Text

Issuance of Amendment No. 253 to Technical Specifications to Add Residual Heat Removal System Containment Spray Function
	ML15343A301
Person / Time
Site:	Cooper
Issue date:	01/22/2016
From:	Thomas Wengert; Plant Licensing Branch IV
To:	Limpias O; Nebraska Public Power District (NPPD)
	Thomas Wengert, NRR/DORL
References
	CAC MF5584
	Download: ML15343A301 (38)
	v • d • e

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 January 22, 2016

SUBJECT:

COOPER NUCLEAR STATION - ISSUANCE OF AMENDMENT TO THE TECHNICAL SPECIFICATIONS TO ADD RESIDUAL HEAT REMOVAL SYSTEM CONTAINMENT SPRAY FUNCTION (CAC NO. MF5584)

Dear Mr. Limpias:

The U.S. Nuclear Regulatory Commission (the Commission) has issued the enclosed Amendment No. 253 to Renewed Facility Operating License No. DPR-46 for the Cooper Nuclear Station. The amendment consists of changes to the technical specifications (TSs) in response to your application dated January 15, 2015, as supplemented by letters dated May 4, 2015, June 9, 2015, and January 12, 2016.

The license amendment request will add a new TS Section 3.6.1.9, "Residual Heat Removal (RHR) Containment Spray and related containment pressure instrumentation to TS 3.3.5.1, "Emergency Core Cooling System (ECCS) Instrumentation," the requirements of which are currently located in the Technical Requirements Manual. The RHR Containment Spray function may be needed in certain small steam line break accident scenarios to maintain the drywell within design temperature limits.

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

Sincerely, Thomas J. Wengert, Senior Project Manager Plant Licensing IV-2 and Decommissioning Transition Branch Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-298

Enclosures:

1. Amendment No. 253 to DPR-46

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

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 NEBRASKA PUBLIC POWER DISTRICT DOCKET NO. 50-298 COOPER NUCLEAR STATION AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 253 License No. DPR-46

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

A. The application for amendment by Nebraska Public Power District (the licensee),

dated January 15, 2015, as supplemented by letters dated May 4, 2015, June 9, 2015, and January 12, 2016, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations set forth in 10 CFR Chapter I; B. The facility will operate in conformity with the application, the provisions of the Act, and the rules and regulations of the Commission; C. There is reasonable assurance (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commission's regulations; D. The issuance of this license 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.

Enclosure 1

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. DPR-46 is hereby amended to read as follows:

(2) Technical Specifications The Technical Specifications contained in Appendix A as revised through Amendment No. 253, are hereby incorporated in the license. The licensee shall operate the facility in accordance with the Technical Specifications.

3. The license amendment is effective as of its date of issuance and shall be implemented within 60 days from the date of issuance.

FOR THE NUCLEAR REGULATORY COMMISSION Meena K. Khanna, Chief Plant Licensing IV-2 and Decommissioning Transition Branch Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Attachment:

Changes to the Renewed Facility Operating License No. DPR-46 and Technical Specifications Date of Issuance: January 22, 2016

ATTACHMENT TO LICENSE AMENDMENT NO. 253 RENEWED FACILITY OPERATING LICENSE NO. DPR-46 DOCKET NO. 50-298 Replace the following pages of the Renewed Facility Operating License No. DPR-46 and Appendix A Technical Specifications with the enclosed revised pages. The revised pages are identified by amendment number and contain marginal lines indicating the areas of change.

Renewed Facility Operating License REMOVE INSERT Technical Specifications REMOVE INSERT ii ii 3.3-31 3.3-31 3.3-39 3.3-39 3.6-25 3.6-25 3.6-26 3.6-26 3.6-27 3.6-27 3.6-28 3.6-28 3.6-29 3.6-29 3.6-30 3.6-30 3.6-31 3.6-31 3.6-32 3.6-32 3.6-33 3.6-33 3.6-34 3.6-34 3.6-35 3.6-35 3.6-36 3.6-36 3.6-37 3.6-37 3.6-38 3.6-38 3.6-39 3.6-39 3.6-40 3.6-40 3.6-41 3.6-42

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

C. This license shall be deemed to contain and is subject to the conditions specified in the following Commission regulations in 10 CFR Chapter I: Part 20, Section 30.34 of Part 30, Section 40.41 of Part 40, Sections 50.54 and 50.59 of Part 50, and Section 70.32 of Part 70; is subject to all applicable provisions of the Act.and to the rules, regulations, and orders of the Commission now or hereafter in effect; and is subject to the additional conditions specified or incorporated below:

(1) Maximum Power Level The licensee is authorized to operate the facility at steady state reactor core power levels not in excess of 2419 megawatts (thermal).

