Text

Issuance of Amendment No. 236, Adoption of Technical Specification Task Force Traveler TSTF-423, Revision 1, Technical Specifications End States, as Part of Consolidated Line Item Improvement Process
	ML15216A266
Person / Time
Site:	Columbia
Issue date:	02/03/2016
From:	Balwant Singal; Plant Licensing Branch IV
To:	Reddemann M; Energy Northwest
	Singal B
References
	CAC MF4616, NEDC-32988-A
	Download: ML15216A266 (79)
	v • d • e

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 Mr. Mark E. Reddemann Chief Executive Officer Energy Northwest P.O. Box 968 (Mail Drop 1023)

Richland, WA 99352-0968 February 3, 2016

SUBJECT:

COLUMBIA GENERATING STATION - ISSUANCE OF AMENDMENT RE:

ADOPTION OF TECHNICAL SPECIFICATION TASK FORCE (TSTF) CHANGE TRAVELER TSTF-423, REVISION 1, "TECHNICAL SPECIFICATIONS END STATES, NEDC-32988-A" (CAC NO. MF4616)

Dear Mr. Reddemann:

The U.S. Nuclear Regulatory Commission (NRC. the Commission) has issued the enclosed Amendment No. 236 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 August 12, 2014, as supplemented by letters dated September 4, 2014, and April 3 and August 11, 2015.

The amendment modifies the TSs to risk-inform requirements regarding selected Required Action end states consistent with NRC-approved Technical Specifications Task Force (TSTF)

Change Traveler TSTF-423, Revision 1, "Technical Specifications End States, NEDC-32988-A,"

dated December 22, 2009, as part of the consolidated line item improvement process. The amendment also modifies the TS Required Actions with a Note prohibiting the use of Limiting Condition for Operation 3.0.4.a when entering the preferred end state (Mode 3) on startup.

A copy of the related Safety Evaluation is also enclosed. The Notice of Issuance will be included in the Commission's next biweekly Federal Register notice.

Docket No. 50-397

Enclosures:

1. Amendment No. 236 to NPF-21

2. Safety Evaluation cc w/encls: Distribution via Listserv Sincerely,

~b.&,~yz_

Balwant K. Singal, Senior Project Manager Plant Licensing Branch IV-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 ENERGY NORTHWEST DOCKET NO. 50-397 COLUMBIA GENERATING STATION AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 236 License No. NPF-21

1.

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

A.

The application for amendment by Energy Northwest (licensee), dated August 12, 2014, as supplemented by letters dated September 4, 2014, and April 3 and August 11, 2015, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act) and the Commission's regulations set forth in 10 CFR Chapter I; B.

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

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

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

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

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. 236 and the Environmental Protection Plan contained in Appendix B, are hereby incorporated in the 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 60 days from the date of issuance.

Attachment:

Changes to the Renewed Facility Operating License No. NPF-21 and Technical Specifications Date of Issuance: February 3, 2016 FOR THE NUCLEAR REGULA TORY COMMISSION Robert J. Pascarelli, Chief Plant Licensing Branch IV-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

ATTACHMENT TO LICENSE AMENDMENT NO. 236 RENEWED FACILITY OPERATING LICENSE NO. NPF-21 DOCKET NO. 50-397 Replace the following pages of the Renewed Facility Operating License No. NPF-21 and 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.

Facility Operating License REMOVE INSERT Technical Specifications REMOVE 3.3.8.2-1 3.4.4-1 3.4.4-2 3.5.1-2 3.5.1-3 3.5.1-4 3.5.1-5 3.6.1.5-1 3.6.1.6-1 3.6.1.6-2 3.6.1.7-1 3.6.1.7-2 3.6.2.3-1 3.6.4.1-1 3.6.4.3-1 3.7.1-2

3. 7.1-3 3.7.3-2

3. 7.4-1 3.7.4-2 3.7.5-1 3.8.1-5 3.8.4-3 3.8.7-2 INSERT 3.3.8.2-1 3.4.4-1 3.4.4-2 3.5.1-2 3.5.1-3 3.5.1-4 3.5.1-5 3.6.1.5-1 3.6.1.6-1 3.6.1.6-2 3.6.1.7-1 3.6.1.7-2 3.6.2.3-1 3.6.4.1-1 3.6.4.3-1 3.7.1-2 3.7.1-3 3.7.3-2

3. 7.4-1 3.7.4-2 3.7.5-1 3.8.1-5 3.8.4-3 3.8.7-2 (2)

Technical Specifications and Environmental Protection Plan The Technical Specifications contained in Appendix A, as revised through Amendment No. 236 and the Environmental Protection Plan contained in Appendix 8, 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)

Shield Wall Deferral (Section 12.3.2, SSER #4, License Amendment #7)

The licensee shall complete construction of the deferred shield walls and window as identified in Attachment 3, as amended by this license amendment.

(12)

Deleted.

(13)

Deleted.

The parenthetical notation following the title of many license conditions denotes the section of the Safety Evaluation Report and/or its supplements wherein the license condition is discussed.

Renewed License No. NPF-21 Amendment No. 236

RPS Electric Power Monitoring 3.3.8.2 3.3 INSTRUMENTATION 3.3.8.2 Reactor Protection System (RPS) Electric Power Monitoring LCO 3.3.8.2 Two RPS electric power monitoring assemblies shall be OPERABLE for each inservice RPS motor generator set or alternate power supply that supports equipment required to be OPERABLE.

APPLICABILITY:

MODES 1, 2, and 3, MODES 4 and 5 with both residual heat removal (RHR) shutdown cooling (SOC) suction isolation valves open, MODE 5 with any control rod withdrawn from a core cell containing one or more fuel assemblies.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One or both required A.1 Remove associated 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months inservice power supplies inservice power supply(s) with one electric power from service.

monitoring assembly inoperable.

B. One or both required B.1 Remove associated 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months inservice power supplies inservice power supply(s) with both electric power from service.

monitoring assemblies inoperable.

C. Required Action and C.1

N 0 TE------------

associated Completion LCO 3.0.4.a is not Time of Condition A or B applicable when entering not met in MODE 1, 2, MODE 3.

or 3.

Be in MODE 3.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Columbia Generating Station 3.3.8.2-1 Amendment No. 44-B,169,225, 236

3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.4 Safety/Relief Valves (SRVs) - < 25% RTP SRVs - < 25% RTP 3.4.4 LCO 3.4.4 The safety function of four SRVs shall be OPERABLE.

APPLICABILITY:

MODE 1 with THERMAL POWER< 25% RTP, MODES 2 and 3.

ACTIONS CONDITION REQUIRED ACTION A. One required SRV A.1

N 0 TE------------

inoperable.

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

Be in MODE 3.

B. Two or more required B.1 Be in MODE 3.

SRVs inoperable.

AND B.2 Be in MODE 4.

COMPLETION TIME 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 Columbia Generating Station 3.4.4-1 Amendment No. 449,169,225, 236

SURVEILLANCE REQUIREMENTS SR 3.4.4.1 SR 3.4.4.2 SURVEILLANCE Verify the safety function lift setpoints of the required SRVs are as follows:

Number of SRVs 2

4 4

Setpoint

_(J2fil9l 1165+/-34.9 1175 +/- 35.2 1185 +/- 35.5 1195 +/- 35.8 1205 +/- 36.1

N 0 TE------------------------------

N o t 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 SRV opens when manually actuated.

SRVs - < 25% RTP 3.4.4 FREQUENCY In accordance with the lnservice Testing Program 24 months Columbia Generating Station 3.4.4-2 Amendment No..:t-49.4-e-9,~, 236

ACTIONS CONDITION C. Two ECCS injection C.1 subsystems inoperable.

OR One ECCS injection and one ECCS spray subsystem inoperable.

D. Required Action and D.1 associated Completion Time of Condition A, B, or C not met.

E. One required ADS valve E.1 inoperable.

F. One required ADS valve F.1 inoperable.

AND OR One low pressure ECCS F.2 injection/spray subsystem inoperable.

Columbia Generating Station REQUIRED ACTION Restore ECCS injection/spray subsystem to OPERABLE status.

N 0 TE--------------

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

Be in MODE 3.

Restore ADS valve to OPERABLE status.

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

ECCS - Operating 3.5.1 COMPLETION TIME 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months 12 hours 14 days 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months 72 hours 3.5.1-2 Amendment No. -149,-+69,~. 236

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

OR Two or more required ADS valves inoperable.

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.

Columbia Generating Station G.1 H.1 REQUIRED ACTION

N 0 TE--------------

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

Be in MODE 3.

Enter LCO 3.0.3.

ECCS - Operating 3.5.1 COMPLETION TIME 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Immediately 3.5.1-3 Amendment No. 449,4B9,~, 236

SURVEILLANCE REQUIREMENTS SR 3.5.1.1 SR 3.5.1.2 SURVEILLANCE Verify, for each ECCS injection/spray subsystem, the piping is filled with water from the pump discharge valve to the injection valve.

N 0 TE-------------------------------

L ow pressure coolant injection (LPCI) subsystems may be considered OPERABLE during alignment and operation for decay heat removal with reactor steam dome pressure less than 48 psig in MODE 3, if capable of being manually realigned and not otherwise inoperable.

ECCS - Operating 3.5.1 FREQUENCY 31 days Verify each ECCS injection/spray subsystem 31 days SR 3.5.1.3 SR 3.5.1.4 manual, power operated, and automatic valve in the flow path, that is not locked, sealed, or otherwise secured in position, is in the correct position.

Verify ADS accumulator backup compressed gas system average pressure in the required bottles is

~ 2200 psig.

Verify each ECCS pump develops the specified flow rate with the specified differential pressure between reactor and suction source.

SYSTEM LPCS LPCI HPCS FLOW RATE

~ 6200 gpm

~ 7200 gpm

~ 6350 gpm DIFFERENTIAL PRESSURE BETWEEN REACTOR AND SUCTION SOURCE

~ 128 psid

~ 26 psid

~ 200 psid 31 days In accordance with the lnservice Testing Program Columbia Generating Station 3.5.1-4 Amendment No. 4-6-9.~.~.~. 236

SURVEILLANCE REQUIREMENTS SR 3.5.1.5 SR 3.5.1.6 SR 3.5.1.7 SR 3.5.1.8 SURVEILLANCE

N 0 TE------------------------------

Vesse I injection/spray may be excluded.

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

N 0 TE------------------------------

Va Ive actuation may be excluded.

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

N 0 TE------------------------------

N ot 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.

N 0 TE------------------------------

EC CS actuation instrumentation is excluded.

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

ECCS - Operating 3.5.1 FREQUENCY 24 months 24 months 24 months on a STAGGERED TEST BASIS for each valve solenoid 24 months Columbia Generating Station 3.5.1-5 Amendment No..:i-w.we.~. 236

3.6 CONTAINMENT SYSTEMS 3.6.1.5 Residual Heat Removal (RHR) Drywell Spray RHR Drywell Spray 3.6.1.5 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 A.1 Restore RHR drywell spray 7 days<1) subsystem inoperable.

subsystem to OPERABLE status.

B. Two RHR drywell spray B.1 Restore one RHR drywell 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months subsystems inoperable.

spray subsystem to OPERABLE status.

C. Required Action and C.1

N 0 TE--------------

associated Completion LCO 3.0.4.a is not Time not met.

applicable when entering MODE 3.

Be in MODE 3.

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

<1) The Completion Time that one train of RHR (RHR-B) 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-B from the modification activity. Upon successful restoration of RHR-B, this footnote is no longer applicable and will expire at 05:00 PST on February 9, 2015.

Columbia Generating Station 3.6.1.5-1 Amendment No..+49,169,225,2-JG, 236

3.6 CONTAINMENT SYSTEMS Reactor Building-to-Suppression Chamber Vacuum Breakers 3.6.1.6 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

N 0 TE-----------------------------------------------------------

S e para te Condition entry is allowed for each line.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more lines with A.1 Close the open vacuum 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months one reactor building-to-breaker.

suppression chamber vacuum breaker not closed.

B. One or more lines with B.1 Close one open vacuum 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months two reactor building-to-breaker.

suppression chamber vacuum breakers not closed.

C. One line with one or C.1 Restore the vacuum 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months more reactor building-to-breaker(s) to OPERABLE suppression chamber status.

vacuum breakers inoperable for opening.

D. Required Action and D.1 -------------N 0 TE------------

associated Completion LCO 3.0.4.a is not Time of Condition C applicable when entering not met.

MODE 3.

Be in MODE 3.

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

Columbia Generating Station 3.6.1.6-1 Amendment No. 449,4-69,~. 236

Reactor Building-to-Suppression Chamber Vacuum Breakers 3.6.1.6 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME E. Two or more lines with E.1 Restore all vacuum 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months one or more reactor breakers in two lines to building-to-suppression OPERABLE status.

chamber vacuum breakers inoperable for opening.

F. Required Action and F.1 Be in MODE 3.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time of Condition A, B AND or E not met.

F.2 Be in MODE 4.

36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months SURVEILLANCE REQUIREMENTS SR 3.6.1.6.1 SR 3.6.1.6.2 SR 3.6.1.6.3 SURVEILLANCE

N 0 TES-----------------------------

1.

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

2.

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

Verify each vacuum breaker is closed.

FREQUENCY 14 days Perform a functional test of each vacuum breaker.

In accordance with the I nservice Testing Program Verify the full open setpoint of each vacuum breaker 24 months is::;; 0.5 psid.

Columbia Generating Station 3.6.1.6-2 Amendment No. ~.-1-e9.~. 236

3.6 CONTAINMENT SYSTEMS Suppression Chamber-to-Drywell Vacuum Breakers 3.6.1.7 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.

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 A.1 Restore one vacuum 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months suppression chamber-to-breaker to OPERABLE drywell vacuum breaker status.

inoperable for opening.

B. Required Action and B.1

N 0 TE--------------

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

MODE 3.

Be in MODE 3.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months C. ------------N 0 TE------------

C.1 Close the open vacuum 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Separate Condition entry breaker disk.

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

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

Columbia Generating Station 3.6.1.7-1 Amendment No. 449,4-W.~. 236

Suppression Chamber-to-Drywell Vacuum Breakers 3.6.1.7 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME D. One or more D.1 Close one open vacuum 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months suppression chamber-to-breaker disk.

drywell vacuum breakers with two disks not closed.

E. Required Action and E.1 Be in MODE 3.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time of Condition C or D AND not met.

E.2 Be in MODE 4.

36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.1.7.1

N 0 TE------------------------------

SR 3.6.1.7.2 SR 3.6.1.7.3 N o t required to be met for vacuum breakers that are open during Surveillances.

Verify each vacuum breaker is closed.

Perform a functional test of each required vacuum breaker.

14 days 31 days Within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after any discharge of steam to the suppression chamber from the safety /relief valves Verify the full open setpoint of each required vacuum 24 months breaker is~ 0.5 psid.

Columbia Generating Station 3.6.1.7-2 Amendment No. 4-W,~,~. 236

3.6 CONTAINMENT SYSTEMS RHR Suppression Pool Cooling 3.6.2.3 3.6.2.3 Residual Heat Removal (RHR) Suppression Pool Cooling LCO 3.6.2.3 Two RHR suppression pool cooling subsystems shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, and 3.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One RHR suppression A.1 Restore RHR suppression 7 days(1) pool cooling subsystem pool cooling subsystem to inoperable.

OPERABLE status.

B. Required Action and B.1

N 0 TE--------------

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

MODE 3.

Be in MODE 3.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months C. Two RHR suppression C.1 Be in MODE 3.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months pool cooling subsystems inoperable.

AND C.2 Be in MODE 4.

