Text

Issuance of Amendment No. 213 Revision to Technical Specifications to Adopt TSTF 505, Revision 2, Provide Risk-Informed Extended Completion Times – RITSTF Initiative 4b
	ML24081A007
Person / Time
Site:	River Bend
Issue date:	05/16/2024
From:	James Drake; NRC/NRR/DORL/LPL4
To:	; Entergy Operations
References
	EPID L-2023-LLA-0037
	Download: ML24081A007 (1)
	v • d • e

May 16, 2024

Vice President, Operations Entergy Operations, Inc.

River Bend Station 5485 US Highway 61 St. Francisville, LA 70775

SUBJECT:

RIVER BEND STATION, UNIT 1 - ISSUANCE OF AMENDMENT NO. 213 RE: REVISION TO TECHNICAL SPECIFICATIONS TO ADOPT TSTF-505, REVISION 2, PROVIDE RISK-INFORMED EXTENDED COMPLETION TIMES - RITSTF INITIATIVE 4b (EPID L-2023-LLA-0037)

Dear Vice President,

Operations:

The U.S. Nuclear Regulatory Commission (NRC, the Commission) has issued the enclosed Amendment No 213 to Renewed Facility Operating License No. NPF-47 for the River Bend Station, Unit 1 (River Bend). The amendment consists of changes to the Technical Specifications (TSs) in response to your application dated February 27, 2023, as supplemented by letter dated January 12, 2024.

The amendment revises the River Bend TSs to permit the use of risk-informed completion times for actions to be taken when limiting conditions for operation are not met.

The changes are based on Technical Specifications Task Force (TSTF) Traveler TSTF-505, Revision 2, Provide Risk-Informed Extended Completion Times - RITSTF [Risk-Informed TSTF] Initiative 4b, dated July 2, 2018. The NRC staff issued a final model safety evaluation approving TSTF-505, Revision 2 on November 21, 2018.

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

Sincerely,

/RA/

Jason J. Drake, Project Manager Plant Licensing Branch IV Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Docket No. 50-458

Enclosures:

1. Amendment 213 to NPF-47

2. Safety Evaluation

cc: Listserv

ENTERGY LOUISIANA, LLC

AND

ENTERGY OPERATIONS, INC.

DOCKET NO. 50-458

RIVER BEND STATION, UNIT 1

AMENDMENT TO RENEWED FACI LITY OPERATING LICENSE

Amendment No. 213 Renewed License No. NPF-47

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

A. The application for amendment by Entergy Operations, Inc. (EOI, the licensee),

dated February 27, 2023, as supplemented by letter dated January 12, 2024, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commissions rules and regulations set forth in 10 CFR Chapter I;

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

C. There is reasonable assurance (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commissions regulations;

D. The issuance of this amendment will not be inimical to the common defense and security or to the health and safety of the public; and

E. The issuance of this amendment is in accordance with 10 CFR Part 51 of the Commissions regulations and all applicable requirements have been satisfied.

Enclosure 1

- 2 -

2. Accordingly, the license is amended by changes to the Technical Specifications as indicated in the attachment to this license amendment, and paragraph 2.C.(2) of Renewed Facility Operating License No. NPF-47 is hereby amended to read as follows:

(2) Technical Specifications and Environmental Protection Plan

The Technical Specifications contained in Appendix A, as revised through Amendment No. 213 and the Environmental Protection Plan contained in Appendix B, are hereby incorporated in the renewed license. EOI shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

3. The license amendment is effective as of its date of issuance and shall be implemented within 180 days from the date of issuance. Implementation of the amendment shall also include the completion of the Attachment 6, Table A6-1, RICT Program PRA Implementation Items.

FOR THE NUCLEAR REGULATORY COMMISSION

Jennivine K. Rankin, Chief Plant Licensing Branch IV Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Attachment:

Changes to Renewed Facility Operating License No. NPF-47 and the Technical Specifications

Date of Issuance: May 16, 2024 ATTACHMENT TO LICENSE AMENDMENT NO. 213

RENEWED FACILITY OPERATING LICENSE NO. NPF-47

RIVER BEND STATION, UNIT 1

DOCKET NO. 50-458

Replace the following pages of Renewed Facility Operating License No. NPF-47 and the Appendix A, Technical Specifications, with the attached revised pages. The revised pages are identified by Amendment number and contain marginal lines indicating the areas of change.

Renewed Facility Operating License

Remove Insert

Technical Specifications

Remove Insert 1.0-23 1.0-23

--- 1.0-23a 3.1-20 3.1-20 3.3-1 3.3-1 3.3-2 3.3-2

--- 3.3-2a 3.3-25 3.3-25 3.3-26 3.3-26 3.3-29 3.3-29 3.3-33 3.3-33 3.3-34 3.3-34 3.3-35 3.3-35 3.3-36 3.3-36

--- 3.3-36a 3.3-37 3.3-37 3.3-44 3.3-44 3.3-45 3.3-45 3.3-48 3.3-48 3.3-49 3.3-49 3.3-62 3.3-62 3.3-63 3.3-63 3.3-66 3.3-66 3.3-72 3.3-72 3.5-1 3.5-1 3.5-2 3.5-2 3.5-2a 3.5-2a 3.5-10 3.5-10 3.6-6 3.6-6

Technical Specifications (continued)

Remove Insert 3.6-10 3.6-10 3.6-11 3.6-11 3.6-13 3.6-13 3.6-14 3.6-14 3.6-23 3.6-23 3.6-25 3.6-25 3.6-37 3.6-37 3.6-65 3.6-65 3.6-67 3.6-67 3.7-1 3.7-1 3.7-2 3.7-2 3.7-16 3.7-16 3.8-2 3.8-2 3.8-2a 3.8-2a 3.8-3 3.8-3

--- 3.8-3a 3.8-4 3.8-4

--- 3.8-4a 3.8-24 3.8-24 3.8-24a 3.8-24a 3.8-35 3.8-35

--- 3.8-35a 3.8-38 3.8-38 3.8-39 3.8-39 5.0-16b 5.0-16b

--- 5.0-16c

(2) EOI, pursuant to Section 103 of the Act and 10 CFR Part 50, to possess, use and operate the facility at the above designated location in accordance with the procedures and limitations set forth in this renewed license;

(3) EOI, pursuant to Section 103 of the Act and 10 CFR Part 70, to receive, possess and to use at any time special nuclear material as reactor fuel, in accordance with the limitations for storage and amounts required for reactor operation, as described in the Final Safety Analysis Report, as supplemented and amended;

(4) EOI, pursuant to Section 103 of the Act and 10 CFR Parts 30, 40 and 70, to receive, possess, and use at any time any byproduct, source and special nuclear material as sealed neutron sources for reactor startup, sealed sources for reactor instrumentation and radiation monitoring equipment calibration, and as fission detectors in amounts as required;

(5) EOI, pursuant to Section 103 of the Act and 10 CFR Parts 30, 40 and 70, to receive, possess, and use in amounts as required any byproduct, source or special nuclear material without restriction to chemical or physical form, for sample analysis or instrument calibration or associated with radioactive apparatus or components; and

(6) EOI, pursuant to Section 103 of the Act and 10 CFR Parts 30, 40 and 70, to possess, but not separate, such byproduct and special nuclear materials as may be produced by the operation of the facility.

(7) EOI, pursuant to the Act and 10 CFR Part 30, 40, and 70 to receive, possess and use, in amounts as required, such byproduct and special nuclear materials as may be produced by the operation of Arkansas Nuclear One, Units 1 and 2, Grand Gulf Nuclear Station, Unit 1, River Bend Station, Unit 1, and Waterford Steam Electric Station, Unit 3, without restriction to chemical or physical form for the purposes of sample analysis, equipment calibration, or equipment repair.

C. This renewed license shall be deemed to contain and is subject to the conditions specified in the Commission's regulations set forth in 10 CFR Chapter I and is subject to all applicable provisions of the Act and the rules, regulations and orders of the Commission now or hereafter in effect; and is subject to the additional conditions specified or incorporated below:

(1) Maximum Power Level

EOI is authorized to operate the facility at reactor core power levels not in excess of 3091 megawatts thermal (100% rated power) in accordance with the conditions specified herein.

(2) Technical Specifications and Environmental Protection Plan

The Technical Specifications contained in Appendix A, as revised through Amendment No. 213 and the Environmental Protection Plan contained in Appendix B, are hereby incorporated in the renewed license. EOI shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

Amendment No. 213 Completion Times 1.3

1.3 Completion Times

EXAMPLES EXAMPLE 1.3-7 (continued)

Condition B is entered, but continues from the time Condition A was initially entered. If Required Action A.1 is met after Condition B is entered, Condition B is exited and operation may continue in accordance with Condition A, provided the Completion Time for Required Action A.2 has not expired.

EXAMPLE 1.3-8

ACTIONS

CONDITION REQUIRED ACTION COMPLETION TIME

A. One subsystem A.1 Restore 7 days inoperable. subsystem to OPERABLE OR status.

In accordance with the Risk Informed Completion Time Program

B. Required Action B.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and associated Completion AND Time not met.

B.2 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months

When a subsystem is declared inoperable, Condition A is entered. The 7 day Completion Time may be applied as discussed in Example 1.3-2.

However, the licensee may elect to apply the Risk Informed Completion Time Program which permits calculation of a Risk Informed Completion Time (RICT) that may be used to complete the Required Action beyond the 7 day Completion Time. The RICT cannot exceed 30 days. After the 7 day Completion Time has expired, the subsystem must be restored to OPERABLE status within the RICT or Condition B must also be entered.

(continued)

RIVER BEND 1.0-23 Amendment No. 81, 213 Completion Times 1.3

1.3 Completion Times

EXAMPLES EXAMPLE 1.3-8 (continued)

The Risk Informed Completion Time Program requires recalculation of the RICT to reflect changing plant conditions. For planned changes, the revised RICT must be determined prior to implementation of the change in configuration. For emergent conditions, the revised RICT must be determined within the time limits of the Required Action Completion Time (i.e., not the RICT) or 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after the plant configuration change, whichever is less.

If the 7 day Completion Time clock of Condition A has expired and subsequent changes in plant condition result in exiting the applicability of the Risk Informed Completion Time Program without restoring the inoperable subsystem to OPERABLE status, Condition B is also entered and the Completion Time clocks for Required Actions B.1 and B.2 start.

If the RICT expires or is recalculated to be less than the elapsed time since the Condition was entered and the inoperable subsystem has not been restored to OPERABLE status, Condition B is also entered and the Completion Time clocks for Required Actions B.1 and B.2 start. If the inoperable subsystems are restored to OPERABLE status after Condition B is entered, Condition A is exited, and therefore, the Required Actions of Condition B may be terminated.

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

RIVER BEND 1.0-23a Amendment No. 213 SLC System 3.1.7

3.1 REACTIVITY CONTROL SYSTEMS

3.1.7 Standby Liquid Control (SLC) System

LCO 3.1.7 Two SLC subsystems shall be OPERABLE.

APPLICABILITY: MODES 1 and 2.

ACTIONS

CONDITION REQUIRED ACTION COMPLETION TIME

A. (C)(E) < 570. A.1 Restore (C)(E) t 570. 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months

B. One SLC subsystem B.1 Restore SLC subsystem to 7 days inoperable for reasons OPERABLE status.

other than Condition A. OR

In accordance with the Risk Informed Completion Time Program

C. Two SLC subsystems C.1 Restore one SLC subsystem 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months inoperable for reasons to OPERABLE status.

other than Condition A.