(2) Technical Specifications The Technical Specifications contained in Appendix A as revised through Amendment No. 253, are hereby incorporated in the license. The licensee shall operate the facility in accordance with the Technical Specifications.

(3) Physical Protection The licensee shall fully implement and maintain in effect all provisions of the Commission-approved physical security, training and qualification and safeguards contingency plans including amendments made pursuant to provisions of the Miscellaneous Amendments and Search Requirements revisions to 10 CFR 73.55 (51 FR 27817 and 27822) and to the authority of 10 CFR 50.90 and 10 CFR 50.54(p). The combined set of plans, which contain Safeguards Information protected under 10 CFR 73.21, are entitled: "Cooper Nuclear Station Safeguards Plan," submitted by letter dated May 17, 2006.

NPPD shall fully implement and maintain in effect all provisions of the Commission-approved cyber security plan (CSP), including changes made pursuant to the authority of 10 CFR 50.90 and 10 CFR 50.54(p). The NPPD CSP was approved by License Amendment No. 238 as supplemented by changes approved by License Amendments 244 and 249.

(4) Fire Protection NPPD shall implement and maintain in effect all provisions of the approved fire protection program that comply with 10 CFR 50.48(a) and 10 CFR 50.48(c), as specified in the license amendment request dated April 24, 2012 (and supplements dated July 12, 2012, January 14, 2013, February 12, 2013, March 13, 2013, June 13, 2013, December 12, 2013, January 17, 2014, February 18, 2014, and April 11, 2014), and as approved in the safety evaluation dated April 29, 2014.

Except where NRG approval for changes or deviations is required by 10 CFR 50.48(c), and provided no other regulation, technical specification, license condition or requirement would require prior NRC approval, the licensee may make changes to the fire protection program without prior approval of the Commission if Amendment No. 253

TABLE OF CONTENTS (continued) 3.3 INSTRUMENTATION (continued) 3.3.7.1 Control Room Emergency Filter (CREF)

System Instrumentation ................................................................. 3.3-61 3.3.8.1 Loss of Power (LOP) Instrumentation ..................................................... 3.3-64 3.3.8.2 Reactor Protection System (RPS) Electric Power Monitoring ........................................................................................... 3.3-67 3.4 REACTOR COOLANT SYSTEM (RCS) ........................................................ 3.4-1 3.4.1 Recirculation Loops Operating ................................................................ 3.4-1 3.4.2 Jet Pumps ............................................................................................... 3.4-4 3.4.3 Safety/Relief Valves (SRVs) and Safety Valves (SVs) ............................ 3.4-6 3.4.4 RCS Operational LEAKAGE ................................................................... 3.4-8 3.4.5 RCS Leakage Detection Instrumentation ................................................ 3.4-10 3.4.6 RCS Specific Activity ............................................................................... 3.4-12 3.4.7 Residual Heat Removal (RHR) Shutdown Cooling System - Hot Shutdown ................................................................. 3.4-14 3.4.8 Residual Heat Removal (RHR) Shutdown Cooling System - Cold Shutdown ............................................................... 3.4-17 3.4.9 RCS Pressure and Temperatrue (PIT) Limits .......................................... 3.4-19 3.4.10 Reactor Steam Dome Pressure .............................................................. 3.4-26 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM .................................................... 3.5-1 3.5.1 ECCS - Operating ................................................................................... 3.5-1 3.5.2 ECCS - Shutdown ................................................................................... 3.5-7 3.5.3 RCIC System .......................................................................................... 3.5-11 3.6 CONTAINMENT SYSTEMS .......................................................................... 3.6-1 3.6.1.1 Primary Containment .............................................................................. 3.6-1 3.6.1.2 Primary Containment Air Lock ................................................................. 3.6-3 3.6.1.3 Primary Containment Isolation Valves (PC IVs) ....................................... 3.6-8 3.6.1.4 Drywell Pressure ..................................................................................... 3.6-16 3.6.1.5 Drywell Air Temperature ......................................................................... 3.6-17 3.6.1.6 Low-Low Set (LLS) Valves ...................................................................... 3.6-18 3.6.1.7 Reactor Building-to-Suppression Chamber Vacuum Breakers ........................................................................................ 3.6-20 3.6.1.8 Suppression-Chamber-to-Drywell Vacuum Breakers .............................. 3.6-23 3.6.1.9 Residual Heat Removal (RHR) Containment Spray ................................ 3.6-25 3.6.2.1 Suppression Pool Average Temperature ................................................. 3.6-27 3.6.2.2 Suppression Pool Water Level ................................................................ 3.6-30 3.6.2.3 Residual Heat Removal (RHR) Suppression Pool Cooling .......................................................................................... 3.6-31 3.6.3.1 Primary Containment Oxygen Concentration .......................................... 3.6-33 3.6.4.1 Secondary Containment. ......................................................................... 3.6-34 3.6.4.2 Secondary Containment Isolation Valves (SCIVs) ................................... 3.6-36 3.6.4.3 Standby Gas Treatment (SGT) System ................................................... 3.6-40 Cooper ii Amendment No. 253

