Text

Issuance of Amendment No. 270 Revision to Technical Specifications to Adopt TSTF 505, Revision 2, Provide Risk-Informed Extended Completion Times-RITSTF Initiative 4B
	ML23013A081
Person / Time
Site:	Columbia
Issue date:	03/15/2023
From:	Mahesh Chawla; NRC/NRR/DORL/LPL4
To:	Schuetz R; Energy Northwest
References
	EPID L-2022-LLA-0023
	Download: ML23013A081 (1)
	v • d • e

March 15, 2023 Mr. Robert Schuetz Chief Executive Officer Energy Northwest 76 North Power Plant Loop P.O. Box 968, Mail Drop 1023 Richland, WA 99352

SUBJECT:

COLUMBIA GENERATING STATION - ISSUANCE OF AMENDMENT NO. 270 RE: REVISION TO TECHNICAL SPECIFICATIONS TO ADOPT TSTF-505, REVISION 2, PROVIDE RISK-INFORMED EXTENDED COMPLETION TIMES - RITSTF INITIATIVE 4b (EPID L-2022-LLA-0023)

Dear Mr. Schuetz:

The U.S. Nuclear Regulatory Commission (the Commission) has issued the enclosed Amendment No. 270 to Renewed Facility Operating License No. NPF-21 for the Columbia Generating Station. The amendment consists of changes to the technical specifications (TSs) in response to your application dated February 3, 2022, as supplemented by letters dated October 4, 2022, and November 28, 2022.

The amendment revises the TS requirements 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 issued a final model safety evaluation approving TSTF-505, Revision 2 on November 21, 2018.

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

Sincerely,

/RA/

Mahesh L. Chawla, Project Manager Plant Licensing Branch IV Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-397

Enclosures:

1. Amendment No. 270 to NPF-21

2. Safety Evaluation cc: Listserv

ENERGY NORTHWEST DOCKET NO. 50-397 COLUMBIA GENERATING STATION AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 270 License No. NPF-21

1.

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

A.

The application for amendment by Energy Northwest (the licensee), dated February 3, 2022, as supplemented by letters dated October 4, 2022, and November 28, 2022, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act) and the Commissions rules and regulations set forth in 10 CFR Chapter I; B.

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

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

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

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

2.

Accordingly, the license is amended by changes to the Technical Specifications as indicated in the attachment to this license amendment, and paragraph 2.C.(2) of Renewed Facility Operating License No. NPF-21 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. 270 and the Environmental Protection Plan contained in Appendix B, are hereby incorporated in the renewed license. The licensee 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.

FOR THE NUCLEAR REGULATORY COMMISSION Jennifer L. Dixon-Herrity, Chief Plant Licensing Branch IV Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Attachment:

Changes to Renewed Facility Operating License No. NPF-21 and the Technical Specifications Date of Issuance: March 15, 2023 Jennifer L.

Dixon-Herrity Digitally signed by Jennifer L. Dixon-Herrity Date: 2023.03.15 08:31:43 -04'00'

ATTACHMENT TO LICENSE AMENDMENT NO.270 TO RENEWED FACILITY OPERATING LICENSE NO. NPF-21 COLUMBIA GENERATING STATION DOCKET NO. 50-397 Replace the following pages of Renewed Facility Operating License No. NPF-21 and the Appendix A, Technical Specifications, with the attached revised pages. The revised pages are identified by amendment number and contain vertical lines indicating the areas of change.

Renewed Facility Operating License REMOVE INSERT Technical Specification REMOVE INSERT 1.3-11 1.3-11 1.3-12 3.1.7-1 3.1.7-1 3.3.1.1-1 3.3.1.1-1 3.3.1.1-2 3.3.1.1-2 3.3.1.1-3 3.3.1.1-3 3.3.1.1-4 3.3.1.1-4 3.3.1.1-5 3.3.1.1-5 3.3.1.1-6 3.3.1.1-6 3.3.1.1-7 3.3.1.1-7 3.3.1.1-8 3.3.1.1-8 3.3.1.1-9 3.3.1.1-9 3.3.1.1-10 3.3.1.1-10 3.3.1.1-11 3.3.1.1-12 3.3.2.2-1 3.3.2.2-1 3.3.4.1-1 3.3.4.1-1 3.3.4.1-2 3.3.4.1-2 3.3.4.1-3 3.3.4.1-3 3.3.4.2-1 3.3.4.2-1 3.3.4.2-2 3.3.4.2-2 3.3.5.1-2 3.3.5.1-2 3.3.5.1-3 3.3.5.1-3 3.3.5.1-4 3.3.5.1-4 3.3.5.1-5 3.3.5.1-5 3.3.5.1-6 3.3.5.1-6 3.3.5.1-7 3.3.5.1-7 3.3.5.1-8 3.3.5.1-8 3.3.5.1-9 3.3.5.1-9

Technical Specification (continued)

REMOVE INSERT 3.3.5.1-10 3.3.5.1-10 3.3.5.1-11 3.3.5.1-11 3.3.5.1-12 3.3.5.1-13 3.3.5.1-14 3.3.5.3-1 3.3.5.3-1 3.3.5.3-2 3.3.5.3-2 3.3.6.1-1 3.3.6.1-1 3.3.6.1-2 3.3.6.1-2 3.3.6.1-3 3.3.6.1-3 3.3.6.1-4 3.3.6.1-4 3.3.6.1-5 3.3.6.1-5 3.3.6.1-6 3.3.6.1-6 3.3.6.1-7 3.3.6.1-7 3.3.6.1-8 3.3.6.1-8 3.3.6.1-9 3.3.6.1-9 3.3.6.1-10 3.3.6.1-10 3.3.6.1-11 3.3.8.1-1 3.3.8.1-1 3.3.8.1-2 3.3.8.1-2 3.3.8.1-3 3.3.8.1-3 3.5.1-1 3.5.1-1 3.5.1-2 3.5.1-2 3.5.1-3 3.5.1-3 3.5.1-4 3.5.1-4 3.5.1-5 3.5.1-5 3.5.1-6 3.5.3-1 3.5.3-1 3.6.1.2-3 3.6.1.2-3 3.6.1.3-1 3.6.1.3-1 3.6.1.3-2 3.6.1.3-2 3.6.1.3-4 3.6.1.3-4 3.6.1.5-1 3.6.1.5-1 3.6.1.6-1 3.6.1.6-1 3.6.1.7-1 3.6.1.7-1 3.6.2.3-1 3.6.2.3-1 3.7.1-1 3.7.1-1 3.7.1-2 3.7.1-2 3.7.1-3 3.7.1-3 3.8.1-2 3.8.1-2 3.8.1-3 3.8.1-3 3.8.1-4 3.8.1-4 3.8.1-5 3.8.1-5 3.8.1-6 3.8.1-6 3.8.1-7 3.8.1-7 3.8.1-8 3.8.1-8 3.8.1-9 3.8.1-9

Technical Specification (continued)

REMOVE INSERT 3.8.1-10 3.8.1-10 3.8.1-11 3.8.1-11 3.8.1-12 3.8.1-12 3.8.1-13 3.8.1-13 3.8.1-14 3.8.1-14 3.8.4-1 3.8.4-1 3.8.4-2 3.8.4-2 3.8.4-3 3.8.4-3 3.8.4-4 3.8.4-4 3.8.4-5 3.8.7-1 3.8.7-1 3.8.7-2 3.8.7-2 5.5-12 5.5-12 5.5-13

Renewed License No. NPF-21 Amendment No. 270 (2)

Technical Specifications and Environmental Protection Plan The Technical Specifications contained in Appendix A, as revised through Amendment No. 270 and the Environmental Protection Plan contained in Appendix B, are hereby incorporated in the renewed license. The licensee shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

a. For Surveillance Requirements (SRs) not previously performed by existing SRs or other plant tests, the requirement will be considered met on the implementation date and the next required test will be at the interval specified in the Technical Specifications as revised in Amendment No. 149.

(3)

Deleted.

(4)

Deleted.

(5)

Deleted.

(6)

Deleted.

(7)

Deleted.

(8)

Deleted.

(9)

Deleted.

(10)

Deleted.

(11)

Deleted.

(12)

Deleted.

(13)

Deleted.

Completion Times 1.3 Columbia Generating Station 1.3-11 Amendment No. 259 270 1.3 Completion Times EXAMPLES (continued)

Required Action A.1 has two Completion Times. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time begins at the time the Condition is entered and each "Once per 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months thereafter" interval begins upon performance of Required Action A.1.

If after Condition A is entered, Required Action A.1 is not met within either the initial 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months or any subsequent 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months interval from the previous performance (plus the extension allowed by SR 3.0.2), Condition B is entered. The Completion Time clock for Condition A does not stop after 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 inoperable A.1 Restore subsystem to OPERABLE status.

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

B.1 Be in MODE 3.

AND B.2 Be in MODE 4.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 36 hours When a subsystem is declared inoperable, Condition A is entered. The 7 day Completion Time may be applied as discussed in Example 1.3-2.

However, the licensee may elect to apply the Risk Informed Completion Time Program which permits calculation of a Risk Informed Completion Time (RICT) that may be used to complete the Required Action beyond the 7 day Completion Time. The RICT cannot exceed 30 days. After the

Completion Times 1.3 Columbia Generating Station 1.3-12 Amendment No. 270 1.3 Completion Times EXAMPLES (continued) 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 Conditions 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.

SLC System 3.1.7 Columbia Generating Station 3.1.7-1 Amendment No. 169,199 225 238 270 3.1 REACTIVITY CONTROL SYSTEMS 3.1.7 Standby Liquid Control (SLC) System LCO 3.1.7 Two SLC subsystems shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, and 3.

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

A.1 Restore SLC subsystem to OPERABLE status.

7 days OR In accordance with the Risk Informed Completion Time Program B. Two SLC subsystems inoperable.

B.1 Restore one SLC subsystem to OPERABLE status.

8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months C. Required Action and associated Completion Time not met.

C.1 Be in MODE 3.

AND C.2 Be in MODE 4.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 36 hours SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.1.7.1 Verify available volume of sodium pentaborate solution is 4587 gallons.

In accordance with the Surveillance Frequency Control Program

RPS Instrumentation 3.3.1.1 Columbia Generating Station 3.3.1.1-1 Amendment No. 169 225 226 253 267 270 3.3 INSTRUMENTATION 3.3.1.1 Reactor Protection System (RPS) Instrumentation LCO 3.3.1.1 The RPS instrumentation for each Function in Table 3.3.1.1-1 shall be OPERABLE.

APPLICABILITY:

According to Table 3.3.1.1-1 ACTIONS

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

1.

Separate Condition entry is allowed for each channel.

2.

When Functions 2.b and 2.c channels are inoperable due to the calculated power exceeding the average power range monitor (APRM) output by more than 2% rated thermal power (RTP) while operating at 25% RTP, entry into associated Conditions and Required Actions may be delayed for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months .

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more required channels inoperable.

A.1 Place channel in trip.

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

NOTE---------

Not applicable when a loss of function occurs.

In accordance with the Risk Informed Completion Time Program

RPS Instrumentation 3.3.1.1 Columbia Generating Station 3.3.1.1-2 Amendment No. 169 225 226 253 270 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. continued

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

Not applicable for Functions 2.a, 2.b, 2.c, 2.d, or 2.f.

A.2 Place associated trip system in trip.

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

NOTE---------

Not applicable when a loss of function occurs.

In accordance with the Risk Informed Completion Time Program

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

Not applicable for Functions 2.a, 2.b, 2.c, 2.d, or 2.f.

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

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

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

NOTE---------

Not applicable when a loss of function occurs.

In accordance with the Risk Informed Completion Time Program

RPS Instrumentation 3.3.1.1 Columbia Generating Station 3.3.1.1-3 Amendment No. 169 225 226 253 270 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. continued B.2 Place one trip system in trip.

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

NOTE---------

Not applicable when a loss of function occurs.

In accordance with the Risk Informed Completion Time Program C. One or more Functions with RPS trip capability not maintained.

C.1 Restore RPS trip capability.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months D. Required Action and associated Completion Time of Condition A, B, or C not met.

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

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

E.1 Reduce THERMAL POWER to < 29.5% RTP.

4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months F. As required by Required Action D.1 and referenced in Table 3.3.1.1-1.

F.1 Be in MODE 2.

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

RPS Instrumentation 3.3.1.1 Columbia Generating Station 3.3.1.1-4 Amendment No. 179 225 226 253 267 270 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME G. As required by Required Action D.1 and referenced in Table 3.3.1.1-1.

G.1 Be in MODE 3.

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

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

Immediately I.

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

I.1 Initiate alternate method to detect and suppress thermal hydraulic instability oscillations.

AND

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

LCO 3.0.4 is not applicable.

I.2 Restore required channels to OPERABLE.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 120 days J. Required Action and associated Completion Time of Condition I not met.

J.1 Reduce THERMAL POWER to less than the value specified in the COLR.

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

RPS Instrumentation 3.3.1.1 Columbia Generating Station 3.3.1.1-5 Amendment No. 169 225 226 253 270 SURVEILLANCE REQUIREMENTS

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

1.

Refer to Table 3.3.1.1-1 to determine which SRs apply for each RPS Function.

2.

When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months provided the associated Function maintains RPS trip capability.

SURVEILLANCE FREQUENCY SR 3.3.1.1.1 Perform CHANNEL CHECK.

In accordance with the Surveillance Frequency Control Program SR 3.3.1.1.2

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

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

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

In accordance with the Surveillance Frequency Control Program SR 3.3.1.1.3

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

Not required to be performed when entering MODE 2 from MODE 1 until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after entering MODE 2.

Perform CHANNEL FUNCTIONAL TEST.

In accordance with the Surveillance Frequency Control Program SR 3.3.1.1.4 Perform CHANNEL FUNCTIONAL TEST.

In accordance with the Surveillance Frequency Control Program

RPS Instrumentation 3.3.1.1 Columbia Generating Station 3.3.1.1-6 Amendment No. 169 225 226 253 270 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.1.1.5 Verify the source range monitor (SRM) and intermediate range monitor (IRM) channels overlap.

Prior to withdrawing SRMs from the fully inserted position SR 3.3.1.1.6

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

Only required to be met during entry into MODE 2 from MODE 1.

Verify the IRM and APRM channels overlap.

In accordance with the Surveillance Frequency Control Program SR 3.3.1.1.7 Calibrate the local power range monitors.

In accordance with the Surveillance Frequency Control Program SR 3.3.1.1.8 Perform CHANNEL FUNCTIONAL TEST.

In accordance with the Surveillance Frequency Control Program SR 3.3.1.1.9 Deleted.

SR 3.3.1.1.10

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

1. Neutron detectors are excluded.

2. For Function 1, not required to be performed when entering MODE 2 from MODE 1 until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after entering MODE 2.

3. For Functions 2.b and 2.f, the recirculation flow transmitters that feed the APRMs are included.

Perform CHANNEL CALIBRATION.

In accordance with the Surveillance Frequency Control Program

RPS Instrumentation 3.3.1.1 Columbia Generating Station 3.3.1.1-7 Amendment No. 225 226 232 253 270 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.1.1.11 Deleted.

SR 3.3.1.1.12 Verify Turbine Throttle Valve - Closure, and Turbine Governor Valve Fast Closure Trip Oil Pressure - Low Functions are not bypassed when THERMAL POWER is 29.5% RTP.

In accordance with the Surveillance Frequency Control Program SR 3.3.1.1.13 Perform CHANNEL FUNCTIONAL TEST.

In accordance with the Surveillance Frequency Control Program SR 3.3.1.1.14 Perform LOGIC SYSTEM FUNCTIONAL TEST.

In accordance with the Surveillance Frequency Control Program SR 3.3.1.1.15

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

1. Neutron detectors are excluded.

2. Channel sensors for Functions 3 and 4 are excluded.

Verify the RPS RESPONSE TIME is within limits.

In accordance with the Surveillance Frequency Control Program

RPS Instrumentation 3.3.1.1 Columbia Generating Station 3.3.1.1-8 Amendment No. 225 226 253 270 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.1.1.16

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

1.

For Function 2.a, not required to be performed when entering MODE 2 from MODE 1 until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after entering MODE 2.

2.

For Functions 2.b and 2.f, the CHANNEL FUNCTIONAL TEST includes the recirculation flow input processing, excluding the flow transmitters.

Perform CHANNEL FUNCTIONAL TEST.

In accordance with the Surveillance Frequency Control Program SR 3.3.1.1.17 Verify the OPRM is not bypassed when APRM Simulated Thermal Power is greater than or equal to the value specified in the COLR and recirculation drive flow is less than the value specified in the COLR.