D. Required Action and D.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time not met.

RIVER BEND 3.1-20 Amendment No. 81, 114, 205, 213 RPS Instrumentation 3.3.1.1

3.3 INSTRUMENTATION

3.3.1.1 Reactor Protection System (RPS) Instrumentation

LCO 3.3.1.1 The RPS instrumentation for each Function in Table 3.3.1.1-1 shall be OPERABLE.

APPLICABILITY: According to Table 3.3.1.1-1.

ACTIONS

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

Separate Condition entry is allowed for each channel.

CONDITION REQUIRED ACTION COMPLETION TIME

A. One or more A.1 Place channel in trip. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months required channels inoperable. OR

NOTE---------

Not applicable when a loss of function occurs.

In accordance with the Risk Informed Completion Time Program

OR

A.2 Place associated trip 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months system in trip. OR

NOTE---------

Not applicable when a loss of function occurs.

In accordance with the Risk Informed Completion Time Program

(continued)

RIVER BEND 3.3-1 Amendment No. 81, 213 RPS Instrumentation 3.3.1.1

ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME

B. One or more Functions withB.1 Place channel in one trip 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months one or more required system in trip.

channels inoperable in both OR trip systems.

NOTE---------

Not applicable when a loss of function occurs.

In accordance with the Risk Informed Completion Time Program

OR

B.2 Place one trip system in 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months trip.

OR

NOTE---------

Not applicable when a loss of function occurs.

In accordance with the Risk Informed Completion Time Program

C. One or more Functions C.1 Restore RPS trip 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months with RPS trip capability not capability.

maintained.

D. Required Action and D.1 Enter the Condition Immediately associated Completion referenced in Table Time of Condition A, B, or 3.3.1.1-1 for the C not met. channel.

(continued)

RIVER BEND 3.3-2 Amendment No. 81, 114, 213 RPS Instrumentation 3.3.1.1

ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME

E. As required by Required E.1 Reduce THERMAL 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Action D.1 and referenced POWER to < 40%

in Table 3.3.1.1-1. RTP.

F. As required by Required F.1 Reduce THERMAL 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Action D.1 and referenced POWER to < 23.8%

in Table 3.3.1.1-1. RTP.

G. As required by Required G.1 Be in MODE 2. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Action D.1 and referenced in Table 3.3.1.1-1.

H. As required by Required H.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Action D.1 and referenced in Table 3.3.1.1-1.

I. As required by Required I.1 Initiate action to fully Immediately Action D.1 and referenced insert all insertable in Table 3.3.1.1-1. control rods in core cells containing one or more fuel assemblies.

RIVER BEND 3.3-2a Amendment No. 213 EOC-RPT Instrumentation 3.3.4.1

3.3 INSTRUMENTATION

3.3.4.1 End of Cycle Recirculation Pump Trip (EOC-RPT) Instrumentation

LCO 3.3.4.1 a. Two channels per trip system for each EOC-RPT instrumentation Function listed below shall be OPERABLE:

1. Turbine Stop Valve (TSV) Closure; and

2. Turbine Control Valve (TCV) Fast Closure, Trip Oil Pressure Low.

OR

b. LCO 3.2.2, MINIMUM CRITICAL POWER RATIO (MCPR), and LCO 3.2.3, Linear Heat Generation Rate (LHGR), limits for inoperable EOC-RPT as specified in the COLR are made applicable.

APPLICABILITY: THERMAL POWER t 40% RTP with any recirculation pump in fast speed.

ACTIONS

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

Separate Condition entry is allowed for each channel.

CONDITION REQUIRED ACTION COMPLETION TIME

A. One or more required A.1 Restore channel to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months channels inoperable. OPERABLE status.

OR

In accordance with the Risk Informed Completion Time Program

OR

(continued)

RIVER BEND 3.3-25 Amendment No. 81, 146, 213 EOC-RPT Instrumentation 3.3.4.1

ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME

A. (continued) A.2 -------------NOTE-------------

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

Place channel in trip. 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 or more Functions B.1 Restore EOC-RPT trip 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months with EOC-RPT trip capability.

capability not maintained.

OR AND B.2 Apply the MCPR and 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months MCPR and LHGR limits LHGR limits for for inoperable EOC-RPT inoperable EOC-RPT as not made applicable. specified in the COLR.

C. Required Action and C.1 Remove the associated 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months associated Completion recirculation pump fast Time not met. speed breaker from service.

OR

C.2 Reduce THERMAL 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months POWER to < 40% RTP.

RIVER BEND 3.3-26 Amendment No. 81, 146, 213 ATWS-RPT Instrumentation 3.3.4.2

3.3 INSTRUMENTATION

3.3.4.2 Anticipated Transient Without Scram Recirculation Pump Trip (ATWS-RPT)

Instrumentation

LCO 3.3.4.2 Two channels per trip system for each ATWS-RPT instrumentation Function listed below shall be OPERABLE:

a. Reactor Vessel Water Level Low Low, Level 2; and

b. Reactor Steam Dome Pressure High.

APPLICABILITY: MODE 1

ACTIONS

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

Separate Condition entry is allowed for each channel.

CONDITION REQUIRED ACTION COMPLETION TIME

A. One or more channels A.1 Restore channel to 14 days inoperable. OPERABLE status.

OR

In accordance with the Risk Informed Completion Time OR Program

A.2 -----------NOTE-------------

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

Place channel in trip. 14 days

OR

In accordance with the Risk Informed Completion Time Program

(continued)

RIVER BEND 3.3-29 Amendment No. 81, 213 ECCS Instrumentation 3.3.5.1

ACTIONS

CONDITION REQUIRED ACTION COMPLETION TIME

B. (continued) B.2 ---------------NOTE----------------

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

Declare High Pressure Core 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months from Spray (HPCS) System discovery of loss of inoperable. HPCS initiation capability AND

B.3 Place channel in trip. 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months

OR

NOTE---------

Not applicable when a loss of function occurs.

In accordance with the Risk Informed Completion Time Program

C. As required by Required C.1 ---------------NOTE----------------

Action A.1 and referenced Only applicable for Functions in Table 3.3.5.1-1. 1.c, 1.d, 1.e, 2.c, 2.d, and 2.e.

Declare supported feature(s) 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months from inoperable when its redundant discovery of loss of feature ECCS initiation initiation capability capability is inoperable. for feature(s) in both divisions

AND

(continued)

RIVER BEND 3.3-33 Amendment No. 81, 193, 213 ECCS Instrumentation 3.3.5.1

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME

C. (continued) C.2 Restore channel to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OPERABLE status. OR

NOTE---------

Not applicable when a loss of function occurs.

In accordance with the Risk Informed Completion Time Program

D. As required by Required D.1 ------------NOTE------------

Action A.1 and referenced Only applicable if HPCS in Table 3.3.5.1-1. pump suction is not aligned to the suppression pool.

Declare HPCS System 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months from inoperable. discovery of loss of HPCS initiation capability

AND

D.2.1 Place channel in trip. 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months

OR

NOTE---------

Not applicable when a loss of function occurs.

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

RIVER BEND 3.3-34 Amendment No. 81, 213 ECCS Instrumentation 3.3.5.1

ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME

D. (continued) D.2.2 Align the HPCS pump 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months suction to the suppression pool.

E. As required by Required E.1 ----------------NOTE-----------------

Action A.1 and referenced Only applicable for Functions in Table 3.3.5.1-1. 1.f, 1.g, and 2.f.

Declare supported feature(s) 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months from discovery of inoperable when its redundant loss of initiation feature ECCS initiation capability for feature(s) capability is inoperable. in both divisions

AND

E.2 Restore channel to OPERABLE 7 days status.

OR

NOTE---------

Not applicable when a loss of function occurs.

In accordance with the Risk Informed Completion Time Program

(continued)

RIVER BEND 3.3-35 Amendment No. 81, 193, 213 ECCS Instrumentation 3.3.5.1

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME

F. As required by Required F.1 Declare Automatic 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months from Action A.1 and Depressurization System discovery of loss of referenced in Table (ADS) valves inoperable. ADS initiation 3.3.5.1-1. capability in both trip systems AND

F.2 Place channel in trip. ------NOTE---------

The Risk Informed Completion Time Program is not applicable when a loss of function occurs.

96 hours0.00111 days 0.0267 hours 1.587302e-4 weeks 3.6528e-5 months or in accordance with the Risk Informed Completion Time Program from discovery of inoperable channel concurrent with HPCS or reactor core isolation cooling (RCIC) inoperable

AND

NOTE---------

The Risk Informed Completion Time Program is not applicable when a loss of function occurs.

8 days or in accordance with the Risk Informed Completion Time Program

(continued)

RIVER BEND 3.3-36 Amendment No. 81, 213 ECCS Instrumentation 3.3.5.1

ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME

G. As required by Required G.1 -------------NOTE-----------

Action A.1 and referenced Only applicable for in Table 3.3.5.1-1. Functions 4.c, 4.e, 4.f, 4.g, 5.c, 5.e, and 5.f.

Declare ADS valves 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months from inoperable. discovery of loss of ADS initiation capability in both AND trip systems

(continued)

RIVER BEND 3.3-36a Amendment No. 213 ECCS Instrumentation 3.3.5.1

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME

G. (continued) G.2 Restore channel to ------NOTE---------

OPERABLE status. The Risk Informed Completion Time Program is not applicable when a loss of function occurs.

96 hours0.00111 days 0.0267 hours 1.587302e-4 weeks 3.6528e-5 months or in accordance with the Risk Informed Completion Time Program from discovery of inoperable channel concurrent with HPCS or RCIC inoperable

AND

NOTE---------

The Risk Informed Completion Time Program is not applicable when a loss of function occurs.

8 days or in accordance with the Risk Informed Completion Time Program

H. Required Action and H.1 Declare associated Immediately associated Completion supported feature(s)

Time of Condition B, C, inoperable.

D, E, F, or G not met.

RIVER BEND 3.3-37 Amendment No. 81, 213 RCIC System Instrumentation 3.3.5.3

3.3 INSTRUMENTATION

3.3.5.3 Reactor Core Isolation Cooling (RCIC) System Instrumentation

LCO 3.3.5.3 The RCIC System instrumentation for each Function in Table 3.3.5.3-1 shall be OPERABLE.

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

ACTIONS

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

Separate Condition entry is allowed for each channel.

CONDITION REQUIRED ACTION COMPLETION TIME

A. One or more channels A.1 Enter the Condition referenced Immediately inoperable. in Table 3.3.5.3-1 for the channel.

B. As required by Required B.1 Declare RCIC System 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months from discovery Action A.1 and inoperable. of loss of RCIC referenced in Table initiation capability 3.3.5.3-1.

AND

B.2 Place channel in trip. 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months

OR

In accordance with the Risk Informed Completion Time Program

C. As required by Required C.1 Restore channel to OPERABLE 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Action A.1 and status.

referenced in Table 3.3.5.3-1.

(continued)

RIVER BEND 3.3-44 Amendment No. 81, 193, 213 RCIC System Instrumentation 3.3.5.3

ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME

D. As required by Required D.1 ----------------NOTE---------------

Action A.1 and referenced in Only applicable if RCIC pump Table 3.3.5.3-1. suction is not aligned to the suppression pool.

Declare RCIC System 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months from inoperable. discovery of loss of RCIC initiation capability AND

D.2.1 Place channel in trip. 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months

OR

In accordance with the Risk Informed Completion Time Program OR

D.2.2 Align RCIC pump suction to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months the suppression pool.