36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months (1) The Completion Time that one train of RHR (RHR-B) 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-B from the modification activity. Upon successful restoration of RHR-B, this footnote is no longer applicable and will expire at 05:00 PST on February 9, 2015.

Columbia Generating Station 3.6.2.3-1 Amendment No. 449,.w.9,~,2-W, 236

3.6 CONTAINMENT SYSTEMS 3.6.4.1 Secondary Containment LCO 3.6.4.1 The secondary containment shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, and 3, Secondary Containment 3.6.4.1 During operations with a potential for draining the reactor vessel (OPDRVs).

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Secondary containment A.1 Restore secondary 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months inoperable in MODE 1, containment to OPERABLE 2, or 3.

status.

B. Required Action and B.1

N 0 TE--------------

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

MODE 3.

Be in MODE 3.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months C. Secondary containment C.1 Initiate action to suspend Immediately inoperable during OPDRVs.

OPDRVs.

Columbia Generating Station 3.6.4.1-1 Amendment No..+e-9,+w.~. 236

3.6 CONTAINMENT SYSTEMS 3.6.4.3 Standby Gas Treatment (SGT) System LCO 3.6.4.3 Two SGT subsystems shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, and 3, SGT System 3.6.4.3 During operations with a potential for draining the reactor vessel (OPDRVs).

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A

One SGT subsystem A.1 Restore SGT subsystem to 7 days inoperable.

OPERABLE status.

B. Required Action and B.1

N 0 TE---------------

associated Completion LCO 3.0.4.a is not Time of Condition A not applicable when entering met in MODE 1, 2, or 3.

MODE 3.

Be in MODE 3.

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

c. Required Action and C.1 Place OPERABLE SGT Immediately associated Completion subsystem in operation.

Time of Condition A not met during OPDRVs.

OR C.2 Initiate action to suspend Immediately OPDRVs.

D. Two SGT subsystems D.1

N 0 TE---------------

inoperable in MODE 1, LCO 3.0.4.a is not 2, or 3.

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 Columbia Generating Station 3.6.4.3-1 Amendment No. +as,~,~. 236

ACTIONS CONDITION REQUIRED ACTION C. Required Action and C.1

N 0 TE---------------

associated Completion LCO 3.0.4.a is not Time of Condition B not applicable when entering met.

MODE 3.

Be in MODE 3.

D. Required Action and D.1 Be in MODE 3.

associated Completion Time of Condition A not met.

AND OR D.2 Be in MODE 4.

Both SW subsystems inoperable.

OR UHS inoperable for reasons other than Condition A.

SURVEILLANCE REQUIREMENTS SR 3.7.1.1 SR 3.7.1.2 SURVEILLANCE Verify the average water level in the UHS spray ponds is ;:o: 432 feet 9 inches mean sea level.

Verify the average water temperature of each UHS spray pond is~ 77°F.

SW System and UHS 3.7.1 COMPLETION TIME 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 FREQUENCY 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 24 hours Columbia Generating Station 3.7.1-2 Amendment No. 449,4-W,~.~. 236

SW System and UHS 3.7.1 SURVEILLANCE REQUIREMENTS SR 3.7.1.3 SR 3.7.1.4 SR 3.7.1.5 SURVEILLANCE

N 0 TE------------------------------

1 so I ati on 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.

FREQUENCY 31 days Verify average sediment depth in each UHS spray 92 days pond is < 0.5 ft.

Verify each SW subsystem actuates on an actual or 24 months simulated initiation signal.

Columbia Generating Station 3.7.1-3 Amendment No. 449,.w.9.~. 236

ACTIONS CONDITION C. Required Action and C.1 associated Completion Time of Condition A or B not met in MODE 1, 2, or 3.

D. Required Action and D.1 associated Completion Time of Condition A not met during OPDRVs.

OR D.2 E. Two CREF subsystems E.1 inoperable in MODE 1, 2, or 3 for reasons other than Condition B.

F. Two CREF subsystems F.1 inoperable during OPDRVs.

OR One or more CREF subsystems inoperable due to inoperable CRE boundary during OPDRVs.

Columbia Generating Station REQUIRED ACTION

N 0 TE------------

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

Be in MODE 3.

Place OPERABLE CREF subsystem in pressurization mode.

Initiate action to suspend OPDRVs.

N 0 TE------------

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

Be in MODE 3.

Initiate action to suspend OPDRVs.

CREF System 3.7.3 COMPLETION TIME 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Immediately Immediately 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Immediately 3.7.3-2 Amendment No. 2-0+,24-e,~, 236

3.7 PLANT SYSTEMS 3.7.4 Control Room Air Conditioning (AC) System Control Room AC System 3.7.4 LCO 3. 7.4 Two control room AC subsystems shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, and 3, During operations with a potential for draining the reactor vessel (OPDRVs).

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One control room AC A.1 Restore control room AC 30 days subsystem inoperable.

subsystem to OPERABLE status.

B. Two control room AC B.1 Verify control room area Once per 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months subsystems inoperable.

temperature < 90°F.

AND B.2 Restore one control room 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months AC subsystem to OPERABLE status.

C. Required Action and C.1

N 0 TE--------------

associated Completion LCO 3.0.4.a is not Time of Condition A or B applicable when entering not met in MODE 1, 2, or MODE 3.

3.

Be in MODE 3.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Columbia Generating Station 3.7.4-1 Amendment No. 4-e-9,4-99.~.~. 236

ACTIONS CONDITION REQUIRED ACTION D. Required Action and D.1 Place OPERABLE control associated Completion room AC subsystem in Time of Condition A not operation.

met during OPDRVs.

OR D.2 Initiate action to suspend OPDRVs.

E. Required Action and E.1 Initiate action to suspend associated Completion OPDRVs.

Time of Condition 8 not met during OPDRVs.

SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.7.4.1 Verify each control room AC subsystem has the capability to remove the assumed heat load.

Control Room AC System 3.7.4 COMPLETION TIME Immediately Immediately Immediately FREQUENCY 24 months Columbia Generating Station 3.7.4-2 Amendment No..u;g,+w,~,2-2+, 236

3.7 PLANT SYSTEMS 3.7.5 Main Condenser Offgas Main Condenser Offgas 3.7.5 LCO 3.7.5 The gross gamma activity rate of the noble gases measured at the main condenser air ejector shall be ~ 332 mCi/second after decay of 30 minutes.

APPLICABILITY:

MODE 1, MODES 2 and 3 with any main steam line not isolated and steam jet air ejector (SJAE) in operation.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Gross gamma activity A.1 Restore gross gamma 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months rate of the noble gases activity rate of the noble not within limit.

gases to within limit.

B. Required Action and B.1 Isolate all main steam lines.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time not met.

OR B.2 Isolate SJAE.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months OR B.3

N 0 TE--------------

LCO 3.0.4.a is not applicable when entering MODE3 Be in MODE 3.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Columbia Generating Station 3.7.5-1 Amendment No. 449,~.~. 236

AC Sources - Operating 3.8.1 ACTIONS CONDITION REQUIRED ACTION F. Required Action and F.1

N 0 TE--------------

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

MODE 3.

Be in MODE 3.

G. Three or more required G.1 Enter LCO 3.0.3.

AC sources inoperable.

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

COMPLETION TIME 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Immediately FREQUENCY 7 days SR 3.8.1.2

N 0 TES-----------------------------

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 2 58.8 Hz and~ 61.2 Hz for DG-1 and DG-2; and

b.

Voltage 2 3910 V and ~ 4400 V and frequency 2 58.8 Hz and~ 61.2 Hz for DG-3.

31 days Columbia Generating Station 3.8.1-5 Amendment No. 4-W,4&+.~. 236

ACTIONS CONDITION 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.

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.

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.

Columbia Generating Station H.1 1.1 J.1 REQUIRED ACTION Declare High Pressure Core Spray System inoperable.

Declare associated supported features inoperable.

N 0 TE-------------

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

Be in MODE 3.

DC Sources - Operating 3.8.4 COMPLETION TIME Immediately Immediately 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 3.8.4-3 Amendment ~.2-04.~. 236

Distribution Systems - Operating 3.8.7 ACTIONS CONDITION REQUIRED ACTION C. Required Action and C.1

N 0 TE--------------

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

MODE 3.

Be in MODE 3.

D. Division 1 250 V DC D.1 Declare associated electrical power supported feature(s) distribution subsystem inoperable.

inoperable.

E. One or more Division 3 E.1 Declare High Pressure AC or DC electrical Core Spray System power distribution inoperable.

subsystems inoperable.

F. Two or more divisions F.1 Enter LCO 3.0.3.

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

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

COMPLETION TIME 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Immediately Immediately Immediately FREQUENCY 7 days Columbia Generating Station 3.8.7-2 Amendment 4-49,4-W,~, 236

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 236 TO RENEWED FACILITY OPERATING LICENSE NO. NPF-21 ENERGY NORTHWEST COLUMBIA GENERATING STATION DOCKET NO. 50-397

1.0 INTRODUCTION

By letter dated August 12, 2014 (Reference 1 ), as supplemented by letters dated September 4, 2014, and April 3 and August 11, 2015 (References 2, 3, and 4, respectively), Energy Northwest (the licensee) submitted a license amendment request (LAR), which proposed changes to the Technical Specifications (TSs) for Columbia Generating Station (CGS). The proposed amendment would modify the TS Required Action end states associated with the implementation of the U.S. Nuclear Regulatory Commission (NRC)-approved Technical Specification Task Force (TSTF) Change Traveler TSTF-423, Revision 1, "Technical Specifications End States, NEDC-32988-A," dated December 22, 2009 (Reference 5). The TS Required Actions end state modifications would permit. for some systems, entry into a hot shutdown (Mode 3) end state rather than a cold shutdown (Mode 4) end state that is the current TS requirement. The amendment also modifies the TS Required Actions with a Note prohibiting the use of Limiting Condition for Operation (LCO) 3.0.4.a when entering the preferred end state (Mode 3) on startup.

The supplemental letters dated April 3 and August 11, 2015, provided additional information that clarified the application, did not expand the scope of the application as originally noticed, and did not change the NRC staff's original proposed no significant hazards consideration determination as published in the Federal Register on November 12, 2014 (79 FR 67200).

TSTF-423 incorporates the NRG-approved Boiling Water Reactor Owners Group's (BWROG's)

Topical Report (TR) 32988-A, Revision 2, "Technical Justification to Support Risk-Informed Modification to Selected Required Action End States for BWR [Boiling Water Reactor] Plants,"

December 2012 (Reference 6), into NUREG-1433, Revision 4, "Standard Technical Specifications - General Electric Plants (BWR/4)," April 2012, and NUREG-1434, Revision 4, "Standard Technical Specifications - General Electric Plants (BWR/6)," April 2012 (References 7 and 8, respectively). The TR conclusions are applicable for all of the boiling-water reactor (BWR) products (BWR/2 through BWR/6). The licensee stated that while the CGS TSs are based primarily on NUREG-1434, a few CGS TSs are based on NUREG-1433. The Federal Register notice published on February 18, 2011 (76 FR 9614),

announced the availability of this TS improvement as part of the consolidated line item improvement process.

TSTF-423 is one of the industry's initiatives developed under the Risk Management Technical Specifications program. These initiatives are intended to maintain or improve safety through the incorporation of risk assessment and management techniques in TS, while reducing unnecessary burden and making TS requirements consistent with the Commission's other risk-informed regulatory requirements, in particular the Maintenance Rule.

The following five operational modes are defined in the CGS TSs. Of specific relevance to TSTF-423 are Modes 3 and 4:

Mode 1 - Power Operation: The reactor mode switch is in run position.

Mode 2 - Startup: The reactor mode switch is in refuel position (with all reactor vessel head closure bolts fully tensioned) or in startup/hot standby position.

Mode 3 - Hot Shutdown: The reactor coolant system (RCS) temperature is above 200 degrees Fahrenheit (°F} and the reactor mode switch is in shutdown position (with all reactor vessel head closure bolts fully tensioned).

Mode 4 - Cold Shutdown: The RCS temperature is equal to or less than 200 °F and the reactor mode switch is in shutdown position (with all reactor vessel head closure bolts fully tensioned).

Mode 5 - Refueling: The reactor mode switch is in shutdown or refuel position, and one or more reactor vessel head closure bolts are less than fully tensioned.

The regulations in paragraph 50.36(c)(2)(i) of Title 10 of the Code of Federal Regulations (10 CFR), state, in part, that:

When a limiting condition for operation of a nuclear reactor is not met, the licensee shall shut down the reactor or follow any remedial action permitted by the technical specifications until the condition can be met.

The Standard Technical Specifications (STSs) and most plant TSs provide, as part of the remedial action, a Completion Time (CT} for the plant to either comply with remedial actions or restore compliance with the LCO. If the LCO or the remedial action cannot be met, then the reactor is required to be shut down. When the STS and individual plant TSs were written, the shutdown condition, or end state specified, was usually cold shutdown.

TR NEDC-32988-A, Revision 2, provides the technical basis to change certain required "end states" when the TS Actions for remaining in power operation cannot be met within the CTs.

Most of the requested TS changes permit an end state of hot shutdown (Mode 3) if risk is assessed and managed, rather than an end state of cold shutdown (Mode 4 ), contained in the current TSs. The proposed LAR was limited to those end states where: (1) entry into the shutdown mode is for a short interval, (2) entry is initiated by inoperability of a single train of equipment or a restriction on a plant operational parameter, unless otherwise stated in the applicable TS, and (3) the primary purpose is to correct the initiating condition and return to power operation as soon as is practical.

2.0 REGULATORY EVALUATION

In 10 CFR 50.36, "Technical specifications," the Commission established its regulatory requirements related to the content of TSs. Pursuant to 1 O CFR 50.36(c), TSs are required to include items in the following specific categories related to station operation: (1) safety limits, limiting safety system settings, and limiting control settings; (2) LCOs; (3) surveillance requirements; (4) design features; (5) administrative controls. The regulations in 10 CFR 50.36(c)(2)(i) state, in part, that:

Limiting conditions for operation are the lowest functional capability or performance levels of equipment required for safe operation of the facility. When a limiting condition for operation of a nuclear reactor is not met, the licensee shall shut down the reactor or follow any remedial action permitted by the technical specifications.

In describing the basis for changing end states, NEDC-32988-A states, in part, that:

Cold shutdown is normally required when an inoperable system or train cannot be restored to an operable status within the allowed time. However, going to cold shutdown results in the loss of steam-driven core cooling systems, challenges the shutdown heat removal systems, and requires restarting the plant.

A more preferred operational MODE is one that maintains adequate risk levels while repairs are completed without causing unnecessary challenges to plant equipment during shutdown and startup transitions.

In the end state changes under consideration in this LAR, a problem with a component or train has, or will, result in a failure to meet a TS, and a controlled shutdown is directed because a TS Action requirement cannot be met within the TS CT.

Most of the current TSs and design basis analyses were developed under the perception that putting a plant in cold shutdown would result in the safest condition and the design basis analyses would bound credible shutdown accidents. In the late 1980s and early 1990s, the NRC and licensees recognized that this perception was incorrect and took corrective actions to improve shutdown operation. At the same time, STSs were developed and many licensees improved their TSs. Since enactment of a shutdown rule was expected, almost all TS changes involving power operation, including a revised end state requirement, were postponed (see, for example, the Final Policy Statement on TS Improvements published in the Federal Register on July 22, 1993 (58 FR 39136); Reference 9). However, in the mid-1990s, the Commission decided a shutdown rule was not necessary in light of industry improvements. Controlling shutdown risk encompasses control of conditions that can cause potential initiating events and responses to those initiating events that do occur. Initiating events are a function of equipment malfunctions and human error. Responses to events are a function of plant sensitivity, ongoing activities, human error, defense-in-depth, and additional equipment malfunctions.

