV in manual control.

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

One PORV inoperable.

B.1 Close associated block valve.

AND B.2 Remove power from associated block valve.

AND B.3.1 Restore PORV to OPERABLE status.

OR B.3.2.1 Verify Opposite Train PORV and PORV Block Valve are OPERABLE 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months 1 hour 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months 1 hour R.E. Ginna Nuclear Power Plant 3.4.11-1 Amendment 150

Pressurizer PORVs 3.4.11 CONDITION REQUIRED ACTION COMPLETION TIME AND B.3.2.2 Restore PORV to OPERABLE status 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR

NOTE------

Not applicable if there is a loss of function.

In accordance with the Risk Informed Completion Time Program C.

One block valve inoperable.

C.1 Place associated PORV in manual control.

AND C.2.1 Restore block valve to OPERABLE status.

OR C.2.2.1 Verify Opposite Train PORV and PORV Block Valve are OPERABLE AND C.2.2.2 Restore PORV Block Valve to OPERABLE status 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months 7 days 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months 7 days OR

NOTE------

Not applicable if there is a loss of function.

In accordance with the Risk Informed Completion Time Program R.E. Ginna Nuclear Power Plant 3.4.11-2 Amendment 150

Pressurizer PORVs 3.4.11 CONDITION REQUIRED ACTION COMPLETION TIME D.

Both block valves inoperable.

D.1 Place associated PORVs in manual control.

AND D.2 Restore at least one block valve to OPERABLE status.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months 72 hours 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.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 12 hours F.

Two PORVs inoperable.

F.1 Initiate action to restore one PORV to OPERABLE status.

AND F.2 Close associated block valves.

AND F.3 Remove power from associated block valves.

AND F.4 Be in MODE 3 with Tavg

< 500F.

Immediately 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months 1 hour 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months R.E. Ginna Nuclear Power Plant 3.4.11-3 Amendment 150

Pressurizer PORVs 3.4.11 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.11.1

- NOTE -

Not required to be performed with block valve closed per LCO 3.4.13.

Perform a complete cycle of each block valve.

In accordance with the Surveillance Frequency Control Program SR 3.4.11.2 Perform a complete cycle of each PORV.

In accordance with the Surveillance Frequency Control Program R.E. Ginna Nuclear Power Plant 3.4.11-4 Amendment 150

ECCS - MODES 1, 2, and 3 3.5.2 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) 3.5.2 ECCS - MODES 1, 2, and 3 LCO 3.5.2 Two ECCS trains shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, and 3.

- NOTE -

1.

In MODE 3, both safety injection (SI) pump flow paths may be isolated by closing the isolation valves for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months to perform pressure isolation valve testing per SR 3.4.14.1. Power may be restored to motor operated isolation valves 878B and 878D for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for the purpose of testing per SR 3.4.14.1 provided that power is restored to only one valve at a time.

2.

Operation in MODE 3 with ECCS pumps declared inoperable pursuant to LCO 3.4.12, "Low Temperature Overpressure Protection (LTOP) System," is allowed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months or until the temperature of both RCS cold legs exceeds 375F, whichever comes first.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One train inoperable.

AND At least 100% of the ECCS flow equivalent to a single OPERABLE ECCS train available.

A.1 Restore train to OPERABLE status.

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

NOTE-------

Not applicable if there is a loss of function.

In accordance with the Risk Informed Completion Time Program R.E. Ginna Nuclear Power Plant 3.5.2-1 Amendment 150

ECCS - MODES 1, 2, and 3 3.5.2 B.

Required Action and associated Completion Time not met.

B.1 Be in MODE 3.

AND B.2 Be in MODE 4.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 12 hours C.

Two trains inoperable.

C.1 Enter LCO 3.0.3 Immediately R.E. Ginna Nuclear Power Plant 3.5.2-2 Amendment 150

ECCS - MODES 1, 2, and 3 3.5.2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.5.2.1 Verify the following valves are in the listed position.

Number Position Function 825A Open RWST Suction to SI Pumps 825B Open RWST Suction to SI Pumps 826A Closed BAST Suction to SI Pumps 826B Closed BAST Suction to SI Pumps 826C Closed BAST Suction to SI Pumps 826D Closed BAST Suction to SI Pumps 851A Open Sump B to RHR Pumps 851B Open Sump B to RHR Pumps 856 Open RWST Suction to RHR Pumps 878A Closed SI Injection to RCS Hot Leg 878B Open SI Injection to RCS Cold Leg 878C Closed SI Injection to RCS Hot Leg 878D Open SI Injection to RCS Cold Leg 896A Open RWST Suction to SI and Containment Spray 896B Open RWST Suction to SI and Containment Spray In accordance with the Surveillance Frequency Control Program SR 3.5.2.2

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

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

Verify each ECCS 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.

Verify each ECCS manual, power operated, and automatic valve in the flow path, that is not locked, sealed or otherwise secured in position is in the correct In accordance with the Surveillance Frequency Control Program R.E. Ginna Nuclear Power Plant 3.5.2-3 Amendment 150

ECCS - MODES 1, 2, and 3 3.5.2 SURVEILLANCE FREQUENCY SR 3.5.2.3 Verify each breaker or key switch, as applicable, for each valve listed in SR 3.5.2.1, is in the correct position.

In accordance with the Surveillance Frequency Control Program SR 3.5.2.4 Verify each ECCS pumps developed head at the test flow point is greater than or equal to the required developed head.

In accordance with the INSERVICE TESTING PROGRAM SR 3.5.2.5 Verify each ECCS automatic valve in the flow path that is not locked, sealed, or otherwise secured in position actuates to the correct position on an actual or simulated actuation signal.

In accordance with the Surveillance Frequency Control Program SR 3.5.2.6 Verify each ECCS pump starts automatically on an actual or simulated actuation signal.

In accordance with the Surveillance Frequency Control Program SR 3.5.2.7 Verify ECCS locations susceptible to gas accumulation are sufficiently filled with water.

In accordance with the Surveillance Frequency Control Program R.E. Ginna Nuclear Power Plant 3.5.2-4 Amendment 150

Containment Air Locks 3.6.2 CONDITION REQUIRED ACTION COMPLETION TIME B.3

- NOTE -

Air lock doors in high radiation areas may be verified locked closed by administrative means.

Verify an OPERABLE door is locked closed in the affected air lock.

Once per 31 days C.

One or more containment C.1 Initiate action to evaluate Immediately air locks inoperable for overall containment leakage reasons other than rate per LCO 3.6.1.

Condition A or B.

AND C.2 Verify a door is closed in the 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months affected air lock.

AND C.3 Restore air lock to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OR

NOTE-------

Not applicable if there is a loss of function.

In accordance with the Risk Informed Completion Time Program OPERABLE status.

D.

Required Action and associated Completion Time not met.

D.1 AND D.2 Be in MODE 3.

Be in MODE 5.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 36 hours R.E. Ginna Nuclear Power Plant 3.6.2-3 Amendment 150

Containment Isolation Boundaries 3.6.3 CONDITION REQUIRED ACTION COMPLETION TIME A.

- NOTE -

Only applicable to penetration flow paths which do not use a closed system as a containment isolation boundary.

One or more penetration flow paths with one containment isolation boundary inoperable except for mini-purge valve leakage not within limit.

A.1 AND A.2 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.

- NOTE -

Isolation boundaries in high radiation areas 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 OR In accordance with the Risk Informed Completion Time Program Once per 31 days following isolation for isolation boundaries outside containment AND Prior to entering MODE 4 from MODE 5 if not performed within the previous 92 days for isolation boundaries inside containment.

R.E. Ginna Nuclear Power Plant 3.6.3-2 Amendment 150

Containment Isolation Boundaries 3.6.3 CONDITION REQUIRED ACTION COMPLETION TIME B.

- NOTE -

Only applicable to penetration flow paths which do not use a closed system as a containment isolation boundary.

One or more penetration flow paths with two containment isolation boundaries inoperable except for mini-purge valve leakage not within limit.

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 C.

- NOTE -

Only applicable to penetration flow paths which use a closed system as a containment isolation boundary.

One or more penetration flow paths with one containment isolation boundary inoperable.

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

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 R.E. Ginna Nuclear Power Plant 3.6.3-3 Amendment 150

Containment Isolation Boundaries 3.6.3 CONDITION REQUIRED ACTION COMPLETION TIME C.2

- NOTE -

Isolation boundaries in high radiation areas may be verified by use of administrative means.

Verify the affected penetration flow path is isolated.

Once per 31 days following isolation for isolation boundaries outside containment AND Prior to entering MODE 4 from MODE 5 if not performed within the previous 92 days for isolation boundaries inside containment D.

One or more mini-purge penetration flow paths with one valve not within leakage limits.

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

24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months R.E. Ginna Nuclear Power Plant 3.6.3-4 Amendment 150

Containment Isolation Boundaries 3.6.3 CONDITION REQUIRED ACTION COMPLETION TIME D.2

- NOTE -

Isolation boundaries in high radiation areas may be verified by use of administrative means.

Verify the affected penetration flow path is isolated.