E. Required Action and E.1 Declare RCIC System Immediately associated Completion Time inoperable.

of Condition B, C, or D not met.

RIVER BEND 3.3-45 Amendment No. 81. 193, 213 Primary Containment and Drywell Isolation Instrumentation 3.3.6.1

3.3 INSTRUMENTATION

3.3.6.1 Primary Containment and Drywell Isolation Instrumentation

LCO 3.3.6.1 The primary containment and dr ywell isolation instrumentation for each Function in Table 3.3.6.1-1 shall be OPERABLE.

APPLICABILITY: According to Table 3.3.6.1-1.

ACTIONS

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

1. Penetration flow paths, except for the drywell 24 inch purge valve penetration flow path, may be unisolated intermittently under administrative controls.

2. Separate Condition entry is allowed for each channel.

CONDITION REQUIRED ACTION COMPLETION TIME

A. One or more required A.1 Place channel in trip. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for channels inoperable. Functions 2.b, 5.b, 5.d, and 5.e

OR

In accordance with the Risk Informed Completion Time Program

AND

24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months for Functions other than Functions 2.b, 5.b, 5.d, and 5.e

OR

In accordance with the Risk Informed Completion Time Program

(continued)

RIVER BEND 3.3-48 Amendment No. 81, 165, 213 Primary Containment and Drywell Isolation Instrumentation 3.3.6.1

ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME

B. One or more automatic B.1 Restore isolation 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Functions with isolation capability.

capability not maintained.

C. Required Action and C.1 Enter the Condition Immediately associated Completion referenced in Table Time of Condition A or B 3.3.6.1-1 for the not met. channel.

D. As required by Required D.1 Isolate associated main 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Action C.1 and referenced steam line (MSL).

in Table 3.3.6.1-1.

OR

D.2.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months

AND

D.2.2 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months

E. As required by Required E.1 Be in MODE 2. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Action C.1 and referenced in Table 3.3.6.1-1.

F. As required by Required F.1 Isolate the affected 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Action C.1 and referenced penetration flow in Table 3.3.6.1-1. path(s).

G. As required by Required G.1 Isolate the affected 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Action C.1 and referenced penetration flow in Table 3.3.6.1-1. path(s).

(continued)

RIVER BEND 3.3-49 Amendment No. 81, 213 Containment Unit Cooler System Instrumentation 3.3.6.3

3.3 INSTRUMENTATION

3.3.6.3 Containment Unit Cooler System Instrumentation

LCO 3.3.6.3 The Containment Unit Cooler System instrumentation for each Function in Table 3.3.6.3-1 shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3.

ACTIONS

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

Separate Condition entry is allowed for each channel.

CONDITION REQUIRED ACTION COMPLETION TIME

A. One or more channels A.1 Enter the Condition Immediately inoperable. referenced in Table 3.3.6.3-1 for the channel.

B. As required by Required B.1 Declare associated 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months from Action A.1 and referenced containment unit cooler discovery of loss of in Table 3.3.6.3-1. subsystem inoperable. containment unit cooler initiation capability in both trip systems

AND

B.2 Place channel in trip. 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OR

In accordance with the Risk Informed Completion Time Program

(continued)

RIVER BEND 3.3-62 Amendment No. 81, 213 Containment Unit Cooler System Instrumentation 3.3.6.3

ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME

C. As required by Required C.1 Declare associated 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months from Action A.1 and referenced containment unit cooler discovery of loss of in Table 3.3.6.3-1. subsystem inoperable. containment unit cooler initiation capability in both trip systems

AND

C.2 Restore channel to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OPERABLE status.

OR

In accordance with the Risk Informed Completion Time Program

D. Required Action and D.1 Declare associated Immediately associated Completion containment unit cooler Time of Condition B or C subsystem inoperable.

not met.

RIVER BEND 3.3-63 Amendment No. 81, 213 Relief and LLS Instrumentation 3.3.6.4

3.3 INSTRUMENTATION

3.3.6.4 Relief and Low-Low Set (LLS) Instrumentation

LCO 3.3.6.4 Two relief and LLS instrumentation trip systems shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3.

ACTIONS

CONDITION REQUIRED ACTION COMPLETION TIME

A. One trip system A.1 Restore trip system to 7 days inoperable. OPERABLE status.

OR

In accordance with the Risk Informed OR Completion Time Program

A.2 Declare associated relief 7 days and LLS valve(s) inoperable.

B. Required Action and B.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time of Condition A not AND met.

B.2 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months OR

Two trip systems inoperable.

RIVER BEND 3.3-66 Amendment No. 81, 213 LOP Instrumentation 3.3.8.1

3.3 INSTRUMENTATION

3.3.8.1 Loss of Power (LOP) Instrumentation

LCO 3.3.8.1 The LOP instrumentation for each Function in Table 3.3.8.1-1 shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3

ACTIONS

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

Separate Condition entry is allowed for each channel.

CONDITION REQUIRED ACTION COMPLETION TIME

A. One or more channels A.1 Place channel in trip. 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months inoperable.

OR

NOTE--------

Not applicable when a loss of function occurs.

In accordance with the Risk Informed Completion Time Program

B. Required Action and B.1 Declare associated DG Immediately associated Completion inoperable.

Time not met.

RIVER BEND 3.3-72 Amendment No. 81, 203, 213 ECCS Operating 3.5.1

3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS), RPV WATER INVENTORY CONTROL, AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM

3.5.1 ECCS -Operating

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

APPLICABILITY: MODE 1, MODES 2 and 3, except ADS valves are not required to be OPERABLE with reactor steam dome pressure d 100 psig.

ACTIONS

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

LCO 3.0.4.b is not applicable to High Pressure Core Spray (HPCS).

CONDITION REQUIRED ACTION COMPLETION TIME

A. One low pressure ECCSA.1 Restore low pressure 7 days injection/spray subsystem ECCS injection/spray OR inoperable. subsystem to OPERABLE status. In accordance with the Risk Informed Completion Time Program

B. HPCS System inoperable. B.1 Verify by administrative 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months means RCIC System is OPERABLE when RCIC is required to be OPERABLE.

AND

(continued)

RIVER BEND 3.5-1 Amendment No. 81, 156, 193, 203, 213 ECCS Operating 3.5.1

ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME

B. (continued) B.2 Restore HPCS System 14 days to OPERABLE status. OR

In accordance with the Risk Informed Completion Time Program

C. Two ECCS injection C.1 Restore one ECCS 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months subsystems inoperable. injection/spray OR subsystem to OR OPERABLE status. In accordance with One ECCS injection and the Risk Informed one ECCS spray Completion Time subsystem inoperable. Program

D. Required Action and D.1 ----------NOTE-----------

associated Completion LCO 3.0.4.a is not Time of Condition A, B, or applicable when C not met. entering MODE 3.

Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months

E. One ADS valve inoperable. E.1 Restore ADS valve to 14 days OPERABLE status. OR

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

RIVER BEND 3.5-2 Amendment No. 81, 185, 213 ECCS Operating 3.5.1

ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME

F. One ADS valve F.1 Restore ADS valve to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months inoperable. OPERABLE status.

OR AND In accordance with One low pressure ECCS the Risk Informed injection/spray Completion Time subsystem inoperable Program

OR

F.2 Restore low pressure 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months ECCS injection/spray

subsystemto OR OPERABL status.E In accordance with the Risk Informed Completion Time Program

G. Two or more ADS valves G.1 ----------NOTE-----------

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

Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months

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

(continued)

RIVER BEND 3.5-2a Amendment No. 81 185, 213 RCIC System 3.5.3

3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS), RPV WATER INVENTORY CONTROL, AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM

3.5.3 RCIC System

LCO 3.5.3 The RCIC System shall be OPERABLE.

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

ACTIONS

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

LCO 3.0.4.b is not applicable to RCIC.

CONDITION REQUIRED ACTION COMPLETION TIME

A. RCIC System inoperable. A.1 Verify by administrative 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months means High Pressure Core Spray System is OPERABLE.

AND

A.2 Restore RCIC System 14 days to OPERABLE status. OR

In accordance with the Risk Informed Completion Time Program

B. Required Action and B.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time not met. AND

B.2 Reduce reactor steam 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months dome pressure to d 150 psig.

RIVER BEND 3.5-10 Amendment No. 81, 156, 193, 213 Primary Containment Air Locks 3.6.1.2

ACTIONS

CONDITION REQUIRED ACTION COMPLETION TIME

C. (continued) C.3 Restore air lock to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OPERABLE status. OR

In accordance with the Risk Informed Completion Time Program

D. Required Action and D.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time of Condition A, B, or AND C not met in MODE 1, 2, or

3. D.2 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months

E. Required Action and E.1 Suspend movement of Immediately associated Completion recently irradiated fuel Time of Condition A, B, or assemblies in the C not met during primary containment.

movement of recently irradiated fuel assemblies in the primary containment

RIVER BEND 3.6-6 Amendment No. 81, 85, 193, 213 PCIVs 3.6.1.3

ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME

A. One or more penetration A.1 Isolate the affected 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months except for flow paths with one PCIV penetration flow path by main steam line inoperable except due to the use of at least one leakage not within limit. closed and de-activated OR automatic valve, closed manual valve, blind In accordance with flange, or check valve the Risk Informed with flow through the Completion Time valve secured. Program

AND

8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months for main steam line

OR

In accordance with the Risk Informed Completion Time Program

AND (continued)

RIVER BEND 3.6-10 Amendment No. 81, 213 PCIVs 3.6.1.3

ACTIONS

CONDITION REQUIRED ACTION COMPLETION TIME

A. (continued) A.2 -----------NOTE------------

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

Verify the affected Once per 31 days penetration flow path is following isolation for isolated. isolation devices outside primary containment, drywell, and steam tunnel

AND

Prior to entering MODE 2 or 3 from MODE 4, if not performed within the previous 92 days, for isolation devices inside primary containment, drywell, or steam tunnel

B. One or more penetration B.1 Isolate the affected 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months flow paths with two PCIVs penetration flow path by inoperable except due to use of at least one leakage not within limit. closed and de-activated automatic valve, closed manual valve, or blind flange.

(continued)

RIVER BEND 3.6-11 Amendment No. 81, 213 PCIVs 3.6.1.3

ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME

D. One or more penetration D.1 Isolate the affected 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months flow paths with one or penetration flow path by more primary containment use of at least one OR purge valves not within closed and de-activated purge valve leakage limits. automatic valve, closed In accordance with manual valve, or blind the Risk Informed flange. Completion Time Program AND

D.2 ----------NOTE-------------

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

Verify the affected Once per 31 days penetration flow path is following isolation for isolated. isolation devices outside primary containment

AND

Prior to entering MODE 2 or 3 from MODE 4 if not performed within the previous 92 days for isolation devices inside primary containment

AND

(continued)

RIVER BEND 3.6-13 Amendment No. 81, 213 PCIVs 3.6.1.3

ACTIONS

CONDITION REQUIRED ACTION COMPLETION TIME

D. (continued) D.3 Perform SR 3.6.1.3.5 Once per 92 days for the resilient seal following isolation purge valves closed to comply with Required Action D.1.

E. Required Action and E.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time of Condition A, B, C, AND or D not met in MODE 1, 2, or 3. E.2 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months

RIVER BEND 3.6-14 Amendment No. 81, 193, 213 LLS Valves 3.6.1.6

3.6 CONTAINMENT SYSTEMS

3.6.1.6 Low-Low Set (LLS) Valves

LCO 3.6.1.6 The LLS function of five safety/relief valves shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3.