ECCS Instrumentation 3.3.5.1 3.3 INSTRUMENTATION 3.3.5.1 Emergency Core Cooling System (ECCS) Instrumentation LCO 3.3.5.1 The ECCS instrumentation for each Function in Table 3.3.5.1-1 shall be OPERABLE.

APPLICABILITY: According to Table 3.3.5.1-1.

ACTIONS

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

Separate Condition entry is allowed for each channel.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more channels A.1 Enter the Condition Immediately inoperable. referenced in Table 3.3.5.1-1 for the channel.

B. As required by Required B.1 -------------NOTES----------

Action A.1 and referenced in 1. Only applicable in Table 3.3.5.1-1. MODES 1, 2, and 3.

2. Only applicable for Functions 1.a, 1.b, 2.a, 2.b, and 2.h.

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

Cooper 3.3-31 Amendment No. 253

ECCS Instrumentation 3.3.5.1 Table 3.3.5.1-1 (page 3 of 6)

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

2. LPCI System (continued)

g. Low Pressure Coolant 1,2,3, 1 per subsystem E SR 3.3.5.1.2 ~ 2107 gpm Injection Pump Discharge SR 3.3.5.1.4(cX*l Flow - Low (Bypass) 4!*l, 5C*l SR 3.3.5.1.5

h. Containment Pressure - 1,2,3 4 B SR 3.3.5.1.2 ~2psigl High SR 3.3.5.1.4 SR 3.3.5.1.5

3. High Pressure Coolant Injection (HPCI) System

a. Reactor Vessel Water Level 1, 4 B SR 3.3.5.1.1 ~ -42 inches

- Low Low (Level 2) SR 3.3.5.1.2 2m,3m SR 3.3.5.1.410 X*l SR 3.3.5.1.5

b. Drywell Pressure - High 1, 4 B SR 3.3.5.1.2 s 1.84 psig SR 3.3.5.1.4(cX*l 211J, 3(1J SR 3.3.5.1.5

c. Reactor Vessel Water Level 1, 2 c SR 3.3.5.1.1 s 54 inches

- High (Level 8) SR 3.3.5.1.2 SR 3.3.5.1.4 2m, 3CIJ SR 3.3.5.1.5

d. Emergency Condensate 1, 2 D SR 3.3.5.1.2 ~ 23 inches Storage Tank (ECST) Level - SR 3.3.5.1.3 Low 211J, 3!1J SR 3.3.5.1.5

e. Suppression Pool Water 1, 2 D SR 3.3.5.1.2 s 4 inches Level- High SR 3.3.5.1.4 211J, 3!1J SR 3.3.5.1.5 continued (a) When the associated ECCS subsystem(s) are required to be OPERABLE per LCO 3.5.2, ECCS - Shutdown.