Once per 31 days for isolation boundaries outside containment AND Prior to entering MODE 4 from MODE 5 if not performed within the previous 92 days for isolation boundaries inside containment E.

One or more mini-purge penetration flow paths with two valves not within leakage limits.

E.1 AND E.2 Initiate action to evaluate overall containment leakage rate per LCO 3.6.1.

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

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

NOTE-------

Not applicable if there is a loss of function.

In accordance with the Risk Informed Completion Time Program F.

Required Action and associated Completion Time not met.

F.1 AND F.2 Be in MODE 3.

Be in MODE 5.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 36 hours R.E. Ginna Nuclear Power Plant 3.6.3-5 Amendment 150

CS, CRFC, and NaOH Systems 3.6.6 3.6 CONTAINMENT SYSTEMS 3.6.6 Containment Spray (CS), Containment Recirculation Fan Cooler (CRFC), and NaOH Systems LCO 3.6.6 Two CS trains, four CRFC units, and the NaOH system shall be OPERABLE.

- NOTE -

In MODE 4, both CS pumps may be in pull-stop for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months for the performance of interlock and valve testing of motor operated valves (MOVs) 857A, 857B, and 857C. Power may also be restored to MOVs 896A and 896B, and the valves placed in the closed position, for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months for the purpose of each test.

APPLICABILITY:

MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One CS train inoperable.

A.1 Restore CS train to OPERABLE status.

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

NOTE--------

Not applicable if there is a loss of function.

In accordance with the Risk Informed Completion Time Program B.

NaOH system inoperable.

B.1 Restore NaOH System to OPERABLE status.

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

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

C.1 Be in MODE 3.

AND C.2 Be in MODE 5.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 84 hours R.E. Ginna Nuclear Power Plant 3.6.6-1 Amendment 150

CS, CRFC, and NaOH Systems 3.6.6 R.E. Ginna Nuclear Power Plant 3.6.6-2 Amendment CONDITION REQUIRED ACTION COMPLETION TIME D.

One or two CRFC units inoperable.

D.1 Restore CRFC unit(s) to OPERABLE status.

7 days OR

NOTE--------

Not applicable if there is a loss of function.

In accordance with the Risk Informed Completion Time Program E.

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

E.1 E.2 Be in MODE 3.

AND Be in MODE 5.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 36 hours F.

Two CS trains inoperable.

OR Three or more CRFC units inoperable.

F.1 Enter LCO 3.0.3.

Immediately SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.6.1 Perform SR 3.5.2.1 and SR 3.5.2.3 for valves 896A and 896B.

In accordance with applicable SRs.

SR 3.6.6.2

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

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

Verify each CS 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 3.6.6.3 Verify each NaOH 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 150

CS, CRFC, and NaOH Systems 3.6.6 SURVEILLANCE FREQUENCY SR 3.6.6.4 Operate each CRFC unit for 15 minutes.

In accordance with the Surveillance Frequency Control Program SR 3.6.6.5 Verify cooling water flow through each CRFC unit.

In accordance with the Surveillance Frequency Control Program SR 3.6.6.6 Verify each CS pump's developed head at the flow test point is greater than or equal to the required developed head.

In accordance with the INSERVICE TESTING PROGRAM SR 3.6.6.7 Verify NaOH System solution volume is 3000 gal.

In accordance with the Surveillance Frequency Control Program SR 3.6.6.8 Verify NaOH System tank NaOH solution concentration is 30% and 35% by weight.

In accordance with the Surveillance Frequency Control Program SR 3.6.6.9 Perform required CRFC unit testing in accordance with the VFTP.

In accordance with the VFTP SR 3.6.6.10 Verify each automatic CS valve in the flow path that is not locked, sealed, or otherwise secured in position actuates to the correct position on an actual or simulated actuation signal.

In accordance with the Surveillance Frequency Control Program SR 3.6.6.11 Verify each CS pump starts automatically on an actual or simulated actuation signal.

In accordance with the Surveillance Frequency Control Program SR 3.6.6.12 Verify each CRFC unit starts automatically on an actual or simulated actuation signal.

In accordance with the Surveillance Frequency Control Program SR 3.6.6.13 Verify each automatic NaOH System valve in the flow path that is not locked, sealed, or otherwise secured in position actuates to the correct position on an actual or simulated actuation signal.

In accordance with the Surveillance Frequency Control Program R.E. Ginna Nuclear Power Plant 3.6.6-3 Amendment 150

CS, CRFC, and NaOH Systems 3.6.6 SURVEILLANCE FREQUENCY SR 3.6.6.14 Verify spray additive flow through each eductor path.

In accordance with the Surveillance Frequency Control Program SR 3.6.6.15 Verify each spray nozzle is unobstructed.

Following maintenance which could result in nozzle blockage SR 3.6.6.16 Verify CS locations susceptible to gas accumulation are sufficiently filled with water.

In accordance with the Surveillance Frequency Control Program R.E. Ginna Nuclear Power Plant 3.6.6-4 Amendment 150

MSIVs and Non-Return Check Valves 3.7.2 3.7 PLANT SYSTEMS 3.7.2 Main Steam Isolation Valves (MSIVs) and Non-Return Check Valves LCO 3.7.2 Two MSIVs and two non-return check valves shall be OPERABLE.

APPLICABILITY:

MODE 1, MODES 2 and 3 except when all MSIVs are closed and de-activated.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One or more valves inoperable in flowpath from a steam generator (SG) in MODE 1.

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

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

NOTE-------

Not applicable if there is a loss of function.

In accordance with the Risk Informed Completion Time Program B.

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

B.1 Be in MODE 2.

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

One or more valves inoperable in flowpath from a SG in MODE 2 or 3.

C.1 AND C.2 Close MSIV.

Verify MSIV is closed.

8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months Once per 7 days D.

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

D.1 AND D.2 Be in MODE 3.

Be in MODE 4.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 12 hours E.

One or more valves inoperable in flowpath from each SG.

E.1 Enter LCO 3.0.3.

Immediately R.E. Ginna Nuclear Power Plant 3.7.2-1 Amendment 150

AFW System 3.7.5 3.7 PLANT SYSTEMS 3.7.5 Auxiliary Feedwater (AFW) System LCO 3.7.5 Two motor driven AFW (MDAFW) trains, one turbine driven AFW (TDAFW) train, and two standby AFW (SAFW) trains shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, and 3.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One TDAFW train flowpath inoperable.

A.1 Restore TDAFW train flowpath to OPERABLE status.

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

One MDAFW train inoperable.

B.1 Restore MDAFW train to OPERABLE status.

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

TDAFW train inoperable.

OR Two MDAFW trains inoperable.

OR One TDAFW train flowpath and one MDAFW train inoperable to opposite steam generators (SGs).

C.1

- NOTE -

LCO 3.0.4.b is not applicable.

Restore one MDAFW train or TDAFW train flowpath 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 R.E. Ginna Nuclear Power Plant 3.7.5-1 Amendment 150

AFW System 3.7.5 CONDITION REQUIRED ACTION COMPLETION TIME D.

All MD and TD (preferred) AFW trains to one or more SGs inoperable.

D.1

- NOTE -

LCO 3.0.4.b is not applicable.

Restore one MDAFW train or TDAFW flowpath to each affected SG to OPERABLE status.

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

NOTE--------

Not applicable if there is a loss of function.

In accordance with the Risk Informed Completion Time Program E.

One SAFW train inoperable.

E.1 Restore SAFW train to OPERABLE status.

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

Both SAFW trains inoperable.

F.1 Restore one SAFW train to OPERABLE status.

7 days G.

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

G.1 Be in MODE 3.

AND G.2 Be in MODE 4.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 12 hours R.E. Ginna Nuclear Power Plant 3.7.5-2 Amendment 150

AFW System 3.7.5 CONDITION REQUIRED ACTION COMPLETION TIME H.

Three AFW trains and both SAFW trains inoperable.

H.1

- NOTE -

LCO 3.0.3 and all other LCO Required Actions requiring MODE changes are suspended until one MDAFW, TDAFW, or SAFW train is restored to OPERABLE status.

Initiate action to restore one MDAFW, TDAFW, or SAFW train to OPERABLE status.

Immediately R.E. Ginna Nuclear Power Plant 3.7.5-3 Amendment 150

AFW System 3.7.5 R.E. Ginna Nuclear Power Plant 3.7.5-4 Amendment SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.5.1 Verify each AFW and SAFW manual, power operated, and automatic valve in each water flow path, and in both steam supply flow paths to the turbine driven pump, that is not locked, sealed, or otherwise secured in position, is in the correct position.

In accordance with the Surveillance Frequency Control Program SR 3.7.5.2

- NOTE -

Required to be met prior to entering MODE 1 for the TDAFW pump.

Verify the developed head of each AFW pump at the flow test point is greater than or equal to the required developed head.

In accordance with the INSERVICE TESTING PROGRAM SR 3.7.5.3 Verify the developed head of each SAFW pump at the flow test point is greater than or equal to the required developed head.