ACTIONS

CONDITION REQUIRED ACTION COMPLETION TIME

A. One LLS valve inoperable. A.1 Restore LLS valve to 14 days OPERABLE status. OR

In accordance with the Risk Informed Completion Time Program

B. Required Action and B.1 ----------NOTE-----------

associated Completion LCO 3.0.4.a is not Time of Condition A not applicable when met. entering MODE 3.

Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months

C. Two or more LLS valves C.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Inoperable.

AND

C.2 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months

RIVER BEND 3.6-23 Amendment No. 81 185, 213 Primary Containment Unit Coolers 3.6.1.7

3.6 CONTAINMENT SYSTEMS

3.6.1.7 Primary Containment Unit Coolers

LCO 3.6.1.7 Two primary containment unit coolers shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3.

ACTIONS

CONDITION REQUIRED ACTION COMPLETION TIME

A. One required primary A.1 Restore required 7 days containment unit cooler primary containment OR inoperable. unit cooler to OPERABLE status. In accordance with the Risk Informed Completion Time Program

B. Two required primary B.1 Restore one required 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months containment unit coolers primary containment inoperable. unit cooler to OPERABLE status.

C. Required Action and C.1 ----------NOTE-----------

associated Completion LCO 3.0.4.a is not Time not met. applicable when entering MODE 3.

Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months

RIVER BEND 3.6-25 Amendment No. 81 185, 213 RHR Suppression Pool Cooling 3.6.2.3

3.6 CONTAINMENT SYSTEMS

3.6.2.3 Residual Heat Removal (RHR) Suppression Pool Cooling

LCO 3.6.2.3 Two RHR suppression pool cooling subsystems shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3.

ACTIONS

CONDITION REQUIRED ACTION COMPLETION TIME

A. One RHR suppression A.1 Restore RHR 7 days pool cooling subsystem suppression pool cooling OR inoperable. subsystem to OPERABLE status. In accordance with the Risk Informed Completion Time Program

B. Required Action and B.1 ----------NOTE-----------

associated Completion LCO 3.0.4.a is not Time of Condition A not applicable when met. entering MODE 3.

Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months

C. Two RHR suppression C.1 Restore one RHR 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months pool cooling subsystems suppression pool cooling inoperable. subsystem to OPERABLE status.

D. Required Action and D.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time of Condition C not AND met.

D.2 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months

RIVER BEND 3.6-37 Amendment No. 81, 165, 185, 213 Drywell Air Lock 3.6.5.2

ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME

C. Drywell air lock inoperable C.1 Verify a door is closed. 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months for reasons other than Condition A or B. AND

C.2 Restore air lock to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OPERABLE status. OR

In accordance with the Risk Informed Completion Time Program

D. Required Action and D.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time not met. AND

D.2 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months

RIVER BEND 3.6-65 Amendment No. 81, 87, 213 Drywell Isolation Valves 3.6.5.3

3.6 CONTAINMENT SYSTEMS

3.6.5.3 Drywell Isolation Valves

LCO 3.6.5.3 Each Drywell Isolation Valve shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3.

ACTIONS

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

1. Penetration flow paths, except for the 24 inch purge valve penetration flow path, may be unisolated intermittently under administrative controls.

2. Separate Condition entry is allowed for each penetration flow path.

3. Enter applicable Conditions and Required Action s for systems made inoperable by Drywell Isolation Valves.

CONDITION REQUIRED ACTION COMPLETION TIME

A. One or more penetrationA.1 Isolate the affected8 hours flow paths with one penetration flow path by drywell isolation valve use of at least one closed OR inoperable. and de-activated automatic valve, closed In accordance with manual valve, blind flange, the Risk Informed or check valve with flow Completion Time through the valve secured. Program

AND

(continued)

RIVER BEND 3.6-67 Amendment No. 81, 87, 213 SSW System and UHS 3.7.1

3.7 PLANT SYSTEMS

3.7.1 Standby Service Water (SSW) System and Ultimate Heat Sink (UHS)

LCO 3.7.1 Two SSW subsystems and the UHS shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3.

ACTIONS

CONDITION REQUIRED ACTION COMPLETION TIME

A. One division with one UHS A.1 Restore cooling tower 30 days cooling tower fan cell fan cell to OPERABLE inoperable. status.

B. Both divisions with one B.1 Restore one cooling 7 days UHS cooling tower fan cell tower fan cell to OR inoperable. OPERABLE status.

In accordance with the Risk Informed Completion Time Program

C. One division with both C.1 Declare associated Immediately UHS cooling tower fan SSW subsystem cells inoperable. inoperable.

D. UHS basin inoperable. D.1 Restore UHS basin to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OPERABLE status.

E. One SSW subsystem with E.1 Restore pump to 30 days one pump inoperable. OPERABLE status.

(continued)

RIVER BEND 3.7-1 Amendment No. 81, 213 SSW System and UHS 3.7.1

ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME

F. Two SSW subsystems withF.1 Restore one pump to 7 days one pump inoperable. OPERABLE status. OR

In accordance with the Risk Informed Completion Time Program

G. One SSW subsystem ------------------NOTES----------------

inoperable for reasons 1. Enter applicable Conditions other than Condition E and Required Actions of LCO orF. 3.8.1, "AC Sources -

Operating," for diesel generator made inoperable by SSW.

2. Enter applicable Conditions and Required Actions of LCO 3.4.9, "Residual Heat Removal (RHR) Shutdown Cooling System - Hot Shutdown," for RHR shutdown cooling subsystem made inoperable by SSW.

G.1 Restore SSW 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months subsystem to OR OPERABLE status.

In accordance with the Risk Informed Completion Time Program

(continued)

RIVER BEND 3.7-2 Amendment No. 81, 213 Control Building Air Conditioning System 3.7.7

3.7 PLANT SYSTEMS

3.7.7 Control Building Air Conditioning (CBAC) System

LCO 3.7.7 Two Control Building Air Conditioning subsystems shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One control building air A.1 Restore control building air 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months conditioning subsystem conditioning subsystem to inoperable. OPERABLE status. OR

In accordance with the Risk Informed Completion Time Program

B. Required Action and B.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time of Condition A not AND met.

B.2 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months OR

Two control building air conditioning subsystems inoperable.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.7.1 Verify each Control Building Air Conditioning subsystem 24 months has the capability to remove the assumed heat load.

RIVER BEND 3.7-16 Amendment No. 192, 213 AC Sources Operating 3.8.1

ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME

A. (continued) -------------------NOTE------------------

Verification is only required if 22 kV onsite circuit is supplying Division III safety related bus E22-S004 from normal power transformer STX-XNS1C.

A.2 Verify E22-S004 is 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months aligned to transfer to the preferred station AND transformer powered by the OPERABLE offsite Once per 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months circuit. thereafter

AND

A.3 Restore required offsite 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months circuit to OPERABLE status. OR

In accordance with the Risk Informed Completion Time Program

AND

24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or in accordance with the Risk Informed Completion Time Program from discovery of two divisions with no offsite power

(continued)

RIVER BEND 3.8-2 Amendment No. 81 125, 176, 205, 213 AC Sources Operating 3.8.1

ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME

B. Automatic transfer function B.1 Restore Division III power 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months not OPERABLE source to the preferred station service transformers

C. One required DG C.1 Perform SR 3.8.1.1 for 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months inoperable. OPERABLE required offsite circuit(s). AND

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

AND

C.2 Declare required 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months from discovery feature(s), supported by of Condition C the inoperable DG, concurrent with inoperable when the inoperability of redundant required redundant required feature(s) are inoperable. feature(s)

AND

(continued)

RIVER BEND 3.8-2a Amendment No. 176, 213 AC Sources Operating 3.8.1

ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME

C. (continued) C.3.1 Determine OPERABLE 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months DG(s) are not inoperable due to common cause failure.

OR

C.3.2 Perform SR 3.8.1.2 for 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OPERABLE DG(s).

AND

C.4 Restore required DG to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or in OPERABLE status. accordance with the Risk Informed Completion Time Program from discovery of an inoperable Division III DG

AND

14 days or in accordance with the Risk Informed Completion Time Program

D. Two required offsite D.1 Declare required 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months from circuits inoperable. feature(s) inoperable discovery of Condition when the redundant D concurrent with required feature(s) are inoperability of inoperable. redundant required feature(s)

AND (continued)

RIVER BEND 3.8-3 Amendment No. 81 125, 176, 205, 213 AC Sources Operating 3.8.1

ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME

D. (continued) D.2 Restore one required offsite24 hours circuit to OPERABLE status.

OR

In accordance with the Risk Informed Completion Time Program

(continued)

RIVER BEND 3.8-3a Amendment No. 213 AC Sources Operating 3.8.1

ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME

E. One required offsite circuit------------------NOTE------------------

inoperable. Enter applicable Conditions and Required Actions of LCO AND 3.8.9, "Distribution Systems Operating," when any One required DG division is de-energized as a inoperable. result of Condition E.

E.1 Restore required offsite 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months circuit to OPERABLE status. OR

In accordance with the Risk Informed Completion Time Program

OR

E.2 Restore required DG to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months OPERABLE status.

OR

In accordance with the Risk Informed Completion Time Program

F. Two required DGsF.1 Restore one required 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months inoperable. DG to OPERABLE status. OR

24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months if Division III DG is inoperable

G. Required Action andG.1 ----------NOTE------------ LCO 3.0.4.a is not Associated Completion applicable when Time of Condition A, B, C, entering MODE 3.

D, E or F not met. ------------------------------

Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months (continued)

RIVER BEND 3.8-4 Amendment No. 81 176 185, 213 AC Sources Operating 3.8.1

ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME

H. Three or more required AC H.1 Enter LCO 3.0.3. Immediately sources inoperable.

RIVER BEND 3.8-4a Amendment No. 213 DC Sources Operating 3.8.4

3.8 ELECTRICAL POWER SYSTEMS

3.8.4 DC Sources Operating

LCO 3.8.4 The Division I, Division II, and Division III DC electrical power subsystems shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3.

ACTIONS

CONDITION REQUIRED ACTION COMPLETION TIME

A. One required battery A.1 Restore battery terminal 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months charger on Division I or II voltage to greater than or inoperable. equal to the minimum established float voltage.

AND

A.2 Verify battery float current Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 2 amps.

AND

A.3 Restore battery charger to 7 days OPERABLE status.

OR

In accordance with the Risk Informed Completion Time Program

B. Division I or II DC electricalB.1 Restore Division I and II 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months power subsystem '& electrical power inoperable for reasons subsystems to OPERABLE OR other than Condition A. status.

In accordance with the Risk Informed Completion Time Program

C. Division III DC electricalC.1 Declare High Pressure Immediately power subsystem Core Spray System and inoperable. Standby Service Water System pump 2C inoperable.

(continued)

RIVER BEND 3.8-24 Amendment No. 81 148 185, 213 DC Sources Operating 3.8.4

ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME

D. Required Action and D.1 -----------NOTE-----------

associated Completion LCO 3.0.4.a is not Time for Division I or II DC applicable when electrical power entering MODE 3.

subsystem not met. ------------------------------

Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months

E. Required Action and E.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time for Division III DC AND electrical power subsystem not met. E.2 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months

RIVER BEND 3.8-24a Amendment No. 81 148 185, 213 Inverters Operating 3.8.7

3.8 ELECTRICAL POWER SYSTEMS

3.8.7 Inverters Operating

LCO 3.8.7 The Division I and Division II inverters shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3.