In accordance with the Surveillance Frequency Control Program

RPS Instrumentation 3.3.1.1 Columbia Generating Station 3.3.1.1-9 Amendment No. 169 225 226 253 270 Table 3.3.1.1-1 (page 1 of 4)

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

1.

Intermediate Range Monitors

a.

Neutron Flux - High 2

3 G

SR 3.3.1.1.1 SR 3.3.1.1.3 SR 3.3.1.1.5 SR 3.3.1.1.6 SR 3.3.1.1.10 SR 3.3.1.1.14 122/125 divisions of full scale 5(a) 3 H

SR 3.3.1.1.1 SR 3.3.1.1.4 SR 3.3.1.1.10 SR 3.3.1.1.14 122/125 divisions of full scale

b.

Inop 2

3 G

SR 3.3.1.1.3 SR 3.3.1.1.14 NA 5(a) 3 H

SR 3.3.1.1.4 SR 3.3.1.1.14 NA

2.

Average Power Range Monitors

a.

Neutron Flux - High (Setdown) 2 3(b)

G SR 3.3.1.1.1 SR 3.3.1.1.6 SR 3.3.1.1.7 SR 3.3.1.1.10(d),(e)

SR 3.3.1.1.16 20% RTP

b.

Simulated Thermal Power - High 1

3(b)

F SR 3.3.1.1.1 SR 3.3.1.1.2 SR 3.3.1.1.7 SR 3.3.1.1.10(d),(e)

SR 3.3.1.1.16 0.62W + 62.9% RTP and 114.9% RTP(c)

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

(b) Each APRM/OPRM channel provides inputs to both trip systems.

(c) 0.62W + 59.8% RTP and 114.9% RTP when reset for single loop operation per LCO 3.4.1, Recirculation Loops Operating.

(d) If the as-found channel setpoint is outside its predefined as-found tolerance, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service.

(e)

The instrument channel setpoint shall be reset to a value that is within the as-left tolerance around the Limiting Trip Setpoint (LTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable.

Setpoints more conservative than the LTSP are acceptable provided that the as-found and as-left tolerances apply to the actual setpoint implemented in the surveillance procedures (Nominal Trip Setpoint) to confirm channel performance. The LTSP and the methodologies used to determine the as-found and as-left tolerances are specified in the Licensee Controlled Specifications.

RPS Instrumentation 3.3.1.1 Columbia Generating Station 3.3.1.1-10 Amendment No. 225 226 232 241 253 270 Table 3.3.1.1-1 (page 2 of 4)

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

2.

Average Power Range Monitors

c.

Neutron Flux - High 1

3(b)

F SR 3.3.1.1.1 SR 3.3.1.1.2 SR 3.3.1.1.7 SR 3.3.1.1.10(d),(e)

SR 3.3.1.1.16 120% RTP

d.

Inop 1,2 3(b)

G SR 3.3.1.1.16 NA

e.

2-Out-of-4 Voter 1,2 2

G SR 3.3.1.1.1 SR 3.3.1.1.14 SR 3.3.1.1.15 SR 3.3.1.1.16 NA

f.

OPRM Upscale (f) 3(b)

I SR 3.3.1.1.1 SR 3.3.1.1.7 SR 3.3.1.1.10(d),(e)

SR 3.3.1.1.16 SR 3.3.1.1.17 NA(g)

(b) Each APRM/OPRM channel provides inputs to both trip systems.

(d) If the as-found channel setpoint is outside its predefined as-found tolerance, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service.

(e)

The instrument channel setpoint shall be reset to a value that is within the as-left tolerance around the Limiting Trip Setpoint (LTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable.

Setpoints more conservative than the LTSP are acceptable provided that the as-found and as-left tolerances apply to the actual setpoint implemented in the surveillance procedures (Nominal Trip Setpoint) to confirm channel performance. The LTSP and the methodologies used to determine the as-found and as-left tolerances are specified in the Licensee Controlled Specifications.

(f)

THERMAL POWER greater than or equal to the value specified in the COLR.

(g)

The OPRM Upscale does not have an Allowable Value. The Period Based Detection Algorithm (PBDA) trip setpoints are specified in the COLR.

RPS Instrumentation 3.3.1.1 Columbia Generating Station 3.3.1.1-11 Amendment No. 270 Table 3.3.1.1-1 (page 3 of 4)

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

3.

Reactor Vessel Steam Dome Pressure - High 1,2 2

G SR 3.3.1.1.8 SR 3.3.1.1.10 SR 3.3.1.1.14 SR 3.3.1.1.15 1079 psig

4.

Reactor Vessel Water Level - Low, Level 3 1,2 2

G SR 3.3.1.1.1 SR 3.3.1.1.8 SR 3.3.1.1.10 SR 3.3.1.1.14 SR 3.3.1.1.15 9.5 inches

5.

Main Steam Isolation Valve

- Closure 1

8 F

SR 3.3.1.1.8 SR 3.3.1.1.10 SR 3.3.1.1.14 SR 3.3.1.1.15 12.5% closed

6.

Primary Containment Pressure - High 1,2 2

G SR 3.3.1.1.8 SR 3.3.1.1.10 SR 3.3.1.1.14 1.88 psig

7.

Scram Discharge Volume Water Level - High

a.

Transmitter/Level Indicating Switch 1,2 2

G SR 3.3.1.1.1 SR 3.3.1.1.8 SR 3.3.1.1.10 SR 3.3.1.1.14 529 ft 9 inches elevation 5(a) 2 H

SR 3.3.1.1.1 SR 3.3.1.1.8 SR 3.3.1.1.10 SR 3.3.1.1.14 529 ft 9 inches elevation

b.

Transmitter/Level Switch 1,2 2

G SR 3.3.1.1.8 SR 3.3.1.1.10(d)(e)

SR 3.3.1.1.14 529 ft 9 inches elevation 5(a) 2 H

SR 3.3.1.1.8 SR 3.3.1.1.10(d)(e)

SR 3.3.1.1.14 529 ft 9 inches elevation (a)

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

(d)

If the as-found channel setpoint is outside its predefinded as-found tolerance, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service.

(e)

The instrument channel setpoint shall be reset to a value that is within the as-left tolerance around the Limiting Trip Setpoint (LTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable.

Setpoints more conservative than the LTSP are acceptable provided that the as-found and as-left tolerances apply to the actual setpoint implemented in the surveillance procedures (Nominal Trip Setpoint) to confirm channel performance. The LTSP and the methodologies used to determine the as-found and the as-left tolerances are specified in the Licensee Controlled Specifications.

RPS Instrumentation 3.3.1.1 Columbia Generating Station 3.3.1.1-12 Amendment No. 270 Table 3.3.1.1-1 (page 4 of 4)

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

8.

Turbine Throttle Valve -

Closure 29.5% RTP 4

E SR 3.3.1.1.8 SR 3.3.1.1.10 SR 3.3.1.1.12 SR 3.3.1.1.14 SR 3.3.1.1.15 7% closed

9.

Turbine Governor Valve Fast Closure, Trip Oil Pressure - Low 29.5% RTP 2

E SR 3.3.1.1.8 SR 3.3.1.1.10 SR 3.3.1.1.12 SR 3.3.1.1.14 SR 3.3.1.1.15 1000 psig

10.

Reactor Mode Switch -

Shutdown Position 1,2 2

G SR 3.3.1.1.13 SR 3.3.1.1.14 NA 5(a) 2 H

SR 3.3.1.1.13 SR 3.3.1.1.14 NA

11.

Manual Scram 1,2 2

G SR 3.3.1.1.4 SR 3.3.1.1.14 NA 5(a) 2 H

SR 3.3.1.1.4 SR 3.3.1.1.14 NA (a)

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

Feedwater and Main Turbine High Water Level Trip Instrumentation 3.3.2.2 Columbia Generating Station 3.3.2.2-1 Amendment No. 149,169 225 270 3.3 INSTRUMENTATION 3.3.2.2 Feedwater and Main Turbine High Water Level Trip Instrumentation LCO 3.3.2.2 Three channels of feedwater and main turbine high water level trip instrumentation shall be OPERABLE.

APPLICABILITY:

THERMAL POWER 25% RTP.

ACTIONS

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

Separate Condition entry is allowed for each channel.

CONDITION REQUIRED ACTION COMPLETION TIME A. One feedwater and main turbine high water level trip channel inoperable.

A.1 Place channel in trip.

7 days OR In accordance with the Risk Informed Completion Time Program B. Two or more feedwater and main turbine high water level trip channels inoperable.

B.1 Restore feedwater and main turbine high water level trip capability.

2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months C. Required Action and associated Completion Time not met.

C.1 Reduce THERMAL POWER to < 25% RTP.

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

EOC-RPT Instrumentation 3.3.4.1 Columbia Generating Station 3.3.4.1-1 Amendment No. 149,169 225 241 270 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 Throttle Valve (TTV) - Closure; and

2.

Turbine Governor Valve (TGV) Fast Closure, Trip Oil Pressure

- Low.

OR

b.

LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)," limits for inoperable EOC-RPT as specified in the COLR are made applicable.

APPLICABILITY:

THERMAL POWER 29.5% RTP.

ACTIONS

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

Separate Condition entry is allowed for each channel.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more required channels inoperable.

A.1 Restore channel to OPERABLE status.

OR 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

EOC-RPT Instrumentation 3.3.4.1 Columbia Generating Station 3.3.4.1-2 Amendment No. 149,169 225 238 241 270 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. continued A.2

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

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

Place channel in trip.

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 with EOC-RPT trip capability not maintained.

AND MCPR limit for inoperable EOC-RPT not made applicable.

B.1 Restore EOC-RPT trip capability.

OR B.2 Apply the MCPR limit for inoperable EOC-RPT as specified in the COLR.

2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months 2 hours C. Required Action and associated Completion Time not met.

C.1 Remove the associated recirculation pump from service.

OR C.2 Reduce THERMAL POWER to < 29.5% RTP.

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

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

When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months provided the associated Function maintains EOC-RPT trip capability.

EOC-RPT Instrumentation 3.3.4.1 Columbia Generating Station 3.3.4.1-3 Amendment No. 168,169 225 238 241 270 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.4.1.1 Perform CHANNEL FUNCTIONAL TEST.

In accordance with the Surveillance Frequency Control Program SR 3.3.4.1.2.a Perform CHANNEL CALIBRATION. The Allowable Value shall be:

TTV - Closure: 7% closed.

In accordance with the Surveillance Frequency Control Program SR 3.3.4.1.2.b Perform CHANNEL CALIBRATION. The Allowable Value shall be:

TGV Fast Closure, Trip Oil Pressure - Low:

1000 psig.

In accordance with the Surveillance Frequency Control Program SR 3.3.4.1.3 Verify TTV - Closure and TGV Fast Closure, Trip Oil Pressure - Low Functions are not bypassed when THERMAL POWER is 29.5% RTP.

In accordance with the Surveillance Frequency Control Program SR 3.3.4.1.4 Perform LOGIC SYSTEM FUNCTIONAL TEST, including breaker actuation.

In accordance with the Surveillance Frequency Control Program SR 3.3.4.1.5

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

Breaker arc suppression time may be assumed from the most recent performance of SR 3.3.4.1.6.

Verify the EOC-RPT SYSTEM RESPONSE TIME is within limits.

In accordance with the Surveillance Frequency Control Program SR 3.3.4.1.6 Determine RPT breaker arc suppression time.

In accordance with the Surveillance Frequency Control Program

ATWS-RPT Instrumentation 3.3.4.2 Columbia Generating Station 3.3.4.2-1 Amendment No. 149,169 225 270 3.3 INSTRUMENTATION 3.3.4.2 Anticipated Transient Without Scram Recirculation Pump Trip (ATWS-RPT)

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

a.

Reactor Vessel Water Level - Low Low, Level 2; and

b.

Reactor Vessel Steam Dome Pressure - High.

APPLICABILITY:

MODE 1.

ACTIONS

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

Separate Condition entry is allowed for each channel.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more channels inoperable.

A.1 Restore channel to OPERABLE status.

OR A.2

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

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

Place channel in trip.

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

ATWS-RPT Instrumentation 3.3.4.2 Columbia Generating Station 3.3.4.2-2 Amendment No. 149,169 225 238 270 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. One Function with ATWS-RPT trip capability not maintained.

B.1 Restore ATWS-RPT trip capability.

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months C. Both Functions with ATWS-RPT trip capability not maintained.

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

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months D. Required Action and associated Completion Time not met.

D.1 Remove the associated recirculation pump from service.

OR D.2 Be in MODE 2.

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

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

When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months provided the associated Function maintains ATWS-RPT trip capability.

SURVEILLANCE FREQUENCY SR 3.3.4.2.1 Perform CHANNEL CHECK for Reactor Vessel Water Level - Low Low, Level 2 Function.

In accordance with the Surveillance Frequency Control Program SR 3.3.4.2.2 Perform CHANNEL FUNCTIONAL TEST.

In accordance with the Surveillance Frequency Control Program

ECCS Instrumentation 3.3.5.1 Columbia Generating Station 3.3.5.1-2 Amendment No. 149,169 225 251 270 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. (continued)

B.2

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

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

Declare High Pressure Core Spray (HPCS) System inoperable.

AND B.3 Place channel in trip.

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

ECCS Instrumentation 3.3.5.1 Columbia Generating Station 3.3.5.1-3 Amendment No. 149,169 225 251 270 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C. As required by Required Action A.1 and referenced in Table 3.3.5.1-1.

C.1

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

Only applicable for Functions 1.c, 1.d, 1.e, 1.f, 2.c, 2.d, 2.e, and 2.f.

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

AND C.2 Restore channel to OPERABLE status.

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

NOTE----------

Not applicable when a loss of function occurs.

In accordance with the Risk Informed Completion Time Program

ECCS Instrumentation 3.3.5.1 Columbia Generating Station 3.3.5.1-4 Amendment No. 149,169 225 270 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME D. As required by Required Action A.1 and referenced in Table 3.3.5.1-1.

D.1

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

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

Declare HPCS System inoperable.

AND D.2.1 Place channel in trip.

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

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

ECCS Instrumentation 3.3.5.1 Columbia Generating Station 3.3.5.1-5 Amendment No. 150,169 225 238 270 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME E. As required by Required Action A.1 and referenced in Table 3.3.5.1-1.

E.1

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

Only applicable for Functions 1.g, 1.h, and 2.g.

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

AND E.2 Restore channel to OPERABLE status.

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

NOTE----------

Not applicable when a loss of function occurs.

In accordance with the Risk Informed Completion Time Program

ECCS Instrumentation 3.3.5.1 Columbia Generating Station 3.3.5.1-6 Amendment No. 169 172, 225 238 270 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME F. As required by Required Action A.1 and referenced in Table 3.3.5.1-1.

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

AND F.2 Place channel in trip.

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

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

ECCS Instrumentation 3.3.5.1 Columbia Generating Station 3.3.5.1-7 Amendment No. 169 172, 225 238 251 270 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME G. As required by Required Action A.1 and referenced in Table 3.3.5.1-1.

G.1

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

Only applicable for Functions 4.b, 4.d, 4.e, 5.b, and 5.d.

Declare ADS valves inoperable.

AND G.2 Restore channel to OPERABLE status.

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

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 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

ECCS Instrumentation 3.3.5.1 Columbia Generating Station 3.3.5.1-8 Amendment No. 166, 169 225 238 251 270 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME H. Required Action and associated Completion Time of Condition B, C, D, E, F, or G not met.

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

Immediately SURVEILLANCE REQUIREMENTS

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

1.

Refer to Table 3.3.5.1-1 to determine which SRs apply for each ECCS Function.

2.

When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed as follows: (a) for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months for Functions 3.c, 3.f, and 3.g; and (b) for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months for Functions other than 3.c, 3.f, and 3.g provided the associated Function or the redundant Function maintains ECCS initiation capability.

SURVEILLANCE FREQUENCY SR 3.3.5.1.1 Perform CHANNEL CHECK.

In accordance with the Surveillance Frequency Control Program SR 3.3.5.1.2 Perform CHANNEL FUNCTIONAL TEST.

In accordance with the Surveillance Frequency Control Program SR 3.3.5.1.3 Perform CHANNEL CALIBRATION.

In accordance with the Surveillance Frequency Control Program

ECCS Instrumentation 3.3.5.1 Columbia Generating Station 3.3.5.1-9 Amendment No. 166, 169 225 238 251 270 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.5.1.4 Perform CHANNEL CALIBRATION.

In accordance with the Surveillance Frequency Control Program SR 3.3.5.1.5 Perform CHANNEL CALIBRATION.