In accordance with the INSERVICE TESTING PROGRAM SR 3.7.5.4 Perform a complete cycle of each AFW and SAFW motor operated suction valve from the Service Water System, each AFW and SAFW discharge motor operated isolation valve, and each SAFW cross-tie motor operated valve.

In accordance with the INSERVICE TESTING PROGRAM SR 3.7.5.5 Verify each AFW automatic valve that is not locked, sealed, or otherwise secured in position, actuates to the correct position on an actual or simulated actuation signal.

In accordance with the Surveillance Frequency Control Program SR 3.7.5.6

- NOTE -

Required to be met prior to entering MODE 1 for the TDAFW pump.

Verify each AFW pump starts automatically on an actual or simulated actuation signal.

In accordance with the Surveillance Frequency Control Program SR 3.7.5.7 Verify each SAFW train can be actuated and controlled from the control room.

In accordance with the Surveillance Frequency Control Program 150

CCW System 3.7.7 3.7 PLANT SYSTEMS 3.7.7 Component Cooling Water (CCW) System LCO 3.7.7 Two CCW trains, two CCW heat exchangers, and the CCW loop header shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One CCW train inoperable.

A.1 Restore CCW train 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.

One CCW heat exchanger inoperable.

B.1 Restore CCW heat exchanger to OPERABLE status.

31 days C.

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

C.1 AND C.2 Be in MODE 3.

Be in MODE 5.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 36 hours R.E. Ginna Nuclear Power Plant 3.7.7-1 Amendment 150

CCW System 3.7.7 CONDITION REQUIRED ACTION COMPLETION TIME D.

Two CCW trains, two CCW heat exchangers, or loop header inoperable.

- NOTE -

LCO 3.0.3 and all other LCO Required Actions requiring MODE changes are suspended until one CCW train, one CCW heat exchanger, and the loop header are restored to OPERABLE status.

D.1 Initiate Action to restore one CCW train, one heat exchanger, and loop header to OPERABLE status.

AND D.2 Be in MODE 3.

AND D.3 Be in MODE 4.

Immediately 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 12 hours SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.7.1

- NOTE -

Isolation of CCW flow to individual components does not render the CCW loop header inoperable.

Verify each CCW manual and power operated valve in the CCW train and heat exchanger flow path and loop header that is not locked, sealed, or otherwise secured in position, is in the correct position.

In accordance with the Surveillance Frequency Control Program SR 3.7.7.2 Perform a complete cycle of each motor operated isolation valve to the residual heat removal heat exchangers.

In accordance with the INSERVICE TESTING PROGRAM R.E. Ginna Nuclear Power Plant 3.7.7-2 Amendment 150

SW System 3.7.8 3.7 PLANT SYSTEMS 3.7.8 Service Water (SW) System LCO 3.7.8 Four SW pumps and the SW loop header shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One SW pump inoperable.

A.1 Restore SW pump to OPERABLE status.

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

Two SW pumps inoperable.

B.1 Restore SW pump(s) 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 C.

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

C.1 Be in MODE 3.

AND C.2 Be in MODE 5.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 36 hours D.

Three or more SW pumps or loop header inoperable.

D.1

- NOTE -

Enter applicable conditions and Required Actions of LCO 3.7.7, "CCW System,"

for the component cooling water heat exchanger(s) made inoperable by SW.

Enter LCO 3.0.3.

Immediately R.E. Ginna Nuclear Power Plant 3.7.8-1 Amendment 150

AC Sources - MODES 1, 2, 3, and 4 3.8.1 3.8 ELECTRICAL POWER SYSTEMS 3.8.1 AC Sources - MODES 1, 2, 3, and 4 LCO 3.8.1 The following AC electrical sources shall be OPERABLE:

a.

One qualified independent offsite power circuit connected between the offsite transmission network and each of the onsite 480 V safeguards buses required by LCO 3.8.9, "Distribution Subsystems

- MODES 1, 2, 3, and 4"; and b.

Two emergency diesel generators (DGs) capable of supplying their respective onsite 480 V safeguards buses required by LCO 3.8.9.

APPLICABILITY:

MODES 1, 2, 3, and 4.

ACTIONS LCO 3.0.4.b is not applicable to DGs.

- NOTE -

CONDITION REQUIRED ACTION COMPLETION TIME A.

Offsite power to one or more 480 V safeguards bus(es) inoperable.

A.1 Declare required feature(s) inoperable when its redundant required feature(s) is inoperable.

AND A.2 Restore 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 A concurrent with inoperability of redundant required feature(s) 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR

NOTE------

Not applicable if there is a loss of function.

In accordance with the Risk Informed Completion Time Program R.E. Ginna Nuclear Power Plant 3.8.1-1 Amendment 150

AC Sources - MODES 1, 2, 3, and 4 3.8.1 CONDITION REQUIRED ACTION COMPLETION TIME B.

One DG inoperable.

B.1 Perform SR 3.8.1.1 for the offsite circuit.

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

AND B.3.1 Determine OPERABLE DG is not inoperable due to common cause failure.

OR B.3.2 Perform SR 3.8.1.2 for OPERABLE DG.

AND B.4 Restore 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 R.E. Ginna Nuclear Power Plant 3.8.1-2 Amendment 150

AC Sources - MODES 1, 2, 3, and 4 3.8.1 CONDITION REQUIRED ACTION COMPLETION TIME C.

Offsite power to one or more 480 V safeguards bus(es) inoperable.

AND One DG inoperable.

- NOTE -

Enter applicable Conditions and Required Actions of LCO 3.8.9, "Distribution Systems - MODES 1, 2, 3, and 4," when Condition C is entered with no AC power source to one distribution train.

C.1 Restore required offsite circuit to OPERABLE status.

OR C.2 Restore DG to OPERABLE status.

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

NOTE------

Not applicable if there is a loss of function.

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

NOTE------

Not applicable if there is a loss of function.

In accordance with the Risk Informed Completion Time Program R.E. Ginna Nuclear Power Plant 3.8.1-3 Amendment 150

AC Sources - MODES 1, 2, 3, and 4 3.8.1 CONDITION REQUIRED ACTION COMPLETION TIME D.

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

D.1 Be in MODE 3.

AND D.2 Be in MODE 5.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 36 hours E.

Two DGs inoperable.

E.1 Enter LCO 3.0.3.

Immediately SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.1 Verify correct breaker alignment and indicated power availability for the offsite circuit to each of the 480 V safeguards buses.

In accordance with the Surveillance Frequency Control Program SR 3.8.1.2

- NOTE -

1.

Performance of SR 3.8.1.9 satisfies this SR.

2.

All DG starts may be preceded by an engine prelube period and followed by a warmupperiod prior to loading.

Verify each DG starts from standby conditions and achieves rated voltage and frequency.

In accordance with the Surveillance Frequency Control Program R.E. Ginna Nuclear Power Plant 3.8.1-4 Amendment 150

AC Sources - MODES 1, 2, 3, and 4 3.8.1 SURVEILLANCE FREQUENCY SR 3.8.1.3

- NOTE -

1.

DG loadings may include gradual loading as recommended by the manufacturer.

2.

Momentary transients outside the load range do not invalidate this test.

3.

This Surveillance shall be conducted on only one DG at a time.

4.

This SR shall be preceded by and immediately follow without shutdown a successful performance of SR 3.8.1.2 or SR 3.8.1.9.

Verify each DG is synchronized and loaded and operates for 60 minutes and < 120 minutes at a load 2025 kW and < 2250 kW.

In accordance with the Surveillance Frequency Control Program SR 3.8.1.4 Verify the fuel oil level in each day tank.

In accordance with the Surveillance Frequency Control Program SR 3.8.1.5 Verify the DG fuel oil transfer system operates to transfer fuel oil from each storage tank to the associated day tank.

In accordance with the Surveillance Frequency Control Program SR 3.8.1.6 Verify transfer of AC power sources from the 50/50 mode to the 100/0 mode and 0/100 mode.

In accordance with the Surveillance Frequency Control Program s

SR 3.8.1.7

- NOTE -

1.

This Surveillance shall not be performed in MODE 1, 2, 3, or 4.

2.

Credit may be taken for unplanned events that satisfy this SR.

Verify each DG does not trip during and following a load rejection of 295 kW.

In accordance with the Surveillance Frequency Control Program R.E. Ginna Nuclear Power Plant 3.8.1-5 Amendment 150

AC Sources - MODES 1, 2, 3, and 4 3.8.1 SURVEILLANCE FREQUENCY SR 3.8.1.8

- NOTE -

1.

This Surveillance shall not be performed in MODE 1, 2, 3, or 4.

2.

Credit may be taken for unplanned events that satisfy this SR.

Verify each DG automatic trips are bypassed on an actual or simulated safety injection (SI) signal except:

a.

Engine overspeed; b.

Low lube oil pressure; and c.

Start failure (overcrank) relay.

In accordance with the Surveillance Frequency Control Program SR 3.8.1.9

- NOTE -

1.

All DG starts may be preceded by an engine prelube period.

2.

This Surveillance shall not be performed in MODE 1, 2, 3, or 4.

3.

Credit may be taken for unplanned events that satisfy this SR.