ACTIONS

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

Enter applicable Conditions and Required Actions of LCO 3.8.9, "Distribution Systems Operating," with any AC vital bus de-energized.

CONDITION REQUIRED ACTION COMPLETION TIME

A. Division I or II inverterA.1 Restore Division I and II24 hours inoperable. inverters to OPERABLE status. OR

In accordance with the Risk Informed Completion Time Program

B. Required Action andB.1 ------------NOTE-------------

associated Completion LCO 3.0.4.a is not Time of Condition A not applicable when entering met. MODE 3.

Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months

RIVER BEND 3.8-35 Amendment No. 81, 185, 196, 213 Inverters Operating 3.8.7

SURVEILLANCE REQUIREMENTS

SURVEILLANCE FREQUENCY

SR 3.8.7.1 Verify correct inverter voltage, frequency, and In accordance with alignment to required AC vital buses. the Surveillance Frequency Control Program

RIVER BEND 3.8-35a Amendment No. 213 Distribution Systems Operating 3.8.9

3.8 ELECTRICAL POWER SYSTEMS

3.8.9 Distribution Systems Operating

LCO 3.8.9 Division I, Division II, and Division III AC and DC, and Division I and II AC vital bus electrical power distribution subsystems shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3.

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

Division III electrical power distribution subsystems are not required to be OPERABLE when High Pressure Core Spray System and Standby Service Water pump 2C are inoperable.

ACTIONS

CONDITION REQUIRED ACTION COMPLETION TIME

A. One or more Division I or II A.1 Restore Division I and 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months AC electrical power II AC electrical power distribution subsystems distribution OR inoperable. subsystems to OPERABLE status. In accordance with the Risk Informed Completion Time Program

B. One or more Division I or II B.1 Restore Division I and 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months AC vital bus distribution II AC vital bus subsystems inoperable. distribution OR subsystems to OPERABLE status. In accordance with the Risk Informed Completion Time Program

(continued)

RIVER BEND 3.8-38 Amendment No. 81, 205, 213 Distribution Systems Operating 3.8.9

ACTION (continued)

CONDITION REQUIRED ACTION COMPLETION TIME

C. One or more Division I or II C.1 Restore Division I and II 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months DC electrical power DC electrical power distribution subsystems distribution subsystems OR inoperable. to OPERABLE status.

In accordance with the Risk Informed Completion Time Program

D. Required Action and D.1 -----------NOTE-------------

associated Completion LCO 3.0.4.a is not Time of Condition A, B, or applicable when C not met. entering MODE 3.

Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months

E. One or more Division III E.1 Declare High Pressure Immediately AC or DC electrical power Core Spray System and distribution subsystems Standby Service Water inoperable. System pump 2C inoperable.

F. Two or more divisions with F.1 Enter LCO 3.0.3. Immediately inoperable distribution subsystems that result in a loss of function.

RIVER BEND 3.8-39 Amendment No. 81 95 185, 205, 213 Programs and Manuals 5.5

5.5 Programs and Manuals

5.5.14 Control Room Envelope Habitability Program (continued)

d. Measurement, at designated locations, of the CRE pressure relative to all external areas adjacent to the CRE boundary during the pressurization mode of operation by one subsystem of the CRFA System, operating at the flow rate required by the VFTP, at a Frequency in accordance with the Surveillance Frequency Control Program. The results shall be trended and used as part of the CRE boundary assessment specified in 5.5.14.c (ii).

e. The quantitative limits on unfiltered air inleakage into the CRE. These limits shall be stated in a manner to allow direct comparison to the unfiltered air inleakage measured by the testing described in paragraph c.

The unfiltered air inleakage limit for radiological challenges is the inleakage flow rate assumed in the licensing basis analyses of DBA consequences. Unfiltered air inleakage limits for hazardous chemicals must ensure that exposure of CRE occupants to these hazards will be within the assumptions in the licensing basis.

f. The provisions of SR 3.0.2 are applicable to the Frequencies for assessing CRE habitability, determining CRE unfiltered inleakage, and measuring CRE pressure and assessing the CRE boundary as required by paragraphs c and d, respectively.

5.5.15 Spent Fuel Storage Rack Neutron Absorber Monitoring Program

This program provides controls for monitoring the condition of the neutron absorber inserts used in the high density storage racks in the spent fuel storage facility in the Fuel Building to verify the Boron-10 areal density is consistent with the assumptions in the spent fuel pool criticality analysis. The program shall be in accordance with NEI 16-03-A, Guidance for Monitoring of Fixed Neutron Absorbers in Spent Fuel Pools," Revision 0, May 2017.

5.5.16 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;

(continued)

RIVER BEND 5.0-16b Amendment No. 196, 201, 213 Programs and Manuals 5.5

5.5 Programs and Manuals

5.5.16 Risk Informed Completion Time Program (continued)

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 functions(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 approved for use with this program in Amendment No. 213, 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.

RIVER BEND 5.0-16c Amendment No. 213 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION

RELATED TO AMENDMENT NO. 213 TO

RENEWED FACILITY OPERATING LICENSE NO. NPF-47

ENTERGY OPERATIONS, INC.

RIVER BEND STATION, UNIT 1

DOCKET NO. 50-458

1.0 INTRODUCTION

By application dated February 27, 2023 (Reference 1), as supplemented by letter dated January 12, 2024 (Reference 2), Entergy Operations, Inc. (Entergy, the licensee) submitted a license amendment request (LAR) for River Bend Station, Unit 1 (River Bend).

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 [Risk-Informed TSTF] Initiative 4b, dated July 2, 2018 (Reference 3). The U.S. Nuclear Regulatory Commission (NRC, the Commission) issued a final model safety evaluation (SE) approving TSTF-505, Revision 2, on November 21, 2018 (Reference 4).

The NRC staff participated in a regulatory audit in October 2023 (Reference 5) to ascertain the information needed to support its review of the application and to develop requests for additional information, as needed. Following the regulatory audit, the licensee submitted a supplemental letter dated January 12, 2024, which included additional information resulting from the audit. On May 6, 2024, the staff issued an audit summary (Reference 6).

The licensee has proposed variations from the TS changes approved in TSTF-505, Revision 2, which are provided in section 2.3, Optional Variations, of attachment 1, Description and Assessment, to the LAR and evaluated in section 3.0 of this SE.

The supplemental letter dated January 12, 2024, provided additional information that clarified the application, did not expand the scope of the application as originally noticed, and did not change the NRC staff's original proposed no signific ant hazards consideration determination as published in the Federal Register (FR) on July 11, 2023 (88 FR 44165).

Enclosure 2

2.0 REGULATORY EVALUATION

2.1 Regulatory Review

2.1.1 Applicable Regulations

Title 10 of the Code of Federal Regulations (10 CFR) Part 50 provides the general provisions for Domestic Licensing of Production and Utilization Facilities. 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 for the staffs review of a licensees application to adopt TSTF-505, Revision 2:

Section 50.36, Technical Specifications, of 10 CFR, paragraphs (c)(2), Limiting conditions for operations, and (c)(5), Administrative controls

Section 50.55a, Codes and standards, of 10 CFR, paragraph (h), Protection and safety systems

Section 50.65, Requirements for monitoring the effectiveness of maintenance at nuclear power plants (i.e., the Maintenance Rule), of 10 CFR

2.1.2 Regulatory Guidance

NRC Regulatory Guides (RGs) provide one way to ensure that the codified regulations continue to be met. The NRC staff considered the following guidance, and industry guidance endorsed by the NRC, during its review of the proposed changes:

RG 1.200, Revision 2, An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities, dated March 2009 and RG 1.200, Revision 3, Acceptability of Probabilistic Risk Assessment Results for Risk-Informed Activities, dated December 2020 (Reference 7).

RG 1.174, An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis, Revision 2, dated March 2009 and RG 1.174, Revision 3, dated January 2018 (Reference 8).

RG 1.177, An Approach for Plant-Specific, Risk-Informed Decisionmaking: Technical Specifications, Revision 1, dated May 2011 and RG 1.177, Revision 2, dated January 2021 (Reference 9).

NUREG-1855, Revision 1, Guidance on the Treatment of Uncertainties Associated with PRAs [Probabilistic Risk Assessments] in Risk-Informed Decisionmaking, dated March 2017 (Reference 10).

NUREG-0800, Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants: LWR [Light-Water Reactor] Edition, (SRP) Section 16.1, Risk-Informed Decision Making: Technical Specifications, dated March 2007 (Reference 11) and Section 19.2, Review of Risk Information Used to Support Permanent

Plant-Specific Changes to the Licensing Basis: General Guidance, dated June 2007 (Reference 12).

Nuclear Energy Institute (NEI) Topical Report NEI 06-09 Revision 0-A (NEI 06-09-A), Risk-Informed Technical Specifications Initiative 4b, Risk-Managed Technical Specifications (RMTS) Guidelines, dated October 2012 (Reference 13), provides guidance for risk-informed TSs. The NRC staff issued a final model SE approving NEI 06-09 on May 17, 2007 (Reference 14).

The licensees submittal cites various revisions of RG 1.200, RG 1.174, and RG 1.177.

The RGs have been updated to Revision 3 of RGs 1.200 and 1.174, and Revision 2 for RG 1.177. The updates do not include any technical changes that would impact the consistency with NEI 06-09-A; therefore the NRC staff finds the updated revisions to the RGs also applicable for use in the licensees adoption of TSTF-505, Revision 2.

2.2 Description of the RICT

The TS LCOs are the lowest functional capability or performance levels of equipment required for safe operation of the facility. When an LCO is not met, the licensee must shut down the reactor or follow any remedial or required action (e.g., testing, maintenance, or repair activity) permitted by the TSs until the condition can be met. The remedial actions (i.e., ACTIONS) associated with an LCO contain conditions that typically describe the ways in which the requirements of the LCO are to be met. Specified with each stated Condition are Required Action(s) and Completion Time(s) (CT). The CTs are referred to as the front stops in the context of this SE. For certain conditions, the TSs require exiting the Mode of Applicability of an LCO (i.e., shut down the reactor).

The licensees submittal requested approval to add a RICT Program to the Administrative Controls section of the TSs, and modify selected CTs to permit extending the CTs, provided risk is assessed and managed as described in NEI 06-09-A. Consistent with table 1, Conditions Requiring Additional Technical Justification, NUREG-1434, BWR [Boiling Water Reactor/6 STS

[Standard Technical Specifications], of TSTF-505, Revision 2, the licensee provided several plant-specific LCOs and associated Actions for which the licensee proposed to be included in the RICT Program, along with additional justification in section 2.3 of the LAR. The NRC staff review of these variations and the justification is provided in section 3.0 of this SE.

The licensee is proposing no changes to the desi gn of the plant or any operating parameter, and no changes to the design basis in the proposed changes to the TS. The effect of the proposed changes, when implemented, will allow CTs to vary based on the risk significance of the given plant configuration (i.e., the equipment out of service at any given time), provided that the system(s) retain(s) the capability to perform the applicable safety function(s) without any further failures (e.g., one train of a two-train system is inoperable). These restrictions on inoperability of all required trains of a system ensure that consistency with the defense-in-depth (DID) philosophy is maintained by following existing guidance when the capability to perform TS safety function(s) is lost.

The proposed RICT Program uses plant-specific operating experience for component reliability and availability data. Thus, the allowances permitted by the RICT Program are directly reflective of actual component performance in conjunction with component risk significance.