In accordance with the Surveillance Frequency Control Program SR 3.3.5.1.6 Perform LOGIC SYSTEM FUNCTIONAL TEST.

In accordance with the Surveillance Frequency Control Program

ECCS Instrumentation 3.3.5.1 Columbia Generating Station 3.3.5.1-10 Amendment No. 166, 169 225 238 251 270 Table 3.3.5.1-1 (page 1 of 5)

Emergency Core Cooling System Instrumentation FUNCTION APPLICABLE MODES OR OTHER SPECIFIED CONDITIONS REQUIRED CHANNELS PER FUNCTION CONDITIONS REFERENCED FROM REQUIRED ACTION A.1 SURVEILLANCE REQUIREMENTS ALLOWABLE VALUE

1. Low Pressure Coolant Injection-A (LPCI) and Low Pressure Core Spray (LPCS)

Subsystems

a.

Reactor Vessel Water Level - Low Low Low, Level 1 1, 2, 3 2(b)

B SR 3.3.5.1.1 SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6

-142.3 inches

b.

Drywell Pressure -

High 1, 2, 3 2(b)

B SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6 1.88 psig

c.

LPCS Pump Start -

LOCA Time Delay Relay 1, 2, 3 1(e)

C SR 3.3.5.1.5 SR 3.3.5.1.6 8.53 seconds and 10.64 seconds

d.

LPCI Pump A Start -

LOCA Time Delay Relay 1, 2, 3 1(e)

C SR 3.3.5.1.5 SR 3.3.5.1.6 17.24 seconds and 21.53 seconds

e.

LPCI Pump A Start -

LOCA/LOOP Time Delay Relay 1, 2, 3 1

C SR 3.3.5.1.2 SR 3.3.5.1.3 SR 3.3.5.1.6 3.04 seconds and 6.00 seconds

f.

Reactor Vessel Pressure - Low (Injection Permissive) 1, 2, 3 1 per valve C

SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6 448 psig and 492 psig (a)

Deleted (b)

Also required to initiate the associated diesel generator (DG).

(e)

Also supports OPERABILITY of 230 kV offsite power circuit pursuant to LCO 3.8.1 and LCO 3.8.2.

ECCS Instrumentation 3.3.5.1 Columbia Generating Station 3.3.5.1-11 Amendment No.238 270 Table 3.3.5.1-1 (page 2 of 5)

Emergency Core Cooling System Instrumentation FUNCTION APPLICABLE MODES OR OTHER SPECIFIED CONDITIONS REQUIRED CHANNELS PER FUNCTION CONDITIONS REFERENCED FROM REQUIRED ACTION A.1 SURVEILLANCE REQUIREMENTS ALLOWABLE VALUE

1. LPCI and LPCS Subsystems

g.

LPCS Pump Discharge Flow -

Low (Minimum Flow) 1, 2, 3 1

E SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6 668 gpm and 1067 gpm

h.

LPCI Pump A Discharge Flow -

Low (Minimum Flow) 1, 2, 3 1

E SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6 605 gpm and 984 gpm

i.

Manual Initiation 1, 2, 3 2

C SR 3.3.5.1.6 NA

2. LPCI B and LPCI C Subsystems

a.

Reactor Vessel Water Level - Low Low Low, Level 1 1, 2, 3 2(b)

B SR 3.3.5.1.1 SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6

-142.3 inches

b.

Drywell Pressure -

High 1, 2, 3 2(b)

B SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6 1.88 psig

c.

LPCI Pump B Start -

LOCA Time Delay Relay 1, 2, 3 1(e)

C SR 3.3.5.1.5 SR 3.3.5.1.6 17.24 seconds and 21.53 seconds

d.

LPCI Pump C Start -

LOCA Time Delay Relay 1, 2, 3 1(e)

C SR 3.3.5.1.5 SR 3.3.5.1.6 8.53 seconds and 10.64 seconds

e.

LPCI Pump B Start -

LOCA/LOOP Time Delay Relay 1, 2, 3 1

C SR 3.3.5.1.2 SR 3.3.5.1.3 SR 3.3.5.1.6 3.04 seconds and 6.00 seconds (a)

Deleted (b)

Also required to initiate the associated DG.

(e)

Also supports OPERABILITY of 230 kV offsite power circuit pursuant to LCO 3.8.1 and LCO 3.8.2.

ECCS Instrumentation 3.3.5.1 Columbia Generating Station 3.3.5.1-12 Amendment No. 270 Table 3.3.5.1-1 (page 3 of 5)

Emergency Core Cooling System Instrumentation FUNCTION APPLICABLE MODES OR OTHER SPECIFIED CONDITIONS REQUIRED CHANNELS PER FUNCTION CONDITIONS REFERENCED FROM REQUIRED ACTION A.1 SURVEILLANCE REQUIREMENTS ALLOWABLE VALUE

2. LPCI B and LPCI C Subsystems

f.

Reactor Vessel Pressure - Low (Injection Permissive) 1, 2, 3, 1 per valve C

SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6 448 psig and 492 psig

g.

LPCI Pumps B & C Discharge Flow -

Low (Minimum flow) 1, 2, 3 1 per pump E

SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6 605 gpm and 984 gpm

h.

Manual Initiation 1, 2, 3 2

C SR 3.3.5.1.6 NA

3. High Pressure Core Spray (HPCS) System

a.

Reactor Vessel Water Level - Low Low, Level 2 1, 2, 3 4(b)

B SR 3.3.5.1.1 SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6

-58 inches

b.

Drywell Pressure -

High 1, 2, 3 4(b)

B SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6 1.88 psig

c.

Reactor Vessel Water Level - High, Level 8 1, 2, 3 2

C SR 3.3.5.1.1 SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6 56.0 inches

d.

Condensate Storage Tank Level - Low 1, 2, 3 2

D SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6 448 ft 1 inch elevation (a)

Deleted (b)

Also required to initiate the associated DG.

(c)

Deleted

ECCS Instrumentation 3.3.5.1 Columbia Generating Station 3.3.5.1-13 Amendment No. 270 Table 3.3.5.1-1 (page 4 of 5)

Emergency Core Cooling System Instrumentation FUNCTION APPLICABLE MODES OR OTHER SPECIFIED CONDITIONS REQUIRED CHANNELS PER FUNCTION CONDITIONS REFERENCED FROM REQUIRED ACTION A.1 SURVEILLANCE REQUIREMENTS ALLOWABLE VALUE

3. HPCS System

e.

Suppression Pool Water Level - High 1, 2, 3 2

D SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6 466 ft 11 inches elevation

f.

HPCS System Flow Rate - Low (Minimum Flow) 1, 2, 3 1

E SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6 1200 gpm and 1512 gpm

g.

Manual Initiation 1, 2, 3 2

C SR 3.3.5.1.6 NA

4. Automatic Depressurization System (ADS) Trip System A

a.

Reactor Vessel Water Level - Low Low Low, Level 1 1, 2(d), 3(d) 2 F

SR 3.3.5.1.1 SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6

-142.3 inches

b.

ADS Initiation Timer 1, 2(d), 3(d) 1 G

SR 3.3.5.1.2 SR 3.3.5.1.3 SR 3.3.5.1.6 115.0 seconds

c.

Reactor Vessel Water Level - Low, Level 3 (Permissive) 1, 2(d), 3(d) 1 F

SR 3.3.5.1.1 SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6 9.5 inches

d.

LPCS Pump Discharge Pressure

- High 1, 2(d), 3(d) 2 G

SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6 119 psig and 171 psig

e.

LPCI Pump A Discharge Pressure

- High 1, 2(d), 3(d) 2 G

SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6 116 psig and 134 psig (a)

Deleted (d)

With reactor steam dome pressure > 150 psig.

ECCS Instrumentation 3.3.5.1 Columbia Generating Station 3.3.5.1-14 Amendment No. 270 Table 3.3.5.1-1 (page 5 of 5)

Emergency Core Cooling System Instrumentation FUNCTION APPLICABLE MODES OR OTHER SPECIFIED CONDITIONS REQUIRED CHANNELS PER FUNCTION CONDITIONS REFERENCED FROM REQUIRED ACTION A.1 SURVEILLANCE REQUIREMENTS ALLOWABLE VALUE

4. ADS Trip System A

f.

Accumulator Backup Compressed Gas System Pressure -

Low 1, 2(d), 3(d) 3 F

SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6 151.4 psig

g.

Manual Initiation 1, 2(d), 3(d) 4 G

SR 3.3.5.1.6 NA

5. ADS Trip System B

a.

Reactor Vessel Water Level - Low Low Low, Level 1 1, 2(d), 3(d) 2 F

SR 3.3.5.1.1 SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6

-142.3 inches

b.

ADS Initiation Timer 1, 2(d), 3(d) 1 G

SR 3.3.5.1.2 SR 3.3.5.1.3 SR 3.3.5.1.6 115.0 seconds

c.

Reactor Vessel Water Level -

Low, Level 3 (Permissive) 1, 2(d), 3(d) 1 F

SR 3.3.5.1.1 SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6 9.5 inches

d.

LPCI Pumps B & C Discharge Pressure

- High 1, 2(d), 3(d) 2 per pump G

SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6 116 psig and 134 psig

e.

Accumulator Backup Compressed Gas System Pressure -

Low 1, 2(d), 3(d) 3 F

SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6 151.4 psig

f.

Manual Initiation 1, 2(d), 3(d) 4 G

SR 3.3.5.1.6 NA (d)

With reactor steam dome pressure > 150 psig.

RCIC System Instrumentation 3.3.5.3 Columbia Generating Station 3.3.5.3-1 Amendment No. 251 270 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 inoperable.

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

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

B.1 Declare RCIC System inoperable.

AND B.2 Place channel in trip.

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

RCIC System Instrumentation 3.3.5.3 Columbia Generating Station 3.3.5.3-2 Amendment No. 251 270 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C. As required by Required Action A.1 and referenced in Table 3.3.5.3-1.

C.1 Restore channel to OPERABLE status.

24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months D. As required by Required Action A.1 and referenced in Table 3.3.5.3-1.

D.1

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

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

Declare RCIC System inoperable.

AND D.2.1 Place channel in trip.

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

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

NOTE---------

Not applicable when a loss of function occurs.

In accordance with the Risk Informed Completion Time Program 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months E. Required Action and associated Completion Time of Condition B, C, or D not met.

E.1 Declare RCIC System inoperable.

Immediately

Primary Containment Isolation Instrumentation 3.3.6.1 Columbia Generating Station 3.3.6.1-1 Amendment No. 169,208 225 270 3.3 INSTRUMENTATION 3.3.6.1 Primary Containment Isolation Instrumentation LCO 3.3.6.1 The primary containment isolation instrumentation for each Function in Table 3.3.6.1-1 shall be OPERABLE.

APPLICABILITY:

According to Table 3.3.6.1-1.

ACTIONS

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

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

2. Separate Condition entry is allowed for each channel.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more required channels inoperable.

A.1 Place channel in trip.

NOTE---------

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

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months or in accordance with the Risk Informed Completion Time Program for Functions 2.a, 2.c, 5.d, 6.a, and 6.b 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 for Functions other than Functions 2.a, 2.c, 5.d, 6.a, and 6.b

Primary Containment Isolation Instrumentation 3.3.6.1 Columbia Generating Station 3.3.6.1-2 Amendment No. 149,169 225 270 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. One or more automatic Functions with isolation capability not maintained.

B.1 Restore isolation capability.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months C. Required Action and associated Completion Time of Condition A or B not met.

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

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

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

OR D.2.1 Be in MODE 3.

AND D.2.2 Be in MODE 4.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 12 hours 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months E. As required by Required Action C.1 and referenced in Table 3.3.6.1-1.

E.1 Be in MODE 2.

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

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

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months G. As required by Required Action C.1 and referenced in Table 3.3.6.1-1.

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

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

Primary Containment Isolation Instrumentation 3.3.6.1 Columbia Generating Station 3.3.6.1-3 Amendment No. 149,169 225 238 264 270 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME H. Required Action and associated Completion Time of Condition F or G not met.

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

H.1 Be in MODE 3.

AND H.2 Be in MODE 4.

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

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

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

OR I.2 Isolate the Reactor Water Cleanup (RWCU) System.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months 1 hour J. As required by Required Action C.1 and referenced in Table 3.3.6.1-1.

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

Immediately SURVEILLANCE REQUIREMENTS

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

1.

Refer to Table 3.3.6.1-1 to determine which SRs apply for each Primary Containment Isolation Function.

2.

When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months provided the associated Function maintains isolation capability.

Primary Containment Isolation Instrumentation 3.3.6.1 Columbia Generating Station 3.3.6.1-4 Amendment No. 150,169 225 238 253 270 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.6.1.1 Perform CHANNEL CHECK.

In accordance with the Surveillance Frequency Control Program SR 3.3.6.1.2 Perform CHANNEL FUNCTIONAL TEST.

In accordance with the Surveillance Frequency Control Program SR 3.3.6.1.3 Perform CHANNEL FUNCTIONAL TEST.

In accordance with the Surveillance Frequency Control Program SR 3.3.6.1.4 Perform CHANNEL CALIBRATION.

In accordance with the Surveillance Frequency Control Program SR 3.3.6.1.5 Perform CHANNEL CALIBRATION.

In accordance with the Surveillance Frequency Control Program SR 3.3.6.1.6 Perform LOGIC SYSTEM FUNCTIONAL TEST.

In accordance with the Surveillance Frequency Control Program

Primary Containment Isolation Instrumentation 3.3.6.1 Columbia Generating Station 3.3.6.1-5 Amendment No. 214,219,225,241 270 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.6.1.7

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

Channel sensors for Functions 1.a, 1.b, and 1.c are excluded.

Verify the ISOLATION SYSTEM RESPONSE TIME is within limits.

In accordance with the Surveillance Frequency Control Program

Primary Containment Isolation Instrumentation 3.3.6.1 Columbia Generating Station 3.3.6.1-6 Amendment No. 169,172 225 270 Table 3.3.6.1-1 (page 1 of 6)

Primary Containment Isolation Instrumentation FUNCTION APPLICABLE MODES OR OTHER SPECIFIED CONDITIONS REQUIRED CHANNELS PER TRIP SYSTEM CONDITIONS REFERENCED FROM REQUIRED ACTION C.1 SURVEILLANCE REQUIREMENTS ALLOWABLE VALUE

1. Main Steam Line Isolation

a.

Reactor Vessel Water Level - Low Low Low, Level 1 1, 2, 3 2

D SR 3.3.6.1.1 SR 3.3.6.1.2 SR 3.3.6.1.4 SR 3.3.6.1.6 SR 3.3.6.1.7

-142.3 inches

b.

Main Steam Line Pressure - Low 1

2 E

SR 3.3.6.1.2 SR 3.3.6.1.4 SR 3.3.6.1.6 SR 3.3.6.1.7 804 psig

c.

Main Steam Line Flow - High 1, 2, 3 2 per MSL D

SR 3.3.6.1.1 SR 3.3.6.1.2 SR 3.3.6.1.4 SR 3.3.6.1.6 SR 3.3.6.1.7 137.9 psid

d.

Condenser Vacuum

- Low 1, 2(a), 3(a) 2 D

SR 3.3.6.1.2 SR 3.3.6.1.4 SR 3.3.6.1.6 7.2 inches Hg vacuum

e.

Main Steam Tunnel Temperature - High 1, 2, 3 2

D SR 3.3.6.1.3 SR 3.3.6.1.4 SR 3.3.6.1.6 170F

f.

Main Steam Tunnel Differential Temperature - High 1,2,3 2

D SR 3.3.6.1.3 SR 3.3.6.1.4 SR 3.3.6.1.6 90F

g.

Manual Initiation 1, 2, 3 4

G SR 3.3.6.1.6 NA

2. Primary Containment Isolation

a.

Reactor Vessel Water Level - Low, Level 3 1, 2, 3 2

F SR 3.3.6.1.1 SR 3.3.6.1.2 SR 3.3.6.1.4 SR 3.3.6.1.6 9.5 inches (a) With any turbine throttle valve not closed.

Primary Containment Isolation Instrumentation 3.3.6.1 Columbia Generating Station 3.3.6.1-7 Amendment No. 169,172 225 253 270 Table 3.3.6.1-1 (page 2 of 6)

Primary Containment Isolation Instrumentation FUNCTION APPLICABLE MODES OR OTHER SPECIFIED CONDITIONS REQUIRED CHANNELS PER TRIP SYSTEM CONDITIONS REFERENCED FROM REQUIRED ACTION C.1 SURVEILLANCE REQUIREMENTS ALLOWABLE VALUE

2. Primary Containment Isolation

b.