Verify on an actual or simulated loss of offsite power signal in conjunction with an actual or simulated SI actuation signal:

a.

De-energization of 480 V safeguards buses; b.

Load shedding from 480 V safeguards buses; and c.

DG auto-starts from standby condition and:

1.

energizes permanently connected loads, 2.

energizes auto-connected emergency loads through the load sequencer, and 3.

supplies permanently and auto-connected emergency loads for 5 minutes.

In accordance with the Surveillance Frequency Control Program R.E. Ginna Nuclear Power Plant 3.8.1-6 Amendment 150

DC Sources - MODES 1, 2, 3, and 4 3.8.4 3.8 ELECTRICAL POWER SYSTEMS 3.8.4 DC Sources - MODES 1, 2, 3, and 4 LCO 3.8.4 The Train A and Train B DC electrical power sources shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One DC electrical power source inoperable.

A.1 Restore DC electrical power source 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 B.

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

B.1 AND B.2 Be in MODE 3.

Be in MODE 5.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 36 hours C.

Both DC electrical power sources inoperable.

C.1 Enter LCO 3.0.3.

Immediately R.E. Ginna Nuclear Power Plant 3.8.4-1 Amendment 150

AC Instrument Bus Sources - MODES 1, 2, 3, and 4 3.8.7 3.8 ELECTRICAL POWER SYSTEMS 3.8.7 AC Instrument Bus Sources - MODES 1, 2, 3, and 4 LCO 3.8.7 The following AC instrument bus power sources shall be OPERABLE:

a.

Inverters for Instrument Buses A and C; and b.

Class 1E constant voltage transformer (CVT) for Instrument Bus B.

APPLICABILITY:

MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One inverter inoperable.

A.1 Power AC instrument bus 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months from its Class 1E or non-Class 1E CVT.

AND A.2 Power AC instrument bus 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months from its Class 1E CVT.

AND A.3 Restore inverter to 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 OPERABLE status.

B.

Class 1E CVT for AC Instrument Bus B inoperable.

B.1 AND B.2 Power AC Instrument Bus B from its non-Class 1E CVT.

Restore Class 1E CVT for AC Instrument Bus B to OPERABLE status.

2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months 7 days OR R.E. Ginna Nuclear Power Plant 3.8.7-1 Amendment 150

AC Instrument Bus Sources - MODES 1, 2, 3, and 4 3.8.7 CONDITION REQUIRED ACTION COMPLETION TIME

NOTE------

Not applicable if there is a loss of function.

In accordance with the Risk Informed Completion Time Program C.

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

C.1 Be in MODE 3.

AND C.2 Be in MODE 5.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 36 hours D.

Two or more required instrument bus sources inoperable.

D.1 Enter LCO 3.0.3.

Immediately SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.7.1 Verify correct static switch alignment to Instrument Bus A and C.

In accordance with the Surveillance Frequency Control Program SR 3.8.7.2 Verify correct Class 1E CVT alignment to Instrument Bus B.

In accordance with the Surveillance Frequency Control Program R.E. Ginna Nuclear Power Plant 3.8.7-2 Amendment 150

Distribution Systems - MODES 1, 2, 3, and 4 3.8.9 3.8 ELECTRICAL POWER SYSTEMS 3.8.9 Distribution Systems - MODES 1, 2, 3, and 4 LCO 3.8.9 Train A and Train B of the following electrical power distribution subsystems shall be OPERABLE:

a.

AC power; b.

AC instrument bus power; and c.

DC power.

APPLICABILITY:

MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One AC electrical power distribution train inoperable.

A.1 Restore AC electrical power distribution train 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 B.

One AC instrument bus electrical power distribution train inoperable.

B.1 Restore AC instrument bus electrical power distribution train to OPERABLE status.

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

NOTE------

Not applicable if there is a loss of function.

In accordance with the Risk Informed Completion Time Program R.E. Ginna Nuclear Power Plant 3.8.9-1 Amendment 150

Distribution Systems - MODES 1, 2, 3, and 4 3.8.9 CONDITION REQUIRED ACTION COMPLETION TIME C.

One DC electrical power distribution train inoperable.

C.1 Restore DC electrical power distribution train 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 D.

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

D.1 Be in MODE 3.

AND D.2 Be in MODE 5.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 36 hours E.

Two trains with inoperable electrical power distribution subsystems that result in a loss of safety function.

E.1 Enter LCO 3.0.3.

Immediately SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.9.1 Verify correct breaker alignments and voltage to required electrical power trains.

In accordance with the Surveillance Frequency Control Program R.E. Ginna Nuclear Power Plant 3.8.9-2 Amendment 150

Programs and Manuals 5.5 e.

The quantitative limits on unfiltered air inleakage into the CRE.

These limits shall be stated in a manner to allow direct comparison to the unfiltered air inleakage measured by the testing described in paragraph c. The unfiltered air inleakage limit for radiological challenges is the inleakage flow rate assumed in the licensing basis analyses of DBA consequences. Unfiltered air inleakage limits for hazardous chemicals must ensure that exposure of CRE occupants to these hazards will be within the assumptions in the licensing basis.

f.

The provisions of SR 3.0.2 are applicable to the Frequencies for assessing CRE habitability and determining CRE unfiltered inleakage as required by paragraph c.

5.5.17 Surveillance Frequency Control Program This program provides controls for the Surveillance Frequencies. The program shall ensure that Surveillance Requirements specified in the Technical Specifications are performed at intervals sufficient to assure the associated Limiting Conditions for Operation are met.

a.

The Surveillance Frequency Control Program shall contain a list of Frequencies of the Surveillance Requirements for which the Frequency is controlled by the program.

b.

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

c.

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

5.5.18 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 MODES 1 and 2; R.E. Ginna Nuclear Power Plant 5.5-13 Amendment 150

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.

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.

The risk assessment approaches and methods shall be acceptable to the NRC. The plant PRA shall be based on the as-built, as-operated, and maintained plant; and reflect the operating experience at the plant, as specified in Regulatory Guide 1.200, Revision 2. Methods to assess the risk from extending the Completion Times must be PRA methods used to support License Amendment No. [XXX], or other methods approved by the NRC for generic use; and any change in the PRA methods to assess risk that are outside these approval boundaries require prior NRC approval.

R.E. Ginna Nuclear Power Plant 5.5-14 Amendment 150

SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 150 TO RENEWED FACILITY OPERATING LICENSE NO. DPR-18 CONSTELLATION GENERATION COMPANY, LLC R. E. GINNA NUCLEAR POWER PLANT DOCKET NO. 50-244

1.0 INTRODUCTION

By application dated May 20, 2021 (Reference 1), Exelon Generation Company, LLC (on February 1, 2022, Exelon Generation Company, LLC was renamed Constellation Energy Generation, LLC) (the licensee) submitted a license amendment request (LAR) as supplemented by letters dated October 14, 2021 April 28, 2022, and June 9, 2022 (Agencywide Documents Access and Management System (ADAMS) Accession Nos. ML21140A324, ML21287A006, ML22118B143, and ML22160A411 respectively) for R.E. Ginna Nuclear Power Plant (Ginna). The amendment would revise technical specification (TS) requirements to permit the use of risk-informed completion times (RICTs) for actions to be taken when limiting conditions for operation (LCOs) are not met. The proposed changes are based on Technical Specifications Task Force (TSTF) Traveler TSTF-505, Revision 2, Provide Risk-Informed Extended Completion Times - RITSTF Initiative 4b, dated July 2, 2018, (Reference 2). 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 (Reference 3).

The licensee has proposed variations from the TS changes approved in TSTF-505, Revision 2, which are provided in Section 2.3 of the LAR and evaluated in Section 3.0 of this SE.

On August 25, 2021 (Reference 5), the NRC staff issued an audit plan that included the audit questions. The NRC staff participated in a regulatory audit during September 2021. The NRC staff performed the audit to ascertain the information needed to support its review of the application and develop requests for additional information, as needed. The licensee responded to the audit questions in supplements dated October 14, 2021, and April 28, 2022. The supplemental letters provided additional information that clarified the application, did not expand the scope of the application as originally noticed, and did not change NRC staffs original proposed no significant hazards consideration determination as published in the Federal Register on August 10, 2021 (86 FR 43686).

2.0 REGULATORY EVALUATION

Title 10 of the Federal Code of Regulations (10 CFR) Part 50 provides the general provisions for Domestic Licensing of Production and Utilization Facilities. The general provisions include but are not limited to establishing the regulatory requirements that a licensee must adhere to for the submittal of a license application. The NRC staff has identified the following applicable Sections within 10 CFR Part 50, along with the provision provided in 10 CFR Part 20 for the staffs review of a licensees application to adopt TSTF-505, Revision 2:

10 CFR 50.36(c)(2), and (c)(5), Technical Specifications 10 CFR 50.55a(h), Codes and Standards 10 CFR 50.65, Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants (i.e., the Maintenance Rule) 10 CFR Part 20, Standard for Protection Against Radiation NRC Regulatory Guides (RG) provide one way to ensure that the codified regulations continue to be met. The NRC staff considered the following guidance, along with 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.