TS 1.0, Use and Application:

Example 1.3-8, will be added to TS 1.3, Completion Times, and will read as follows:

EXAMPLE 1.3-8

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One A.1 Restore subsystem 7 days subsystem to OPERABLE inoperable. status. OR

In accordance with the Risk Informed Completion Time Program

B. Required B.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Action and associated AND Completion Time not B.2 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months met.

When a subsystem is declared inoperable, Condition A is entered.

The 7 day Completion Time may be applied as discussed in Example 1.3-2. However, the licensee may elect to apply the Risk Informed Completion Time Program which permits calculation of a Risk Informed Completion Time (RICT) that may be used to complete the Required Action beyond the 7 day Completion Time.

The RICT cannot exceed 30 days. After the 7 day Completion Time has expired, the subsystem must be restored to OPERABLE status within the RICT or Condition B must also be entered.

The Risk Informed Completion Time Program requires recalculation of the RICT to reflect changing plant conditions. For planned changes, the revised RICT must be determined prior to implementation of the change in configuration. For emergent conditions, the revised RICT must be determined within the time limits of the Required Action Completion Time (i.e., not the RICT) or 12 hours1.388889e-4 days 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 DID philosophy.

Principle 3: The proposed LB change maintains sufficient safety margins.

Principle 4: When the proposed LB change results in an increase in risk, the increase should be small and consistent with the intent of the Commissions policy statement on safety goals for the operations of nuclear power plants.

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

Principle 5: The impact of the proposed LB change should be monitored by using performance measurement strategies.

3.1 Method of NRC Staff Review

Each of the key principles and tiers are addressed in NEI 06-09-A and approved in the final model SE issued by the NRC for TSTF-505, Revi sion 2. NEI 06-09-A 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 RGs 1.174 and 1.177 is discussed below.

3.2 Review of Key Principles

3.2.1 Key Principle 1: Evaluation of Compliance with Current Regulations

Paragraph 50.36(c)(2) of 10 CFR states that LCOs are the lowest functional capability or performance levels of equipment required for safe operation of the facility. When an LCO of a

nuclear reactor is not met, the licensee shall shut down the reactor or follow any remedial action permitted by the TS until the condition can be met.

The CTs in the current TSs were established using experiential data, risk insights, and engineering judgement. The RICT Program provides the necessary administrative controls to permit extension of CTs and, thereby, delay reactor shutdown or Required Actions, if risk is assessed and managed appropriately within specified limits and programmatic requirements and the safety margins and DID remain sufficient. The option to determine the extended CT in accordance with the RICT Program allows the licensee to perform an integrated evaluation in accordance with the methodology described in NEI 06-09-A and proposed TS 5.5.16, Risk Informed Completion Time Program. The RICT is limited to a maximum of 30 days (termed the backstop).

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

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One subsystem A.1 Restore subsystem 7 days inoperable. to OPERABLE status. OR

In accordance with the Risk Informed Completion Time Program

In attachment 2, Technical Specification Page Markups, and enclosure 1, List of Revised Required Actions to Corresponding PRA Functions, to the LAR, as supplemented, the licensee provided a list of the TSs, associated LCOs, and Required Actions for the CTs that included modifications and variations from the approved TSTF-505. The modifications and variations consisted of proposed changes to the Required Actions and CTs. Furthermore, consistent with table 1 of TSTF-505, Revision 2, for River Bend TSs 3.3.4.1.A, 3.3.6.4.A, 3.3.8.1.A, 3.6.1.2.C, 3.6.1.3.D, 3.6.1.7.A, and 3.6.5.2.C in section 2.0 of enclosure 1 to the LAR, the licensee included additional technical justification to demonstrate the acceptability for including these TSs in the RICT Program. The NRC staff reviewed the proposed changes to the TSs, associated LCOs, Required Actions and CTs provided by the licensee for the scope of the RICT Program and concluded, with the incorporation of the RICT Program, that the required performance levels of equipment specified in LCOs are not changed and only the required 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 staff finds that the proposed RICT Program provided in section 2.0 of this SE, LCOs, Required Actions, and CTs meet the first key principle of RGs 1.174 and 1.177.

3.2.2 Key Principle 2: Evaluation of DID

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

Preserve a reasonable balance among the layers of defense.

Preserve adequate capability of design features without an overreliance on programmatic activities as compensatory measures.

Preserve system redundancy, independence, and diversity commensurate with the expected frequency and consequences of challenges to the system, including consideration of uncertainty.

Preserve adequate defense against potential CCFs [common cause failures].

Maintain multiple fission product barriers.

Preserve sufficient defense against human errors.

Continue to meet the intent of the plants design criteria.

The licensee requested the use of a RICT Program to extend the existing CTs for the respective TS LCOs described in attachment 2 to the LAR, as supplemented. For the TS LCOs, in attachment 5, Evaluation of Instrumentation and Control Systems, and enclosure 1 to 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 River Bends redundant or diverse means to mitigate accidents to ensure consistency with the plant LB requirements using the guidance described in RG 1.174, RG 1.177, and TSTF-505, to ensure adequate DID (for each of the functions) to operate the facility in the proposed manner (i.e., that the changes are consistent with the DID criteria).

and enclosure 1 to the LAR provided information supporting the River Bend evaluation of the redundancy, diversity, and DID for each TS LCO and TS Required Action as it relates to instrumentation and control (I&C) and electrical power systems. The NRC staff confirmed that for the following TS LCOs, the above DID criteria were applicable except for the criteria for maintaining multiple fission product barriers.

LCOs related to I&C:

TS 3.3.1.1, Reactor Protection System (RPS) Instrumentation TS 3.3.4.1, End of Cycle Recirculation Pump Trip (EOC-RPT)

Instrumentation TS 3.3.4.2, Anticipated Transient Without Scram Recirculation Pump Trip (ATWS-RPT) Instrumentation TS 3.3.5.1, Emergency Core Cooling System (ECCS) Instrumentation TS 3.3.5.3, Reactor Core Isolation Cooling (RCIC) System Instrumentation TS 3.3.6.1, Primary Containment and Drywell Isolation Instrumentation TS 3.3.6.3, Containment Unit Cooler System Instrumentation TS 3.3.6.4, Relief and Low-Low Set (LLS) Instrumentation TS 3.3.8.1, Loss of Power (LOP) Instrumentation

LCOs related to electrical power systems:

TS 3.8.1, AC Sources - Operating TS 3.8.4, DC Sources - Operating

TS 3.8.7, Inverters - Operating TS 3.8.9, Distribution Systems - Operating

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 Safety Analysis Report (USAR) (Reference 15) sections, and as reflected in attachment 5 to the LAR for each I&C LCO above. The staff verified, that in accordance with the River Bend USAR and equipment and actions credited in attachment 5 to 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 staff concludes that there is sufficient redundancy, diversity, and DID, to protect against CCFs and potential single failure for the River Bend instrumentation systems evaluated in LAR attachment 2 during a RICT. There is at least one diverse means specified by the licensee for initiating mitigating action for each accident event, thus providing DID against a failure of instrumentation during the RICT for each TS LCO. The DID specified by the licensee does not overly rely on manual actions as the diverse means; therefore, there is not over-reliance of program matic activities as compensatory measures.

Therefore, the 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, according to USAR section 8.1.4, AC offsite power connects to the 4.16 kilovolt Class 1E onsite power system through normal or preferred station service transformers. The Class 1E onsite power system consists of two fully redundant buses (one bus per division) for Divisions I and II and a third Division III bus for the high pressure core spray system, which are all backed by their dedicated DGs - only two of three divisions required for safe shutdown. According to USAR section 8.3.2.1.1, the 125-volt (V) DC power system consists of three ungrounded Class 1E buses - only two buses are required for safe shutdown. According to USAR section 8.3.1.1.3.7, the 120-V AC vital power system has two distribution panels (one per Divisions I and II) with each panel supplied by one inverter - only one inverter associated with one division is required for safe shutdown.

The NRC staff evaluated the LAR for a potential loss of function (LOF) for each electrical proposed RICT based on TSTF-505. The staff did not find any LOF for the proposed RICTs.

The staff reviewed the LAR, as supplemented, to verify that each effected electrical TS LCO condition can be entered voluntarily or involuntarily based on NEI 06-09-A, and to evaluate if the affected electrical power systems under those TS LCO conditions could perform their safety functions (assuming no additional failures other than those considered in the applicable RICT condition). The staff verified the design success criteria in LAR table E1-1, In-scope TS/LCO Conditions to Corresponding PRA Functions, for each of the electrical TS LCO conditions and finds that the minimum operable electrical power systems would remain available to support their safety functions to mitigate postulated design-basis accidents, safely shutdown the reactor, and maintain the reactor in a safe shutdown condition. The staff also finds that RICT estimates are provided for each of the electrical TS LCO conditions in the LAR table E1-2, In-Scope TS/LCO Conditions RICT Estimate, consist ent with NEI 06-09A. Based on above evaluation, the staff finds that the River Bend electrical power systems would continue to provide safety functions as intended with the proposed TS changes.

In enclosure 12, Risk Management Action Examples, to the LAR, the licensee provided examples of risk management actions (RMAs) that may be considered during a RICT Program entry for the above required conditions to reduce the risk impact and ensure adequate DID. The

NRC staff evaluated the RMA examples provided in enclosure 12, section 4.0, including the electrical examples for inoperable DG and offsite circuit. The staff determined that RMAs had the required level of detail, that would reduce risk impact and provide adequate DID. Based on this review, the staff determined that those examples provide reasonable assurance that the actual RMAs when implemented to monitor and c ontrol the risk for each TS LCO condition will be of similar quality and tailored for that LCO.

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

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 staff examined the design information from the River Bend USAR and the risk informed TS LCO conditions for the affected safety functions. Based on this information, the staff confirmed that under any given design-basis accident evaluated in the River Bend USAR, the affected protective features maintain adequate DID.

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

The NRC staff reviewed all TS LCOs proposed by t he licensee in attachment 2 to the LAR, as supplemented, and concludes that the proposed changes do not alter the ways in which the River Bend systems fail, do not introduce new CCF modes, and the system independence is maintained. The 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 DID against a potential single failure during a RICT. The 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 DID 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 t he licensees proposed changes are consistent with the NRC-endorsed guidance described in NEI 06-09-A and satisfy the second key principle in RGs 1.177 and 1.174. Additionally, the staff finds that the changes are consistent with the DID philosophy as described in RG 1.174.

3.2.3 Key Principle 3: Evaluation of Safety Margins

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

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, as supplemented, the licensee proposed to add a new program, Risk Informed Completion Time Program, in section 5.0, Administrative Controls, of the River Bend TSs, which requires adherence to NEI 06-09-A.

The NRC staff evaluated the effect on safety margins when the RICT is applied to extend the CT up to a backstop of 30 days in a TS condition with sufficient trains remaining operable to fulfill the TS safety function. Although the licensee will be able to have design-basis equipment out of service longer than the current TSs allow, any increase in unavailability is expected to be relatively small and is addressed by the consideration of the single failure criterion in the design-basis analyses. Acceptance criteria for operability of equipment are not changed and ensure that sufficient trains remain operable to fulfill the TS safety function (i.e., the operability of the remaining train(s) will ensure that the current safety margins are maintained.) The staff finds that when the specified TS safety function remains feasible, sufficient safety margins would be maintained during the extended CT of the RICT Program.

Safety margins are also maintained if PRA functionality is determined for the inoperable train, which would result in an increased CT. Credit for PRA functionality, as described in NEI 06-09-A, is limited to the inoperable train, loss of offsite power (LOOP), or component.