Reactor Vessel Water Level - Low Low, Level 2 1, 2, 3 2(e)

H SR 3.3.6.1.2 SR 3.3.6.1.4 SR 3.3.6.1.6

-58 inches

c.

Drywell Pressure -

High 1, 2, 3 2(e)

H SR 3.3.6.1.2 SR 3.3.6.1.4 SR 3.3.6.1.6 1.88 psig

d.

Reactor Building Vent Exhaust Plenum Radiation -

High 1, 2, 3 2

F SR 3.3.6.1.1 SR 3.3.6.1.2 SR 3.3.6.1.4 SR 3.3.6.1.6 16.0 mR/hr

e.

Manual Initiation 1, 2, 3 4

G SR 3.3.6.1.6 NA

3. Reactor Core Isolation Cooling (RCIC) System Isolation

a.

RCIC Steam Line Flow - High 1, 2, 3 1

F SR 3.3.6.1.1 SR 3.3.6.1.2 SR 3.3.6.1.4 SR 3.3.6.1.6 250 inches wg

b.

RCIC Steam Line Flow - Time Delay 1, 2, 3 1

F SR 3.3.6.1.2 SR 3.3.6.1.4 SR 3.3.6.1.6 3.00 seconds

c.

RCIC Steam Supply Pressure - Low 1, 2, 3 2

F SR 3.3.6.1.2 SR 3.3.6.1.4 SR 3.3.6.1.6 61 psig

d.

RCIC Turbine Exhaust Diaphragm Pressure - High 1, 2, 3 2

F SR 3.3.6.1.2 SR 3.3.6.1.4 SR 3.3.6.1.6 20 psig (e)

Also required to initiate the associated LOCA Time Delay Relay Function pursuant to LCO 3.3.5.1.

Primary Containment Isolation Instrumentation 3.3.6.1 Columbia Generating Station 3.3.6.1-8 Amendment No. 172,199 225 253 270 Table 3.3.6.1-1 (page 3 of 6)

Primary Containment Isolation Instrumentation FUNCTION APPLICABLE MODES OR OTHER SPECIFIED CONDITIONS REQUIRED CHANNELS PER TRIP SYSTEM CONDITIONS REFERENCED FROM REQUIRED ACTION C.1 SURVEILLANCE REQUIREMENTS ALLOWABLE VALUE

3. RCIC System Isolation

e.

RCIC Equipment Room Area Temperature - High 1, 2, 3 1

F SR 3.3.6.1.3 SR 3.3.6.1.4 SR 3.3.6.1.6 180F

f.

RCIC Equipment Room Area Differential Temperature - High 1, 2, 3 1

F SR 3.3.6.1.3 SR 3.3.6.1.4 SR 3.3.6.1.6 60F

g.

Reactor Water Cleanup (RWCU)

System /RCIC Steam Line Routing Area Temperature -

High 1, 2, 3 1

F SR 3.3.6.1.3 SR 3.3.6.1.4 SR 3.3.6.1.6 180F

h.

Manual Initiation 1, 2, 3 1(b)

G SR 3.3.6.1.6 NA

4. RWCU System Isolation

a.

Differential Flow -

High 1, 2, 3 1

F SR 3.3.6.1.1 SR 3.3.6.1.2 SR 3.3.6.1.5 SR 3.3.6.1.6 67.4 gpm

b.

Differential Flow -

Time Delay 1, 2, 3 1

F SR 3.3.6.1.2 SR 3.3.6.1.5 SR 3.3.6.1.6 46.5 seconds

c.

Blowdown Flow -

High 1, 2, 3 1

F SR 3.3.6.1.1 SR 3.3.6.1.2 SR 3.3.6.1.5 SR 3.3.6.1.6 SR 3.3.6.1.7 271.7 gpm

d.

Heat Exchanger Room Area Temperature - High 1, 2, 3 1

F SR 3.3.6.1.3 SR 3.3.6.1.4 SR 3.3.6.1.6 160F (b)

RCIC Manual Initiation only inputs into one of the two trip systems.

Primary Containment Isolation Instrumentation 3.3.6.1 Columbia Generating Station 3.3.6.1-9 Amendment No. 161,169 225 251 253 270 Table 3.3.6.1-1 (page 4 of 6)

Primary Containment Isolation Instrumentation FUNCTION APPLICABLE MODES OR OTHER SPECIFIED CONDITIONS REQUIRED CHANNELS PER TRIP SYSTEM CONDITIONS REFERENCED FROM REQUIRED ACTION C.1 SURVEILLANCE REQUIREMENTS ALLOWABLE VALUE

4. RWCU System Isolation

e.

Heat Exchanger Room Area Ventilation Differential Temperature - High 1, 2, 3 1

F SR 3.3.6.1.3 SR 3.3.6.1.4 SR 3.3.6.1.6 70F

f.

Pump Room Area Temperature - High 1, 2, 3 1 per room F

SR 3.3.6.1.3 SR 3.3.6.1.4 SR 3.3.6.1.6 180F

g.

Pump Room Area Ventilation Differential Temperature - High 1, 2, 3 1 per room F

SR 3.3.6.1.3 SR 3.3.6.1.4 SR 3.3.6.1.6 100F

h.

RWCU/RCIC Line Routing Area Temperature - High 1, 2, 3 1

F SR 3.3.6.1.3 SR 3.3.6.1.4 SR 3.3.6.1.6 180F

i.

RWCU Line Routing Area Temperature -

High 1, 2, 3 1 per room F

SR 3.3.6.1.3 SR 3.3.6.1.4 SR 3.3.6.1.6 Room 409, 509 Areas 175F Room 408, 511 Areas 180F

j.

Reactor Vessel Water Level - Low Low, Level 2 1, 2, 3 2

F SR 3.3.6.1.2 SR 3.3.6.1.4 SR 3.3.6.1.6

-58 inches

k.

Standby Liquid Control (SLC)

System Initiation 1, 2, 3 2(c)

I SR 3.3.6.1.6 NA

l.

Manual Initiation 1, 2, 3 2

G SR 3.3.6.1.6 NA (c) SLC System Initiation only inputs into one of the two trip systems.

Primary Containment Isolation Instrumentation 3.3.6.1 Columbia Generating Station 3.3.6.1-10 Amendment No. 208,220 225 270 Table 3.3.6.1-1 (page 5 of 6)

Primary Containment Isolation Instrumentation FUNCTION APPLICABLE MODES OR OTHER SPECIFIED CONDITIONS REQUIRED CHANNELS PER TRIP SYSTEM CONDITIONS REFERENCED FROM REQUIRED ACTION C.1 SURVEILLANCE REQUIREMENTS ALLOWABLE VALUE

5. Residual Heat Removal (RHR) Shutdown Cooling (SDC) System Isolation

a.

Pump Room Area Temperature - High 3

1 per room F

SR 3.3.6.1.3 SR 3.3.6.1.4 SR 3.3.6.1.6 150F

b.

Pump Room Area Ventilation Differential Temperature - High 3

1 per room F

SR 3.3.6.1.3 SR 3.3.6.1.4 SR 3.3.6.1.6 70F

c.

Heat Exchanger Area Temperature -

High 3

1 per room F

SR 3.3.6.1.3 SR 3.3.6.1.4 SR 3.3.6.1.6 Room 505 Area 140F Room 507 Area 160F Room 605 Area 150F Room 606 Area 140F

d.

Reactor Vessel Water Level - Low, Level 3 3

2 J

SR 3.3.6.1.1 SR 3.3.6.1.2 SR 3.3.6.1.4 SR 3.3.6.1.6 9.5 inches

e.

Reactor Vessel Pressure - High 1, 2, 3 1

F SR 3.3.6.1.2 SR 3.3.6.1.4 SR 3.3.6.1.6 135 psig

f.

Manual Initiation 1, 2, 3 2

G SR 3.3.6.1.6 NA (d)

Deleted

Primary Containment Isolation Instrumentation 3.3.6.1 Columbia Generating Station 3.3.6.1-11 Amendment No. 270 Table 3.3.6.1-1 (page 6 of 6)

Primary Containment Isolation Instrumentation FUNCTION APPLICABLE MODES OR OTHER SPECIFIED CONDITIONS REQUIRED CHANNELS PER TRIP SYSTEM CONDITIONS REFERENCED FROM REQUIRED ACTION C.1 SURVEILLANCE REQUIREMENTS ALLOWABLE VALUE

6. Traversing Incore Probe Isolation

a.

Reactor Vessel Water Level - Low, Low, Level 2 1, 2, 3 2

G SR 3.3.6.1.2 SR 3.3.6.1.4 SR 3.3.6.1.6

-58 inches

b.

Drywell Pressure -

High 1, 2, 3 2

G SR 3.3.6.1.2 SR 3.3.6.1.4 SR 3.3.6.1.6 1.88 psig

LOP Instrumentation 3.3.8.1 Columbia Generating Station 3.3.8.1-1 Amendment No. 149,169 225 264 270 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 required channels inoperable.

A.1 Enter the Condition referenced in Table 3.3.8.1-1 for the channel.

Immediately B. As required by Required Action A.1 and referenced in Table 3.3.8.1-1.

B.1 Declare associated DG inoperable.

AND B.2 Restore channel to OPERABLE status.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months from discovery of loss of initiation capability for the associated DG 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

LOP Instrumentation 3.3.8.1 Columbia Generating Station 3.3.8.1-2 Amendment No. 149,169 225 238 270 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C. As required by Required Action A.1 and referenced in Table 3.3.8.1-1.

C.1 Place channel in trip.

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

NOTE----------

Not applicable when a loss of function occurs.

In accordance with the Risk Informed Completion Time Program D. Required Action and associated Completion Time of Condition B or C not met.

D.1 Declare associated DG inoperable.

OR

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

Only applicable for Functions 1.c and 1.d.

D.2.1 Open offsite circuit supply breaker to associated 4.16 kV ESF bus.

AND D.2.2 Declare associated offsite circuit inoperable.

Immediately Immediately Immediately

LOP Instrumentation 3.3.8.1 Columbia Generating Station 3.3.8.1-3 Amendment No. 149,169 225 238 253 270 SURVEILLANCE REQUIREMENTS

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

1.

Refer to Table 3.3.8.1-1 to determine which SRs apply for each LOP Function.

2.

When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months provided the associated Function maintains initiation capability.

SURVEILLANCE FREQUENCY SR 3.3.8.1.1 Perform CHANNEL FUNCTIONAL TEST.

In accordance with the Surveillance Frequency Control Program SR 3.3.8.1.2 Perform CHANNEL CALIBRATION.

In accordance with the Surveillance Frequency Control Program SR 3.3.8.1.3 Perform CHANNEL CALIBRATION.

In accordance with the Surveillance Frequency Control Program SR 3.3.8.1.4 Perform LOGIC SYSTEM FUNCTIONAL TEST.

In accordance with the Surveillance Frequency Control Program

ECCS - Operating 3.5.1 Columbia Generating Station 3.5.1-1 Amendment No. 187 225 230 245 251 253 264 270 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS), RPV WATER INVENTORY CONTROL, AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM 3.5.1 ECCS - Operating LCO 3.5.1 Each ECCS injection/spray subsystem and the Automatic Depressurization System (ADS) function of six safety/relief valves shall be OPERABLE.

APPLICABILITY:

MODE 1, MODES 2 and 3, except ADS valves are not required to be OPERABLE with reactor steam dome pressure 150 psig.

ACTIONS

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

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

CONDITION REQUIRED ACTION COMPLETION TIME A. One low pressure ECCS injection/spray subsystem inoperable.

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

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

ECCS - Operating 3.5.1 Columbia Generating Station 3.5.1-2 Amendment No. 149,169,225,236 270 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B HPCS System inoperable.

B.1 Verify by administrative means RCIC System is OPERABLE when RCIC System is required to be OPERABLE.

AND B.2 Restore HPCS System to OPERABLE status.

Immediately 14 days OR In accordance with the Risk Informed Completion Time Program C. Two ECCS injection subsystems inoperable.

OR One ECCS injection and one ECCS spray subsystem inoperable.

C.1 Restore ECCS injection/spray subsystem to OPERABLE status.

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR In accordance with the Risk Informed Completion Time Program D. Required Action and associated Completion Time of Condition A, B, or C not met.

D.1

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

LCO 3.0.4.a is not 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 E. One required ADS valve inoperable.

E.1 Restore ADS valve to OPERABLE status.

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

ECCS - Operating 3.5.1 Columbia Generating Station 3.5.1-3 Amendment No. 149,169,225,236 270 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME F.

One required ADS valve inoperable.

AND One low pressure ECCS injection/spray subsystem inoperable.

F.1 Restore ADS valve to OPERABLE status.

OR F.2 Restore low pressure ECCS injection/spray subsystem to OPERABLE status.

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR In accordance with the Risk Informed Completion Time Program 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR In accordance with the Risk Informed Completion Time Program G. Required Action and associated Completion Time of Condition E or F not met.

OR Two or more required ADS valves inoperable.

G.1

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

LCO 3.0.4.a is not 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

ECCS - Operating 3.5.1 Columbia Generating Station 3.5.1-4 Amendment No. 169,205,225,229,236 238 243 246 249 270 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME H. HPCS and Low Pressure Core Spray (LPCS) Systems inoperable.

OR Three or more ECCS injection/spray subsystems inoperable.

OR HPCS System and one or more required ADS valves inoperable.

OR Two or more ECCS injection/spray subsystems and one or more required ADS valves inoperable.

H.1 Enter LCO 3.0.3.

Immediately SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.5.1.1 Verify, for each ECCS injection/spray subsystem, locations susceptible to gas accumulation are sufficiently filled with water.

In accordance with the Surveillance Frequency Control Program

ECCS - Operating 3.5.1 Columbia Generating Station 3.5.1-5 Amendment No. 169,205,225,236 238 246 249 270 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.5.1.2

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

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

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

In accordance with the Surveillance Frequency Control Program SR 3.5.1.3 Verify ADS accumulator backup compressed gas system average pressure in the required bottles is 2200 psig.

In accordance with the Surveillance Frequency Control Program SR 3.5.1.4 Verify each ECCS pump develops the specified flow rate with the specified differential pressure between reactor and suction source.

DIFFERENTIAL PRESSURE BETWEEN REACTOR AND SYSTEM FLOW RATE SUCTION SOURCE LPCS 6200 gpm 128 psid LPCI 7200 gpm 26 psid HPCS 6350 gpm 200 psid In accordance with the INSERVICE TESTING PROGRAM SR 3.5.1.5

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

Vessel injection/spray may be excluded.

Verify each ECCS injection/spray subsystem actuates on an actual or simulated automatic initiation signal.

In accordance with the Surveillance Frequency Control Program

ECCS - Operating 3.5.1 Columbia Generating Station 3.5.1-6 Amendment No. 270 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.5.1.6

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

Valve actuation may be excluded.

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

In accordance with the Surveillance Frequency Control Program SR 3.5.1.7

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

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

Verify each required ADS valve opens when manually actuated.

In accordance with the Surveillance Frequency Control Program SR 3.5.1.8

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

ECCS actuation instrumentation is excluded.

Verify the ECCS RESPONSE TIME for each ECCS injection/spray subsystem is within limits.

In accordance with the Surveillance Frequency Control Program

RCIC System 3.5.3 Columbia Generating Station 3.5.3-1 Amendment No. 169,187 225 251 270 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 means High Pressure Core Spray System is OPERABLE.

AND A.2 Restore RCIC System to OPERABLE status.

Immediately 14 days OR In accordance with the Risk Informed Completion Time Program B. Required Action and associated Completion Time not met.

B.1 Be in MODE 3.

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

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

Primary Containment Air Lock 3.6.1.2 Columbia Generating Station 3.6.1.2-3 Amendment No. 149,169 225 270 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. (continued)

B.3

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

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

Verify an OPERABLE door is locked closed.

Once per 31 days C. Primary containment air lock inoperable for reasons other than Condition A or B.

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

AND C.2 Verify a door is closed.

AND C.3 Restore air lock to OPERABLE status.

Immediately 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months 24 hours OR In accordance with the Risk Informed Completion Time Program D. Required Action and associated Completion Time not met.

D.1 Be in MODE 3.

AND D.2 Be in MODE 4.

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

PCIVs 3.6.1.3 Columbia Generating Station 3.6.1.3-1 Amendment No. 169,208 225 251 270 3.6 CONTAINMENT SYSTEMS 3.6.1.3 Primary Containment Isolation Valves (PCIVs)

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

APPLICABILITY:

MODES 1, 2, and 3 ACTIONS

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

1.

Penetration flow paths may be unisolated intermittently under administrative controls.

2.

Separate Condition entry is allowed for each penetration flow path.

3.

Enter applicable Conditions and Required Actions for systems made inoperable by PCIVs.