RG 1.174, Revision 2, An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis.

RG 1.177, Revision 1, An Approach for Plant-Specific, Risk-Informed Decision-making:

Technical Specifications.

NUREG-1855, Revision 1, Guidance on the Treatment of Uncertainties Associated with PRAs [Probabilistic Risk Assessment] in Risk-Informed Decisionmaking.

NUREG-0800, Standard Review Plan [SRP] for the Review of Safety Analysis Reports for Nuclear Power Plants: LWR [light-water reactor] Edition, Chapter 19, Section 19.2, Review of Risk Information Used to Support Permanent Plant-Specific Changes to the Licensing Basis: General Guidance and Section 16.1, Risk-Informed Decision Making:

Technical Specifications.

NEI TR 06-09-A, Risk-Informed Technical Specifications Initiative 4b, Risk-Managed Technical Specifications (RMTS) Guidelines.. (The NRC staff issued a final model SE approving NEI 06-09 on May 17, 2007.)

The licensees submittal cites Revision 2 of RG 1.200 (Reference 6) and RG 1.174 (Reference 7), and Revision 1 of RG 1.177 (Reference 8). The RGs have been updated to Revision 3 of RG 1.200 (Reference 9) and 1.174, and Revision 2 for RG 1.177 (Reference 10). The updates do not include any technical changes that would impact the consistency with Nuclear Energy Institute (NEI) Topical Report (TR) 06-09-A (Reference 11), therefore the NRC staff finds the updated revisions to the RGs also applicable for use in the licensees adoption of TSTF-505, Revision 2.

Description of Risk-Informed Completion Time Program The TS LCOs are the lowest functional capability or performance levels of equipment required for safe operation of the facility. When an LCO is not met, the licensee must shut down the reactor or follow any Required Action (e.g., testing, maintenance, or repair activity) permitted by the TSs until the condition can be met. The Required 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 Required Action is a completion time (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 (i.e., shut down the reactor).

The licensees submittal requested approval to add a RICT program to the Administrative Controls Section of the TS, and modify selected CTs to permit extending the CTs, provided risk is assessed and managed as described in NEI TR 06-09-A. Consistent with Table 1 of TSTF-505, Rev. 2 for Conditions Requiring Additional Technical Justification NUREG-1431, Westinghouse STS (standard technical specifications), in Section 2.3 of the SE the licensee provided several plant-specific LCOs and associated Required Actions which Ginna proposed to be included in the RICT Program, along with additional justification. The NRC staffs review of these variations and the justification is provided in Section 3.1 of this SE.

The effect of the licensees 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 (D-I-D) 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.

For TS use and application:

Example 1.3-8, will be added to TS 1.3, CTs, 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 5.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-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 1.3-8. 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, Condition A is exited, and therefore, the Required Actions of Condition B may be terminated.

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 2, and the three-tiered approach outlined in Section C of RG 1.177, Revision 1. 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 defense in depth (D-I-D) 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 Staff Review Each of the key principles and tiers are addressed in NEI TR 06-09-A and approved in the final model safety evaluation issued by the NRC for TSTF-505, Revision 2. The industry guidance provides a methodology for extending existing CTs, and 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 RG 1.177 is discussed below.

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 Required 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 D-I-D remains 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 TR 06-09-A and TS 5.5.18. The RICT is limited to a maximum of 30 days (termed the back stop).

The typical CT is modified by the application of the RICT program as shown in the following example. The changed portion is indicated in italics.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One subsystem inoperable.

A.1 Restore subsystem to OPERABLE status.

7 days OR In accordance with the Risk Informed Completion Time Program In Attachments 1 and 2 and Enclosure 1 of 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, Rev. 2 for Ginna TS 3.6.2.C.3, TS 3.6.6.A.1, and 3.7.2.A in Section 2.3 in of the LAR the licensee included additional technical justification to demonstrate the acceptability for including these TS in the RICT program. The NRC staff reviewed the proposed changes to the TS, 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, only the required CT for the Required Actions are modified, such that 10 CFR 50.36(c)(2) will remain met. Based on the discussion provided above, the NRC staff finds that the TS program provided in Section 2.0 of this SE, LCOs, Required Actions, and CTs meet the first key principle of RG 1.174, and RG 1.177.

The NRC staff notes for TS 3.7.5. Condition D.1 the TS is explicit in that the requirement is for the auxiliary feedwater system (AFW) trains. In Section 10.5.1 of the Ginna UFSAR, the auxiliary feedwater system is described as consisting of a preferred AFW and a standby auxiliary feedwater system (SAFW). Therefore, if the SAFW trains are operable, then Condition D will not result in a loss of function, since the SAFW is an acceptable backup to the AFW system at Ginna.

Key Principle 2: Evaluation of Defense in Depth (D-I-D)

In RG 1.174, Revision 2, the NRC identified the following considerations used for evaluation of how the LB change is maintained for the D-I-D 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 common cause failures (CCFs).

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 prescribed in Attachment 2 of the LAR, as supplemented. For the TS LCOs, in and Enclosure 1 of 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 Ginna Nuclear Power Plants redundant or diverse means to mitigate accidents to ensure consistency with the plant LB requirements using the guidance prescribed in RG 1.174, RG 1.177, and TSTF-505, to ensure adequate D-I-D (for each of the functions) to operate the facility in the proposed manner (i.e., that the changes are consistent with the D-I-D criteria).

, Information Supporting Instrumentation Redundancy and Diversity, and of the LAR provided information supporting the Ginna evaluation of the redundancy, diversity, and D-I-D for each TS LCO and TS Required Action as it related to I&C, electrical, and power systems. The NRC confirmed that for the following TS LCOs, the above D-I-D criteria were applicable except for the criteria for maintaining multiple fission product barriers.

TS 3.3.1.1, Reactor Protection System Instrumentation [I&C specific]

TS 3.3.2.2, Feedwater System and Main Turbine High Water Level Trip Instrumentation

[I&C specific]

TS 3.3.4.2, Anticipated Transient Without Scram Recirculation Pump Trip Instrumentation [I&C specific]

TS 3.3.5.1, Emergency Core Cooling System Instrumentation [I&C specific]

TS 3.3.5.3, Reactor Core Isolation Cooling System Instrumentation [I&C specific]

TS 3.3.6.1, Primary Containment Isolation Instrumentation [I&C specific]

TS 3.3.8.1, Loss of Power (LOP) Instrumentation [I&C specific]

TS 3.3.4, LOP Diesel Generator Start Instrumentation [electrical specific]

TS 3.8.1, AC Sources - Operating [power-related]

TS 3.8.4, DC Sources - MODES 1, 2, 3, and 4 [power-related]

TS 3.8.7, AC Instrument Bus Sources - MODES 1, 2, 3, and 4 [electrical-related]

TS 3.8.9, Distribution Systems - MODES 1, 2, 3, and 4 [power-related]

For the TS LCOs specific to I&C, 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) (Reference 12) sections, and as reflected in of the LAR for each I&C LCO above. The NRC staff verified, that in accordance with the Ginna UFSAR and equipment and actions credited in Attachment 5 of the LAR, 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 NRC staff concludes that there is sufficient redundancy, diversity, and D-I-D, to protect against CCFs and potential single failure for the Ginna instrumentation systems evaluated in LAR Attachment 5 during a RICT. There is at least one diverse means specified by the licensee for initiating mitigating action for each accident event, thus providing D-I-D against a failure of instrumentation during the RICT for each TS LCO.

The D-I-D 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.

For the TS LCOs specific to electrical and power systems, the Ginna UFSAR states that the plant is designed such that the safety functions are maintained assuming a single failure within the electrical power system. Single-failure requirements are typically suspended for the time that a plant is not meeting an LCO (i.e., in an ACTION statement). The staff reviewed the information the licensee provided in the LAR as supplemented for the proposed TS LCOs and TS Bases, and the UFSAR to verify the capability of the affected electrical power systems to perform their safety functions (assuming no additional failures) is maintained. The staff verified that the design success criteria for the affected TS LCO reflect the redundant or absolute minimum electrical power source/subsystem required to be operable to support the safety functions necessary to mitigate postulated design-basis accidents (DBAs), safely shutdown the reactor, and maintain the reactor in a safe shutdown condition. In addition, the staff reviewed the risk management action (RMA) examples which provide reasonable assurance that the appropriate RMAs will be implemented to monitor and control risk. The NRC staff finds that the intent of the plants design criteria (e.g., safety functions) applicable to the electrical and power related TS LCOs provided above are maintained.

The NRC staff notes that while in a TS LCO condition, the redundancy of the function will be temporarily relaxed and, consequently, the system reliability will be degraded accordingly. The NRC staff examined the design information from the Ginna UFSAR and the risk informed TS LCO conditions for the affected safety functions. Based on this information, the NRC staff confirmed that under any given DBA evaluated in the Ginna UFSAR, the affected protective features maintain adequate D-I-D.