In practice, the risk during shutdown operations is often addressed via voluntary actions and application of the Maintenance Rule set forth in 10 CFR 50.65, "Requirements for monitoring the effectiveness of maintenance at nuclear power plants." The regulations in 10 CFR 50.65(a)(4) state, in part, that:

Before performing maintenance activities..., the licensee shall assess and manage the increase in risk that may result from the proposed maintenance activities. The scope of the assessment may be limited to structures, systems, and components that a risk-informed evaluation process has shown to be significant to public health and safety.

The NRC staff's approved TSTF-423 states that the changes proposed are consistent with the following rules, regulations, and associated regulatory guidance. Regulatory Guide (RG) 1.182, "Assessing and Managing Risk Before Maintenance Activities at Nuclear Power Plants,"

May 2000 (Reference 10), provides guidance on implementing the provisions of 10 CFR 50.65(a)(4) by endorsing the revised Section 11 (published separately) to the Nuclear Management and Resource Council (NUMARC) 93-01, Revision 3, "Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," July 2000 (Reference 11 ). RG 1.182 was withdrawn since it was determined that the document (RG 1.182) was redundant due to the inclusion of its subject matter in Revision 3 of RG 1.160, "Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," May 2012 (Reference 12). Withdrawal of RG 1.182 was published in the Federal Register on November 27, 2012 (77 FR 70846). The Federal Register notice also stated that withdrawal of RG 1.182 neither altered any prior or existing licensing commitments based on its use, nor constituted backfitting as defined in 10 CFR 50.109 (the Backfit Rule) and was not otherwise inconsistent with the issue finality provisions in 10 CFR Part 52. As stated in its application dated August 12, 2104, the licensee is committed to compliance with RG 1.160, Revision 3.

In addition, the NRC staff observed that RG 1.160 endorsed Revision 4A of the NUMARC 93-01, "Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," April 2011 (Reference 13). NUMARC 93-01 provides methods that are acceptable to the NRC staff for complying with the provisions of Section 50.65, "Requirements for monitoring the effectiveness of maintenance at nuclear power plants," of 10 CFR Part 50, "Domestic Licensing of Production and Utilization Facilities." The model safety evaluation (SE) for the TSTF (Reference 14) currently refers to the guidance in Revision 2 of the NUMARC 93-01. In its letter dated August 12, 2014, the licensee states that Energy Northwest will follow Section 11 of NUMARC 93-01, Revision 4A.

In addition, per the application, Energy Northwest has made a Regulatory Commitment to follow NU MARC 93-01, Revision 4A (April 2011 ).

In its letter dated August 12, 2014, the licensee further stated, in part, that The proposed TS changes are consistent with TSTF-423, Revision 1. The TSTF traveler is based on NUREG-1433 Revision 3.0, "Standard Technical Specifications General Electric Plants, BWR/4," and NUREG-1434 Revision 3.0, "Standard Technical Specifications General Electric Plants, BWR/6." While Columbia's [CGS]

TS are based primarily on NUREG-1434, a few Columbia TS are based on NUREG-1433. Therefore, adaption of the TS markups contained in TSTF-423, Revision 1 is required. The proposed variations/deviations are described in Table 1 of this document."

3.0 TECHNICAL EVALUATION

Note: Deviations from TSTF-423 and the model SE are described in Table 1 to Attachment 1 of the licensee's letter dated August 12, 2014.

3.1 Proposed TS Changes

In its LAR, the licensee proposed the following TS changes:

TS 3.3.8.2: Reactor Protection System (RPS) Electric Power Monitoring Current TS 3.3.8.2 Required Action C.1 states:

Be in MODE 3.

[Be in MODE 4. (Required Action C.2)]

Revised TS 3.3.8.2 Required Action C.1 would state:

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

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

Be in MODE 3.

Current TS 3.3.8.2 Required Action C.2, which states "Be in MODE 4," with a CT of "36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months ,"

would be deleted.

For TS 3.3.8.2, the application does not specify any deviation from TSTF-423, Revision 1, (Reference 5), or the TSTF model SE.

TS 3.4.4: Safety/Relief Valves (SRVs) - < 25% RTP [Reactor Thermal Power]

Current TS 3.4.4 Condition A states:

One or more required SRVs inoperable.

Revised TS 3.4.4 Condition A would state:

One required SRV inoperable.

Required Action A.1 must be taken as follows:

Be in MODE 3.

[Be in MODE 4. (Required Action A.2)].

Current TS 3.4.4 Required Action A.1 states:

Be in MODE 3.

Revised TS 3.4.4 Required Action A.1 would state:

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

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

Be in MODE 3.

Current TS 3.4.4 Required Action A.2, which states "Be in MODE 4," with a CT of "36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months ,"

would be deleted.

New TS 3.4.4 Condition B would state:

Two or more required SRVs inoperable.

New TS Required Action B.1, with a CT of "12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ," would state:

Be in MODE 3.

New TS Required Action B.2, with a CT of "36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months ," would state:

Be in MODE 4.

The application explains a deviation from TSTF-423 as follows (as stated):

Energy Northwest proposes to modify the existing Condition A from "one or more required SRVs [safety relief valves] inoperable" to "one required SRV inoperable." The Required Action is to be in Mode 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , which is consistent with the TSTF-423 change to STS Condition B. New Condition B for "two or more required SRVs inoperable" is consistent with the TSTF-423 change to Condition C and requires being in Mode 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and Mode 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months .

The application explains a deviation from the model SE as follows (as stated):

The model SE lists the number of SRVs to be operable for both the safety function and relief function. In NUREG-1434, a specific number for these SRVs is bracketed depending upon a plant's design configuration. The Columbia TS requires that the safety function of four SRVs be operable.

The Conditions and proposed modification for end state Required Actions are as described in the table provided in the application. The model SE is based on the STS.

TS 3.5.1: ECCS [Emergency Core Cooling System] - Operating Current TS 3.5.1 Required Action D.1 states:

Be in MODE 3.

[Be in MODE 4 (Required Action D.2)]

Revised TS 3.5.1 Required Action D.1 would state:

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

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

Be in MODE 3.

Current TS 3.5.1 Required Action D.2, which states "Be in MODE 4," with a CT of "36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months ,"

would be deleted.

Current TS 3.5.1 Required Action G.1 states:

Be in MODE 3.

[Reduce reactor dome pressure to ::;;150 psig. (Required Action G.2)]

Revised TS 3.5.1 Required Action G.1 would state:

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

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

Be in MODE 3.

Current TS 3.5.1 Required Action G.2, which states "Reduce reactor steam dome pressure to

150 psig," with a CT of "36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months ," would be deleted.

Per the application, there is no deviation from TSTF-423.

The application explains a deviation from the model SE as follows (as stated):

The model SE lists the number of SRVs required to be operable for the ADS

[automatic depressurization system] function. In NUREG-1434, the specific number is bracketed. The Columbia TS require the ADS function of six SRVs be operable.

TS 3.6.1.5: Residual Heat Removal (RHR) Drywell Spray Current TS 3.6.1.5 Required Action C.1 states:

Be in MODE 3.

AND

[Be in MODE 4. (Required Action C.2)]

Revised TS 3.6.1.5 Required Action C.1 would state:

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

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

Be in MODE 3.

Current TS 3.6.1.5 Required Action C.2, which states "Be in MODE 4," with a CT of "36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months ,"

would be deleted.

Per the application, there is no deviation from TSTF-423.

The application explains a deviation from the model SE as follows (as stated):

The Columbia TS refer to this system as "RHR Drywell Spray System" rather than "RHR Containment Spray System". The Columbia-specific design described in the TS Bases differs slightly from that described in the STS Bases (NUREG-1434 Volume 2) and the model SE.

TS 3.6.1.6: Reactor Building-to-Suppression Chamber Vacuum Breakers New TS 3.6.1.6 Condition D would state:

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

New TS 3.6.1.6 Required Action D1, with a CT of "12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , would state:

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

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

Be in MODE 3.

Current TS 3.6.1.6 Condition D and Required Action D.1 would be renumbered as Condition E and Required Action E.1, respectively.

Current TS 3.6.1.6 Condition E states:

Required Action and associated Completion Time not met.

Revised TS 3.6.1.6 Condition E, renumbered as Condition F, would state:

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

Current TS 3.6.1.6 Required Actions E.1 and E.2 would be renumbered as F.1 and F.2, respectively.

Per the application, there is no deviation from TSTF-423.

The application explains a deviation from the model SE as follows (as stated):

This Specification from the BWR/4 STS applies to Columbia.

TS 3.6.1. 7: Suppression Chamber-to-Drvwell Vacuum Breakers New TS 3.6.1. 7 Condition B would state:

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

New TS 3.6.1. 7 Required Action B.1, with a CT of "12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , would state:

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

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

Be in MODE 3.

Current TS 3.6.1. 7 Condition B would be renumbered as Condition C and current TS 3.6.1. 7 Required Action B.1 would be renumbered as Required Action C.1.

Current TS 3.6.1.7 Condition C would be renumbered as Condition D and current TS 3.6.1.7 Required Action C.1 would be renumbered as Required Action D.1.

Current TS 3.6.1. 7 Condition D states:

Required Action and associated Completion Time not met.

Revised TS 3.6.1.7 Condition D, renumbered as Condition E, would state:

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

Current TS 3.6.1.7 Required Actions D.1 and D.2 would be renumbered as Required Actions E.1 and E.2, respectively.

The application explains a deviation from TSTF-423 as follows (as stated):

TSTF-423 added a new Condition B and renumbered the subsequent two Conditions (now Condition C and D). Condition D is applicable when the Required Action and associated Completion Time of Condition C is not met and requires being in Mode 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and Mode 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . Energy Northwest proposes to add the new Condition B consistent with TSTF-423. However, the Columbia TS contain three subsequent Conditions, and Energy Northwest proposes to renumber these to be Conditions C, D, and E.

TSTF-423 modified Condition D to apply only to Condition C. The Required Action is to be in Mode 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and Mode 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . Energy Northwest proposes to revise the analogous Columbia TS Condition E to apply to Conditions C and D. The Required Action is to be in Mode 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and Mode 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months , which is consistent with the existing Required Action and associated Completion Time and is not changed by TSTF-423.

The application explains a deviation from the model SE as follows (as stated):

This Specification from the BWR/4 STS applies to Columbia.

The model SE lists the number of suppression chamber-to-drywell vacuum breakers required to be operable. In NUREG-1433, the specific number is bracketed. The Columbia TS require seven suppression chamber-to-drywell vacuum breakers be operable for opening.

The Conditions and proposed modification for end state Required Actions are as described in this table. The model SE is based on the SE for NEDC-32988-A Revision 2.

TS 3.6.2.3: Residual Heat Removal (RHR) Suppression Pool Cooling Current TS 3.6.2.3 Condition B states:

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

Two RHR suppression pool cooling subsystems inoperable.

Revised TS 3.6.2.3 Condition B would state:

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

Current TS 3.6.2.3 Condition B.1 states:

Be in MODE 3.

AND Revised TS 3.6.2.3 Required Action B.1, with a CT of "12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ," would state:

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

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

Be in MODE 3.

Current TS 3.6.2.3 Required Action B.2, which states "Be in MODE 4," with a CT of "36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months ,"

would be deleted.

New TS 3.6.2.3 Condition C would state:

Two RHR suppression pool cooling subsystems inoperable.

New TS 3.6.2.3 Required Action C.1, with a CT of "12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ," would state:

Be in MODE 3.

New TS 3.6.2.3 Required Action C.2, with a CT of "36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months ," would state:

Be in MODE 4.

The application explains a deviation from TSTF-423 as follows (as stated):

In order to accommodate the TSTF-423 change to Condition B, Energy Northwest proposes to create new Condition C for "two RHR [residual heat removal] suppression pool cooling subsystems inoperable." The Required Actions are to be in Mode 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and Mode 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months , which is consistent with the existing Required Action and associated Completion Times and is not changed by TSTF-423.

Per the application, there is no deviation from the TSTF model SE.

TS 3.6.4.1: Secondary Containment Current TS 3.6.4.1 Required Action B.1 states:

Be in MODE 3.

AND

[Be in MODE 4. (Required Action B.2)]

Revised TS 3.6.4.1 Required Action B.1, with a CT of "12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ," would state:

N 0 TE-------------------------------------------------

L CO 3.0.4.a is not applicable when entering MODE 3.

Be in MODE 3.

Current TS 3.6.4.1 Required Action B.2, which states "Be in MODE 4," with a CT of "36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months ,"

would be deleted.

Per the application, there is no deviation from the TSTF-423 model SE.

TS 3.6.4.3: Standby Gas Treatment (SGT) System Current TS 3.6.4.3 Required Action B.1 states:

Be in MODE 3.

AND

[Be in MODE 4. (Required Action B.2)]

Revised TS 3.6.4.3 Required Action B.1, with a CT of "12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ," would state:

N 0 TE-------------------------------------------------

L CO 3.0.4.a is not applicable when entering MODE 3.

Be in MODE 3.

Current TS 3.6.4.3 Required Action B.2, which states "Be in MODE 4," with a CT of "36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months ,"

would be deleted.

Current TS 3.6.4.3 Required Action D.1 states:

Enter LCO 3.0.3.

Revised TS 3.6.4.3 Required Action D.1 would state:

N 0 TE-------------------------------------------------

L CO 3.0.4.a is not applicable when entering MODE 3.

Be in MODE 3.

The current CT for TS 3.6.4.3 Required Action D.1, which states "Immediately," would be revised to state "12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ."

Per the application, there is no deviation from TSTF-423/model SE.

TS 3.7.1: Standby Service Water (SW) System and Ultimate Heat Sink (UHS)

New TS 3.7.1 Condition C would state:

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

New TS 3.7.1 Required Action C.1, with a CT of "12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ," would state:

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

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

Be in MODE 3.

Current TS 3. 7.1 Condition C states:

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

Both SW subsystems inoperable.

UHS inoperable for reasons other than Condition A.

Revised TS 3.7.1 Condition C, renumbered as Condition D, would state:

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

Both SW subsystems inoperable.

UHS inoperable for reasons other than Condition A.

Current TS 3.7.1 Required Actions C.1 and C.2 would be renumbered as Required Actions D.1 and D.2, respectively.

The application explains a deviation from TSTF-423 as follows (as stated):

TSTF-423 relocated the Condition for "one SSW [standby service water]

subsystem inoperable" from Condition C to Condition B. This Condition was already numbered as Condition B in the Columbia TS. Thus, this change is not proposed.

Energy Northwest proposes to add Condition C for "Required Action and associated Completion Time of Condition B not met," which is consistent with TSTF-423. However, TSTF-423 also applies this new Condition to Condition A. In NUREG-1434, Condition A is for "one or more cooling towers with one cooling tower fan inoperable." This Condition is not applicable to Columbia and is not included in the Columbia TS. Thus, Energy Northwest proposes to only apply new Condition C to existing Condition B.

TSTF-423 renumbered Condition B to Condition D. In NUREG-1434 this Condition is related to water temperature in the ultimate heat sink (UHS).

This Condition is not included in the Columbia TS. Thus, this change is not proposed.

TSTF-423 renumbered Condition D to Condition E. This Condition is applicable to the following situations: 1) Required Action and associated Completion Time of Condition D not met; 2) Both SSW subsystems inoperable; or 3) UHS inoperable for reasons other than Condition A.