4.

Enter applicable Conditions and Required Actions of LCO 3.6.1.1, "Primary Containment,"

when PCIV leakage results in exceeding overall containment leakage rate acceptance criteria.

CONDITION REQUIRED ACTION COMPLETION TIME A. ------------NOTE------------

Only applicable to penetration flow paths with two PCIVs.

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

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

AND 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months or in accordance with the Risk Informed Completion Time Program except for main steam line AND 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months or in accordance with the Risk Informed Completion Time Program for main steam line

PCIVs 3.6.1.3 Columbia Generating Station 3.6.1.3-2 Amendment No. 169,208 225 270 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. (continued)

A.2

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

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

2. Isolation devices that are locked, sealed, or otherwise secured may be verified by use of administrative means.

Verify the affected penetration flow path is isolated.

Once per 31 days following isolation for isolation devices outside primary containment AND Prior to entering MODE 2 or 3 from MODE 4 if primary containment was de-inerted while in MODE 4, if not performed within the previous 92 days, for isolation devices inside primary containment

PCIVs 3.6.1.3 Columbia Generating Station 3.6.1.3-4 Amendment No. 169,208 225 270 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C. (continued)

C.2

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

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

2. Isolation devices that are locked, sealed, or otherwise secured may be verified by use of administrative means.

Verify the affected penetration flow path is isolated.

Once per 31 days following isolation for isolation devices outside primary containment AND Prior to entering MODE 2 or 3 from MODE 4 if primary containment was de-inerted while in MODE 4, if not performed within the previous 92 days, for isolation devices inside primary containment

RHR Drywell Spray 3.6.1.5 Columbia Generating Station 3.6.1.5-1 Amendment No. 149,169,225,230,236 245 270 3.6 CONTAINMENT SYSTEMS 3.6.1.5 Residual Heat Removal (RHR) Drywell Spray LCO 3.6.1.5 Two RHR drywell spray subsystems shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, and 3.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One RHR drywell spray subsystem inoperable.

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

7 days OR In accordance with the Risk Informed Completion Time Program B. Two RHR drywell spray subsystems inoperable.

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

8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months C. Required Action and associated Completion Time not met.

C.1

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

LCO 3.0.4.a is not 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

Reactor Building-to-Suppression Chamber Vacuum Breakers 3.6.1.6 Columbia Generating Station 3.6.1.6-1 Amendment No. 149,169,225,236 270 3.6 CONTAINMENT SYSTEMS 3.6.1.6 Reactor Building-to-Suppression Chamber Vacuum Breakers LCO 3.6.1.6 Each reactor building-to-suppression chamber vacuum breaker shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, and 3.

ACTIONS

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

Separate Condition entry is allowed for each line.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more lines with one reactor building-to-suppression chamber vacuum breaker not closed.

A.1 Close the open vacuum breaker.

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months B. One or more lines with two reactor building-to-suppression chamber vacuum breakers not closed.

B.1 Close one open vacuum breaker.

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months C. One line with one or more reactor building-to-suppression chamber vacuum breakers inoperable for opening.

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

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

D.1

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

LCO 3.0.4.a is not 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 .

Suppression Chamber-to-Drywell Vacuum Breakers 3.6.1.7 Columbia Generating Station 3.6.1.7-1 Amendment No.149,169,225,236 270 3.6 CONTAINMENT SYSTEMS 3.6.1.7 Suppression Chamber-to-Drywell Vacuum Breakers LCO 3.6.1.7 Seven suppression chamber-to-drywell vacuum breakers shall be OPERABLE for opening.

AND Nine suppression chamber-to-drywell vacuum breakers shall be closed, except when performing their intended function.

APPLICABILITY:

MODES 1, 2, and 3.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One required suppression chamber-to-drywell vacuum breaker inoperable for opening.

A.1 Restore one vacuum breaker to OPERABLE status.

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR In accordance with the Risk Informed Completion Time Program B. Required Action and associated Completion Time of Condition A not met.

B.1

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

LCO 3.0.4.a is not 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 C. ------------NOTE------------

Separate Condition entry is allowed for each suppression chamber-to-drywell vacuum breaker.

One or more suppression chamber-to-drywell vacuum breakers with one disk not closed.

C.1 Close the open vacuum breaker disk.

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

RHR Suppression Pool Cooling 3.6.2.3 Columbia Generating Station 3.6.2.3-1 Amendment No. 149,169,225,230,236 245 270 3.6 CONTAINMENT SYSTEMS 3.6.2.3 Residual Heat Removal (RHR) Suppression Pool Cooling LCO 3.6.2.3 Two RHR suppression pool cooling subsystems shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, and 3.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One RHR suppression pool cooling subsystem inoperable.

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

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

B.1

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

LCO 3.0.4.a is not 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 C. Two RHR suppression pool cooling subsystems inoperable.

C.1 Be in MODE 3.

AND C.2 Be in MODE 4.

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

SW System and UHS 3.7.1 Columbia Generating Station 3.7.1-1 Amendment No. 195,205,225 270 3.7 PLANT SYSTEMS 3.7.1 Standby Service Water (SW) System and Ultimate Heat Sink (UHS)

LCO 3.7.1 Division 1 and 2 SW subsystems and UHS shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, and 3.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Average sediment depth in one or both spray ponds 0.5 ft and

< 1.0 ft.

A.1 Restore average sediment depth to within limits.

30 days B. One SW subsystem inoperable.

B.1

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

1. Enter applicable Conditions and Required Actions of LCO 3.8.1, "AC Sources -

Operating," for diesel generator made inoperable by SW System.

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 SW System.

SW System and UHS 3.7.1 Columbia Generating Station 3.7.1-2 Amendment No. 149,169,225,233,236 238 270 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. continued Restore SW subsystem to OPERABLE status.

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR In accordance with the Risk Informed Completion Time Program C. Required Action and associated Completion Time of Condition B not met.

C.1

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

LCO 3.0.4.a is not 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 D. Required Action and associated Completion Time of Condition A not met.

OR Both SW subsystems inoperable.

OR UHS inoperable for reasons other than Condition A.

D.1 Be in MODE 3.

AND D.2 Be in MODE 4.

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

SW System and UHS 3.7.1 Columbia Generating Station 3.7.1-3 Amendment No. 149,169,225,236 238 270 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.1.1 Verify the average water level in the UHS spray ponds is 432 feet 9 inches mean sea level.

In accordance with the Surveillance Frequency Control Program SR 3.7.1.2 Verify the average water temperature of each UHS spray pond is 77F.

In accordance with the Surveillance Frequency Control Program SR 3.7.1.3

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

Isolation of flow to individual components does not render SW subsystem inoperable.

Verify each SW subsystem manual, power operated, and automatic valve in the flow path servicing safety related systems or components, that is not locked, sealed, or otherwise secured in position, is in the correct position.

In accordance with the Surveillance Frequency Control Program SR 3.7.1.4 Verify average sediment depth in each UHS spray pond is < 0.5 ft.

In accordance with the Surveillance Frequency Control Program SR 3.7.1.5 Verify each SW subsystem actuates on an actual or simulated initiation signal.

In accordance with the Surveillance Frequency Control Program

AC Sources - Operating 3.8.1 Columbia Generating Station 3.8.1-2 Amendment No. 195,197,225 265 270 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. (continued)

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

AND A.3 Restore offsite circuit to OPERABLE status.

24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months from discovery of no offsite power to one division concurrent with inoperability of redundant required feature(s) 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 required DG inoperable.

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

AND B.2 Declare required feature(s),

supported by the inoperable DG, inoperable when the redundant required feature(s) are inoperable.

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

AC Sources - Operating 3.8.1 Columbia Generating Station 3.8.1-3 Amendment No. 197,205 225 265 270 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. (continued)

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

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

AND B.4.1 Restore required DG to OPERABLE status.

OR B.4.2.1 Establish risk management actions for the alternate AC sources.

AND B.4.2.2 Restore required DG to OPERABLE status.

24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 24 hours if not performed within the past 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 72 hours from discovery of an inoperable DG OR In accordance with the Risk Informed Completion Time Program 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months 14 days OR In accordance with the Risk Informed Completion Time Program

AC Sources - Operating 3.8.1 Columbia Generating Station 3.8.1-4 Amendment No. 169,197,225 270 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C. Two offsite circuits inoperable.

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

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

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

AND One required DG inoperable.

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

Enter applicable Conditions and Required Actions of LCO 3.8.7, "Distribution Systems - Operating,"

when Condition D is entered with no AC power source to any division.

D.1 Restore offsite circuit to OPERABLE status.

OR D.2 Restore required DG to OPERABLE status.

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

AC Sources - Operating 3.8.1 Columbia Generating Station 3.8.1-5 Amendment No. 169,181,225,236 238 270 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME E. Two required DGs inoperable.

E.1 Restore one required DG to OPERABLE status.

2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months OR 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months if Division 3 DG is inoperable F. Required Action and associated Completion Time of Condition A, B, C, D, or E not met.

F.1

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

LCO 3.0.4.a is not 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 G. Three or more required AC sources inoperable.

G.1 Enter LCO 3.0.3.

Immediately SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.1 Verify correct breaker alignment and indicated power availability for each offsite circuit.

In accordance with the Surveillance Frequency Control Program

AC Sources - Operating 3.8.1 Columbia Generating Station 3.8.1-6 Amendment No. 173,215 225 238 270 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.2

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

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

2. A modified DG start involving idling and gradual acceleration to synchronous speed may be used for this SR as recommended by the manufacturer.

When modified start procedures are not used, the time, voltage, and frequency tolerances of SR 3.8.1.7 must be met.

Verify each required DG starts from standby conditions and achieves steady state:

a. Voltage 3910 V and 4400 V and frequency 58.8 Hz and 61.2 Hz for DG-1 and DG-2; and

b. Voltage 3910 V and 4400 V and frequency 58.8 Hz and 61.2 Hz for DG-3.

In accordance with the Surveillance Frequency Control Program SR 3.8.1.3

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

1.

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

2.

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

3.

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

4.

This SR shall be preceded by, and immediately follow, without shutdown, a successful performance of SR 3.8.1.2 or SR 3.8.1.7.

5.

The endurance test of SR 3.8.1.14 may be performed in lieu of the load-run test in SR 3.8.1.3 provided the requirements, except the upper load limits, of SR 3.8.1.3 are met.

Verify each required DG is synchronized and loaded and operates for 60 minutes at a load 4000 kW and 4400 kW for DG-1 and DG-2, and 2340 kW and 2600 kW for DG-3.

In accordance with the Surveillance Frequency Control Program

AC Sources - Operating 3.8.1 Columbia Generating Station 3.8.1-7 Amendment No. 181,204 225 238 270 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.4 Verify each required day tank contains fuel oil to support greater than or equal to one hour of operation at full load plus 10%.

In accordance with the Surveillance Frequency Control Program SR 3.8.1.5 Check for and remove accumulated water from each required day tank.

In accordance with the Surveillance Frequency Control Program SR 3.8.1.6 Verify each required fuel oil transfer subsystem operates to automatically transfer fuel oil from the storage tank to the day tank.

In accordance with the Surveillance Frequency Control Program SR 3.8.1.7

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

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

Verify each required DG starts from standby condition and achieves:

a. For DG-1 and DG-2 in 15 seconds, voltage 3910 V and frequency 58.8 Hz, and after steady state conditions are reached, maintains voltage 3910 V and 4400 V and frequency 58.8 Hz and 61.2 Hz; and

b. For DG-3, in 15 seconds, voltage 3910 V and frequency 58.8 Hz, and after steady state conditions are reached, maintains voltage 3910 V and 4400 V and frequency 58.8 Hz and 61.2 Hz.

In accordance with the Surveillance Frequency Control Program

AC Sources - Operating 3.8.1 Columbia Generating Station 3.8.1-8 Amendment No. 203,204 225 238 270 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.8

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

The automatic transfer function of this Surveillance shall not normally be performed in MODE 1 or 2.

However, this Surveillance may be performed to re-establish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced. Credit may be taken for unplanned events that satisfy this SR.

Verify automatic and manual transfer of the power supply to safety related buses from the startup offsite circuit to the backup offsite circuit.

In accordance with the Surveillance Frequency Control Program SR 3.8.1.9

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

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

2. If performed with the DG synchronized with offsite power, it shall be performed at a power factor as close to the power factor of the single largest post-accident load as practicable.

However, if grid conditions do not permit, the power factor limit is not required to be met.

Under this condition, the power factor shall be maintained as close to the limit as practicable.

Verify each required DG rejects a load greater than or equal to its associated single largest post-accident load, and following load rejection, the frequency is 66.75 Hz.

In accordance with the Surveillance Frequency Control Program

AC Sources - Operating 3.8.1 Columbia Generating Station 3.8.1-9 Amendment No. 203,204 225 238 270 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.10

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

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

2. If performed with the DG synchronized with offsite power, it shall be performed at a power factor of 0.9 for DG-1 and DG-2, and 0.91 for DG-3. However, if grid conditions do not permit, the power factor limit is not required to be met. Under this condition, the power factor shall be maintained as close to the limit as practicable.

Verify each required DG does not trip and voltage is maintained 4784 V during and following a load rejection of a load 4400 kW for DG-1 and DG-2 and 2600 kW for DG-3.

In accordance with the Surveillance Frequency Control Program

AC Sources - Operating 3.8.1 Columbia Generating Station 3.8.1-10 Amendment No. 173,204 225 238 270 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.11

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

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

2. This Surveillance shall not normally be performed in MODE 1, 2, or 3 (not applicable to DG-3). However, portions of the Surveillance may be performed to re-establish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced. Credit may be taken for unplanned events that satisfy this SR.

Verify on an actual or simulated loss of offsite power signal:

a. De-energization of emergency buses;

b. Load shedding from emergency buses for Divisions 1 and 2; and

c.

DG auto-starts from standby condition and:

1.

energizes permanently connected loads in 15 seconds for DG-1 and DG-2, and in 18 seconds for DG-3,

2.

energizes auto-connected shutdown

loads,

3.

maintains steady state voltage 3910 V and 4400 V,

4.

maintains steady state frequency 58.8 Hz and 61.2 Hz, and

5.

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

In accordance with the Surveillance Frequency Control Program

AC Sources - Operating 3.8.1 Columbia Generating Station 3.8.1-11 Amendment No. 181,204 225 238 270 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.12

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

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

2. This Surveillance shall not normally be performed in MODE 1 or 2 (not applicable to DG-3). However, portions of the Surveillance may be performed to re-establish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced. Credit may be taken for unplanned events that satisfy this SR.

Verify on an actual or simulated Emergency Core Cooling System (ECCS) initiation signal each required DG auto-starts from standby condition and:

a. For DG-1 and DG-2, in 15 seconds achieves voltage 3910 V, and after steady state conditions are reached, maintains voltage 3910 V and 4400 V and, for DG-3, in 15 seconds achieves voltage 3910 V, and after steady state conditions are reached, maintains voltage 3910 V and 4400 V;

b. In 15 seconds, achieves frequency 58.8 Hz and after steady state conditions are achieved, maintains frequency 58.8 Hz and 61.2 Hz;

c.

Operates for 5 minutes;

d. Permanently connected loads remain energized from the offsite power system; and

e. Emergency loads are auto-connected to the offsite power system.

In accordance with the Surveillance Frequency Control Program

AC Sources - Operating 3.8.1 Columbia Generating Station 3.8.1-12 Amendment No. 203,204 225 238 270 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.13

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

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

Verify each required DG's automatic trips are bypassed on an actual or simulated ECCS initiation signal except:

a. Engine overspeed;

b. Generator differential current; and

c.

Incomplete starting sequence.

In accordance with the Surveillance Frequency Control Program SR 3.8.1.14

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

1. Momentary transients outside the load, excitation current, and power factor ranges do not invalidate this test.

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

3. If performed with the DG synchronized with offsite power, it shall be performed at a power factor of 0.9 for DG-1 and DG-2, and 0.91 for DG-3. However, if grid conditions do not permit, the power factor limit is not required to be met.

Under this condition, the power factor shall be maintained as close to the limit as practicable.

Verify each required DG operates for 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months s:

a. For 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months loaded 4650 kW for DG-1 and DG-2, and 2850 kW for DG-3; and

b. For the remaining hours of the test loaded 4400 kW for DG-1 and DG-2, and 2600 kW for DG-3.

In accordance with the Surveillance Frequency Control Program

AC Sources - Operating 3.8.1 Columbia Generating Station 3.8.1-13 Amendment No. 203,204 225 238 270 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.15

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

1. This Surveillance shall be performed within 5 minutes of shutting down the DG after the DG has operated 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months loaded 4000 kW for DG-1 and DG-2, and 2340 kW for DG-3.