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

The NRC staff reviewed all TS LCOs proposed by the licensee in Attachment 2 of the LAR, as supplemented and concludes that the proposed changes do not alter the ways in which the Ginna systems fail, do not introduce new CCF modes, and the system independence is maintained. The NRC staff finds that some proposed changes reduce the level of redundancy of the affected systems, and this reduction may reduce the level of defense against some CCFs; however, such reductions in redundancy and defense against CCFs are acceptable due to existing diverse means available to maintain adequate D-I-D against a potential single failure during a RICT. The NRC staff finds that extending the selected CTs with the RICT program following loss of redundancy, but maintaining the capability of the system to perform its safety function, is an acceptable reduction in D-I-D during the proposed RICT period provided that the licensee identifies and implements compensatory measures in accordance with the RICT program during the extended CT.

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

Key Principle 3: Evaluation of Safety Margins Paragraph 50.55a(h) of 10 CFR (Codes and Standards) requires, in part, that protection systems of nuclear power reactors of all types must meet the requirements specified in this paragraph. Section 2.2.2 of RG 1.177 states, in part, that sufficient safety margins are maintained when:

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

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

The licensee is not proposing in this application to change any quality standard, material, or operating specification. In the LAR, the licensee proposed to add a new program, Risk Informed Completion Time Program, in Section 5.0, Administrative Controls, of the TSs, which would require adherence to NEI 06-09-A. NEI 06-09-A, Condition 2 in part, stipulates that

[for] the TS LCOs and action requirements to which the RMTS will apply, the LAR will provide justification with comparison of the TS functions to the PRA modeled functions of the SSCs subject to those LCO actionsor an appropriate disposition or programmatic restriction will be provided. In its supplemental letter dated April 28, 2022, the licensee provided additional information regarding the application of a RICT for the TS Required Actions 3.4.11.B.3 and 3.4.11.C.2. In support of applying a RICT for TS LCO 3.4.11.B and TS 3.4.11.C the licensee added conditions that require verifying that at least one train of PORV and PORV block valve is operable prior to applying RMTS to a single inoperable PORV or PORV block valve. The proposed conditions for applying RMTS are consistent with the condition assumed in the analysis of record (AOR). Specifically, the AOR for a Steam Generator Tube Ruptures (SGTR) event assumes (on page 174 of the UFSAR, Section 15.6.3.3.3.1) that one train of Power-Operated Relief Valve (PORV) and PORV block valve is operable to reduce pressure in the event the normal pressurizer spray valves are not available. The licensee confirmed that the proposed conditions are reflected in Ginnas Emergency Operating Procedure (EOP) E-3, Steam Generator Tube Rupture, where Step 19.b requires verifying at least one PORV is available for depressurization. Additionally, one block valve is verified operable prior to using a PORV for depressurization to ensure the flow path can be isolated should the PORV fail closed.

Furthermore, the licensee added a NOTE to ensure the application of RICT is not applicable if there is a loss of function, in accordance with the RICT program. The NRC staffs evaluation of the TS markup for the proposed changes is provided under Key Principle 1 of this SE.

Based on the above, for TS 3.4.11.B.3 and TS 3.4.11.C.2, the NRC staff finds that the licensee included appropriate programmatic restrictions consistent NEI 06-09-A, and the assumptions used in the AOR for the SGTR are consistent with the TS requirements and are adequately reflected in the Ginna EOP. The modified portions of TS 3.4.11.B.3 and TS 3.4.11.C.2 are acceptable. Therefore, the NRC staff concludes that the proposed TS changes provide reasonable assurance that the safety function of the PORV and PORV block valve would be maintained and a LOF would not occur when applying a RICT.

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 RICT would allow the licensee to have design-basis equipment out of service longer than the current TS allow any increase in unavailability is expected to be insignificant and is addressed by the consideration of the single failure criterion in the design-basis analyses. The 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 probabilistic risk assessment (PRA) functionality is determined for the inoperable train which would result in an increased CT. Credit for PRA functionality, as described in NEI 06-09-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 Ginna remains applicable and unchanged, sufficient safety margins would be maintained during the extended CT, and 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 meet the third key principle of RG 1.177.

Key Principle 4: Change in Risk Consistent with the Safety Goal Policy Statement 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 Chapter 16.1 of the SRP (Reference 13), RG 1.177, Revision 1, and RG 1.174, Revision 2. 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 (ICLERP); 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 will be small and consistent with the intent of the Commissions Safety Goal Policy Statement. In addition, the NRC staff evaluated the licensees proposed changes against the three-tiered approach in RG 1.177, Revision 1, for the licensees evaluation of the risk associated with a proposed TS CT change. The results of the staffs review are discussed below.

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

Enclosures 2 and 4 of the LAR identified the following modeled hazards and alternate methodologies the licensee proposed to be used in the Ginna RICT program to assess the risk contribution for extending the CT of a TS LCO.

Internal Events PRA model (includes internal floods)

Internal Fire Events PRA model Seismic Hazard: CDF penalty of 3.4E-06 per year, and a LERF penalty of 1.9E-06 per year Extreme Winds and Tornado Hazards: Configuration-specific CDF and LERF penalties Other External Hazards: screened out from RICT program based on Appendix 6-A of the American Society of Mechanical Engineers (ASME)/American Nuclear Society (ANS)

RA-Sa-2009 PRA Standard Evaluation of Modeled PRAs For the modeled PRAs, which includes the internal events PRA (IEPRA) and fire PRA (FPRA) in of the LAR, the licensee confirmed that the PRA models had been peer reviewed using the ASME/ANS RA-Sc -2007 PRA Standard for the IEPRA, and ASME/ANS RA-Sa -2009 PRA Standard for the FPRA, as endorsed by RG 1.200, Revision 1 and 2, respectively. For the open facts and observations (F&Os) resulting in these peer reviews the licensee stated that closure of the F&Os was performed using an independent assessment process. The NRC staff confirmed that the licensee performed closure of the F&Os consistent with Appendix X to NEI 05-04. 07-12, and 12-13, as endorsed in RG 1.200, Revision 3. The NRC staff evaluated the two remaining open F&Os, along with their dispositions. In Enclosure 9 of the LAR, the licensee provided a brief discussion and list of the key assumptions and sources of uncertainty, along with treatment for the application of TSTF-505. In its supplement, Ginna confirmed that the IEPRA and FPRA models credit installed and portable equipment used as part of the FLEX strategy.

The NRC staff concluded that the licensees credit for FLEX equipment in the TSTF-505 application is appropriate because the licensee used consensus human reliability analysis methodologies and practices, acceptable failures rates, and performed sensitivity studies to assess the impact on the TSTF-505 application. The NRC staff notes that Ginna confirmed for the equipment credited in the adoption of NFPA-805 that is also used to mitigate non-fire events, and that the use of this equipment is directly referenced in the emergency response procedures, thereby ensuring this equipment can be used for all hazards.

The NRC staff reviewed the PRA models peer review history provided by the licensee in of the LAR, as supplemented. The licensee adequately applied the guidance for establishing PRA technical acceptability for the aforementioned models. The NRC staff further considered the key assumptions and sources of uncertainty identified by the licensee, proposed use of surrogates in the PRA models for specific TS functions, and credit for FLEX. Therefore, the NRC staff finds the Ginna scope, and acceptability of the modeled IEPRA and FPRA to be commensurate with the RICT application for use in the integrated decision-making process are consistent with RG 1.174.

Evaluation of Seismic Hazard The licensees approach for including the seismic risk contribution in the RICT calculation is to add a penalty seismic CDF and a penalty seismic LERF to each RICT calculation. The proposed bounding seismic CDF estimate is based on using the plant-specific seismic hazard curves developed in response to the Near-Term Task Force recommendation 2.1 (Reference 15), and a plant-level high confidence of low probability of failure (HCLPF) capacity of 0.20g 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 3.4E-06 per year. The staff finds that the method to determine the baseline seismic CDF acceptable because it is consistent with the approach used in GI-199. The NRC staff verified the input parameters identified by the licensee to confirm the proposed bounding seismic CDF estimate.

Concerning the proposed bounding seismic LERF estimate, the licensee explains in the LAR that an estimate of the seismic LERF is obtained by verifying the estimated seismic CDF (as described above) with a limiting fragility for containment integrity, also assumed to be 0.2g PGA HCLPF. The calculated seismic LERF is 1.9E-06 per year. NRC staff finds that the licensees approach to determining a seismic LERF estimate to be acceptable because use of a 0.2g PGA HCLPF as the limiting fragility for containment integrity is conservative.

The licensee addressed the incremental risk associated with seismic-induced LOOP in its supplement. A seismic LOOP frequency across the entire hazard interval is 1.3E-05 per year.

This is about 0.7% of the total internal events 24-hour non-recovered LOOP frequency of 1.9E-03 per year already addressed in the IEPRA. The NRC staff evaluated the licensees analysis and finds it adequately addresses the impact of seismically induced LOOP on risk and that its exclusion from the non-recovered LOOP frequency has an insignificant impact on the RICT program calculations.