Energy Northwest proposes to renumber existing Condition C to Condition D and modify it to be consistent with TSTF-423 but recognize the Columbia-specific Conditions as follows: 1) Required Action and associated Completion Time of Condition A not met; 2) both SW [service water] subsystems inoperable; or 3) UHS inoperable for reasons other than Condition A. The Required Action is to be in Mode 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and Mode 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months .

Note that Condition A for Columbia is related to UHS water inventory.

TSTF-423 provisions are not proposed to be applied to this Condition A.

The application explains a deviation from the model SE as follows (as stated):

The model SE discusses cooling towers and UHS temperature. In NUREG-1434, these requirements are bracketed. The Columbia TS do not contain these requirements. The Columbia TS contain requirements for sediment depth in the spray ponds.

The Conditions and proposed modification for end state Required Actions are as described in this table. The model SE is based on the STS.

TS 3.7.3: Control Room Emergency Filtration (CREF) System Current TS 3.7.3 Required Action C.1 states:

Be in MODE 3.

[Be in MODE 4. (Required Action C.2)]

Revised TS 3.7.3 Required Action C.1 would state:

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

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

Be in MODE 3.

Current TS 3.7.3 Required Action C.2, which states "Be in MODE 4," with a CT of "36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months ,"

would be deleted.

Current TS 3.7.3 Required Action E.1 states:

Enter LCO 3.0.3.

Revised TS 3.7.3 Required Action E.1 would state:

N 0 TE-------------------------------------------------

L CO 3.0.4.a is not applicable when entering MODE 3.

Be in MODE 3.

The CT for current TS 3.6.4.3 Required Action E.1, which states "Immediately," would be revised to state "12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

Per the application, there is no deviation from TSTF-423.

The application explains a deviation from the model SE as follows (as stated):

The Columbia TS refer to this system as "Control Room Emergency Filtration (CREF) System" rather than "Control Room Fresh Air (CRFA)

System". The Columbia-specific design described in the TS Bases differs slightly from that described in the STS Bases (NUREG-1434 Volume 2) and the model SE.

Due to the adoption of TSTF-448 in the Columbia TS, the Required Actions and associated Completion Times of Condition B differ from that described in the model SE.

TS 3.7.4: Control Room Air Conditioning (AC) System Current TS 3.7.4 Required Action C.1 states:

Be in MODE 3.

[Be in MODE 4. (Required Action C.2)]

Revised TS 3.7.4 Required Action C.1 would state:

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

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

Be in MODE 3.

Current TS 3.7.4 Required Action C.2, which states "Be in MODE 4," with a CT of "36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months ,"

would be deleted.

The application explains a deviation from TSTF-423 as follows (as stated):

The TS markups in TSTF-423 preceded the issuance of TSTF-477, "Adding an Action Statement for Two Inoperable Control Room Air Conditioning Subsystems." As such, TSTF-423 removes the requirement to go to Mode 4 from Condition Band Condition D. Condition Bis for the Required Action and associated Completion Time of Condition A not met in Mode 1, 2, or 3.

Condition A is for one control room AC [air conditioning] subsystem inoperable.

Condition D is for two control room AC subsystems inoperable in Mode 1, 2, or 3.

Energy Northwest has adopted TSTF-477, which created a new Condition B for two control room AC subsystem inoperable and provided an allowed outage time of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . Condition C is for the Required Action and associated Completion Time of Condition A or B not met in Mode 1, 2, or 3. This Condition C encompasses the changes made to Conditions B and D in TSTF-423. Thus, Energy Northwest proposes to modify Condition C consistent with TSTF-423.

The application explains a deviation from the model SE as follows (as stated):

The Columbia-specific design described in the TS Bases differs slightly from that described in the STS Bases (NUREG-1434 Volume 2) and the model SE.

Due to the adoption of TSTF-477, the Conditions and proposed modification for end state Required Actions are as described in this table and differ from the model SE.

TS 3.7.5: Main Condenser Offgas Current TS 3.7.5 Required Action B.3.1 states:

Be in MODE 3.

AND

[Be in MODE 4. (Required Action B.3.2)]

Revised TS 3.7.5 Required Action B.3.1, renumbered as Required Action B.3, would state:

N 0 TE-------------------------------------------------

L CO 3.0.4.a is not applicable when entering MODE 3.

Be in MODE 3.

Current TS 3.7.5 Required Action B.3.2, which states "Be in MODE 4," with a CT of "36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months ,"

would be deleted.

Per the application, there is no deviation from TSTF-423.

The application explains a deviation from the model SE as follows (as stated):

The model SE contains the value for gross gamma activity rate of the noble gases. In NUREG-1434 the specific number is bracketed. The Columbia TS require the gross gamma activity rate of the noble gases be less than or equal to 332 [microcuries (mCi)]/second. Additionally, the model SE contains the location for the measurement of the activity rate. In NUREG-1434 this information is bracketed. The Columbia TS require the activity rate be measured at the main condenser air ejector.

TS 3.8.1: AC [Alternating Current] Sources - Operating Current TS 3.8.1 Required Action F.1 states:

Be in MODE 3.

AND

[Be in MODE 4 (Required Action F.2)]

Revised TS 3.8.1 Required Action F.1 would state:

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

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

Be in MODE 3.

Current TS 3.8.1 Required Action F.2, which states "Be in MODE 4, with a CT of "36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months ,

would be deleted.

The application explains a deviation from TSTF-423 as follows (as stated):

NUREG-1434 Condition Fis for one required automatic load sequencer inoperable. This Condition is not included in the Columbia TS. NUREG-1434 Condition G is analogous to Columbia Condition F. Energy Northwest proposed to modify Condition F consistent with TSTF-423.

The application explains a deviation from the model SE as follows (as stated):

The Columbia-specific design described in the TS Bases differs slightly from that described in the STS Bases (NUREG-1434 Volume 2) and the model SE.

The model SE includes the requirement for automatic load sequencers.

In NUREG-1434 this information is bracketed. The Columbia TS do not contain this requirement.

The Conditions and proposed modification for end state Required Actions are as described in the table provided in the application. The model SE is based on the STS.

TS 3.8.4: DC [Direct Current] Sources - Operating Current TS 3.8.4 Required Action J.1 states:

Be in MODE 3.

AND

[Be in MODE 4. (Required Action J.2)]

Revised TS 3.8.4 Required Action J.1 would state:

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

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

Be in MODE 3.

Current TS 3.8.1 Required Action J.2, which states "Be in MODE 4," with a CT of "36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months ,"

would be deleted.

The application explains a deviation from TSTF-423 as follows (as stated):

TSTF-423 created new Condition D for "Required Action and associated Completion Time for Division 1 or 2 DC [direct current] electrical power subsystem for Condition A, B, or C not met." Condition A for "one battery charger on one division inoperable" is analogous to Columbia's Condition A. Condition B for "one battery on one division inoperable" is analogous to Columbia's Condition D. Condition C for "Division 1 or 2 DC electrical power subsystem inoperable for reasons other than Condition A or B" is analogous to Columbia's Condition G. Thus, Columbia's existing Condition J is analogous to the TSTF-423 Condition D. Energy Northwest proposes to modify Condition J consistent with TSTF-423.

TSTF-423 renumbered existing Condition D to Condition E. This condition is for "Division 3 DC electrical power subsystem inoperable for reasons other than Condition A or B." This change is not applicable to the Columbia TS.

TSTF-423 renumbered existing Condition E to Condition F. This Condition was modified to apply only when the Required Action and associated Completion Time for Division 3 DC electrical power subsystem for Condition A, B, or E not met." The Columbia TS already contain an existing Condition (H) that applies when the Required Action and associated Completion Time of Division 3-related Conditions are not met.

Thus, no changes are proposed to existing Condition H.

The application explains a deviation from the model SE as follows (as stated):

The Conditions and proposed modification for end state Required Actions are as described in the table provided in the application. The model SE is based on the STS.

TS 3.8. 7: Distribution Systems - Operating Current TS 3.8. 7 Required Action C.1 states:

Be in MODE 3.

[Be in MODE 4. (Required Action C.2)]

Revised TS 3.8.7 Required Action C.1 would state:

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

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

Be in MODE 3.

Current TS 3.8.7 Required Action C.2, which states, "Be in MODE 4," with a CT of "36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months ,"

would be deleted.

The application explains a deviation from TSTF-423 as follows (as stated):

TSTF-423 modified Condition D. This Condition is for "Required Action and associated Completion Time of Condition A, B, or C not met." Energy Northwest proposes to modify the analogous Condition C for "Required Action and associated Completion Time of Condition A or B not met" consistent with TSTF-423. NUREG-1434 contains Condition B for "one or more Division 1 and 2 AC [alternating current] vital buses inoperable." The Columbia TS do not contain this Condition. Thus, for Columbia, the TSTF-423 provisions are only applied when Condition A or B (which is analogous to NUREG-1434 Condition C) are not met.

The application explains a deviation from the model SE as follows (as stated):

The Columbia-specific design described in the TS Bases differs slightly from that described in the STS Bases (NUREG-1434 Volume 2) and the model SE.

The model SE includes the requirement for vital AC buses. In NUREG-1434 this requirement is bracketed. The Columbia TS do not contain this requirement.

The Conditions and proposed modification for end state Required Actions are as described in this table. The model SE is based on the STS.

Based on its review of the licensee's deviations from TSTF-423 and model SE as listed above, the NRC staff concludes that the licensee's information provides acceptable explanations/clarifications for its proposed changes, meets the intent of the technical requirements specified in the NRC approved TR NEDC-32988 SE dated September 27, 2002 (Reference 15), and the proposed changes are consistent with the TSTF-423 changes. A detailed technical evaluation is provided below in SE Section 3.4.

An overview of the generic evaluation and associated risk assessment is provided below, along with a summary of the associated TS changes discussed in TR NEDC-32988 A as well as the licensee's optional changes and variations from TSTF-423 and the model SE stated above.

3.2 Risk Assessment The objective of the BWROG TR NEDC-32988-A risk assessment was to show that any risk increases associated with the proposed changes in TS end states are either negligible or negative (i.e., a net decrease in risk). The BWROG TR documents a risk-informed analysis of the proposed TS change. Probabilistic Risk Assessment (PRA) results and insights are used, in combination with results of deterministic assessments, to identify and propose changes in "end states" for all BWR plants. This is in accordance with guidance provided in RG 1.17 4, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant Specific Changes to the Licensing Basis," July 1998 (Reference 16), and RG 1.177, "An Approach for Plant Specific Risk-Informed Decisionmaking: Technical Specifications," August 1998 (Reference 17). The three-tiered approach documented in RG 1.177 was followed. The first tier of the three-tiered approach includes the assessment of the risk impact of the proposed change for comparison to acceptance guidelines consistent with the Commission's Safety Goal Policy Statement, as documented in RG 1.17 4. The first tier aims at ensuring that there are no unacceptable temporary risk increases as a result of the TS change, such as when equipment is taken out of service. The second tier addresses the need to preclude potentially high-risk configurations that could result if equipment is taken out of service, concurrently with the equipment out of service, as allowed by this TS change. The third tier addresses the application of 10 CFR 50.65(a)(4) of the Maintenance Rule for identifying risk-significant configurations, resulting from maintenance-related activities and taking appropriate compensatory measures to avoid such configurations.

The TSs invokes a risk assessment because 10 CFR 50.65(a)(4) is applicable to maintenance-related activities and does not cover other operational activities beyond the effect they may have on existing maintenance-related risk.

The BWROG's risk assessment approach was found to be comprehensive and acceptable in the SE for the topical report. In addition, the analyses show that the three-tiered approach criteria for allowing TS changes are met as follows:

Risk Impact of the Proposed Change (Tier 1 ): The risk changes associated with the TS changes in TSTF-423, in terms of mean yearly increases in core damage frequency (CDF) and large early release frequency (LERF), are risk neutral or risk beneficial. In addition, there are no significant temporary risk increases, as defined by RG 1.177 criteria, associated with the implementation of the TS end state changes.

Avoidance of Risk-Significant Configurations (Tier 2): The performed risk analyses, which are based on single LCOs, indicate that there are no high-risk configurations associated with the TS end state changes. The reliability of redundant trains is normally covered by a single LCO. When multiple LCOs occur, which affect trains in several systems, the plant's risk-informed configuration risk management program, or the risk assessment and management program implemented in response to the Maintenance Rule, 10 CFR 50.65(a)(4), shall ensure that high-risk configurations are avoided. As part of the implementation of TSTF-423, the licensee has committed to follow Section 11 of NUMARC 93-01, Revision 3, as specified in Section 4.0. The NRC staff concludes that such guidance is adequate for preventing risk-significant plant configurations.

Configuration Risk Management (Tier 3): The licensee has a program in place to ensure compliance with 10 CFR 50.65(a)(4) to assess and manage the risk from maintenance activities. This program can support the licensee's decision in selecting the appropriate actions to control risk for most cases in which a risk-informed TS is entered.

The generic risk impact of the end state mode change was evaluated subject to the following assumptions and TSTF-IG-05-02, "Implementation Guidance for TSTF-423, Revision 0,

'Technical Specifications End States, NEDC-32988-A,"' September 2005 (Reference 18):

1.

The entry into the end state is initiated by the inoperability of a single train of equipment or a restriction on a plant operational parameter, unless otherwise stated in the applicable technical specification.

2.

The primary purpose of entering the end state is to correct the initiating condition and return to power as soon as is practical.

3.

When Mode 3 is entered as the repair end state, the time the reactor coolant pressure is above 500 pounds per square inch gauge (psig) will be minimized. If reactor coolant pressure is above 500 psig for more than 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , the associated plant risk will be assessed and managed.

These assumptions are consistent with typical entries into Mode 3 for short duration repairs, which is the intended use of the TS end state changes. The NRC staff concludes that, going to Mode 3 (hot shutdown) instead of going to Mode 4 (cold shutdown) to carry out equipment repairs that are of short duration, does not have any adverse effect on plant risk.

3.4 Assessment of TS Changes Adoption of TSTF-423 requires the following NOTE be added to each Required Action where the end state is changed to Mode 3: "LCO 3.0.4.a is not applicable when entering MODE 3".

The addition of this NOTE is acceptable because it prevents an inappropriate use of the LCO 3.0.4.a allowance to go up in Mode with the specified system being inoperable. Since the basis for the NOTE is the same for all affected LCOs, the NRC staffs discussion on the basis for acceptance is not repeated in each assessment below.

3.4.1 LCO 3.3.8.2: Reactor Protection System (RPS) Electric Power Monitoring The RPS Electric Power Monitoring System is provided to isolate the RPS bus from the normal uninterruptible power supply or an alternate power supply in the event of over voltage, under voltage, or under frequency. This system protects the load connected to the RPS bus against unacceptable voltage and frequency conditions and forms an important part of the primary success path of the essential safety circuits. Some of the essential equipment powered from the RPS buses include the RPS logic, scram solenoids, and various valve isolation logic. The TS change allows the plant to remain in Mode 3 until the repairs are completed.

LCO: For Modes 1, 2, and 3, and Modes 4 and 5 with both RHR shutdown cooling suction isolation valves open, and Mode 5 with any control rod withdrawn from a core cell containing one or more fuel assemblies, two RPS electric power monitoring assemblies shall be OPERABLE for each in-service RPS motor generator set, or alternate power supply that supports equipment required to be OPERABLE.

Condition Requiring Entry into End State: If the LCO cannot be met, the associated in-service power supply(s) must be removed from service within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months (Required Action B.1 ). In Modes 1, 2, and 3, if the in-service power supply(s) cannot be removed from service within the allotted time, the plant must be placed in Mode 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and Mode 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months (Required Actions C.1 and C.2).