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

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

Verify each required DG starts and achieves:

a. For DG-1 and DG-2, in 15 seconds, voltage 3910 V and frequency 58.8 Hz, and after steady state conditions are reached, maintains voltage 3910 V and 4400 V and frequency 58.8 Hz and 61.2 Hz; and

b. For DG-3, in 15 seconds, voltage 3910 V and frequency 58.8 Hz, and after steady state conditions are reached, maintains voltage 3910 V and 4400 V and frequency 58.8 Hz and 61.2 Hz.

In accordance with the Surveillance Frequency Control Program SR 3.8.1.16

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

This Surveillance shall not normally be performed in MODE 1, 2, or 3 (not applicable to DG-3). However, this Surveillance may be performed to re-establish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced.

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

Verify each required DG:

a. Synchronizes with offsite power source while loaded with emergency loads upon a simulated restoration of offsite power;

b. Transfers loads to offsite power source; and

c.

Returns to ready-to-load operation.

In accordance with the Surveillance Frequency Control Program

AC Sources - Operating 3.8.1 Columbia Generating Station 3.8.1-14 Amendment No. 203,204 225 238 270 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.17

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

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

Verify, with a DG operating in test mode and connected to its bus, an actual or simulated ECCS initiation signal overrides the test mode by:

a. Returning DG to ready-to-load operation; and

b. Automatically energizing the emergency load from offsite power.

In accordance with the Surveillance Frequency Control Program SR 3.8.1.18

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

This Surveillance shall not normally be performed in MODE 1, 2, or 3. However, this Surveillance may be performed to re-establish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced. Credit may be taken for unplanned events that satisfy this SR.

Verify interval between each sequenced load block is within +/- 10% of design interval for each time delay relay.

In accordance with the Surveillance Frequency Control Program

DC Sources - Operating 3.8.4 Columbia Generating Station 3.8.4-1 Amendment 169,204 225 270 3.8 ELECTRICAL POWER SYSTEMS 3.8.4 DC Sources - Operating LCO 3.8.4 The Division 1, Division 2, and Division 3 DC electrical power subsystems shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, and 3.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One required Division 1 or 2 125 V DC battery charger inoperable.

A.1 Restore battery terminal voltage to greater than or equal to the minimum established float voltage.

AND A.2 Verify battery float current 2 amps.

AND A.3 Restore required battery charger to OPERABLE status.

2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 72 hours OR In accordance with the Risk Informed Completion Time Program

DC Sources - Operating 3.8.4 Columbia Generating Station 3.8.4-2 Amendment 169,204 225 258 270 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. One required Division 3 125 V DC battery charger inoperable.

B.1 Restore battery terminal voltage to greater than or equal to the minimum established float voltage.

AND B.2 Verify battery float current 2 amps.

AND B.3 Restore required battery charger to OPERABLE status.

2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 72 hours OR In accordance with the Risk Informed Completion Time Program C. One required Division 1 250 V DC battery charger inoperable.

C.1 Restore battery terminal voltage to greater than or equal to the minimum established float voltage.

AND C.2 Verify battery float current 2 amps.

AND C.3 Restore required battery charger to OPERABLE status.

2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 72 hours OR In accordance with the Risk Informed Completion Time Program

DC Sources - Operating 3.8.4 Columbia Generating Station 3.8.4-3 Amendment 169,204,225, 236 270 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME D. One required Division 1 or 2 125 V DC battery inoperable.

D.1 Restore battery to OPERABLE status.

2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months OR In accordance with the Risk Informed Completion Time Program E. One required Division 3 125 V DC battery inoperable.

E.1 Restore battery to OPERABLE status.

2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months OR In accordance with the Risk Informed Completion Time Program F. One required Division 1 250 V DC battery inoperable.

F.1 Restore battery to OPERABLE status.

2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months OR In accordance with the Risk Informed Completion Time Program G. Division 1 or 2 125 V DC electrical power subsystem inoperable for reasons other than Condition A or D.

G.1 Restore Division 1 and 2 125 V DC electrical power subsystems to OPERABLE status.

2 Hours OR In accordance with the Risk Informed Completion Time Program

DC Sources - Operating 3.8.4 Columbia Generating Station 3.8.4-4 Amendment 169,204 225 238 270 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME H. Required Action and associated Completion Time of Condition B or E not met.

OR Division 3 DC electrical power subsystem inoperable for reasons other than Condition B or E.

H.1 Declare High Pressure Core Spray System inoperable.

Immediately I.

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

OR Division 1 250 V DC electrical power subsystem inoperable for reasons other than Condition C or F.

I.1 Declare associated supported features inoperable.

Immediately J. Required Action and associated Completion Time of Condition A or D not met.

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

J.1

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

LCO 3.0.4.a is not 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

DC Sources - Operating 3.8.4 Columbia Generating Station 3.8.4-5 Amendment 270 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.4.1 Verify battery terminal voltage is greater than or equal to the minimum established float voltage.

In accordance with the Surveillance Frequency Control Program SR 3.8.4.2 Verify each required battery charger supplies the required load for 1.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months at:

a. 126 V for the 125 V battery chargers; and

b. 252 V for the 250 V battery charger.

In accordance with the Surveillance Frequency Control Program SR 3.8.4.3

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

1. The modified performance discharge test in SR 3.8.6.6 may be performed in lieu of SR 3.8.4.3.

2. This Surveillance shall not be performed in MODE 1, 2, or 3 for the Division 1 and 2 125 V DC batteries. However, credit may be taken for unplanned events that satisfy this SR.

Verify battery capacity is adequate to supply, and maintain in OPERABLE status, the required emergency loads for the design duty cycle when subjected to a battery service test.

In accordance with the Surveillance Frequency Control Program

Distribution Systems - Operating 3.8.7 Columbia Generating Station 3.8.7-1 Amendment No. 149,169,225 254 258, 261 265 270 3.8 ELECTRICAL POWER SYSTEMS 3.8.7 Distribution Systems - Operating LCO 3.8.7 The following AC and DC electrical power distribution subsystems shall be OPERABLE:

a.

Division 1 and Division 2 AC electrical power distribution subsystems;

b.

Division 1 and Division 2 125 V DC electrical power distribution subsystems;

c.

Division 1 250 V DC electrical power distribution subsystem; and

d.

Division 3 AC and DC electrical power distribution subsystems.

APPLICABILITY:

MODES 1, 2, and 3.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Division 1 or 2 AC electrical power distribution subsystem inoperable.

A.1 Restore Division 1 and 2 AC electrical power distribution subsystems to OPERABLE status.

8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months OR In accordance with the Risk Informed Completion Time Program B. Division 1 or 2 125 V DC electrical power distribution subsystem inoperable.

B.1 Restore Division 1 and 2 125 V DC electrical power distribution subsystems to OPERABLE status.

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

Distribution Systems - Operating 3.8.7 Columbia Generating Station 3.8.7-2 Amendment No. 149,169,225 254 258, 261 265 270 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C. Required Action and associated Completion Time of Condition A or B not met.

C.1

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

LCO 3.0.4.a is not 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 D. Division 1 250 V DC electrical power distribution subsystem inoperable.

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

Immediately E. One or more Division 3 AC or DC electrical power distribution subsystems inoperable.

E.1 Declare High Pressure Core Spray System inoperable.

Immediately F. Two or more divisions with inoperable electrical power distribution subsystems that result in a loss of function.

F.1 Enter LCO 3.0.3.

Immediately SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.7.1 Verify correct breaker alignments and indicated power availability to required AC and DC electrical power distribution subsystems.

In accordance with the Surveillance Frequency Control Program

Programs and Manuals 5.5 Columbia Generating Station 5.5-12 Amendment 238 270 5.5 Programs and Manuals 5.5.15 Surveillance Frequency Control Program This program provides controls for Surveillance Frequencies. The program shall ensure that Surveillance Requirements specified in the Technical Specifications are performed at intervals sufficient to assure the associated Limiting Conditions for Operation are met.

a.

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

b.

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

c.

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

5.5.16 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;

c.

When a RICT is being used, any changes 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, system, 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:

Programs and Manuals 5.5 Columbia Generating Station 5.5-13 Amendment 270 5.5 Programs and Manuals 5.5.16 Risk Informed Completion Time Program (continued)

1.

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

2.

Risk Management Actions (RMAs) not already credited in the RICT calculation shall be implemented that support redundant or diverse SSCs that perform the function(s) of the inoperable SSCs, and, if practicable, reduce the frequency of initiating events that challenge the function(s) performed by the inoperable SSCs.

e.

The risk assessment approaches and methods shall be acceptable to the NRC.

The plant PRA shall be based on the as-built, as operated, and maintained plant; and reflect the operating experience at the plant as specified in Regulatory Guide 1.200, Revision 2. Methods to assess the risk from extending the Completion Times must be PRA methods used to support this program in Amendment No.

270, 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.

SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 270 TO RENEWED FACILITY OPERATING LICENSE NO. NPF-21 ENERGY NORTHWEST COLUMBIA GENERATING STATION DOCKET NO. 50-397

1.0 INTRODUCTION

By letter dated February 3, 2022 (Reference 1), as supplemented by letters dated October 4, 2022 (Reference 2), and November 28, 2022 (Reference 3), Energy Northwest (the licensee) submitted a license amendment request (LAR) for Columbia Generating Station (Columbia).

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 (TSTF-505)

(Reference 4). The U.S. Nuclear Regulatory Commission (NRC, the Commission) issued a final revised model safety evaluation (SE) to be used when preparing a plant-specific SE of an LAR to adopt TSTF-505 on November 21, 2018 (Reference 5).

The licensee has proposed variations from the TS changes approved in TSTF-505, which are provided in section 2.3, Optional Variations, of attachment 1, Description and Assessment, to the LAR and evaluated in sections 3.2.1 and 3.2.6 of this SE.

The NRC staff participated in a regulatory audit in August 2022 to ascertain the information needed to support its review of the application and to develop requests for additional information (RAIs), as needed. Following the regulatory audit, the licensee submitted a supplement letter dated October 4, 2022, that included additional information resulting from the audit. In review of the supplemental information, the NRC issued an RAI in email correspondence dated October 28, 2022 (Reference 6). The licensee provided a response to the RAI in letter dated November 28, 2022. On December 20, 2022, the NRC staff issued an audit summary (Reference 7).

The supplemental letters dated October 4, 2022, and November 28, 2022, provided additional information that clarified the application, did not expand the scope of the application as originally noticed, and did not change the NRC staffs original proposed no significant hazards consideration determination as published in the Federal Register on April 19, 2022 (87 FR 23273).

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 the licensees application to adopt TSTF-505.

Paragraphs (c)(2), Limiting conditions for operations, and (c)(5), Administrative controls, of 10 CFR 50.36, Technical specifications Paragraph (h), Protection and safety systems, of 10 CFR 50.55a, Codes and standards 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, along with industry guidance endorsed by the NRC, during its review of the proposed changes:

RG 1.200, Revision 2, An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities (Reference 8) and Revision 3, Acceptability of Probabilistic Risk Assessment Results for Risk-Informed Activities (Reference 9).

RG 1.174, Revisions 2 and 3, An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis (Reference

10) (Reference 11).

RG 1.177, Revision 2, An Approach for Plant-Specific, Risk-Informed Decision-making:

Technical Specifications (Reference 12).

NUREG-1855, Revision 1, Guidance on the Treatment of Uncertainties Associated with PRAs [Probabilistic Risk Assessments] in Risk-Informed Decisionmaking (Reference 13).

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 (Reference 14).

Nuclear Energy Institute (NEI) Topical Report NEI 06-09, Revision 0-A, Risk-Informed Technical Specifications Initiative 4b, Risk-Managed Technical Specifications (RMTS)

Guidelines, dated October 2012 (NEI 06-09-A) (Reference 15), provides guidance for risk-informed TSs. The NRC staff issued a final SE approving NEI 06-09 on May 17, 2007 (Reference 16).

The licensees submittals cite RG 1.174, Revision 2 ; RG 1.177; and RG 1.200, Revision 2, for the internal events (includes internal flooding) PRA (IEPRA) and seismic PRA (SPRA) models, and RG 1.200, Revision 3, for the fire PRA (FPRA). RG 1.174 has been updated to Revision 3.

The update does not include any technical changes that impact the consistency with NEI 06-09-A, therefore, the NRC staff finds the updated revision to RG 1.174 also applicable for use in the licensees adoption of TSTF-505 and will be the revision referred to in the remainder of the SE.

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 required action (e.g., testing, maintenance, or repair activity) permitted by the TSs until the condition can be met. The required actions (i.e., ACTIONS) associated with an LCO contain Conditions that typically describe the ways in which the requirements of the LCO can fail to be met. Specified with each stated Condition are Required Action(s) and Completion Time(s) (CT). The CTs are referred to as the front stops in the context of this SE. For certain conditions, the TSs require exiting the Mode of Applicability of an LCO (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.

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

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

2.2.1 TS 1.0 Use and Application Example 1.3-8 will be added to TS 1.3, Completion Times, and reads as follows:

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

A.1 Restore subsystem to OPERABLE status.

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

B.1 Be in MODE 3.

AND B.2 Be in MODE 4.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 36 hours When a subsystem is declared inoperable, Condition A is entered. The 7 day Completion Time may be applied as discussed in Example 1.3-2.

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

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

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

If the RICT expires or is recalculated to be less than the elapsed time since the Condition was entered and the inoperable subsystem has not been restored to OPERABLE status, Condition B is also entered and the

Completion Time clocks for Required Actions B.1 and B.2 start. If the inoperable subsystems are restored to OPERABLE status after Condition B is entered, 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 changes meet the five key principles provided in RGs 1.174 and 1.177 and the three-tiered approach outlined in RG 1.177.

3.1 Method of Staff Review Each of the key principles and tiers are addressed in NEI 06-09-A and approved in the final model SE issued by the NRC for TSTF-505, Revision 2. NEI 06-09-A provides a methodology for extending existing CTs, and to thereby delay exiting the operational mode of applicability or taking Required Actions if risk is assessed and managed within the limits and programmatic requirements established by a RICT Program. The NRC staffs evaluation of the licensees proposed use of RICTs against the key safety principles of RGs 1.174 and 1.177 is discussed below.

3.2 Review of Key Principles 3.2.1 Key Principle 1: Evaluation of Compliance with Current Regulations Paragraph 50.36(c)(2) of 10 CFR requires that LCOs are the lowest functional capability or performance levels of equipment required for safe operation of the facility. When an LCO of a nuclear reactor is not met, the licensee shall shut down the reactor or follow any required action permitted by the TS until the condition can be met.

The CTs in the current TSs were established using experiential data, risk insights, and engineering judgement. The RICT Program provides the necessary administrative controls to permit extension of CTs and, thereby, delay reactor shutdown or Required Actions, if risk is assessed and managed appropriately within specified limits and programmatic requirements and the safety margins and DID remains sufficient. The option to determine the extended CT in accordance with the RICT Program allows the licensee to perform an integrated evaluation in accordance with the methodology prescribed in NEI 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 back stop).

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

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

A.1 Restore subsystem to OPERABLE status.

7 days OR In accordance with the Risk Informed Completion Time Program In attachment 2, Proposed Technical Specification Changes (Mark-Up), 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, for Columbia TSs 3.3.4.1.A, 3.3.8.1.B, 3.3.8.1.C, 3.6.1.2.C, and 3.6.1.5.A, in section 2.0, Additional Justification for Specific Actions, of enclosure 1 to the LAR, as supplemented, 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 that, with the incorporation of the RICT Program, the required performance levels of equipment specified in LCOs are not changed, only the required CT for the Required Actions are modified, such that 10 CFR 50.36(c)(2) will continue to be met. Based on the discussion provided above, the NRC staff finds that the TS program provided in section 2.0 of this SE, LCOs, Required Actions, and CTs meet the first key principle of RGs 1.174 and 1.177.

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

Preserve a reasonable balance among the layers of defense.

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

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

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

Maintain multiple fission product barriers.

Preserve sufficient defense against human errors.

Continue to meet the intent of the plants design criteria.

The licensee requested to use the RICT Program to extend the existing CTs for the respective TS LCOs described in attachment 2 to the LAR, as supplemented. For the TS LCOs in attachment 6, 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 Columbias redundant or diverse means to mitigate accidents to ensure consistency with the plant licensing basis requirements using the guidance in RGs 1.174 and 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, as supplemented, provided information supporting the Columbia 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 confirmed that for the following TS LCOs, the above DID criteria were applicable except for the criteria for maintaining multiple fission product barriers.