The NRC staff finds that, during RICTs for structures, systems, and components (SSCs) credited in the design basis to mitigate seismic events, the licensee's proposed methodology captures the risk associated with seismically induced failures of redundant SSCs because such SSCs are assumed to be fully correlated. In summary, the NRC staff finds the licensees proposal to use the seismic CDF contributions of 3.4E-06 per year, and a seismic LERF contribution of 1.9E-06 per year to be acceptable for the licensees RICT Program for Ginna, because (1) the licensee used the most current site-specific seismic hazard information for Ginna, (2) the licensee used an acceptably low plant level HCLPF value of 0.2g and a combined beta factor of 0.4 consistent with the information for Ginna in the GI-199 evaluation, (3) the licensee determined a seismic LERF penalty based on its estimate of seismic CDF combined with using a containment integrity fragility of 0.2g PGA HCLPF, and (4) adding baseline seismic risk to RICT calculations, which assumes the fully correlated failures, is conservative for SSCs credited in seismic events, while any potential for non-conservative results for SSCs that are not credited in seismic events is small or nonexistent.

Evaluation of Extreme Winds and Tornado Hazards Section 4 of Enclosure 4 to the LAR discusses the licensees evaluation of the extreme wind and tornado impact on this application. The licensee concluded that all non-missile high wind hazards can be screened from consideration for the TSTF-505 application, based on EXT-C1 Criterion C of ASME/ANS RA-Sa-2009, which is screening criterion PS4 (i.e., Bounding mean CDF is < 1E-06 per year). The licensee also concluded that tornado missile hazards can be screened from consideration for the TSTF-505 application, based on EXT-C1 Criterion B of ASME/ANS RA-Sa-2009, which is screening criterion PS3 (i.e., Design basis event mean frequency is < 1E-05 per year and the mean conditional core damage probability is < 0.1).

The licensee further states that the CDF due to tornado missiles for certain maintenance configurations is determined to be above 1E-06/year, requiring a high winds penalty to be established for the TSTF-505 calculations. For most plant configurations associated with LCOs encompassed in the RICT program, the licensee proposed a CDF penalty of 1E-05 per year and LERF penalty of 2E-06 per year. In addition, the licensee proposed a different CDF penalty of 7E-5 per year specifically for LCOs, 3.7.5F and a different LERF penalty of 5E-6 per year specifically for LCOs 3.6.2.C, and 3.6.3.E.

The NRC staff reviewed the licensees evaluation provided in Section 4 of Enclosure 4, as supplemented and finds the licensees determination of CDF and LERF high wind penalties acceptable because (1) the penalties are based on the results of a high wind risk assessment that uses the IEPRA as the foundation and a number of simplifying and conservative assumptions, (2) all LCOs encompassed by the RICT program were evaluated and the results applied conservatively to determine a high wind penalty on a plant configuration basis, and (3) the high wind penalties are conservatively applied using total high wind CDF and LERF values as the CDF and LERF values in the RICT calculations.

Furthermore, the NRC staff finds that the licensees consideration of the risk from extreme winds and tornadoes for the RICT program is acceptable because conservatively estimated LCO-specific high wind penalty factors will be added to the delta-risk of all RICT calculations.

Evaluation of Other External Hazards Besides seismic, and extreme winds and tornado hazards discussed above, the licensee confirmed that other external hazards for Ginna have insignificant contribution and proposed these hazards be screened out from the RICT program. For external floods, the licensees conclusions regarding insignificant risk contribution are based on the flood hazard reevaluation report (FHRR) and flood Focused Evaluation report for Ginna (Reference 16) and (Reference 17). For ice cover hazard, the licensee explained that the plant is designed for an ice cover event as it pertains to the water intake screens and that the principal effect of ice accumulation would be to cause a LOOP power event, which is addressed in the IEPRA model.

The licensee provided its assessment of other external hazard risk for the RICT Program in LAR. The hazards assessed in LAR are those identified for consideration in non-mandatory Appendix 6-A of the ASME/ANS PRA Standard and provides a guide for identification of most of the possible external events for a plant site.

The NRC staff reviewed the information in the submittal and supplement, and finds that the contributions from external flooding, ice cover hazard, and 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. Furthermore, the NRC staff finds that plant procedures exist to ensure that flood protection features will be available during RICTs to manage the external flooding risk in the RICT Program. For all other external hazards, the NRC staff notes that the preliminary screening criteria and progressive screening criteria used and presented in LAR Table E4-5 are the same criteria that were presented in supporting requirements for screening external hazards EXT-B1 and EXT-C1 of the ASME/ANS PRA Standard.

Application of PRA Models, Results and Insights in the RICT Program The Ginna base PRA models that have been determined to be acceptable 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. In the LAR, the licensee provided the information needed to support the requested LCO actions proposed for the Ginna RICT program consistent with all the Limitations and Conditions prescribed in Section 4.0 of NEI 06-09-A.

The NRC staff did not identify any insufficiencies in the licensees information or the CRMP tool as described in the Enclosure 8 of the LAR. Furthermore, as stated in Attachment 7 of the LAR, the Ginna design criteria of the applicable systems are maintained [t]he change[s] requested in the LAR [do] not physically change the applicable systems.]. The NRC staff finds that the Ginna 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 NRC staff concludes that the proposed application of the Ginna RICT program is appropriate for use in the adoption of TSTF-505 for performing RICT calculations.

The licensee provided in Enclosure 5 of the submittal the estimated total CDF and LERF to of the base PRA models to demonstrate that Ginna Nuclear Plant meets 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 TS 5.5.18. The estimated current total CDF and LERF for Ginna PRAs meet the RG 1.174, Revision 3 guidelines, therefore, the NRC staff concludes 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.

Based on the above, the NRC staff finds that the licensee has satisfied the intent of tier 1 in RG 1.177, Revision 1 and RG 1.174, Revision 2, for determining the PRA acceptable, and that the scope of the PRA models (i.e., IEPRA, FPRA) evaluated PRA hazards, external hazards, and seismic methodology is appropriate for this application.

Tier 2: Avoidance of Risk-Significant Plant Configurations As prescribed in RG 1.177, Revision 1, the second tier evaluates the capability of the licensee to identify 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. In Section 2 of Enclosure 10 of the LAR the licensee confirmed that the risk thresholds associated with 10 CFR 50.65(a)(4) will be coordinated with the RICT limits. Enclosure 12 of the LAR identifies three kinds of RMAs (i.e., actions to provide increased risk awareness and control, actions to reduce the duration of maintenance activities, and actions to minimize the magnitude of the risk increase). The LAR also explains that RMAs will be implemented, in accordance with current plant procedures, no later than the time at which the 1E-06 incremental core damage probability or 1E-07 incremental ICLERP threshold is reached and under emergent conditions when the instantaneous CDF and LERF thresholds are exceeded.

The NRC staff concludes that the RICT program requirements, that include limits established for entry into a RICT, and implementation of RMAs are consistent with NEI 06-09-A. Therefore, the proposed changes are consistent with the intent of Tier 2 in RG 1.177, Revision 1.

Tier 3: Risk--Informed Configuration Risk Management The third tier stipulates 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 based on the underlying PRA models. The CRMP is then used to evaluate configuration-specific risk for planned activities associated with the RMTS extended CT, as well as emergent conditions which 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.

Paragraph 50.36(c)(5) of 10 CFR identifies administrative controls as the provisions relating to organization and management, procedures, [thereby] assuring operation of the facility in a safe manner. In Enclosure 8 of the submittal, Attributes of the Real-Time Risk Model, the licensee confirmed that future changes made to the baseline PRA models and changes made to the online model (i.e., CRMP) are controlled and documented by plant procedures. Enclosure 10 of the LAR, provided the attributes that the licensees RICT program procedures will address, which are consistent with NEI TR 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).

Based on the licensees incorporation of NEI 06-09-A in the TS, as discussed in LAR and its 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, the NRC staff finds the licensees Tier 3 program is acceptable and supports the proposed implementation of the RICT program.

The licensee has demonstrated the technical acceptability and scope of its PRA models and alternative methods, including consideration of the impact of seismic events, extreme winds and tornado hazards, and other external 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.

Key Principle 5: Performance Measurement Strategies - Implementation and Monitoring RG 1.177, Revision 1 and RG 1.174, Revision 3, establish the need for an implementation and monitoring program to ensure that extensions to TS CTs do not degrade operational safety over time and that no adverse degradation occurs due to unanticipated degradation or common cause mechanisms. Enclosure 11 of the January 31, 2020, submittal, states that 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.

Furthermore, in Enclosure 11 of the LAR, the licensee confirmed that the cumulative risk is calculated at least every refueling cycle, but the recalculation period does not exceed 24 months, which 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) the RICT program will monitor the average annual cumulative risk increase as described in NEI 06-09-A, thereby ensuring the program, as implemented, continues to meet 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.

4.0 CHANGES TO THE OPERATING LICENSE In its letter dated June 9, 2022 (ADAMS Accession No. ML21160A411), the licensee proposed the addition of the following condition to the Renewed Facility Operating License of Ginna to document the NRCs approval of the use of Risk-Informed Completion Times TSTF 505, Revision 2, Provide Risk Informed Extended Completion Times RITSTF Initiative 4b Constellation Energy Generation, LLC is approved to implement TSTF-505, Revision 2, modifying the Technical Specification requirements related to Completion Times (CT) for Required Actions to provide the option to calculate a longer, Risk-Informed CT (RICT). The methodology for using the new Risk-Informed Completion Time Program is described in NEI 06-09-A, Risk-Informed Technical Specifications Initiative 4b, Risk-Managed Technical Specifications (RMTS)

Guidelines, Revision 0, which was approved by the NRC on May 17, 2007.