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

(d) The instrument channel setpoint shall be reset to a value that is within the as-left tolerance around the Limiting Trip Setpoint (LTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable. Setpoints more conservative than the LTSP are acceptable provided that the as-found and as-left tolerances apply to the actual setpoint implemented in the Surveillance procedures (Nominal Trip Setpoint) to confirm channel performance. The Limiting Trip Setpoint and the methodologies used to determine the as-found and the as-left tolerances are specified in the Technical Requirements Manual.

(f) With reactor steam dome pressure >150 psig.

Cooper 3.3-39 Amendment No. 253

RHR Containment Spray 3.6.1.9 3.6 CONTAINMENT SYSTEMS 3.6.1.9 Residual Heat Removal (RHR) Containment Spray LCO 3.6.1.9 Two RHR containment spray subsystems shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3.

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

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

C. Required Action and C.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time not met. AND C.2 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months Cooper 3.6-25 Amendment No. 253

RHR Containment Spray 3.6.1.9 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.1.9. 1 Verify each RHR containment spray subsystem 31 days 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 or can be aligned to the correct position.

SR 3.6.1.9.2 Verify each required RHR pump develops a flow rate In accordance with of > 7700 gpm through the associated heat the lnservice exchanger while operating in the suppression pool Testing Program cooling mode.

SR 3.6.1.9.3 Verify each spray nozzle is unobstructed. Following maintenance which could result in nozzle blockage Cooper 3.6-26 Amendment No. 253

Suppression Pool Average Temperature 3.6.2.1 3.6 CONTAINMENT SYSTEMS 3.6.2.1 Suppression Pool Average Temperature LCO 3.6.2.1 Suppression pool average temperature shall be:

a. s 95°F when THERMAL POWER is> 1% RTP and no testing that adds heat to the suppression pool is being performed;

b. s 105°F when THERMAL POWER is> 1% RTP and testing that adds heat to the suppression pool is being performed; and

c. s 110°F when THERMAL POWER is s 1% RTP.

APPLICABILITY: MODES 1, 2, and 3.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Suppression pool average A.1 Verify suppression pool Once per hour temperature > 95°F but s average temperature 110°F. s 110°F.

THERMAL POWER is > 1% A.2 Restore suppression pool 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months RTP. average temperature to s 95°F.

Not performing testing that adds heat to the suppression pool.

(continued)

Cooper 3.6-27 Amendment No. 253 I

Suppression Pool Average Temperature 3.6.2.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME B. Required Action and B.1 Reduce THERMAL 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time POWER to s 1% RTP.

of Condition A not met.

C. Suppression pool average C.1 Suspend all testing that Immediately temperature> 105°F. adds heat to the suppression pool.

AND THERMAL POWER is > 1%

RTP.

AND Performing testing that adds heat to the suppression pool.

D. Suppression pool average D. 1 Place the reactor mode Immediately temperature > 110°F but switch in the shutdown s 120°F. position.

AND D.2 Verify suppression pool Once per 30 minutes average temperature s 120°F.

AND D.3 Be in MODE4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months (continued)

Cooper 3.6-28 Amendment No. 2531

Suppression Pool Average Temperature 3.6.2.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME E. Suppression pool average E.1 Depressurize the reactor 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months temperature > 120°F. vessel to < 200 psig.

E.2 Be in MODE4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.2.1.1 Verify suppression pool average temperature is within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months the applicable limits.

5 minutes when performing testing that adds heat to the suppression pool Cooper 3.6-29 Amendment No. 253 I

Suppression Pool Water Level 3.6.2.2 3.6 CONTAINMENT SYSTEMS 3.6.2.2 Suppression Pool Water Level LCO 3.6.2.2 Suppression pool water level shall be 2: 12 ft 7 inches ands 12 ft 11 inches.

APPLICABILITY: MODES 1, 2, and 3.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Suppression pool water A.1 Restore suppression pool 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months level not within limits. water level to within limits.