Modification for End State Required Actions: The change allows the plant to remain in Mode 3 until the repair actions are completed. Required Action C.2, which required the plant to be in Mode 4, is deleted allowing the plant to stay in MODE 3 while completing repairs.

Assessment: To reach Mode 3, per the TS, there must be a functioning power supply with protective circuitry in operation. However, the over voltage, under voltage, or under frequency condition must exist for an extended time period to cause damage. There is a low probability of this occurring in the short period of time that the plant would remain in Mode 3 without this protection.

The specific failure condition of interest is not risk-significant for BWR PRAs. If the required restoration actions cannot be completed within the specified time, going into Mode 4 at CGS would cause loss of the high-pressure reactor core isolation cooling (RCIC} system and loss of the power conversion system (condenser/feedwater), and would require activating the RHR system. In addition, emergency operating procedures (EOPs) direct the operator to take control of the depressurization function if low-pressure injection/spray systems are needed for reactor pressure vessel (RPV) water makeup and cooling.

Based on the low probability of loss of the RPS power monitoring system during the infrequent and limited time in Mode 3 and the number of systems available in Mode 3, the NRC staff concludes that the risks of staying in Mode 3 are approximately the same as, and in some cases, lower than the risks of going to the Mode 4 end state; therefore, the change is acceptable.

In its letter dated April 3, 2015, the licensee stated, in part, that The SE Assessment is applicable to the Columbia design because Columbia has equivalent systems with the following clarifications: Going to Mode 4 would cause loss of the high-pressure steam-driven injection system - reactor core isolation and cooling system. Columbia's high pressure core spray (HPCS) system is motor driven. Columbia does not have a steam driven high pressure core injection (HPCI) system. This aspect of the BWR-5 configuration is addressed on page 25 of the SE for TR NEDC-32988, Revision 2.

Based on its review, the NRC staff concludes that the information provided by the licensee is consistent with the staff's SE for the topical report TR-NEDC-32988, Revision 2, which states that a motor-driven HPCS system, such as CGS's system, is capable of mitigating any potential accidents in Mode 3 and can function during a station blackout, therefore, the staff's assessment for the proposed change remains unaffected and the change is acceptable.

3.4.2 TS 3.4.4: Safety/Relief Valves (SRVs) - < 25% RTP The function of the SRVs is to protect the plant against severe overpressurization events.

These TSs provide the operability requirements for the SRVs as described below. The TS change allows the plant to remain in Mode 3 until the repairs are completed.

LCO: For CGS, the safety function of four SRVs shall be OPERABLE.

Condition requiring entry into end state: If the LCO cannot be met with one or more required SRVs inoperable, the plant must be placed in Mode 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in Mode 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months .

Proposed modification for end state required actions: If the LCO cannot be met with one required SRV inoperable, the plant must be placed in Mode 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . If two or more SRVs become inoperable, the plant must be placed in Mode 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and Mode 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months .

Assessment: The BWROG did a comparative PRA evaluation of the core damage risks of operation in the current end state and in the proposed Mode 3 end state. The evaluation indicates that the core damage risks are lower in Mode 3 than in Mode 4. Going to Mode 4 for one inoperable SRV would cause loss of the high-pressure steam-driven injection system (RCIC and HPCS), and loss of the power conversion system (condenser/feedwater), and require activating the RHR system. In addition, the EOPs direct the operator to take control of the depressurization function if low pressure injection/spray systems are needed for RPV water makeup and cooling. Based on the low probability of loss of the necessary overpressure protection function and the number of systems available in Mode 3, the NRC staff concludes that the risks of staying in Mode 3 are approximately the same as and in some cases lower than the risks of going to the Mode 4 end state. The proposed change would allow the inoperable SRV to be repaired in a plant operating mode with lower risks. After repairs are made, the plant can be brought to full-power operation with less potential for transients and errors. The plant is taken into cold shutdown only when four or more SRVs are inoperable.

The requested change to allow operation in Mode 3 with a minimum number of SRVs inoperable is acceptable after a plant-specific evaluation. Since the time spent in Mode 3 to perform the repair is infrequent and limited, and in light of defense-in-depth considerations, the NRC staff concludes the proposed change is acceptable.

In its letter dated April 3, 2015, the licensee stated, in part, that Columbia has 18 SRVs. The SRVs can actuate by either of two modes: the safety mode or the relief mode. In the safety mode (or spring operation), the direct action of the steam pressure in the main steam line will act against a spring loaded disk that will pop open when the valve inlet pressure exceeds the spring force. In the relief mode (or power actuated mode of operation), a pneumatic piston/cylinder and mechanical linkage assembly are used to open the valve by overcoming the spring force, even with the valve inlet pressure equal to 0 psig.

Seven of the SRVs that provide the safety and relief function are part of the Automatic Depressurization System specified in LCO 3.5.1, "ECCS - Operating."

In the Columbia severe over pressurization event, only 4 SRVs with the highest setpoints are assumed to operate in the safety mode to mitigate the event.

While the number of SRVs (4) at Columbia is less than what is discussed in the SE, the Assessment remains applicable to the Columbia design with the following clarification: Going to Mode 4 would cause loss of the high-pressure steam-driven injection system (RCIC). Columbia's HPCS system is motor driven.

Columbia does not have a steam driven HPCI system. This aspect of the BWR-5 configuration is addressed on page 25 of the SE. The variability among BWR plants regarding the number of SRVs is also addressed on page 25 of the SE.

Note that Columbia is taken to cold shutdown when two or more required SRVs are inoperable.

Based on its review, the NRC staff concludes that the licensee's plant-specific information regarding its SRV system, does not affect the functions of the systems discussed in the assessment and, therefore, the change is acceptable.

3.4.3 LCO 3.5.1: Emergency Core Cooling Systems (ECCS) - Operating The ECCS provides cooling water to the core in the event of a loss-of-coolant accident (LOCA).

This set of ECCS TS provides the operability requirements for the various ECCS subsystems as described below. This TS change would delete the secondary actions. The plant can remain in Mode 3 until the required repair actions are completed. The reactor is not depressurized.

LCO: Each ECCS injection/spray subsystem and the Automatic Depressurization System (ADS) function of eight safety/relief valves shall be OPERABLE.

Condition Requiring Entry into End State: If the LCO cannot be met, the following actions must be taken for the listed conditions:

a.

If one low-pressure ECCS injection/spray subsystem is inoperable, the subsystem must be restored to OPERABLE status in 7 days (Condition A).

b.

If the high-pressure core spray (HPCS) system is inoperable, restore to OPERABLE status within 14 days (Condition B).

c.

Two ECCS injection subsystems inoperable or one ECCS injection and one ECCS spray subsystem inoperable. One ECCS injection/spray subsystem must be restored to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months (Condition C).

d.

If the Required Action and associated Completion Time of Condition A, B, or C is not met, then place the plant in Mode 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in Mode 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months (Condition D).

e.

If one ADS valve is inoperable, it must be restored to operable status within 14 days (Condition E).

f.

If one ADS valve is inoperable and one low pressure ECCS injection/spray subsystem inoperable, the ADS valve must be restored to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or the low-pressure ECCS injection/spray subsystem must be restored to operable status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months (Condition F).

g.

If the Required Action and associated Completion Time of Condition E or F is not met or two or more required ADS valves become inoperable, the plant must be placed in Mode 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and the reactor steam dome pressure reduced to less than or equal to 150 psig within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months (Condition G).

h.

If 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 are inoperable, LCO 3.0.3 must be entered immediately (Condition H).

Modification for End State Required Actions:

a.

No change in Required Actions for Conditions A through C.

b.

If the Required Action, and associated Completion Time of Condition A, B, or C is not met, then place the plant in Mode 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months (Condition D.1 ). Required Action D.2 is deleted, allowing the plant to stay in Mode 3 while completing repairs.

c.

No change in Required Actions for Conditions E and F.

d.

A revised Condition G specifies that if the Required Action and associated Completion Time of Condition E or F is not met or two or more required ADS valves become inoperable, then place the plant in Mode 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months (G.1 ). Required Action G.2 is deleted allowing the plant to stay in Mode 3 while completing repairs.

Assessment: The BWROG performed a comparative PRA evaluation in TR NEDC-32988-A of the core damage risks of operation in the current end state and the MODE 3 end state. The NRC staff's conclusion described in the September 27, 2002, SE for the TR (Reference 15) on BWROG's PRA evaluation, indicates that the core damage risks are lower in Mode 3 than in the current end state Mode 4. For CGS, going to Mode 4 for one ECCS subsystem or one ADS valve would cause loss of the high-pressure steam driven RCIC system, and loss of the power conversion system (condenser/feedwater), and would require activating the RHR system. In addition, plant EOPs direct the operator to take control of the depressurization function if low-pressure injection/spray systems are needed for RPV water makeup and cooling.

Based on the low probability of loss of the reactor coolant inventory and the number of systems available in Mode 3, the NRC staff concludes that the risks of staying in Mode 3 are approximately the same as and in some cases lower than the risks of going to the Mode 4 end state; therefore, the change is acceptable.

In its letter dated April 3, 2015, the licensee stated, in part, that The Columbia design is based on the BWR-6 design as described in NUREG-1434 Columbia has a low pressure coolant injection (LPCI) system; a low pressure core spray (LPCS) system and a high pressure core spray (HPCS) system.

The Columbia automatic depressurization system (ADS) consists of 7 of the 18 SRVs. The number of SRVs which serve the ADS function is different but the function is the same as the BWR-6 design.

While the number of SRVs (7) which perform the ADS function at Columbia is less than what is discussed in the SE, the Assessment remains applicable to the Columbia design with the following clarification: Going to Mode 4 would cause loss of the high pressure steam-driven injection system (RCIC). Columbia's HPCS system is motor driven. Columbia does not have a steam driven HPCI system. This aspect of the BWR-5 configuration is addressed on page 25 of the SE. The variability among BWR plants regarding the number of ADS valves is also addressed on page 25 of the SE.

Based on its review, the NRC staff concludes that licensee's plant-specific information regarding its ECCS does not adversely affect the functions of the systems discussed in the assessment, therefore, the change is acceptable.

3.4.4 LCO 3.6.1.5: Residual Heat Removal (RHR) Drvwell Spray The primary containment must be able to withstand a postulated bypass leakage pathway that allows the passage of steam from the drywell directly into the primary containment airspace, bypassing the suppression pool. The primary containment also must be able to withstand a low-energy steam release into the primary containment airspace. The RHR drywell spray system is designed to mitigate the effects of bypass leakage and low-energy line breaks.

LCO: Two RHR drywell spray subsystems shall be OPERABLE.

Condition Requiring Entry into End State: If one RHR drywell spray subsystem is inoperable, it must be restored to operable status within 7 days (Required Action A.1 ). If two RHR drywell spray subsystems are inoperable, one of them must be restored to operable status within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months (Required Action B.1 ). If the RHR drywell spray system cannot be restored to operable status within the allotted time, the plant must be placed in Mode 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months (Required Action C.1) and in Mode 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months (Required Action C.2).

Modification for End State Required Actions:

Delete Required Action C.2.

Assessment: The primary containment is designed with a suppression pool so that, in the event of a LOCA, steam released from the primary system is channeled through the suppression pool water and condensed without producing significant pressurization of the primary containment. The primary containment is designed so that with the pool initially at the minimum water level and the worst single failure of the primary containment heat removal systems, suppression pool energy absorption combined with subsequent operator controlled pool cooling will prevent the primary containment pressure from exceeding its design value.

However, the primary containment must also withstand a postulated bypass leakage pathway that allows the passage of steam from the drywell directly into the primary containment airspace, bypassing the suppression pool. The primary containment also must withstand a postulated low-energy steam release into the primary containment airspace. The main function of the RHR drywell spray system is to suppress steam, which is postulated to be released into the primary containment airspace through a bypass leakage pathway and a low-energy line break under design-basis accident (OBA) conditions, without producing significant pressurization of the primary containment (i.e., ensure that the pressure inside primary containment remains within analyzed design limits).

Under the conditions assumed in the OBA, steam blown down from the break could find its way into the primary containment through a bypass leakage pathway. In addition to the OBA, a postulated low-energy pipe break could add more steam into the primary containment airspace. Under such an extremely unlikely scenario (very small frequency of a OBA combined with the likelihood of a bypass pathway and a concurrent low-energy pipe break inside the primary containment), the RHR drywell spray system could be needed to condense steam so that the pressure inside the primary containment remains within the analyzed design limits. Furthermore, containments have considerable margin to failure above the design limit (it is very likely that the containment will be able to withstand pressures as much as three times the design limit). For these reasons, the unavailability of one or both RHR drywell spray subsystems has no significant impact on COF or LERF, even for accidents initiated during operation at power. Therefore, it is very unlikely that the RHR drywell spray system will be challenged to mitigate an accident occurring during power operation. This probability becomes extremely unlikely for accidents that would occur during a small fraction of the year (less than 3 days) during which the plant would be in Mode 3 (associated with lower initial energy level and reduced decay heat load as compared to power operation) to repair the failed RHR drywell spray system.

Section 5.1 in the NRC staff's September 27, 2002, SE for the TR summarizes the NRC staff's risk basis for approval of LCO 3.6.1. 7, "Residual Heat Removal (RHR) Containment Spray System." The argument for staying in Mode 3 instead of going to Mode 4 to repair the RHR containment spray system (one or both trains) is also supported by defense-in-depth considerations. Section 5.2 in the September 27, 2002, SE for the TR, makes a comparison between the current (Mode 4) and the proposed (Mode 3) end state, with respect to the means available to perform critical functions (i.e., functions contributing to the defense-in-depth philosophy} whose success is needed to prevent core damage and containment failure and mitigate radiation releases. The risk and defense-in-depth arguments, used according to the "integrated decision-making" process of RGs 1.174 and 1.177, support the conc.lusion that Mode 3 is as safe as Mode 4 (if not safer) for repairing an inoperable RHR containment spray system. Since the time spent in Mode 3 to perform the repair is infrequent and limited, and in light of defense-in-depth considerations, the proposed change is acceptable.

In its letter dated April 3, 2015, the licensee stated, in part, that Although the Columbia design is based on the BWR-6 design described in NUREG-1434, the Columbia nomenclature uses "Orywell Spray" instead of "Containment Spray". The RHR Orywell Spray system at Columbia is also used to scrub inorganic iodines and particulates from the primary containment atmosphere in addition to suppressing steam released through a bypass leakage pathway. The SE Assessment is applicable to the Columbia design. The Assessment for this LCO also references Sections 5.1 and 5.2 of the SE for the TR. These sections remain applicable to Columbia as well.

Based on its review of the licensee's above clarification regarding nomenclature of its plant-specific system, the NRC staff concludes that the change is acceptable since it does not affect the function of the subject system or the staff's assessment for the change discussed above.

3.4.5 LCO 3.6.1.6 - Reactor Building-to-Suppression Chamber Vacuum Breakers The reactor building-to-suppression chamber vacuum breakers relieve vacuum when the primary containment depressurizes below the pressure of the reactor building, thereby serving to preserve the integrity of the primary containment.

LCO: Each reactor building-to-suppression chamber vacuum breaker shall be OPERABLE.

Condition requiring entry into end state: If one line has one or more reactor building-to suppression chamber vacuum breakers inoperable for opening, the breaker(s) must be returned to operability within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months (Required Action C.1 ). If the vacuum breaker(s) cannot be returned to operability within the allotted time, the plant must be placed in Mode 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months (Required Action E.1) and in Mode 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months (Required Action E.2).

Proposed modification for end state required actions: Add new Condition O to relate only to Condition C. Renumber old Condition 0 to E with no change to Required Actions and Completion Times. Renumber and modify Condition E to Condition F with Required Actions F.1 and F.2 with no change to Completion Times to address the Required actions related to Conditions A, B, and E.