TS 3.3.1.1, Reactor Protection System (RPS) Instrumentation TS 3.3.2.2, Feedwater and Main Turbine High Water Level Trip 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 Isolation Instrumentation TS 3.3.8.1, Loss of Power (LOP) Instrumentation TS 3.8.1, AC [Alternating Current] Sources - Operating TS 3.8.4, DC [Direct Current] Sources - Operating TS 3.8.7, Distribution Systems - Operating For the TS LCOs specific to I&C (i.e., TSs 3.3.1.1, 3.3.2.2, 3.3.4.1, 3.3.4.2, 3.3.5.1, 3.3.5.3, 3.3.6.1, and 3.3.8.1), the NRC staff reviewed the specific trip logic arrangements, redundancy, backup systems, manual actions, and diverse trips specified for each of the protective safety functions and associated instrumentation as described in the associated Updated Final Safety Analysis Report (UFSAR) (Reference 17) sections, and as reflected in attachment 6 and enclosure 1 to the LAR, as supplemented, for each I&C LCO above. The NRC staff verified that, in accordance with the Columbia UFSAR, the equipment and actions credited in attachment 6 and enclosure 1 to the LAR, as supplemented, and the notes proposed in the LAR that prohibit the application of the RICT Program when there is a loss of function in all applicable operating modes, the affected protective feature performs its intended function by ensuring the ability to detect and mitigate the associated event or accident when the CT of a channel is extended.

Furthermore, the NRC staff concludes that there is sufficient I&C redundancy, diversity, and DID, to protect against CCFs and potential single failure for the instrumentation systems evaluated in LAR attachment 6 and enclosure 1, as supplemented, during a RICT. There is at least one diverse means, including manual actuations, 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 licensee identified, that in accordance with the attachment 6 to the LAR, the manual actuation is the only diversity to the risk-informed TS 3.3.1.1 Function 5, Main Steam Isolation Valve Closure under the main steam line break (MSLB) outside the containment accident. The NRC staff verified, however, per the Columbia UFSAR section 15.6.4, Steam System Piping Break Outside Containment, and table 15.6-4, Sequence of Events for Steam Line Break Outside Containment, the safety relief valve and reactor pressure vessel are diversities to the Main Steam Isolation Valve Closure scram under the MSLB accident.

The NRC staff confirms that automatic diversities exist for all proposed changes, and thus concludes that there is not over-reliance of programmatic activities as compensatory measures.

Therefore, the NRC staff finds that the DID principle for the I&C safety functions is maintained.

For the TS LCOs specific to electrical power systems (i.e., TSs 3.8.1, 3.8.4, and 3.8.7), the NRC staff reviewed the information the licensee provided in the LAR, as supplemented, for the proposed TS LCOs, TS Bases, and the UFSAR to verify the capacity and capability of the affected electrical power systems to perform their safety functions (assuming no additional failures) is maintained. The NRC staff verified that the design success criteria in enclosure 1, table E1-1, In-scope TS/LCO Conditions to Corresponding PRA Functions, to the LAR, as supplemented, for the affected TS LCOs reflect the minimum electrical power source(s)/subsystem(s) required to be operable to support their safety functions necessary to mitigate postulated design basis accidents (DBAs), safely shutdown the reactor, and maintain the reactor in a safe shutdown condition. In addition, the NRC staff reviewed the risk management action (RMA) examples in enclosure 12, Risk Management Action Examples, to the LAR, which provide reasonable assurance that the appropriate RMAs will be implemented to monitor and control risk. The NRC staff finds that the intent of the plants design criteria (e.g.,

safety functions) applicable to the electrical power systems related TS LCOs provided above is maintained.

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

Considering that the CT extensions are 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 maintains adequate DID. Therefore, the NRC staff finds the TS LCOs proposed by the licensee in attachment 2 to the LAR, as supplemented, are acceptable for the RICT Program.

The NRC staff reviewed all TS LCOs proposed by the licensee in attachment 2 to the LAR, as supplemented, and concludes that the proposed changes do not alter the ways in which the Columbia systems fail, do not introduce new CCF modes, and the system independence is maintained.

The NRC staff finds that some proposed changes reduce the level of redundancy of the affected systems, and this reduction may reduce the level of defense against some CCFs; however, such reductions in redundancy and defense against CCFs are acceptable due to existing diverse means available to maintain adequate DID against a potential single failure during a

RICT. The NRC staff finds that extending the selected CTs with the RICT Program following loss of redundancy, but maintaining the capability of the system to perform its safety function, is an acceptable reduction in 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 the licensees proposed changes are consistent with the NRC-endorsed guidance prescribed in NEI 06-09-A and satisfy the second key principle in RGs 1.174 and 1.177. Additionally, the NRC staff concludes that the changes are consistent with the DID philosophy as described in RG 1.174.

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

a.

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

b.

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

The licensee is not proposing to change any quality standard, material, or operating specification in this application. In the LAR, as supplemented, the licensee proposed to add a new program, Risk Informed Completion Time Program, in section 5.0, Administrative Controls, of the Columbia 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 is able to have design basis equipment out of service longer than the current TS allowance, any increase in unavailability is expected to be insignificant and is addressed by the consideration of the single failure criterion in the design basis analyses. Acceptance criteria for operability of equipment are not changed and, if sufficient trains remain operable to fulfill the TS safety function, the operability of the remaining train(s) ensures that the current safety margins are maintained. The NRC staff finds that if the specified TS safety function remains operable, sufficient safety margins would be maintained during the extended CT of the RICT Program.

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

Based on the above, the NRC staff finds that the design basis analyses for Columbia remains applicable and unchanged, sufficient safety margins are maintained during the extended CT, and the proposed changes to the TSs do not include any change in the standards applied or the safety analysis acceptance criteria. The NRC staff concludes that the proposed changes meet 10 CFR 50.55a(h), and therefore, the third key principle of RGs 1.174 and 1.177.

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 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 risk, and the implementation of a CRMP to identify risk-significant plant configurations.

The NRC staff evaluated the licensees processes and methodologies for determining that the change in risk from implementation of RICTs is small and consistent with the intent of the Commissions Safety Goal Policy Statement (Reference 18). In addition, the NRC 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 NRC staffs review are discussed below.

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

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

IEPRA model Internal FPRA model SPRA model Other External Hazards: screened out from the RICT Program based on Appendix 6-A of the American Society of Mechanical Engineers / American Nuclear Society (ASME/ANS) RA-Sa-2009, Addenda to ASME/ANS RA-S 2008, Standard for Level 1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications, (ASME/ANS RA-Sa-2009 PRA Standard) (Reference 19)

Evaluation of IEPRA and FPRA Models The IEPRA and FPRA models supporting the RICT Program are discussed in enclosure 2 to the LAR, as supplemented. The licensee stated that the PRA models had been peer reviewed using the ASME/ANS RA-Sa-2009 PRA Standard for the IEPRA and FPRA. The licensee stated in section 2.0, PRA Quality/Technical Adequacy, of enclosure 2 to the LAR, as supplemented, that the IEPRA model has been assessed and peer reviewed against RG 1.200, Revision 2, and that the FPRA has been assessed and peer reviewed against RG 1.200, Revision 3. 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. The NRC staff

confirmed that the licensee performed closure of the F&Os consistent with the Final Revision of Appendix X to NEI 05-04/07-12/12-16, Close-Out of Facts and Observations (Reference 20),

as endorsed in RG 1.200, Revision 3.

In enclosure 9, Key Assumptions and Sources of Uncertainty, to the LAR, the licensee provided a discussion of the key assumptions and sources of uncertainty, along with treatment for the application of the RICT Program. In its LAR, the licensee stated that the Columbia PRA models credit installed and portable equipment used as part of the flexible and diverse coping (FLEX) strategy. To address concerns with the uncertainty of the methods used to model FLEX equipment and operator actions described in the NRC staff memorandum, Assessment of the Nuclear Energy Institute 16-06, Crediting Mitigating Strategies in Risk-Informed Decision Making, Guidance for Risk-Informed Changes to Plants Licensing Basis, of May 2017 (Reference 21), the licensee provided the results of a sensitivity study in enclosure 1, section 3.0, Modeling of Flex, to the LAR, as supplemented, that demonstrated that the modeling of FLEX equipment in all three PRA models had a negligible impact on CDF and LERF and does not constitute a key source of uncertainty for this application. The NRC staff concluded that the licensee has appropriately considered the key assumptions and sources of uncertainty in its PRAs, and the licensees credit for FLEX equipment in the TSTF-505 LAR is appropriate because the licensee used consensus human reliability analysis methodologies and practices, acceptable failures rates, and performed sensitivity studies to assess the impact on the RICTs.

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 IEPRA and FPRA models. The NRC staff further considered the key assumptions and key sources of uncertainty identified by the licensee, the licensees proposed use of surrogates in the PRA models for specific TS functions, and credit for FLEX equipment. Therefore, the NRC staff finds the Columbia IEPRA and FPRA models to be acceptable commensurate with the RICT application because the licensees use of the PRA models in the integrated decision-making process is consistent with RG 1.174.

Evaluation of SPRA Model The SPRA model supporting the RICT Program is discussed in section 2.0 of enclosure 2 to the LAR, as supplemented. The licensee stated that the SPRA model has been peer reviewed against the requirements of the ASME/ANS RA-S Case 1, Case for ASME/ANS RA-Sb-2013 Standard for Level 1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications (Reference 22), which was endorsed by RG 1.200, Revision 3.

Therefore, the NRC staff concludes that the licensee used an NRC-endorsed standard for its SPRA used to support this application, and therefore, finds it is acceptable.

The licensee stated that the Columbia SPRA model received a full-scope peer review in December 2018. The SPRA was subjected to independent assessment F&O closure reviews in July and November 2019, and March 2020. The July and November 2019 reviews included focused-scope peer reviews for F&O resolutions that were determined to be PRA upgrades. All finding level F&Os were successfully closed at the end of the three F&O closure reviews. The NRC staff finds that the Columbia SPRA was appropriately peer reviewed consistent with RG 1.200, Revision 2. F&Os closure reviews were performed consistent with corresponding NRC-accepted guidance, and all F&O findings have been closed. Therefore, the NRC staff concludes that the Columbia SPRA is acceptable for use in the RICT Program.

In section 2.0, Assessment of Internal Events, Fire, and Seismic PRA Epistemic Uncertainty Impacts, of enclosure 9 to the LAR, the licensee provided a discussion of potential key assumptions and sources of uncertainty for this application. The licensee concluded that there are no key sources of uncertainty in the SPRA for this application. In section 3.0 of enclosure 1 to the LAR, the licensee stated that the SPRA was developed based on the IEPRA and included the same FLEX strategies as the IEPRA. A sensitivity analysis shows that the seismic CDF remains unchanged if FLEX strategies are not credited. The NRC staff finds that the licensee has appropriately considered the key assumptions and sources of uncertainty in its SPRA for this application in accordance with RG 1.200, Rev. 3 and its modeling of FLEX strategies in the SPRA is acceptable for this application.

The licensee stated in its supplement dated October 4, 2022, that it identified an issue with the quantification software. The licensees approach to resolve this quantification issue caused an overestimated mean value using the advanced cutset upper bound evaluation (ACUBE) quantification method. Regarding the seismically induced failure probabilities for ground motion bins, the licensee stated in its supplement that bins greater than 3.1g were set to TRUE [i.e.,

guaranteed failure,] to enable quantification at the required truncations within a reasonable time frame. This resulted in minimal impact on RICTs. The licensee also performed a sensitivity analysis by setting all fragilities that have a probability of 0.9 or greater to TRUE, which reduces the reliance on ACUBE. The results showed minimal change in the RICT durations. In addition, the licensee stated that configuration-specific RMAs will be implemented if warranted based on risk information including the seismic risk contributors. Based on its review, the NRC staff finds that the uncertainty associated with truncation level, seismically-induced failure probabilities for ground motion bins, and fragilities that have a probability of 0.9 or greater does not impact this application because: (1) the treatment likely will not impact the RICT calculations based on sensitivity studies, and (2) because configuration-specific operator action RMAs will be implemented as needed based on seismic risk information about important operator actions.

In summary, the NRC staff reviewed the SPRA model peer review history provided by the licensee in enclosure 2 to the LAR, as supplemented. The NRC staff reviewed the key assumptions and sources of uncertainty identified by the licensee, seismic uncertainty, and proposed credit for FLEX. The NRC staff finds that the licensee adequately applied the guidance for establishing SPRA technical acceptability for this application, and therefore, the Columbia SPRA model is acceptable for use in the licensees RICT application.

Evaluation of Other External Hazards (Non-Seismic)

Besides the seismic hazard discussed above, the licensee confirmed that other external hazards for Columbia have an insignificant contribution to RICT and proposed that these hazards be screened from the RICT Program. In enclosure 4 of the LAR, as supplemented, the licensee provided its evaluation of external hazards for the RICT Program, and also evaluated configuration-specific impacts on the RICT Program for these hazards.

In enclosure 4 to the LAR, the licensee stated that the volcanic activity hazard does not impact the proposed RICTs because recent ash fall and seismic monitoring capability provide adequate time to take mitigating actions in the event of volcanic activity. The NRC staffs review of the licensees evaluation of the volcanic activity hazard finds that the licensee appropriately considered the risk from volcanic activity in the proposed RICTs in accordance with the ASME/ANS RA-Sa-2009 PRA Standard and that the volcanic activity hazard has an insignificant contribution to the proposed RICTs.

The licensee provided its evaluation of the external flooding hazard based on the Columbia plant and its post-Fukushima 50.54(f) request for information and the flood hazard reevaluation report submitted to NRC for review on October 6, 2016 (Reference 23). The external flooding hazard has been screened because natural topography maintains natural drainage away from the site. The NRC staff reviewed the licensees evaluation of the external flooding hazard and finds that the licensee appropriately considered the risk from external flooding in the proposed RICTs in accordance with the PRA Standard ASME/ANS RA-Sa-2009 and that the external flooding hazard has an insignificant contribution to configuration risk and can be excluded from the calculation of the proposed RICTs.

The licensee provided its evaluation of extreme wind, tornado and its missiles hazards based on the Columbia plant. The extreme wind and tornado hazard has been screened because, using table 6-1, Tornado wind speed Estimates for United States Nuclear Power Plant Sites, of NUREG/CR-4461 (Reference 24), the licensee calculated the probability of a design basis tornado striking the site to be approximately 1E-6 per year and all structures, systems, and components (SSCs) are protected from external missiles by passive permanent barrier structures or redundant systems. The NRC staff reviewed the licensees evaluation of the extreme wind, tornado and its missiles hazards and finds that the licensee appropriately considered the risk from extreme wind, tornado and its missiles hazards in the proposed RICTs in accordance with ASME/ANS RA-Sa-2009 PRA Standard, and that the hazards have an insignificant contribution to configuration risk and can be excluded from the calculation of the proposed RICTs.

The licensee provided its evaluation of all other external hazards in table E4-1, Evaluation of Risks from External Hazards, of enclosure 4 to the LAR. The NRC staff notes that the list of hazards assessed is essentially the same list of hazards as presented in table 4-1, Hazards, of NUREG-1855, Revision 1. The licensee provided a screening disposition for each external hazard and concluded that no unique PRA model for these hazards is required to assess configuration risk for the RICT Program. The licensee also evaluated all external hazards impacts on configurations specific for the RICT Program and concluded that there are no impacts from the external hazards. The NRC staff notes that the preliminary screening criteria and progressive screening criteria used is the same criteria presented in Supporting Requirements EXT-B1, EXT-B2, and EXT-C1 of the ASME/ANS RA-Sa-2009 PRA Standard.

Based on the NRC staffs review of the information provided by the licensee, the staff finds that the contributions from the other external hazards have an insignificant contribution to configuration risk and can be excluded from the calculation of the proposed RICTs because they either do not challenge the plant or they are bounded by the external hazards analyzed for the plant.

Application of PRA Models, Results and Insights in the RICT Program The Columbia base PRA models that have been determined to be acceptable in this SE are incorporated into an application-specific PRA model (i.e., CRMP tool), that is 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. The LAR, as supplemented, provided all information needed to support the requested LCO actions proposed for the Columbia RICT Program consistent with the limitations and conditions detailed in section 4.0 of the NRCs final SE incorporated in NEI 06-09-A.