Constellation Energy Generation, LLC will complete the implementation items listed in of Exelon Letter to the NRC dated May 20, 2021, prior to implementation of the RICT Program. All issues identified in the attachment will be addressed and any associated changes will be made, focused-scope peer reviews will be performed on changes that are PRA upgrades as defined in the PRA standard (ASME/ANS RA-Sa -2009, as endorsed by RG 1.200, Revision 2), and any findings will be resolved and reflected in the PRA of record prior to the implementation of the RICT Program.

The NRC staff finds that the proposed license condition is acceptable because it explicitly states that prior to implementation, the Ginna 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 Commissions regulations, the staff notified the New York State official on April 28, 2022, of the proposed issuance of the amendments. The State official had no comments.

6.0 ENVIRONMENTAL CONSIDERATION

The amendments change requirements with respect to the installation or use of facility components located within the restricted area as defined in 10 CFR Part 20 or change inspections or surveillance requirements. 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, which was published in the Federal Register on August 10. 2021 (86 FR 43686) that the amendments involve no significant hazards consideration, and there has been no public comment on such finding. Accordingly, the amendments meet the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9) and (10). 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 NRC staff has evaluated the proposed changes against each of the five key principles in RG 1.177 and RG 1.174, including the variations from the approved TSTF-505 discussed in Section 3.0 of this SE. The NRC 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, implementation items, and associated guidance, is acceptable to assure that the Commissions regulations continue to be met.

Based on the considerations discussed above, the NRC staff concludes 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.

REFERENCES 1 Gudger, David, Exelon Generation, letter to U.S. Nuclear Regulatory Commission, "License Amendment Request to Revise Technical Specifications to Adopt Risk Informed Completion TImes TSTF-505, Revision 2, "Provide Risk-Informed Extended Completion Times -

RITSTS Initiative 4b.," dated May 20, 2021 (ADAMS Accession No. ML21140A324).

2 U.S. Nuclear Regulatory Commission, "TSTF-505, Revision 2, TSTF Comments on Draft Safety Evaluation for Traveler TSTF-505, Provide Risk-Informed Extended Completion Times and Submittal of TSTF-505, Revision 2," dated July 2, 2018 (ADAMS Package Accession No. ML18183A493).

3 U.S. Nuclear Regulatory Commission, "Final Revised Model Safety Evaluation of Traveler TSTF-505, Revision 2, Provide Risk Informed Extended Completion Times - RITSTF Initiative 4B," TSTF-505, Revision 2, dated November 21, 2018 (ADAMS Package Accession No. ML18269A041).

4 Grudger, David, T., Exelon Generation, letter to U.S. Nuclear Regulatory Commission, "Supplemental Information No. 1 for R.E. Ginna Nuclear Power Plant to Adopt TSTF-505, "Provide Risk-Informed Extended CTs-RITSTF Initiative 4b," Revision 2 and 10 CFR 50.69, Risk-Informed Categorization and Treatment of SSCs for Nuclear Power Reactors," dated October 14, 2021 (ADAMS Accesion No. ML21287A006).

5 Sreenivas, V., U.S. Nuclear Regulatory Commission, letter to Exelon Generation Company, LLC, "Ginna, Units 1 - Regulatory Audit Plan Regarding License Amendment Requests to Adopt 10 CFR 50.69 and Permit Use of Risk-Informed Completion Times in Accordance with TSTF-505, Revision 2," dated MONTH XX, 2022 (ADAMS Accession No. ML21222A114).

`6 U.S. Nuclear Regulatory Commission, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities," RG 1.200, Revision 2, dated March 2009 (ADAMS Accession No. ML090410014).

7 U.S. Nuclear Regulatory Commission, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis,"

RG 1.174, Revision 2, dated May 2011 (ADAMS Accession No. ML100910006).

8 U.S. Nuclear Regulatory Commission, "An Approach for Plant-Specific, Risk-Informed Decisionmaking: Technical Specifications," RG 1.177, Revision 1, dated May 2011 (ADAMS Accession No. ML100910008).

9 U.S. Nuclear Regulatory Commission, "RG 1.200, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities,""

Revision 3, December 2020 (ADAMS Accession No. ML202388871),.

10 U.S. Nuclear Regulatory Commission, Regulatory Guide 1.177, Revision 2, "Plant-Specific, Risk-Informed Decisionmaking: Technical Specifications," Issue Date: January 2021 (ADAMS Accession No. ML20164A034).

11 Nuclear Energy Institute, "Risk-Informed Technical Specifications Initiative 4b: Risk-Managed Technical Specification (RMTS)," Topical Report NEI 06-09, Revision 0-A, dated October 2012 (ADAMS Package Accession No. ML122860402).

12 Exelon Generation Company, LLC, "R.E. Ginna Nuclear Plant (Ginna) Updated Final Safety Analysis Report," UFSAR Revision 28, dated November 2018 (ADAMS Package Accession No. ML20339A309).

13 U.S. Nuclear Regulatory Commission, "Standard Reveiw Plan for the Review of Safety Analysis Reports for Nuclear Power Plants, Risk-Informed Decision Making: Technical Specifications," NUREG-0800, Chapter 16.1, dated March 2007 (ADAMS Accession No. ML070380228).

14 Andersen, Victoria, Nuclear Energy Institute, letter to Rosenberg, Stacey, U.S. Nuclear Regulatory Commission, "Final Revision of Appendix X to NEI 05-04/07-12/12-16, Close-Out of Facts and Observations," NEI 05-04/07-12/12-16, dated February 21, 2017 (ADAMS Package Accession No. ML17086A431).

15 Kaegi, G.T. Exelon Generation Co. LLC to U.S. NRC DOcument Control Desk, "

Subject:

LaSalle Co. Station, Units 1 and 2 Seismic Hazard and Screening Report (Centroal and Eastern U.S. (CEUS) SItes), Response to NRC Request for Information Pursuant to 10 CFR 50.54(f) Regarding Recommendation 2.1 of the Near Tearm Task Force Review," March 31, 2014 (ADAMS Accession No. ML14091A013).

16 Korsnick, Mary G., Exelon Generation Company to U.S. NRC Document Control Desk, "R.E. Ginna Nuclear Power PLant, RFOL No. DPR-18, Docket No. 50-244, "Flood Hazard Reevaluation Report Pursuant to 10 CFR 50.54(f) Regarding the Fukushima Near-Term Task Force Recommendation 2.1: Flooding," dated March 11, 2015 (ADAMS Accession No. ML15072A009).

17 Exelon Generation Company to U.S. NRC Document Control Desk, "R.E. Ginna Nuclear Power Plant, RFOL Do. DPR-18, Docket No. 50-244, "Request for Information Enclosure 2, Recommendation 2.1 Flooding, Required response 3, Flooding Focused Evaluation Summary Submittal," dated March 10, 2017 (ADAMS Accession No. ML17069A004).

Principal Contributors: A. Brown, NRR/APLA J. Circle, NRR/APLA J. Evans NRR/APLA M. Valentin, NRR/APLC D. Wu, NRR/APLC N. Carte, NRR/EICB M. Ling, NRR/EICB V. Goel, NRR/EEEB J. Wilson, NRR/STSB A. Russell, NRR/STSB S. Summer, NRR/SNSB A. Stubbs, NRR/SCPB Date: June 21, 2022

ML22119A094

by memorandum OFFICE NRR/DORL/LPL1/PM NRR/DORL/LPL1/LA NRR/DRA/APLC/BC NRR/DRA/APLA/BC NAME VSreenivas KZeleznock SRosenberg RPascarelli DATE 04/29/2022 05/04/2022 04/08/2022 04/08/2022 OFFICE NRR/DEX/EEEB/BC NRR/DEX/EICB/BC NRR/DSS/STSB/BC NRR/DSS/SCPB/BC NAME MWendell MWaters VCusumano BWittick DATE 04/08/2022 04/08/2022 04/08/2022 04/06/2022 OFFICE NRR/DSS/SNSB/BC OGC/NLO NRR/DORL/LPL1/BC NRR/DORL/LPL1/PM NAME SKrepel STurk JDanna VSreenivas DATE 04/25/2022 05/25/2022 06/21/2022 06/21/2022

v t e Letter Sequence Approval
EPID:L-2021-LLA-0091, TSTF-505, TSTF-505 (Approved, Closed)
Initiation Request, Request, Request Acceptance, Acceptance Supplement, Supplement, Supplement, Supplement Administration Questions Answers Results Approval, Approval, Approval Other: ML21222A114
MONTHYEAR2022-04-28 [Table View]

ML22119A094

Text

SUBJECT:

Dear Mr. 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

Subject:

Navigation menu

Search