Assessment: The BWROG has determined that the specific failure condition of interest is not risk significant in BWR PRAs. The reduced end state would only be applicable to the situation where the vacuum breaker(s) in one line are inoperable for opening, with the remaining operable vacuum breakers capable of providing the necessary vacuum relief function. By remaining in Mode 3, HPCS, RCIC, and the power conversion system (condensate/feedwater) remain available for water makeup and decay heat removal (OHR). Additionally, the EOPs direct the operators to take control of the depressurization function if low pressure injection/spray are needed for RCS makeup and cooling. Therefore, defense-in-depth is maintained with respect to water makeup and OHR by remaining in Mode 3. The existing end state remains unchanged for conditions involving more than one line or vacuum breakers that are stuck in the open position, as established by Condition F.

Since the time spent in Mode 3 to perform the repair is infrequent and limited, and in light of defense-in-depth considerations, the proposed change is acceptable.

In its letter dated April 3, 2015, the licensee stated, in part, that The Columbia design for suppression chamber vacuum breakers consists of two vacuum breakers (a mechanical vacuum breaker and an air operated butterfly valve), located in series in each of three 24 inch lines from the reactor building to the suppression chamber airspace. The butterfly valve is actuated by a differential pressure switch. The mechanical vacuum breaker is self-actuating similar to a check valve. Both can be remotely operated for testing purposes.

The two vacuum breakers in series must be closed to maintain a leak tight primary containment boundary.

The Columbia design is similar to the BWR-4 design as described in NUREG-1433. The BWR-4 design has two vacuum breakers in series in each of two lines from the reactor building from the suppression chamber.

While the of number lines with vacuum breakers at Columbia is more than what is discussed in the SE, the Assessment remains applicable to the Columbia design with the following clarification: Going to Mode 4 would cause loss of the high-pressure steam-driven injection system (RCIC). Columbia's HPCS system is motor driven. Columbia does not have a steam driven HPCI system. This aspect of the BWR-5 configuration is addressed on page 25 of the SE.

The NRC staff has reviewed the licensee's plant-specific system design differences and*

concludes that these differences have no impact on the staff's assessment for the change discussed above. Regarding CGS's motor-driven HPCS versus a steam-driven HPCS, as stated above in SE Section 3.4.1, both are fully capable of mitigating any potential accidents in Mode 3 and can function during a station blackout. Therefore, both HPCS designs have equivalent functions.

3.4.6 LCO 3.6.1.7 - Suppression Chamber-to-Drvwell Vacuum Breakers The function of the suppression chamber-to-drywell vacuum breakers is to relieve vacuum in the drywell, thereby preventing an excessive negative differential pressure across the drywell boundary.

LCO: 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.

Condition requiring entry into end state: If one suppression chamber-to-drywell vacuum breaker is inoperable for opening, the breaker must be returned to operability within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months (Required Action A.1 ). If the vacuum breaker cannot be returned to operability within the allotted time, the plant must be placed in Mode 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months (Required Action D.1) and in Mode 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months (Required Action D.2).

Proposed modification for end state required actions: Add new Condition B to relate only to Condition A. Renumber old Condition B and C to C and D with no change to Required Actions and Completion Times. Renumber and revise old Condition D to E to apply to Conditions C and D with Required Actions to be in Mode 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months (Required Action E.1) and in Mode 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months (Required Action E.2).

Assessment: The BWROG has determined that the specific failure of interest is not risk significant in BWR PRAs. The reduced end state would only be applicable to the situation where one suppression chamber-to-drywall vacuum breaker is inoperable for opening, with the remaining operable vacuum breakers capable of providing the necessary vacuum relief function.

By remaining in Mode 3, HPCS, RCIC, and the power conversion systems are available.

Additionally, the EOPs direct the operators to take control of the depressurization function if low pressure injection/spray are needed for RCS makeup and cooling. Therefore, defense-in-depth is maintained with respect to water makeup and OHR by remaining in Mode 3. The existing end state remains unchanged for conditions involving any suppression chamber-to-drywall vacuum breakers that are stuck open, as established by new Condition B.

Since the time spent in Mode 3 to perform the repair is infrequent and limited, and in light of defense-in-depth considerations, the proposed change is acceptable.

In its letter dated April 3, 2015, the licensee stated, in part, that The Columbia design for suppression chamber to drywall vacuum breakers consists of 9 internal vacuum breakers located on the vent header of the vent system between the drywall and the suppression chamber, which allow air and steam flow from the suppression chamber to the drywall when the drywall is at a negative pressure with respect to the suppression chamber.

The Columbia design is similar to the BWR-4 design as described in NUREG-1433. The BWR-4 design has 12 internal vacuum breakers located on the vent header of the vent system between the drywall and the suppression chamber.

While the number of internal vacuum breakers at Columbia is less than what is discussed in the SE, the Assessment remains applicable to the Columbia design because Columbia has equivalent systems with the following clarification: Going to Mode 4 would cause loss of the high-pressure steam-driven injection system (RCIC). Columbia's HPCS system is motor driven. Columbia does not have a steam driven HPCI system. This aspect of the BWR-5 configuration is addressed on page 25 of the SE.

The NRC staff has reviewed the design differences between the CGS and the systems described in the TSTF-423 SE regarding the Suppression Chamber-to-Drywall Vacuum Breakers system, and determined that it has no impact on the staff's assessment since the functions of systems discussed in the assessment are similar to those of CGS.

3.4.7 LCO 3.6.2.3: Residual Heat Removal (RHR) Suppression Pool Cooling Following a OBA, the RHR Suppression Pool Cooling System removes heat from the suppression pool. The suppression pool is designed to absorb the sudden input of heat from the primary system. In the long term, the pool continues to absorb residual heat generated by fuel in the reactor core. Some means must be provided to remove heat from the suppression pool so that the temperature inside the primary containment remains within design limits. At CGS, this function is provided by two redundant RHR suppression pool cooling subsystems.

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

Condition Requiring Entry into End State: If one RHR suppression pool cooling subsystem is inoperable (Condition A), it must be restored to operable status within 7 days (Required Action A.1 ). If two RHR suppression pool cooling subsystems are inoperable (Condition B), ),

the plant must be placed in Mode 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months (Required Action B.1) and in Mode 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months (Required Action B.2).

Modification for End State Required Actions: Current Required Action B.2 is deleted allowing the plant to stay in Mode 3 while completing repairs on one RHR suppression pool cooling subsystem being inoperable. As a result, Condition B relates to Condition A only. Current Condition B for two RHR suppression pool cooling subsystems inoperable has been relocated to a new Condition C with Required Actions C.1 and C.2, identical to the existing Required Actions B.1 and B.2, to maintain existing requirements unchanged.

Assessment: The BWROG completed a comparative PRA evaluation of the core damage risks of operation in the current end state versus operation in the Mode 3 end state. The results described in TR NEOC-32988-A and as evaluated by the NRC staff in the associated September 27, 2002, SE, indicated that the core damage risks while operating in Mode 3 (assuming the individual failure conditions) are lower or comparable to the current end state.

One loop of the RHR suppression pool cooling system is sufficient to accomplish the required safety function. By remaining in Mode 3, HPCS, RCIC, and the power conversion system (condensate/feedwater) remain available for water makeup and OHR. Additionally, the plant EOPs direct the operators to take control of the depressurization function if low-pressure injection/spray are needed for RCS makeup and cooling. Since defense-in-depth is improved with respect to water makeup and OHR by remaining in Mode 3, the change is acceptable.

3.4.8 LCO 3.6.4.1: Secondary Containment Following a OBA, the function of the secondary containment is to contain, dilute, and stop radioactivity (mostly fission products) that may leak from primary containment. Its leak tightness is required to ensure that the release of radioactivity from the primary containment is restricted to those leakage paths and associated leakage rates assumed in the accident analysis and that fission products entrapped within the secondary containment structure will be treated by the standby gas treatment system prior to discharge to the environment.

LCO: The secondary containment shall be OPERABLE.

Condition Requiring Entry into End State: If the secondary containment is inoperable, it must be restored to operable status within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months (Required Action A.1 ). If it cannot be restored to operable status within the allotted time, the plant must be placed in Mode 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months (Required Action B.1) and in Mode 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months (Required Action B.2).

Modification for End State Required Actions: Required Action B.2 is deleted allowing the plant to stay in Mode 3 while completing repairs.

Assessment: This LCO entry condition does not include gross leakage through an un-isolable release path. The BWROG concluded in NEOC-32988-A, Revision 2 that previous generic PRA work related to Appendix J requirements has shown that containment leakage is not risk significant. The primary containment and all other primary and secondary containment-related functions would still be operable, including the standby gas treatment system, thereby minimizing the likelihood of an unacceptable release. By remaining in Mode 3, HPCS, RCIC, and the power conversion system ( condensate/feedwater) remain available for water makeup and OHR. Additionally, the plant EOPs direct the operators to take control of the depressurization function if low-pressure injection/spray is needed for RCS makeup and cooling.

Therefore, the NRC staff concludes that the change is acceptable because defense-in-depth is improved with respect to water makeup and OHR by remaining in Mode 3.

As stated in the September 27, 2002, SE for the TR, the NRC staff's approval relies upon the primary containment, and all other primary and secondary containment-related functions to still be operable, including the standby gas treatment system, for maintaining defense-in-depth while in this reduced end state.

3.4.9 LCO 3.6.4.3: Standby Gas Treatment (SGT) System The function of the SGT system is to ensure that radioactive materials that leak from the primary containment into the secondary containment following a OBA are filtered and adsorbed prior to exhausting to the environment.

LCO: Two SGT subsystems shall be OPERABLE.

Condition Requiring Entry into End State: If one SGT subsystem is inoperable, it must be restored to operable status within 7 days (Required Action A.1 ). If the SGT subsystem cannot be restored to operable status within the allotted time, the plant must be placed in Mode 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months (Required Action B.1) and in Mode 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months (Required Action B.2). In addition, if two SGT subsystems are inoperable in Modes 1, 2, or 3, LCO 3.0.3 must be entered immediately (Required Action 0.1 ).

Modification for End State Required Actions: Required Action B.2 is deleted, allowing the plant to stay in Mode 3 while completing repairs. Required Action 0.1 is changed to "Be in Mode 3" with a Completion Time of "12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ."

Assessment: The unavailability of one or both SGT subsystems has no impact on COF or LERF, irrespective of the mode of operation at the time of the accident. Furthermore, the challenge frequency of the SGT system (i.e., the frequency with which the system is expected to be challenged to mitigate offsite radiation releases resulting from materials that leak from the primary to the secondary containment above TS limits) is less than 1.0E-6/yr (year].

Consequently, the conditional probability that this system will be challenged during the repair time interval while the plant is at either the current or the proposed end state (i.e., Mode 4 or Mode 3, respectively) is less than 1.0E-8. This probability is considerably smaller than probabilities considered "negligible" in RG 1.177 for much higher consequence risks, such as large early release.

Section 5.1 of the NRC staff's September 27, 2002, SE for TR NEOC-32988-A evaluates the NRC staff's risk basis for approval of LCO 3.6.4.3, "Standby Gas Treatment (SGT) System."

According to this evaluation, which applies to BWR-6 design (CGS is a BWR-5 facility, however, CGS's SGT system design is similar to BWR-6), staying in Mode 3 instead of going to Mode 4 to repair the SGT system (one or both trains) is also supported by defense-in-depth considerations.

Section 5.2 of the staff's September 27, 2002, SE for the TR (Reference 15) details a comparison between the Mode 3 and the Mode 4 end state, with respect to the means available to perform critical functions (i.e., functions contributing to the defense-in-depth philosophy) whose success is needed to prevent core damage and containment failure, and to mitigate radiation releases. The risk and defense-in-depth arguments, used according to the "integrated decision-making" process of RGs 1.17 4 and 1.177, support the conclusion that Mode 3 is as safe as Mode 4 for repairing an inoperable SGT system. Therefore, the NRC staff concludes that the change is acceptable.

3.4.10 LCO 3.7.1: Standby Service Water (SW) System and Ultimate Heat Sink (UHS)

The SW system (in conjunction with the UHS) is designed to provide cooling water for the removal of heat from certain safe shutdown-related equipment heat exchangers following a OBA or transient.

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

Condition Requiring Entry into End State: As stated below, Energy Northwest did not propose modifications to the End State requirements for an inoperable UHS.

If one SW subsystem is inoperable, the SW subsystem must be restored to operable status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months (Required Action B.1 ). Condition C requires that if the required action(s) and associated completion time(s) of Condition A or Bare not met OR Both SW subsystems are inoperable, the plant must be placed in Mode 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months (Required Action C.1) and in Mode 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months (Required Action C.2).

Modification for End State Required Actions: A new Condition C is added for "Required Action and associated Completion Time of Condition B not met," be in MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

The current Condition C is renumbered to Condition D requiring the plant to be placed in MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months (Required Action 0.1) and MODE 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months (Required Action 0.2) if "Required Action and associated Completion Time of Condition A (Average sediment depth in one or both spray ponds~ 0.5 ft and< 1.0 ft.) not met, OR Both SW subsystems inoperable, OR UHS inoperable for reasons other than Condition A."

Assessment: The BWROG performed a comparative PRA evaluation (Reference 6) of the core damage risks when operating in the current end state versus the proposed Mode 3 end state.

The results indicated that the core damage risks while operating in Mode 3 (assuming the individual failure conditions) are lower or comparable to the current end state. By remaining in Mode 3, HPCS, RCIC, and the power conversion system (condensate/feedwater) remain available for water makeup and OHR. Additionally, the EOPs direct the operators to take control of the depressurization function if low-pressure injection/spray is needed for RCS makeup and cooling. Therefore, the NRC staff concludes that the change is acceptable because defense-in-depth is improved with respect to water makeup and OHR by remaining in Mode 3, and the required safety function can still be performed with the RHR SW subsystem components that are still operable.

In its letter dated April 3, 2015, the licensee stated, in part, that The Columbia design for UHS consists of two concrete spray ponds with redundant pumping and sprays facilities. A siphon between the ponds allows for water flow from one pond to the other. The combined volume of the two ponds is sized such that sufficient water inventory is available for all SW System post-accident cooling requirements for a 30 day period with no external makeup water source available.

The BWR-6 UHS design described in NUREG-1434 uses two concrete makeup water basins, each containing one cooling tower with two fan cells per basin.

The combined basin volume is sized such that sufficient water inventory is available for all SW System post-accident cooling requirements for a 30 day period with no external makeup water source available.

Columbia's SW System consists of two independent cooling water headers (subsystems A and B), and their associated pumps, piping, valves, and instrumentation which provides cooling water to the diesel generators, the RHR heat exchangers, RCIC, LPCI, LPCS auxiliary equipment (room cooler, pump cooler), and the essential chillers.

The BWR-6 SW System design described in NUREG-1434 uses subsystems A and B to supply cooling water to redundant equipment required for a safe reactor shutdown.

Energy Northwest did not propose modifications to the End State requirements for an inoperable UHS.

The design of the Columbia SW System is similar to the BWR-6 design and the function it satisfies is the same. The SE Assessment remains applicable to the Columbia design.

The NRC staff has reviewed the design differences between the CGS and the systems described in the TSTF-423 SE regarding the SSW System and UHS, and determined that the differentiation does not invalidate the applicability of the TSTF-423 changes and the staffs assessment for the proposed change remains unaffected.