B. Required Action and B.1 Be in MODE3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time not met. AND B.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 3.6.2.2.1 Verify suppression pool water level is within limits. 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Cooper 3.6-30 Amendment No. 253 I

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

APPLICABILITY: MODES 1, 2, and 3.

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

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

C. Required Action and C. 1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time not met. AND C.2 Be in MODE4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months Cooper 3.6-31 Amendment No. 253 I

RHR Suppression Pool Cooling 3.6.2.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.2.3.1 Verify each RHR suppression pool cooling subsystem 31 days 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 or can be aligned to the correct position.

SR 3.6.2.3.2 Verify each RHR pump develops a flow rate > 7700 In accordance gpm through the associated heat exchanger while with the lnservice operating in the suppression pool cooling mode. Testing Program Cooper 3.6-32 Amendment No. 253 I

Primary Containment Oxygen Concentration 3.6.3.1 3.6 CONTAINMENT SYSTEMS 3.6.3.1 Primary Containment Oxygen Concentration LCO 3.6.3.1 The primary containment oxygen concentration shall be < 4.0 volume percent.

APPLICABILITY: MODE 1 during the time period:

a. From 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after THERMAL POWER is > 15% RTP following startup, to

b. 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months prior to reducing THERMAL POWER to < 15% RTP prior to a reactor shutdown.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Primary containment oxygen A.1 Restore oxygen 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months concentration not within concentration to within limit. limit.

B. Required Action and B.1 Reduce THERMAL 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months associated Completion Time POWER to s 15% RTP.

not met. I SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.3.1.1 Verify primary containment oxygen concentration is 7 days within limits.

Cooper 3.6-33 Amendment No. 253 I

Secondary Containment 3.6.4.1 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, During movement of recently irradiated fuel assemblies in the secondary containment, 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, 2, or containment to

3. OPERABLE status.

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

inoperable during movement LCO 3.0.3 is not of recently irradiated fuel applicable.

assemblies in the secondary -----------------------------

containment or during OPDRVs. Suspend movement of Immediately recently irradiated fuel assemblies in the secondary containment.

AND (continued)

Cooper 3.6-34 Amendment No. 253 I

Secondary Containment 3.6.4.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C. (continued) C.2 Initiate action to suspend Immediately OPDRVs.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.4.1.1 Verify secondary containment vacuum is ~ 0.25 inch 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months of vacuum water gauge.

SR 3.6.4.1.2 Verify all secondary containment equipment hatches 31 days are closed and sealed.

SR 3.6.4.1.3 Verify one secondary containment access door in 31 days each access opening is closed.

SR 3.6.4.1.4 Verify each SGT subsystem can maintain~ 0.25 inch 24 months on a of vacuum water gauge in the secondary containment STAGGERED for 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months at a flow rate s 1780 cfm. TEST BASIS Cooper 3.6-35 Amendment No. 253 I

SCI Vs 3.6.4.2 3.6 CONTAINMENT SYSTEMS 3.6.4.2 Secondary Containment Isolation Valves (SCIVs)

LCO 3.6.4.2 Each SCIV shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3, During movement of recently irradiated fuel assemblies in the secondary containment, During operations with a potential for draining the reactor vessel (OPDRVs).

ACTIONS

--~~~~--~~-------~~--------~~------~~---~~----NOl"ES----~-~--------~----~---~-~~--~-------~----~~-

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

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

3. Enter applicable Conditions and Required Actions for systems made inoperable by SC IVs.

CONDITION REQUIRED ACl"ION COMPLETION TIME A. One or more penetration A.1 Isolate the affected 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months flow paths with one SCIV penetration flow path by inoperable. use of at least one closed and de-activated automatic valve, closed manual valve, or blind flange.

(continued)

Cooper 3.6-36 Amendment No. 253 I

SCI Vs 3.6.4.2 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. (continued) A.2 -------------NOTES------------

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

2. Isolation devices that Once per 31 days are locked, sealed, or otherwise secured may be verified by use of administrative means.

Verify the affected penetration flow path is isolated.

B. --------~~~-NOl"E-------~----- B.1 Isolate the affected 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Only applicable to penetration flow path by penetration flow paths with use of at least one closed two isolation valves. and de-activated

automatic valve, closed manual valve, or blind One or more penetration flange.

flow paths with two SCIVs inoperable.

c. Required Action and C.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 or B not met AND in MODE 1, 2, or 3.