Based on the above, the NRC staff finds that t he design-basis analyses for River Bend remain 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 staff finds that the proposed changes meet 10 CFR 50.55a(h), and therefore the third key principle of RGs 1.177and 1.174.

3.2.4 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 risk-informed approach described in Section 16.1 of the SRP and RG 1.177.

This approach addresses the calculated change in risk as measured by the change in core damage frequency (CDF) and large early release frequency (LERF), as well as the incremental conditional core damage probability and incremental conditional large early release probability; the use of compensatory measures to reduce ri sk; and the implementation of a configuration risk management program (CRMP) to identify ri sk-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. 1 In addition, the staff evaluated the licensees proposed changes against the three-tiered approach in RG 1.177 for the licensees evaluation of the risk associated with a proposed TS CT change. The results of the staffs review are discussed below.

3.2.4.1 Tier 1: PRA Capability and Insights

Tier 1 evaluates the impact of the proposed changes on plant operational risk. The Tier 1 review involves two aspects: (1) scope and acceptability of the PRA models and their application to the proposed changes, and (2) a review of the PRA results and insights described in the licensees application.

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

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

Internal Fire Events PRA (FPRA) model

Seismic Hazard: a CDF penalty of 3.93E-06 per year, and a LERF penalty of 5.34E-07 per year

Other External Hazards: screened out from RICT Program based on appendix 6-A of the American Society of Mechanical Engineers / American Nuclear Society (ASME/ANS) RA-Sa-2009, Standard for Level 1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications, Addendum A to RA-S-2008, (ASME/ANS RA-SA-2009 PRA Standard) (Reference 16)

3.2.4.1.1 Evaluation of Modeled PRAs

In enclosure 2 to the LAR, the licensee confirmed that the PRA models, which include internal events, internal flooding, and fire hazard PRA had been peer reviewed using the ASME/ANS RA-Sa-2009 PRA Standard as endorsed by RG 1.200, Revision 2. For the open facts and observations (F&Os) resulting from these peer reviews, the licensee stated that closure of the F&Os was performed using an independent assessment process consistent with Final Revision to Appendix X NEI 05-04/07-12/12-16, Close-out of Facts and Observations, dated February 21, 2017 (Reference 17), as endorsed in RG 1.200, Revision 2 and all F&Os were closed.

In enclosure 9, Key Assumptions and Sources of Uncertainty, to the LAR, as supplemented, the licensee provided a brief discussion on the screening and criteria for evaluating PRA assumptions and sources of uncertainty to identify those that are key for the application. The

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

licensee identified two key assumptions and sources of uncertainty that did not meet the screening criteria: (1) credit for containment airlock venting and (2) credit for recovery actions with limited procedural guidance. In its January 12, 2024, supplement, the licensee provided the results of sensitivity studies. For the first uncertainty item, the sensitivity studies showed significant impact on two potential RICT calculations. The licensee identified what additional RMAs would be instituted if either of these two RICTs were entered. The NRC staff determined that the use of additional RMAs is consistent with the guidance of NEI 06-09-A. For the second uncertainty item, the licensee showed that it does not adversely affect any calculated RICT.

With regards to whether digital I&C systems are credited in the PRA model, in response to APLA Question 04 in the LAR supplement, the licensee stated that the only system credited in the River Bend PRA with digital I&C is the control building chilled water system (system designator HVK). The licensee demonstrated low risk significance for the system. The NRC staff finds that based on the licensee's analysis of the minimal risk contribution its digital components adequately demonstrate that this source of uncertainty does not impact this application.

In its LAR, as supplemented, the licensee confirmed that the IEPRA (including internal flooding) and FPRA models credit permanently installed and portable equipment used as part of the diverse and flexible mitigation capability (FLEX) strategy and described how the modeling is consistent with the May 2022 NRC memorandum regarding the NRCs staff updated assessment of identified challenges and strategies for incorporating FLEX equipment into a PRA model in support of risk-informed decision-making in accordance with the guidance of RG 1.200. In its supplement, the licensee provided the results of a sensitivity study, which removed FLEX credit, demonstrating that FLEX does not significantly impact any RICT calculations. The licensee also proposed implementation item # 3 to update the appropriate basic events associated with the motor-driven centrifugal FLEX Pump 1 (FLX-P1) to increase the multiplier to a factor of 10, which is based upon updated data (i.e., change the multiplier applied to the NUREG/CR-6928, Industry-Average Performance for Components and Initiating Events at U.S. Commercial Nuclear Power Plants (Reference 18), motor-driven pump failure data from five to ten) and to address three recommendations related to documentation resulting from an independent review of FLEX modeling in the PRA. Based on the licensees description and the proposed implementation item, the NRC staff finds that the licensees credit for FLEX equipment in the TSTF-505 application is acceptable for the RICT Program because the licensee used consensus human reliability analysis methodologies and practices, failures rates, and performed sensitivity studies to assess the impact on the TSTF-505 application.

The NRC staff reviewed the PRA models peer review history provided by the licensee in enclosure 2 to the LAR, as supplemented. The licensee adequately applied the guidance for establishing PRA technical acceptability for the aforementioned models. The staff further considered the key assumptions and key sources of uncertainty identified by the licensee and credit for FLEX. Therefore, the staff finds the River Bend scope, and technical acceptability of the PRA modeled internal events (including internal flooding) and fire to be commensurate with the RICT application for use in the integrated decision-making process are consistent with RG 1.174.

3.2.4.1.2 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 19), and a plant-level high confidence of low probability of failure (HCLPF) capacity of 0.16g referenced to the peak ground acceleration (PGA). The uncertainty parameter for seismic capacity was represented by a composite variability factor ( c) of 0.4. The calculated seismic CDF penalty is 3.93E-06 per year. The staff finds that the method to determine the baseline seismic CDF is acceptable because it is consistent with the approach used in NRC Generic Issue (GI)-199, Implications of Updated Probabilistic Seismic Hazard Estimates in Central and Eastern United States on Existing Pl ants (Reference 20). In its supplement to the LAR, the licensee explained the basis for using a plant-level HCLPF value of 0.16g instead of that used for GI-199 for River Bend (0.10g). The staffs review finds the use of 0.16g for the plant-level HCLPF to be acceptable for this application, because the licensee used a scaling factor for seismic fragility based on a ratio of plant-specific seismic capacity (SSE) to seismic demand (GMRS) for a frequency range of interest from 1 hertz (Hz) to 10 Hz.

Concerning the proposed bounding seismic LERF estimate, the licensee explains in the LAR that an estimate of the seismic LERF is obtained by convolving the estimated seismic CDF (as described above) with a limiting fragility for containment integrity of 0.3g PGA HCLPF. The calculated seismic LERF is 5.34E-07 per year. The NRC staff finds that the licensees approach to estimating the seismic LERF is acceptable because the use of a 0.3g PGA HCLPF as the limiting fragility for containment integrity is conservative.

The licensee addressed the incremental risk associated with a seismic-induced LOOP in section 4.2, Seismically-Induced Loss of Offsite Power Challenges, of the LAR enclosure 4. A seismic LOOP frequency across the entire hazard interval is 3.36E-08 per year, which is about 5.2 percent of the total internal events 24-hour non-recovered LOOP frequency of 6.13E-07 per year already addressed in the IEPRA. The NRC staff evaluated the licensees analysis and finds that it adequately addresses the impact of a seismically-induced LOOP on risk and that the exclusion of the impact of a seismically-induced LOOP on risk from the non-recovered LOOP frequency has an insignificant impact on the RICT calculations.

The NRC staff finds that, during RICTs for st ructures, systems, and components (SSCs) credited in the design basis to mitigate seismic events, the licensees proposed methodology captures the risk associated with seismically induced failures of redundant SSCs because such SSCs are assumed to be fully correlated. By assuming full correlation, the seismic risk for those RICTs will not increase if one of the redundant SSCs is unavailable because simultaneous failure of all redundant trains would be assumed in a seismic PRA.

During RICTs for SSCs that are not credited in seismic events, the proposed methodology for considering seismic risk contributions is conservative because the seismically induced failure of such SSCs would not result in a risk increase associated with the plant configuration during the RICT, but the seismic penalty is still included in the calculation. During RICTs for SSCs that are credited in seismic events, the proposed methodology is acceptable for this application because the plant-level HCLPF value used for the RICT calculations provides a conservative estimate of HCLPF values for all the credited SSCs.

In summary, the NRC staff finds that the licensees proposal to use the seismic CDF contributions of 3.93E-06 per year and a seismic LERF contribution of 5.34E-07 per year to be acceptable for the licensees RICT Program for River Bend because, (1) the licensee used the most current site-specific seismic hazard informati on, (2) the licensee used a realistic plant-level HCLPF value of 0.16g PGA and a composite variability factor of 0.4, (3) the licensee determined a seismic LERF penalty based on its estimate of seismic CDF combined with a conservative

containment integrity fragility of 0.3g PGA HCLPF, and (4) adding a baseline seismic risk to RICT calculations, which assumes the fully correlated failures, is acceptable for this application.

3.2.4.1.3 Evaluation of Other External Hazards

Besides seismic hazard discussed above, the li censee concluded that other external hazards for River Bend have insignificant contribution and proposed that these hazards be screened out from the RICT Program. The licensee provided its assessment of other external hazard risk for the RICT Program in LAR enclosure 4. The hazards assessed in the LAR are those identified for consideration in non-mandatory appendix 6-A of the ASME/ANS RA-Sa-2009 PRA Standard, which provides a guide for identification of most of the possible external events for a plant site.

The NRC staff reviewed the information in the LAR, as supplemented, and finds that other external hazards, besides seismic, have an insignificant contribution to configuration risk and can be excluded from the calculation of the proposed RICTs because they either do not challenge the plant or they are bounded by the external hazards analyzed for the plant. The staff finds that the licensee appropriately screened out all other external hazards from consideration in the RICT Program because the licensees preliminary and progressive screening criteria used and presented in table E4-2, Progressive Screening Approach for Addressing External Hazards, of LAR enclosure 4 are the same criteria (i.e., EXT-B1, EXT-B2 and EXT-C1) in the ASME/ANS RA-Sa-2009 PRA Standard for screening external hazards and, therefore, are acceptable.

3.2.4.1.4 Application of PRA Models, Results, and Insights in the RICT Program

The River Bend base PRA models that are 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 and supplement, the licensee provided all information needed to support the requested LCO actions proposed for the River Bend RICT Program consistent with all the limitations and conditions described in section 4.0 of NEI 06-09-A.

LAR enclosure 8, Attributes of the Real-Time Model, section 2.0, Translation of Baseline Model for Use in Configuration Risk, identifies several specific modifications that are made to the baseline PRA model to produce the CRMP model, or the real time risk tool, that is used to make the RICT calculations. In response to APLA Question 05 in the LAR supplement, the licensee provided additional details on how adjustments to the CRMP model are made to reflect changing conditions that could affect the model and associated RICT calculations, such as seasonal variations and time in the core cycle that could impact the success criteria. The NRC staff finds that the licensees CRMP model is in accordance with NEI 06 A with respect to the treatment of changing plant conditions, such as the weather and seasonal variations, because it is capable of being adjusted in real-time to account for changing plant conditions or assesses these conditions conservatively for the RICT calculations.