3.4.11 LCO 3.7.3: Control Room Emergency Filtration (CREF) System The CREF system provides a radiologically controlled environment from which the unit can be safely operated following a OBA. The CREF system consists of two independent and redundant high-efficiency air filtration subsystems for treatment of recirculated air or outside supply air.

Each subsystem consists of a demister, an electric heater, a prefilter, a high-efficiency particulate air (HEPA) filter, an activated charcoal adsorber section, a second HEPA filter, a fan, and the associated ductwork and dampers. Demisters remove water droplets from the airstream. Prefilters and HEPA filters remove particulate matter that may be radioactive. The charcoal adsorbers provide a holdup period for gaseous iodine, allowing time for decay.

LCO: Two CREF subsystems shall be OPERABLE.

Condition Requiring Entry into End State: If one CREF subsystem is inoperable for reasons other than inoperable boundary, it must be restored to operable status within 7 days (Required Action A.1 ). If one or more CREF subsystems are inoperable due to inoperable control room envelope (CRE) boundary in MODE 1, 2, or 3, initiate action to implement mitigating actions immediately (Required Action B.1 ), verify mitigating actions within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months (Required Action B.2), and Restore CRE boundary to OPERABLE status within 90 days (Required Action B.3). If the CREF subsystems cannot be restored to operable status within the allotted time, the plant must be placed in Mode 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months (Required Action C.1) and in Mode 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months (Required Action C.2). If two CREF subsystems are inoperable in Mode 1, 2, or 3, for reasons other than Condition B, LCO 3.0.3 must be entered immediately (Required Action E.1 ).

Modification for End State Required Actions: Delete Required Action C.2, and changed Required Action E.1 to "Be in Mode 3," with a Completion Time of "12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ."

Assessment: The unavailability of one or both CRFA subsystems (as stated in the licensee's letter dated April 3, 2015 and the staff's determination below, that the CRFA system is similar to CGS's CREF system), has no significant impact on CDF or LERF, independent of the mode of operation at the time of the accident. Furthermore, the challenge frequency of the CRFA system (i.e., the frequency with which the system is expected to be challenged to provide a radiologically controlled environment in the main control room following a OBA which leads to core damage and leaks of radiation from the containment that can reach the control room) is less than 1.0E-6/yr. Consequently, the conditional probability that this system will be challenged

during the repair time interval while the plant is at either the current or the proposed end state (i.e., Mode 4 or Mode 3, respectively) is less than 1.0E-8. This probability is considerably smaller than the probabilities considered "negligible" in RG 1.177 for much higher consequence risks, such as a large early release.

Section 5.1 of the NRC staff's September 27, 2002, SE for TR NEDC-32988-A summarizes the NRC staff's risk argument for approval of LCO 3.7.3, "Control Room Fresh Air (CRFA) System."

The argument for staying in Mode 3 instead of going to Mode 4 to repair the CRFA system (one or both trains) is also supported by defense-in-depth considerations. Section 5.2 makes a comparison between the current (Mode 4) and the proposed (Mode 3) end state, with respect to the means available to perform critical functions (i.e., functions contributing to the defense-in-depth philosophy) whose success is needed to prevent core damage and containment failure and mitigate radiation releases. The risk and defense-in-depth arguments, used according to the "integrated decision-making" process of RGs 1.17 4 and 1.177, support the conclusion that Mode 3 is as safe as Mode 4 (if not safer) for repairing an inoperable CRFA system.

In its letter dated April 3, 2015, the licensee stated, in part, that The Columbia design is similar to the BWR-6 design as described in NUREG-1434. The Columbia nomenclature uses "Control Room Emergency Filtration (CREF) System" instead of "Control Room Fresh Air (CRFA) System" used in the BWR-6 TS.

The Columbia design consists of two independent subsystems. Each subsystem consists of an electric heater, a prefilter, a high efficiency particulate air (HEPA) filter, an activated charcoal adsorber section, a filter unit fan, a control room recirculation fan, and the associated ductwork, valves or dampers, doors, barriers, and instrumentation. The electric heater is used to limit the relative humidity of the air entering the filter train. Prefilters and HEPA filters remove particulate matter which may be radioactive. The charcoal adsorbers provide a holdup period for gaseous iodine, allowing time for decay.

The BWR-6 design as described in NUREG-1434 consists of two independent subsystems. Each CRFA subsystem consists of a demister, an electric heater, a prefilter, a high efficiency particulate air (HEPA) filter, an activated charcoal adsorber section, a second HEPA filter, a fan, and the associated ductwork, valves or dampers, doors, barriers, and instrumentation. Demisters remove water droplets from the airstream. Prefilters and HEPA filters remove particulate matter, which may be radioactive. The charcoal adsorbers provide a holdup period for gaseous iodine, allowing time for decay.

While the Columbia design is slightly different than the BWR-6 design, the function it satisfies is the same and the SE Assessment remains applicable to the Columbia design. The Assessment for this LCO also references Sections 5.1 and 5.2 of the SE for the TR. These sections are applicable to Columbia as well.

The NRC staff's review of the design and functions of CGS's CREF system versus those assessed in the staff's SE for CRFA determined that slight differences have no impact on the staff's assessment since the functions of both systems are similar.

3.4.12 LCO 3. 7.4: Control Room Air Conditioning (AC) System The control room air conditioning system provides temperature control for the control room following control room isolation during accident conditions.

LCO: Two control room air conditioning subsystems shall be OPERABLE.

Condition Requiring Entry into End State: If one control room air conditioning subsystem is inoperable, it must be restored to operable status within 30 days (Required Action A.1 ). If two control room air conditioning subsystems are inoperable, verify control room area temperature

90°F once per 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months and restore one control room air conditioning subsystem to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months (Required Actions B.1 and B.2). If the required actions and associated completion times cannot be met (Condition C), the plant must be placed in Mode 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months (Required Action C.1) and in Mode 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months (Required Action C.2).

Modification for End State Required Actions: Required Action C.2 is deleted, allowing the plant to stay in Mode 3 while completing repairs.

Assessment: The unavailability of one or both air conditioning subsystems has no significant impact on CDF or LERF, independent of the mode of operation at the time of the accident.

Furthermore, the challenge frequency of the air conditioning system (i.e., the frequency with which the system is expected to be challenged to provide temperature control for the control room following control room isolation following a OBA that leads to core damage) is less than 1.0E-6/yr. Consequently, the conditional probability that this system will be challenged during the repair time interval while the plant is at either the current or the proposed end state (i.e.,

Mode 4 or Mode 3, respectively) is less than 1.0E-8. This probability is considerably smaller than probabilities considered "negligible" in RG 1.177 for much higher consequence risks, such as large early release.

Section 5.1 of the NRC staff's September 27, 2002, SE for TR NEDC-32988-A summarizes the staff's risk basis for approval of LCO 3.7.4, "Control Room Air Conditioning (CRAC) System."

Per the licensee's letter and the staff's determination below, the BWR CRAC system is similar to the CGS's CAC system. The basis for staying in Mode 3 instead of going to Mode 4 to repair the CRAC system (one or both trains) is supported by defense in-depth considerations.

Section 5.2 of the staff's SE (Reference 15) makes a comparison between the Mode 3 and the Mode 4 end states, with respect to the means available to perform critical functions (i.e.,

functions contributing to the defense-in-depth philosophy) whose success is needed to prevent core damage and containment failure, and to mitigate radiation releases. The risk and defense in depth arguments, used according to the "integrated decision-making" process of RGs 1.17 4 and 1.177, support the conclusion that Mode 3 is as safe as Mode 4 for repairing an inoperable control room air conditioning system. Therefore, the NRC staff concludes that the change is acceptable.

In its letter dated April 3, 2015, the licensee stated, in part, that The Columbia design is similar to the BWR-6 design as described in NUREG-1434.

The Columbia design consists of two independent, redundant subsystems that provide cooling of recirculated control room air. Each subsystem consists of an air filter, two cooling coils (one normal and one emergency), a control room recirculation fan, ductwork, dampers, and instrumentation and controls to provide for control room temperature control.

The BWR-6 design as described in NUREG-1434 consists of two independent, redundant subsystems that provide cooling and heating of recirculated control room air. Each subsystem consists of heating coils, cooling coils, fans, chillers, compressors, ductwork, dampers, and instrumentation and controls to provide for control room temperature control.

While the Columbia design is slightly different than the BWR-6 design, the function it satisfies is the same and the SE Assessment remains applicable to the Columbia design. The Assessment for this LCO also references Sections 5.1 and 5.2 of the SE for the TR. These sections are applicable to Columbia as well.

The staff's review of the design and functions of CGS's CRAC system versus that assessed in the staff's SE for CRAC determined that slight differences have no impact on the staff's assessment since the functions of both systems are similar.

3.4.13 LCO 3. 7.5: Main Condenser Off gas The offgas from the main condenser normally includes radioactive gases. The gross gamma activity rate is controlled to ensure that accident analysis assumptions are satisfied and that offsite dose limits will not be exceeded during postulated accidents. The main condenser off gas (MCOG) gross gamma activity rate is an initial condition of a OBA that assumes a gross failure of the MCOG system pressure boundary.

LCO: The gross gamma activity rate of the noble gases measured at the main condenser air ejector shall be::; 332 mCi [millicuries] /second after decay of 30 minutes.

Condition Requiring Entry into End State: If the gross radioactivity rate of the noble gases is not within limits (Condition A), the radioactivity rate of the noble gases must be restored to within limits within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months (Required Action A.1 ). If the Required Action and associated Completion Time cannot be met (Condition B), one of the following must occur:

All main steam lines must be isolated within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months (Required Action B.1 ),

or The steam jet air ejector (SJAE) must be isolated within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months (Required Action B.2),

or The plant must be placed in Mode 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months (Required Action B.3.1) and in Mode 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months (Required Action B.3.2).

Modification for End State Required Actions: Required Action B.3.2 is deleted, allowing the plant to stay in Mode 3 while completing repairs.

Assessment: The failure to maintain the gross gamma activity rate of the noble gases in the MCOG system within limits has no significant impact on COF or LERF, independent of the mode of operation at the time of the accident. Furthermore, the challenge frequency of the MCOG system (i.e., the frequency with which the system is expected to be challenged to mitigate offsite radiation releases following a OBA) is less than 1.0E-6/yr. Consequently, the conditional probability that this system will be challenged during the repair time interval while the plant is at either the current or the proposed end state (i.e., Mode 4 or Mode 3, respectively) is less than 1.0E-8. This probability is considerably smaller than probabilities considered "negligible" in RG 1.177 for much higher consequence risks, such as large early release.

Section 5.1 of the NRC staff's September 27, 2002, SE for TR NEOC-32988-A summarizes the staff's risk basis for approval of LCO 3.7.6 (equivalent to CGS TS LCO 3.7.5) "Main Condenser Offgas." Staying in Mode 3 instead of going to Mode 4 to repair the MCOG system (one or both trains) is supported by defense-in-depth considerations. Section 5.2 of the staff's SE (Reference 15) makes a comparison between the Mode 3 and the Mode 4 end states, with respect to the means available to perform critical functions (i.e., functions contributing to the defense-in-depth philosophy) whose success is needed to prevent core damage and containment failure, and to mitigate radiation releases. The risk and defense-in-depth considerations, used according to the "integrated decision-making" process of RGs 1.17 4 and 1.177, support the conclusion that Mode 3 is as safe as Mode 4 for repairing an inoperable MCOG system. Therefore, the NRC staff concludes that the change is acceptable.

In its letter dated April 3, 2015, the licensee stated, in part, that The SE Assessment is applicable to the Columbia design because Columbia has equivalent systems. The Assessment for this LCO also references Sections 5.1 and 5.2 of the SE for the TR. These sections are applicable to Columbia as well.

The NRC staff's review of the design and functions of CGS's MCOG system versus that assessed in the staff's SE determined that the staff's assessment is applicable because the TS requirements are identical.

3.4.14 LCO 3.8.1: AC Sources - Operating CGS Class 1 E AC Electrical Power Distribution System AC sources consist of the offsite power sources and the onsite standby power sources (diesel generators (DGs) 1, 2, and 3). The Class 1 E AC distribution system supplies electrical power to three divisional load groups, with each division powered by an independent Class 1 E 4.16 kilo Volt (kV) engineered safety feature (ESF) bus. Each ESF bus has two separate and independent offsite sources of power. Each ESF bus has a dedicated onsite DG. The ESF systems of any two of the three divisions provide power for the minimum safety functions necessary to shut down the unit and maintain it in a safe shutdown condition.

Offsite power is supplied to the switchyard from the transmission network. From the switchyard two electrically and physically separated circuits provide AC power to each 4.16 kV ESF bus.

The offsite AC electrical power sources are designed and located so as to minimize to the extent practical the likelihood of their simultaneous failure under operating and postulated accident and environmental conditions.

LCO: The following AC electrical power sources shall be OPERABLE:

a.

Two qualified circuits between the offsite transmission network and the onsite Class 1 E AC Electric Power Distribution System; and

b.

Three diesel generators (DGs).

Condition Requiring Entry into End State: The plant operators must bring the plant to Mode 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months (Required Action F.1) and Mode 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months (Required Action F.2) following the sustained inoperability of either or both required offsite circuits; one or two required EDGs; or one required offsite circuit and one or two required EDGs.

Modification for End State Required Actions: Required Action F.2 is deleted, allowing the plant to stay in Mode 3 while completing repairs. The plant will remain in Mode 3 (hot shutdown)

(Required Action F.1 ).

Assessment: Entry into any of the conditions for the AC power sources implies that the AC power sources have been degraded and the single-failure protection for the safe shutdown equipment may be ineffective. Consequently, as specified in TS 3.8.1 at present, the plant operators must bring the plant to Mode 4 when the required action is not completed by the specified time for the associated action.

In NEDC-32988-A, Revision 2 (Reference 6), the BWROG performed a comparative PRA evaluation of the core damage risks of operation in the current end state and in the Mode 3 end state. Events initiated by the loss-of-offsite power are dominant contributors to CDF in most BWR PRAs, and the high-pressure core cooling systems (RCIC and HPCS) play a major role in mitigating these events. The conclusion described in the NRC staff's September 27, 2002, SE for TR NEDC-32988-A on BWROG's PRA evaluation, indicates that the core damage risks are lower in Mode 3 than in Mode 4 for inoperable AC power sources. Going to Mode 4 for one inoperable AC power source would cause loss of high-pressure RCIC system and loss of the power conversion system (condenser/feedwater), and would require activating the RHR system.

In addition, plant EOPs direct the operator to take control of the depressurization function if low-pressure injection/spray systems are needed for RPV water makeup and cooling.

Based on the low probability of loss of the AC power and the number of systems available in Mode 3, the NRC staff concludes that the risks of staying in Mode 3 are lower than going to the Mode 4 end state; therefore, the NRC staff concludes that the change is acceptable.

In its letter dated April 3, 2015, the licensee stated, in part, that The Columbia design consists of offsite power sources and the onsite standby power sources. As required by 10 CFR 50, Appendix A, GDC 17, the design of the AC electrical power system provides independence and redundancy to ensure an available source of power to the Engineered Safety Feature (ESF) systems. From the switchyard two qualified, electrically and physically separated circuits provide AC power to the Divisions 1 and 2 4.16 kV ESF buses, while only one qualified circuit provides AC power to the Division 3 4.16 kV ESF bus. One qualified circuit to Divisions 1, 2 and 3 4.16 kV ESF buses is from the 230 kV Ashe substation. The other qualified circuit to Divisions 1 and 2 4.16 kV ESF buses is from the 115 kV Benton substation. Each 4.16 kV ESF bus has connections to a respective diesel generator. The Columbia design uses relay timing to load the emergency diesel generators rather than an automatic sequencer.