The NRC staff did not identify any insufficiencies in the licensees information or the CRMP tool as described in enclosure 8, Attributes of the Real-Time Model, to the LAR. Furthermore, as stated in attachment 1 to the LAR, the proposed changes do not change the design, configuration, or method of operation of the plant. The proposed changes do not involve a physical alteration of the plant (no new or different kind of equipment will be installed). The NRC staff finds that the Columbia PRA models and CRMP tool used reflects the as-built, as-operated plant consistent with RG 1.200, Revision 2, for the IEPRA and SPRA, and RG 1.200, Revision 3, for the FPRA, for ensuring PRA acceptability is maintained. Therefore, the NRC staff concludes that the proposed application of Columbia RICT Program is appropriate for use in the adoption of TSTF-505 for performing RICT calculations.

The licensee provided in enclosure 5, Baseline CDF and LERF, to the LAR, as supplemented, the estimated mean total CDF and LERF of the base PRA models to demonstrate that Columbia meets the 1E-4/year CDF and 1E-5/year LERF criteria of RG 1.174 consistent with the guidance in NEI 06-09-A, and that these guidelines are satisfied for implementation of a RICT.

The licensee has incorporated NEI 06-09-A into TS 5.5.16. The estimated current mean total CDF and LERF for Columbia PRAs meet RG 1.174 guidelines, therefore, the NRC staff concludes that the PRA results and insights used by the licensee in the RICT Program are consistent with NEI 06-09-A.

3.2.4.1.1 Tier 1 Conclusions Based on the above information, the NRC staff concludes that the licensee satisfies the intent of Tier 1 in RG 1.177 and Section 16.1 of the SRP for determining the acceptability of the PRA, and that the scope of the PRA models (i.e., IEPRA, SPRA, and FPRA) and the evaluation of other external hazards, are appropriate for this application.

3.2.4.2 Tier 2: Avoidance of Risk-Significant Plant Configurations As described in RG 1.177, 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) are 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). In the LAR, the licensee also explains that RMAs are implemented, in accordance with current plant procedures and 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 Tier 2 attributes of the proposed RICT Program, including limits established for entry into a RICT and implementation of RMAs, are consistent with NEI 06-09-A. Therefore, the proposed changes are consistent with the intent of Tier 2 in RG 1.177.

3.2.4.3 Tier 3: Risk--Informed Configuration Risk Management The third tier stipulates that a licensee should develop a program that ensures 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. In enclosure 10 to the LAR, the licensee provided the attributes that the RICT Program procedures will address, which are consistent with NEI 06-09-A. The NRC staff finds that the licensee has identified appropriate administrative controls consistent with NEI 06-09-A and 10 CFR 50.36(c)(5).

Based on the licensees incorporation of NEI 06-09-A in the TSs (discussed in LAR attachment 2, as supplemented), and its use of RMAs (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. This includes considering the impact of seismic events and other external hazards, and that the models can support implementation of the RICT Program for determining extensions to CTs. The licensee has made proper consideration of key assumptions and sources of uncertainty. The risk metrics are consistent with the approved methodology of NEI 06-09-A and the acceptance guidance in RGs 1.174 and 1.177. The RICT Program is controlled administratively through plant procedures and training and follows the NRC-approved methodology in NEI 06-09-A. The NRC staff concludes that the RICT Program satisfies the fourth key principle of RGs 1.174 and 1.177 and is, therefore, acceptable.

3.2.5 Key Principle 5: Performance Measurement Strategies - Implementation and Monitoring The guidance in RGs 1.174 and 1.177 establishes 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 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 06-09-A.

The NRC staff concludes that the RICT Program satisfies the fifth key principle of RGs 1.174 and 1.177 because: (1) the RICT Program monitors the average annual cumulative risk increase as described in NEI 06-09-A, thereby providing reasonable assurance that 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 monitors changes to the reliability and availability of these SSCs.

3.2.6 Removal of Obsolete Information In attachment 1, section 2.3 to the LAR, the licensee proposes to delete two expired footnotes and an expired Note as follows:

a. TS 3.6.1.5, Residual Heat Removal (RHR) Drywell Spray, Condition A, CT contains footnote (1) that states:

The Completion Time that one train of RHR (RHR-A) can be inoperable as specified by Required Action A.1 may be extended beyond the 7 day completion time up to 7 days to support restoration of RHR-A following pump and motor replacement. This footnote will expire at 23:59 PST

[Pacific Standard Time] February 28, 2019.

b. TS 3.6.2.3, Residual Heat Removal (RHR) Suppression Pool Cooling, Condition A, CT contains footnote (1) that states:

The Completion Time that one train of RHR (RHR-A) can be inoperable as specified by Required Action A.1 may be extended beyond the 7 day completion time up to 7 days to support restoration of RHR-A following pump and motor replacement. This footnote will expire at 23:59 PST February 28, 2019.

c. TS 3.8.4, DC Sources - Operating, Required Action G.1, CT contains a Note that states:

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

Until June 30, 2021, a Completion Time of 16 hours1.851852e-4 days 0.00444 hours 2.645503e-5 weeks 6.088e-6 months is applicable for replacement of WMA-42-8F1E or its failed starter coil.

The licensee proposes to delete the footnotes (shown above) in Columbias TS 3.6.1.5 and TS 3.6.2.3 Condition A, CTs, which allows a one-time extension of the CT following an RHR pump and motor replacement, with an expiration date of February 28, 2019. The licensee proposes to remove these temporary changes, which were approved in Amendment No. 245 (Reference 25) for Columbia. This change is editorial in nature and does not affect the applicability of TSTF-505 to the Columbia TS. The NRC staff therefore finds this to be acceptable.

The licensee proposes to delete the note (shown above) in Columbias TS 3.8.4 Required Action G.1 CT, which allows a one-time extension of the CT following replacement of a motor control center cubicle containing a defective control power transformer, with an expiration date of June 30, 2021. The licensee proposes to remove this temporary change, which was approved in Amendment No. 258 (Reference 26) for Columbia. This change is editorial in nature and does not affect the applicability of TSTF-505 to the Columbia TS. The NRC staff therefore finds this to be acceptable.

Based on the above review, the NRC staff concludes that TSs 3.6.1.5, 3.6.2.3, and 3.8.4 as amended by the proposed changes, continue to meet the requirements of 10 CFR 50.36(c)(2) because the LCOs continue to state the lowest functional capability or performance levels of equipment required for safe operation of the facility. The NRC staff concludes that the required actions, as amended by the proposed change, provide reasonable assurance that facility operation remains safe during the time the LCOs are not met. Therefore, the NRC staff concludes that the proposed changes to delete footnote (1) in TSs 3.6.1.5 and 3.6.2.3, and the CT note in TS 3.8.4 are acceptable because these footnotes and note are expired, and therefore, obsolete.

3.2.7 Technical Evaluation Conclusion The NRC staff evaluated the proposed changes against each of the five key principles in RGs 1.174 and 1.177 including the proposed variations from the approved TSTF-505 as discussed in sections 3.2.1 through 3.2.5 and removal of obsolete information in section 3.2.6 of this SE. The NRC staff concludes that the changes proposed by the licensee satisfy the key principles of risk informed decision-making identified in RGs 1.174 and 1.177, and therefore, the requested adoption of the proposed changes to the TSs and associated guidance, is acceptable to assure the paragraphs of 10 CFR Part 50 identified in section 2.0 of this SE continue to be met.

4.0 STATE CONSULTATION

In accordance with the Commissions regulations, the Washington State official was notified of the proposed issuance of the amendment on January 12, 2023. The State official had no comments.

5.0 ENVIRONMENTAL CONSIDERATION

The NRC staff has determined that the amendment involves no significant increase in the amounts, and no significant change in the types, of any effluents that may be released offsite, and that there is no significant increase in individual or cumulative occupational radiation exposure. The Commission has previously issued a proposed finding that the amendment involves no significant hazards consideration published in the Federal Register on April 19, 2022 (87 FR 23273), 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 Dittmer, J. Kent, Energy Northwest, letter to U.S. Nuclear Regulatory Commission, Columbia Generating Station, Docket No. 50-397 License Amendment Request to Adopt TSTF-505, Revision 2, Provide Risk-Informed Extended Completion Times - RITSTF Initiative 4b, dated February 3, 2022 (Agencywide Documents Access and Management System Accession No. ML22034A992).

2 Hauger, J. S., Energy Northwest, letter to U.S. Nuclear Regulatory Commission, Columbia Generating Station, Docket No. 50-397, Supplement to License Amendment Request to Adopt TSTF-505, Revision 2, Provide Risk-Informed Extended Completion Times - RITSTF Initiaitve 4b, dated October 4, 2022 (ML22277A603).

3 Hauger, J. S., Energy Northwest, letter to U.S. Nuclear Regulatory Commission, Columbia Generating Station, Docket No. 50-397, Response to Request for Additional Information Related to License Amendment Request to Adopt TSTF-505, Revision 2, Provide Risk-Informed Extended Completion Times - RITSTF Initiative 4b, dated November 28, 2022 (ML22332A516).

4 Technical Specifications Task Force, TSTF Comments on Draft Safety Evaluation for Traveler TSTF-505, Provide Risk-Informed Extended Competion Times and Submittal of TSTF-505, Revision 2, TSTF-505, Revision 2, dated July 2, 2018 (ML18183A493).

5 Cusumano, V. G., U.S. Nuclear Regulatory Commission, letter to Technical Specifcations Task Force, Final Revised Model Safety Evlaution of Traveler TSTF-505, Revision 2, Provide Risk Informed Extended Completion Times - RITSTF Initiative 4[b], dated November 21, 2018 (ML18269A041).

6 Chawla, M., U.S. Nuclear Regulatory Commission, email to T. Collis, Energy Northwest, Final - Request for Additional Information - Columbia Generating Station-License Amendment Request to Adopt TSTF-505 - EPID L-2022-LLA-0023, dated October 28, 2022 (ML22301A143).

7 Chawla, M. L., U.S. Nuclear Regulatory Commission, letter to R. Schuetz, Energy Northwest, Columbia Generating Station - Regulatory Audit Summary in Support of Review for License Amendment Request to Revise Technical Specifications to Adopt TSTF-505, Revision 2 (EPID L-2022-LLA-0023), dated December 20, 2022 (ML22340A689).

8 U.S. Nuclear Regulatory Commission, An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities, Regulatory Guide 1.200, Revision 2, dated March 2009 (ML090410014).

9 U.S. Nuclear Regulatory Commission, Acceptability of Probabilistic Risk Assessment Results for Risk-Informed Activities, Regulatory Guide 1.200, Revision 3, dated December 2020 (ML20238B871).

10 U.S. Nuclear Regulatory Commission, An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis, Regulatory Guide 1.174, Revision 2, dated May 2011 (ML100910006).

11 U.S. Nuclear Regulatory Commission, An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis, Regulatory Guide 1.174, Revision 3, dated January 2018 (ML17317A256).

12 U.S. Nuclear Regulatory Commission, Plant-Specific, Risk-Informed Decisionmaking:

Technical Specifications, Regulatory Guide 1.177, Revision 2, dated January 2021 (ML20164A034).

13 U.S. Nuclear Regulatory Commission, Guidance on the Treatment of Uncertainties Associated with PRAs in Risk-Informed Decisionmaking, Final Report, NUREG-1855, Revision 1, dated March 2017 (ML17062A466).

14 U.S. Nuclear Regulatory Commission, Risk-informed Decision Making: Technical Specifications, NUREG-0800, Standard Review Plan for the Review of Safety Anlysis Reports for Niuclear Power Plants, Section 16.1, Revision 1, dated March 2007 (070380228).

15 Bradley, B., Nuclear Energy Institute, letter to S. D. Stuchell, U.S. Nuclear Regulatory Commission, NEI 06-09, Risk Informed Technical Specifications Initiative 4b; Risk Managed Technical Specifications (RMTS) Guidelines, Revision 0-A, dated October 2012 (ML122860402).

16 Golder, J. M., U.S. Nuclear Regulatory Commission, letter to B. Bradley, Nuclear Energy Institute, Final Safety Evaluation for Nuclear Energy Insittute (NEI) Topical Report (TR) NEI 06-09, Risk-Infomed Techncial Specification Initiative 4b, Risk-Managed Technical Specifications (RMTS) Guidelines (TAC No. MD4995), dated May 17, 2007 (ML071200238).

17 Brown, D. P., Energy Northwest, letter to U.S. Nuclear Regulatory Commission, Columbia Generating Station, Docket No. 50-397, 10 CFR 50.71 Maintenance of Records Licensing Basis Document Update and Biennial Commitment Change Report, dated December 15, 2021 (21349B351).

18 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).

19 American Society of Mechanical Engineers (ASME)/American Nuclear Society (ANS),

Addenda to ASME/ANS RA-S 2008, Standard for Level 1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications, PRA Standard ASME/ANS RA-Sa-2009, February 2009, New York, NY (Copyright).

20 Anderson, V. K., Nuclear Energy Institute, letter to S. Rosenberg, U.S. Nuclear Regulatory Commission, Final Revision of Appendix X to NEI 05-04/07-12/12-16, Close-Out of Facts and Observations, dated February 21, 2017 (ML17086A431).

21 Reisi-Fard, M., U.S. Nuclear Regulatory Commission, memorandum to J. G. Giitter, U.S.

Nuclear Regulatory Commission, Assessment of the Nuclear Energy Institute 16-06, Crediting Mitigating Strategies in Risk-Informed Decision Making, Guidance for Risk-Informed Changes to Plants Licensing Basis, dated May 30, 2017 (ML17031A269).

22 American Society of Mechanical Engineers (ASME)/American Nuclear Society (ANS),

Case for ASME/ANS RA-Sb-2013, Standard for Level 1/Large Early Release Frequency Probabilisitc Risk Assessment for Nuclear Power Plant Applications, dated November 22, 2017, New York, NY (Copyright).

23 Javorik, A. L., Energy Northwest, letter to U.S. Nuclear Regulatory Commission, Flooding Hazard Reevaluation Report, Response to NRC Request for Information Pursuant to 10 CFR 50.54(F) Regarding Recommendation 2.1 of the Near-Term Task Force Review of

Insights from the Fukushima Dai-ichi Accident, October 6, 2016 (ML16286A309; not publicly available).

24 Pacific Northwest National Laboratory, Tornado Climatology of the Contiguous United States, NUREG/CR-4461, Revision 2, dated February 2007 (ML070810400),.

25 Klos, J., U.S. Nuclear Regulatory, letter to M. E. Reddemann, Energy Northwest, Columbia Generating Station - Issuance of Amendment Re: Request for a One-Time Extension of the Residual Heat Removal Train A Completion Time (CAC No. MF8794; EPID L-2016-LLA-0016), dated October 30, 2017 (ML17290A127).

26 Klos, J., U.S. Nuclear Regulatory Commission, letter to B. J. Sawatzke, Energy Northwest, Columbia Generating Station - Issuance of Amendment No. 258 Re: Changes to Technical Specificatio Limiting Conditions for Operation 3.8.4 and 3.8.7 (Exigent Circumstances)

(EPID L-2020-LLA-0080), dated May 12, 2020 (ML20125A080).

Principal Contributors: K. Bucholtz, NRR T. Hilsmeier, NRR J. Hyslop, NRR N. Iqbal, NRR K. Tetter, NRR D. Wu, NRR C. Jackson, NRR A. Russell, NRR E. Kleeh, NRR S. Wyman, NRR H. Wagage, NRR M. Li, NRR W. Roggenbrodt, NRR N. Carte, NRR Date: March 15, 2023

ML23013A081

by email OFFICE NRR/DORL/LPL4/PM NRR/DORL/LPL4/LA*

NRR/DEX/EEEB/BC*

NRR/DEX/EICB/BC*

NAME MChawla PBlechman WMorton MWaters DATE 1/12/2023 1/23/2023 w/comments 12/15/2022 12/12/2022 OFFICE NRR/DRA/APLA/BC*

NRR/DRA/APLB/BC (A)* NRR/DRA/APLC/BC*

NRR/DSS/SCPB/BC*

NAME RPascarelli JRobinson SVasavada BWittick DATE 12/15/2022 12/15/2022 12/15/2022 12/15/2022 OFFICE NRR/DSS/SNSB/BC (A*)

NRR/DSS/STSB/BC*

OGC*

NRR/DORL/LPL4/BC*

NAME DWoodyatt VCusumano ELicon JDixon-Herrity DATE 12/15/2022 12/15/2022 3/6/2023 3/15/2023 OFFICE NRR/DORL/LPL4/PM*

NAME MChawla DATE 3/15/2023

v t e Letter Sequence Approval
EPID:L-2022-LLA-0023, TSTF 505 (Approved, Closed)
Initiation Request, Request Acceptance Supplement Administration Questions 28 October 2022 Answers 28 November 2022 Results Approval, Approval, Approval Other: ML22165A296
MONTHYEAR2022-03-18 [Table View]

ML23013A081

Text

SUBJECT:

Dear Mr. Schuetz:

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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