LAR enclosure 1, table E1-1, identifies each TS LCO proposed to be included in the RICT Program, describes whether the systems and components involved in the TS LCO are explicitly modeled in the PRA or not, and compares the design basis and PRA success criteria. For certain TS LCO conditions, LAR table E1-1 illustrates that the associated SSCs are not explicitly modeled in the PRAs but will be represented using a surrogate event. In the LAR, the licensee

proposed Implementation Item Nos. 1 and 2 to update the PRA modeling and surrogates for LCO 3.3.1.1 Condition A and B (related to RPS instrumentation logic) and LCO 3.3.5.1, Conditions F and G, LCO 3.3.6.4, Condition A (related to the automatic depressurization system safety relief valve individual pilot valves). In response to APLA Question 01 in the LAR supplement, the licensee provided additional clarification on certain proposed LCO surrogates.

The NRC staff found the proposed LCO surrogates, with the proposed implementation items to update the PRA model, to be acceptable for the RICT Program.

The NRC staff did not identify any insufficiencies in the licensees information on the CRMP tool as described in the LAR, as supplemented. The staff finds that the River Bend PRA models and CRMP tool used will continue to reflect the as -built, as-operated plant consistent with RG 1.200, Revision 2 for ensuring PRA acceptability is maintained. Therefore, the staff concludes that the proposed application of the River Bend RICT Program is appropriate for use in the adoption of TSTF-505 for performing RICT calculations.

The licensee provided in enclosure 5 to the LAR, the estimated total CDF and LERF to of the base PRA models to demonstrate that River Bend meets the 1E -4/year CDF and 1E-5/year LERF criteria of RG 1.174 consistent with the guidance in NEI 06 A and that these guidelines will be satisfied for implementation of a RICT.

The licensee has incorporated NEI 06 A into proposed new TS 5.5.16. The estimated current total CDF and LERF for River Bend 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 A.

Based on the above conclusions 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., internal events (including internal flooding) and fire) evaluated PRA hazards, external hazards, and seismic methodology is appropriate for this application.

3.2.4.2 Tier 2: Avoidance of Risk -Significant Plant Configurations

As described in RG 1.177, Revision 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 2.0, RICT Program and Procedures, of enclosure 10, Program Implementation, to 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 to 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 w ill 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 large early release probability 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 guidance in RG 1.177, Revision 1,

and the licensees Tier 2 program is accept able and supports the proposed implementation of the RICT Program.

3.2.4.3 Tier 3: Risk-Informed Configuration Risk Management

Tier 3 of RG 1.177 stipulates that a licensee sh ould 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 to the LAR, 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 to the LAR provided the attributes that the licensees RICT Program procedures will address, which are consistent with NEI 06 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 A in the TS, as discussed in LAR attachment 1; 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.

3.2.4.4 Key Principle 4 Conclusions

The licensee has demonstrated the technical acceptability and scope of its PRA models and alternative methods, including consideration of the impact of seismic events, and other external hazards, and that the models can support implem entation 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 RGs 1.177 and 1.174. The RICT Program will be controlled administratively through plant procedures and training and follows the NRC-approved methodology in NEI 06 A. The NRC staff finds that the RICT Program satisfies the fourth key principle of RG 1.177 and is, therefore, acceptable.

3.2.5 Key Principle 5: Performance Measurem ent 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. In enclosure 11, Monitoring Program, to the LAR, the licensee 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 to 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 A.

The NRC staff finds that the RICT Program sati sfies 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 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.

3.3 Technical Conclusion

The NRC staff has evaluated the proposed changes against each of the five key principles in RGs 1.177 and 1.174, including the optional variations from the approved TSTF-505 discussed in section 3.0 of this SE. The staff concludes that the changes proposed by the licensee satisfy the key principles of risk-informed decisionm aking identified in RG 1.174, and RG 1.177 and, therefore, the requested adoption of the proposed changes to the TSs and associated guidance, is acceptable to assure the regulatory requirements of 10 CFR Part 50 identified in section 2.1 of this SE will continue to be met.

4.0 STATE CONSULTATION

In accordance with the Commissions regulations, the Louisiana State official was notified of the proposed issuance of the amendment on April 19, 2024. The State official had no comments.

5.0 ENVIRONMENTAL CONSIDERATION

The amendment changes a requirement with respect to the installation or use of a facility component located within the restricted area as defined in 10 CFR Part 20. The NRC staff has determined that the amendment involves no significant increase in the amounts, and no significant change in the types, of any effluents that may be released offsite, and that there is no significant increase in the individual or cumulative occupational radiation exposure. The Commission has previously issued a proposed finding that the amendment involves no significant hazards consideration published in Federal Register on July 11, 2023 (88 FR 44165),

and there has been no public comment on such finding. Accordingly, the amendment meets the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9). Pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the issuance of the amendment.

6.0 CONCLUSION

The Commission has concluded, based on the considerations discussed above, that: (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) there is reasonable assurance that such activities will be conducted in compliance with the Commissions regulations, and (3) the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public.

7.0 REFERENCES

1. Couture, P., Entergy, letter to NRC, License Amendment Request to Revise Technical Specifications to Adopt Risk Informed Completion Times TSTF-505, Revision 2, Provide Risk-Informed Extended Completion Times - RITSTF Initiative 4b, dated February 27, 2023 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML23058A215).

2. Couture, P., Entergy, letter to NRC, Supplement to License Amendment Request to Revise Technical Specifications to Adopt Risk Informed Completion Times TSTF-505, Revision 2, Provide Risk-Informed Extended Completion Times - RITSTF Initiative 4b, and Application to Adopt 10 CFR 50.69, Risk-Informed Categorization and Treatment of Structures, Systems, and Components for Nuclear Power Reactors dated January 12, 2024 (ML24016A248).

3. Technical Specifications Task Force, 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 (Package ML18183A493).

4. Cusumano, V. G., NRC, letter to TSTF, Final Revised Model Safety Evlaution of Traveler TSTF-505-, Revision 2, Provide Risk Informed Extended Competion Times -

RITSTF Initiative 4b, dated November 21, 2018 (Package ML18269A041).

5. Drake, J. J., NRC, letter to Entergy, River Bend Station, Unit 1 - Regulatory Audit Plan in Support of License Amendment Requests to Revise Technical Specifications to Adopt Risk-Informed Competion Times and Implement the Provisions of 10 CFR 50.69 (EPID L-2023-LLA-0037 and EPID L-2023-LLA-0038), dated October 6, 2023 (ML23278A240).

6. Drake, J. J., NRC, letter to Entergy, River Bend Station, Unit 1 - Summary of Regulatory Audit in Support of License Amendment Requests to Revise Technical Specifications to Adopt Risk-Informed Completion Times and Implement the Provisions of 10 CFR 50.69 (EPID L-2023-LLA-0037 and EPID L-2023-LLA-0038), dated May 6, 2024 (ML24102A284).

7. NRC, An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities, RG 1.200, Revision 2, dated March 2009 and RG 1.200, Revision 3, Acceptability of Probabilistic Risk Assessment Results for Risk-Informed Activities, dated December 2020 (ML090410014 and ML202338B871, respectively)

8. NRC, 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 and RG 1.174, Revision 3, dated January 2018 (ML100910006 and ML17317A256, respectively).

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

10. NRC, Guidance on the Treatment of Uncertainties Associated with PRAs in Risk-Informed Decisionmaking, NUREG 1855, Revision 1, Final Report, dated March 2017 (ML17062A466).

11. NRC, Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants, NUREG-0800 Section 16.1, Revision 1, Risk-Informed Decision Making:

Techncila Specifications, dated March 2007 (ML070380228).

12. NRC, Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants, NUREG-0800 Section 19.2, Review of Risk Information Used to Support Permanent Plant-Specific Changes to the Licensing Basis: General Guidance, dated June 2007 (ML071700658).

13. Bradley, B., NEI, letter to S. D. Stuchell, NRC, NEI 06-09, Risk-Informed Technical Specifications Initiative 4b: Risk-Managed Techn ical Specification (RMTS) Guidelines, Revision 0-A, dated October 2012 (Package ML122860402).

14. Golder, J. M., NRC, letter to B. Bradley, NEI, Final Safety Evaluation For Nuclear Energy Institute (NEI) Topical Report (TR) NEI 06 09, Risk-Informed Technical Specifications Initiative 4b, Risk-Managed Techn ical Specifications (RMTS) Guidelines,'

Revision 0-A, dated May 17, 2007 (ML071200238).

15. Entergy Operations, Inc., River Bend Stat ion, Unit 1, Updated Safety Analysis Report, USAR Revision 28, dated July 2023 (ML23209A761).

16. ASME/ANS, Standard for Level 1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications, Addendum A to RA-S-2008, PRA Standard ASME/ANS RA-Sa-2009, dated February 2009

17. Andersen, Victoria, NEI, letter to S. Rosenberg, NRC, Final Revision of Appendix X to NEI 05-04/07-12/12-16, Close-Out of Facts and Observations, dated February 21, 2017 (ADAMS Package Accession No. ML17086A431).

18. Idaho National Laboratory, Industry-Average Performance for Components and Initiating Events at U.S. Commercial Nuclear Power Plants, NUREG/CR 6928, dated February 2007 (ML070650650).

19. Mashburn, W. F., Entergy, letter to NRC, Entergy Operations Inc. Seismic Hazard and Screening Report (CEUS Sites), Response NRC Request for Information Pursuant to 10 CFR 50.54(f) Regarding Recommendation 2.1 of the Near-Term Task Force Review of Insights from the Fukushima Dai-ichi Accident, dated March 26, 2014 (ML14091A426).

- 20 -

20. Hiland, P., NRC, memorandum to B. W. Sheron, NRC, Safety/Risk Assessment Results for Generic Issue 199, Implications of Updated Probabilistic Seismic Hazard Estimates in Central and Eastern United States on Existing Plants, dated September 2, 2010 (Package ML100270582).

Principal Contributors: A. Schwab M.Biro C. Moulton T. Dinh S. Park E. Kleeh V.Goel M.Li K.West

Date: May 16, 2024

ML24081A007 *concurrence via email NRR-058 OFFICE NRR/DORL/LPL4/PM* NRR/DORL/LPL4/LA* NRR/DEX/EEEB/BC* NRR/DEX/EICB/BC*

NAME JDrake PBlechman WMorton FSacko DATE 4/5/2024 4/11/2023 w/comments 4/25/2024 4/22/2024 OFFICE NRR/DRA/APLA/BC* NRR/DRA/APLC/BC* NRR/DSS/SNSB/BC* NRR/DSS/SCPB/BC*

NAME RPascarelli SVasavada PSahd MValentin DATE 2/22/2024 4/22/2024 5/3/2024 4/25/2024 OFFICE NRR/DEX/EMIB* NRR/DSS/STSB/BC OGC - NLO* NRR/DORL/LPL4/BC*

NAME SBailey SMehta MCarpentier JRankin DATE 5/6/2025 5/10/2024 5/1/2024 5/16/2024 OFFICE NRR/DORL/LPL4/PM*

NAME JDrake DATE 5/16/2024

v t e Letter Sequence Approval
EPID:L-2023-LLA-0037, TSTF 505 (Approved, Closed)
Initiation Request, Request Acceptance, Acceptance Supplement Administration Questions Answers Results Approval, Approval Other: ML23089A070, ML23278A240
MONTHYEAR2023-04-04 [Table View]

ML24081A007

Text

SUBJECT:

Dear Vice President,

Enclosures:

Attachment:

1.0 INTRODUCTION

2.0 REGULATORY EVALUATION

3.0 TECHNICAL EVALUATION

4.0 STATE CONSULTATION

5.0 ENVIRONMENTAL CONSIDERATION

6.0 CONCLUSION

7.0 REFERENCES

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