While the Columbia design is slightly different than that described for BWR-4 as described in NUREG-1433 and BWR-6 as described in NUREG-1434, the function it satisfies is the same and the SE Assessment is applicable to the Columbia design with the following clarifications: The steam driven cooling system is RCIC. The main feedwater pumps at Columbia are also steam-driven.

This aspect of the BWR-5 configuration is addressed on page 25 of the SE. The variability among BWR plants regarding supports systems is addressed on pages 25 and 26 of the SE.

The NRC staff's review of the design and functions of CGS's AC sources system versus that assessed in the staffs SE for the same system, determined that slight differences have no impact on the staff's assessment since the functions of the safety systems specified in the assessment, are identical.

3.4.15 LCO 3.8.4: DC Sources - Operating The station DC electrical power system provides the AC emergency power system with control power. It also provides both motive and control power to selected safety-related equipment.

The DC electrical power system is designed to have sufficient independence, redundancy, and testability to perform its safety functions, assuming a single failure. The 125 Volts direct current (VDC) electrical power system consists of three independent Class 1 E DC electrical power subsystems, Divisions 1, 2, and 3. Each subsystem consists of a battery, associated battery charger(s), and all the associated control equipment and interconnecting cabling.

LCO: For Modes 1, 2, and 3, the Division 1, Division 2, and Division 3 DC electrical power subsystems shall be OPERABLE.

Condition Requiring Entry into End State: The plant operators must bring the plant to Mode 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months (Required Action J.1) and Mode 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months (Required Action J.2), if Required Actions and Associated Completion Time not met following the sustained inoperability of one DC electrical power subsystem for a period of 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Modification for End State Required Actions: The proposed TS change is to remove the requirement to place the plant in Mode 4. The required action in J.2 is deleted.

Assessment: If one of the DC electrical power subsystems is inoperable, the remaining DC electrical power subsystems have the capacity to support a safe shutdown and to mitigate an accident condition. In NEDC-32988-A, Revision 2 (Reference 6), the BWROG performed a comparative PRA evaluation of the core damage risks of operation in the current end state and in the Mode 3 end state, with one DC system inoperable. Events initiated by the loss-of-offsite power are dominant contributors to CDF in most BWR PRAs, and the high-pressure core cooling systems, RCIC and HPCS, play a major role in mitigating these events. The NRC staff's conclusion, as described in the NRC's September 27, 2012, SE for TR NEDC-32988-A on BWROG's PRA evaluation, indicates that the core damage risks are lower in Mode 3 than in Mode 4. Going to Mode 4 for one inoperable DC power source would cause loss of the RCIC system, and loss of the power conversion system (condenser/feedwater), and would require activating the RHR system. In addition, plant EOPs direct the operator to take control of the depressurization function if low-pressure injection/spray systems are needed for RPV water makeup and cooling.

Based on the low probability of loss of the DC power and the number of systems available in Mode 3, the NRC staff concludes in the SE for the BWR topical report that the risk of staying in Mode 3 are approximately the same or in some cases lower than the risk of going to the Mode 4 end state; therefore, the NRC staff concludes that the change is acceptable.

In its letter dated April 3, 2015, the licensee stated, in part, that The Columbia design for DC sources has 3 divisions. Two of the divisions consist of a 125 V DC battery and charger. One division consists of one 250 V DC battery and charger subsystem and one 125 V DC battery and charger subsystem. This is consistent with the number of subsystems for the BWR-6 design as described in NUREG-1434.

While the Columbia design is slightly different than that described for BWR-4 as described in NUREG-1433 and BWR-6 as described in NUREG-1434, the SE Assessment is applicable to the Columbia design with the following clarifications:

The steam driven cooling system is RCl,C. The main feedwater pumps at Columbia are also steam-driven. This aspect of the BWR-5 configuration is addressed on page 25 of the SE. The variability among BWR plants regarding supports systems is addressed on pages 25 and 26 of the SE.

The NRC staffs review of the design and functions of CGS's DC sources system versus that assessed in the staff's SE for the same system, determined that slight differences between those systems have no impact on the staff's assessment since the functions of the safety systems are identical.

3.4.16 LCO 3.8. 7: Distribution Systems - Operating Per CGS TS, the onsite Class 1 E AC and DC electrical power distribution systems are divided by division into three independent AC and DC electrical power distribution subsystems.

The primary AC distribution system consists of each 4.16 kV ESF bus that has at least one separate and independent offsite source of power, as well as a dedicated onsite DG source.

The secondary plant AC distribution system includes 480 Volt (V) ESF load centers and associated loads, motor control centers, and transformers. In addition, CGS has three independent 125 voe electrical power distribution subsystems.

CGS's supplement letter dated April 3, 2015 provides additional information on CGS's Distribution Systems.

LCO: For Modes 1, 2, and 3, Division 1, Division 2, and Division 3 AC and DC, electrical power distribution subsystems shall be OPERABLE.

Condition Requiring Entry into End State: The plant operators must bring the plant to Mode 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and Mode 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months (Condition C, Required Actions C.1 and C.2) following the sustained inoperability of Division 1 or 2 AC electrical power distribution subsystem (Condition A) or Division 1 or 2 DC electrical power distribution subsystems for a period of 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months (each for Condition A) and 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months (Condition B), and 16 hours1.851852e-4 days 0.00444 hours 2.645503e-5 weeks 6.088e-6 months (for Condition A or B),

respectively, from initial discovery of failure to meet the LCO.

Modification for End State Required Actions: Required Action C.2 is deleted allowing the plant to stay in Mode 3 while completing repairs.

Assessment: If one of the AC/DC subsystems is inoperable, the remaining AC/DC subsystems have the capacity to support a safe shutdown and to mitigate an accident condition. In NEDC-32988-A, Revision 2 (Reference 6), the BWROG did a comparative PRA evaluation of the core damage risks of operation in the current end state and in the proposed Mode 3 end state. Events initiated by the loss-of-offsite power are dominant contributors to CDF in most BWR PRAs, and the steam-driven core-cooling systems isolation condenser, RCIC and HPCS play a major role in mitigating these events. The evaluation indicates that the core damage risks are lower in Mode 3 than in Mode 4. Going to Mode 4 for one inoperable AC/DC power source would cause loss of the high-pressure steam-driven injection system (RCIC and HPCS),

and loss of the power conversion system ( condenser/feedwater), and require activating the RHR system. In addition, the EOPs direct the operator to take control of the depressurization function if low-pressure injection/spray systems are needed for RPV water makeup and cooling.

Based on the low probability of loss of the AC/DC electrical subsystems during the infrequent and limited time in Mode 3 and the number of systems available in Mode 3, the NRC staff concludes that the risks of staying in Mode 3 are approximately the same as and, in some cases, lower than the risks of going to the Mode 4 end state; therefore, the NRC staff concludes that the change is acceptable.

In its letter dated April 3, 2015, the licensee stated, in part, that

[The] Columbia design for distribution systems consists of three divisions. There are Division 1 and 2 AC electrical power distribution subsystems, Division 1 and 2 125 V DC electrical power distribution subsystems, a Division 1 250 V DC electrical power distribution subsystem and a Division 3 AC and DC electrical distribution subsystems.

The Columbia design is similar to the BWR-6 design as described in NUREG-1434 which has 2 divisions of AC, DC and AC vital bus electrical power distribution. Columbia TS do not contain the vital AC buses.

While the Columbia design is slightly different than that described for BWR-4 as described in NUREG-1433 and BWR-6 as described in NUREG-1434, the SE Assessment is applicable to the Columbia design with the following clarifications:

The steam driven cooling system is RCIC. The main feedwater pumps at Columbia are also steam-driven. This aspect of the BWR-5 configuration is addressed on page 25 of the SE. The variability among BWR plants regarding supports systems is addressed on pages 25 and 26 of the SE.

The NRC staff's review of the differences in the design of CGS Distribution Systems versus that assessed in the staff's SE for Distribution Systems in TR NEDC-32988, Revision 2 (Reference 15), has no impact on the staff's assessment since the functions of the mitigating systems specified in the assessment are similar, and therefore the change is acceptable.

3.5 Summary Based upon the above assessments, and because the time spent in Mode 3 to perform the repair on any of the systems described above would be infrequent and limited, and in light of the defense-in-depth considerations (discussed above and in TR NEDC-32988-A, Revision 2 (Reference 6), and as evaluated by the NRC staff's associated SE dated September 27, 2002 (Reference 15), the NRC staff concludes that the proposed changes to the CGS TS, described above, are acceptable.

4.0 REGULATORY COMMITMENTS In its application, the licensee made the following regulatory commitments:

REGULATORY COMMITMENTS DUE DATE/EVENT Energy Northwest will follow the guidance established in Implement with Section 11 of NUMARC 93-01, "Industry Guidance for amendment Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," Nuclear Management and Resource Council (NUMARC), Revision 4A, April 2011.

Energy Northwest will follow the guidance established in Implement with TSTF-IG-05-02, Revision 2, "Implementation Guidance amendment for TSTF-423, Revision 1, 'Technical Specifications End States, NEDC-32988-A."'

The NRC staff has determined that the licensee's regulatory commitments are consistent with the Notice of Availability of Model Application concerning TSTF-423 published in the Federal Register on March 23, 2006 (71 FR 14726).

5.0 STATE CONSULTATION

In accordance with the Commission's regulations, the Washington State official was notified of the proposed issuance of the amendment. The State official had no comments.

6.0 ENVIRONMENTAL CONSIDERATION

The amendment changes a requirement with respect to the installation or use of a facility component located within the restricted area as defined in 10 CFR Part 20. The NRC staff has determined that the amendment involves no significant increase in the amounts, and no significant change in the types, of any effluents that may be released offsite, and that there is no significant increase in individual or cumulative occupational radiation exposure. The Commission has previously issued a proposed finding that the amendment involves no significant hazards consideration and there has been no public comment on such finding published in the Federal Register on November 12, 2014 (79 FR 67200). 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.

7.0 CONCLUSION

The Commission has concluded, based on the considerations discussed above, that: (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) there is reasonable assurance that such activities will be conducted in compliance with the Commission's 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.

8.0 REFERENCES

1.

Hettel, William G., Energy Northwest Inc., letter to U.S. Nuclear Regulatory Commission, "License Amendment Request for Adaption of Technical Specification Task Force (TSTF) Traveler TSTF-423, Revision 1, Using the Consolidated Line Item Improvement Process," dated August 12, 2014 (ADAMS Accession No. ML14234A457).

2.

Gregoire, D. W., Energy Northwest Inc., letter to U.S. Nuclear Regulatory Commission, "Erratum for License Amendment Request for Adaption of Technical Specification Task Force (TSTF) Traveler TSTF-423, Revision 1, Using the Consolidated Line Item Improvement Process," dated September 4, 2014 (ADAMS Accession No. ML14268A233).

3.

Hettel, William G., Energy Northwest Inc., letter to U.S. Nuclear Regulatory Commission, "Response to Request for Additional Information Related to License Amendment Request for Adoption of Technical Specification Task Force (TSTF)

Traveler, TSTF-423, Revision 1," dated April 3, 2015 (ADAMS Accession No. ML15103A271 ).

4.

Hettel, William G., Energy Northwest Inc., letter to U.S. Nuclear Regulatory Commission, "Affected Technical Specification Pages Supporting License Amendment Request for Adoption of Technical Specification Task Force (TSTF) Traveler, TSTF-423, Revision 1, Using the Consolidated Line Item Improvement Process," dated August 11, 2015 (ADAMS Accession No. ML152238005).

5.

Technical Specifications Task Force, letter to U.S. Nuclear Regulatory Commission, "Transmittal of Revised Risk-Informed End State Travelers," dated December 22, 2009 (ADAMS Accession No. ML093570241 ); includes TSTF-423, Revision 1, "Technical Specifications End States, NEDC-32988-A."

6.

BWR Owners Group, NEDC-32988-A, Revision 2, "Technical Justification to Support Risk-Informed Modification to Selected Required Action End States for BWR Plants,"

December 2002 (ADAMS Accession No. ML030170084 ).

7.

U.S. Nuclear Regulatory Commission, NUREG-1433, Revision 4, "Standard Technical Specifications - General Electric Plants (BWR/4)," April 2012 (ADAMS Accession No. ML12104A192).

8.

U.S. Nuclear Regulatory Commission, NUREG-1434, Revision 4, "Standard Technical Specifications - General Electric Plants (BWR/6)," April 2012 (ADAMS Accession No. ML12104A195).

9.

Federal Register, Vol. 58, No. 139, p. 39136, "Final Policy Statement on Technical Specifications Improvements for Nuclear Power Plants," dated July 22, 1993.

10.

U.S. Nuclear Regulatory Commission, Regulatory Guide 1.182, "Assessing and Managing Risk Before Maintenance Activities at Nuclear Power Plants," May 2000 (ADAMS Accession No. ML003699426).

11.

Nuclear Management and Resource Council, NUMARC 93-01, Revision 3, "Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants,"

July 2000 (ADAMS Accession No. ML031500684).

12.

U.S. Nuclear Regulatory Commission, Regulatory Guide 1.160, Revision 3, "Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," May 2012 (ADAMS Accession No. ML113610098).

13.

Nuclear Management and Resource Council, NUMARC 93-01, Revision 4A, "Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants,"

April 2011 (ADAMS Accession No. ML11116A198).

14.

U.S. Nuclear Regulatory Commission, "Model Application for Plant-Specific Adoption of TSTF-423, Revision 1, 'Technical Specifications End States, NEDC-32988-A,' for Boiling Water Reactor Plants Using the Consolidated Line Item Improvement Process."

(ADAMS Accession No. ML102730688).

15.

U.S. Nuclear Regulatory Commission, NRC Safety Evaluation for Topical Report NEDC-32988, Revision 2, dated September 27, 2002 (ADAMS Accession No. ML022700603).

16.

U.S. Nuclear Regulatory Commission, Regulatory Guide 1.174, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant Specific Changes to the Licensing Basis, August 1998 (ADAMS Accession No. ML003740133).

17.

U.S. Nuclear Regulatory Commission, Regulatory Guide 1.177, "An Approach for Plant Specific Risk-Informed Decisionmaking: Technical Specifications, August 1998 (ADAMS Accession No. ML003740176).

18.

BWR Owners Group, TSTF-IG-05-02, Implementation Guidance for TSTF-423, Revision 0, "Technical Specifications End States, NEDC-32988-A, September 2005 (ADAMS Accession No. ML052700156).

Principal Contributor: R. Grover, NRR Date: February 3, 2016

ML15216A266

Memo dated 1/6/16 OFFICE N RR/DORL/LPL4-1 /PM N RR/DORL/LPL4-1 /LA NRR/DSS/STSB/BC NAME BSingal JBurkhardt RElliott*

DATE 1/8/16 1/8/16 1/6/16 OFFICE OGC NRR/DORL/LPL4-1/BC NRR/DORL/LPL4-1/PM NAME STurk RPascarelli BSingal DATE 1/19/16 02/03/16 02/03/16

v t e Letter Sequence Approval
CAC:MF4616, (Approved, Closed)
Initiation Acceptance... Administration Questions Answers Results Approval Other:
MONTHYEAR2016-02-03 [Table View]

ML15216A266

Text

SUBJECT:

Dear Mr. Reddemann:

Enclosures:

Attachment:

1.0 INTRODUCTION

2.0 REGULATORY EVALUATION

3.0 TECHNICAL EVALUATION

3.1 Proposed TS Changes

5.0 STATE CONSULTATION

6.0 ENVIRONMENTAL CONSIDERATION

7.0 CONCLUSION

8.0 REFERENCES

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