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

Cooper 3.6-37 Amendment No. 253 I

SCI Vs 3.6.4.2 ACTIONS (continued}

CONDITION REQUIRED ACTION COMPLETION TIME D. Required Action and D.1 --------------NOTE-------------

associated Completion Time LCO 3.0.3 is not of Condition A or B not met applicable.

during movement of recently irradiated fuel assemblies in the secondary containment Suspend movement of Immediately or during OPDRVs. recently irradiated fuel assemblies in the secondary containment.

AND D.2 Initiate action to suspend Immediately OPDRVs.

Cooper 3.6-38 Amendment No. 253 I

SCI Vs 3.6.4.2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.4.2.1 ------------------------------NOTES------------------------------

1. Valves and blind flanges in high radiation areas may be verified by use of administrative means.

2. Not required to be met for SCIVs that are open under administrative controls.

Verify each secondary containment isolation manual 31 days valve and blind flange that is not locked, sealed, or otherwise secured and is required to be closed during accident conditions is closed.

SR 3.6.4.2.2 Verify the isolation time of each power operated In accordance automatic SCIV is within limits. with the In service Testing Program SR 3.6.4.2.3 Verify each automatic SCIV actuates to the isolation 24 months position on an actual or simulated actuation signal.

Cooper 3.6-39 Amendment No. 253 I

SGT System 3.6.4.3 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, During movement of recently irradiated fuel assemblies in the secondary containment, 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 ?days inoperable. to OPERABLE status.

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

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

c. Required Action and ----~~------~-----NOTE---~---~----~---

associated Completion Time LCO 3.0.3 is not applicable.

of Condition A not met ------------------------------------------

during movement of recently irradiated fuel assemblies in C.1 Place OPERABLE SGT Immediately the secondary containment subsystem in operation.

or during OPDRVs.

OR (continued)

Cooper 3.6-40 Amendment No. 253 I

SGT System 3.6.4.3 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C. (continued) C.2.1 Suspend movement of Immediately recently irradiated fuel assemblies in secondary containment.

AND C.2.2 Initiate action to suspend Immediately OPDRVs.

D. Two SGT subsystems D.1 Enter LCO 3.0.3 Immediately inoperable in MODE 1, 2, or 3.

E. Two SGT subsystems E.1 --~------~-NOTE-----~-------

inoperable during movement LCO 3.0.3 is not of recently irradiated fuel applicable.

assemblies in the secondary -----------------------------

containment or during OPDRVs. Suspend movement of Immediately recently irradiated fuel assemblies in secondary containment.

AND (continued)

Cooper 3.6-41 Amendment No. 253 I

SGT System 3.6.4.3 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME E. (continued) E.2 Initiate action to suspend Immediately OPDRVs.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.4.3.1 Operate each SGT subsystem for O!: 10 continuous 31 days hours with heaters operating.

SR 3.6.4.3.2 Perform required SGT filter testing in accordance with In accordance with the Ventilation Filter Testing Program (VFTP). the VFTP SR 3.6.4.3.3 Verify each SGT subsystem actuates on an actual or 24 months simulated initiation signal.

SR 3.6.4.3.4 Verify the SGT units cross tie damper is in the correct 24 months position, and each SGT room air supply check valve and SGT dilution air shutoff valve can be opened.

Cooper 3.6-42 Amendment No. 253 I

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 253 TO RENEWED FACILITY OPERATING LICENSE NO. DPR-46 NEBRASKA PUBLIC POWER DISTRICT COOPER NUCLEAR STATION DOCKET NO. 50-298

1.0 INTRODUCTION

By application dated January 15, 2015 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML15021A127), as supplemented by letters dated May 4, 2015 (ADAMS Accession No. ML15132A652), June 9, 2015 (ADAMS Accession No. ML15167A065), and January 12, 2016 (ADAMS Accession No. ML16021A322), Nebraska Public Power District (NPPD, the licensee), requested changes to the technical specifications (TSs) for Cooper Nuclear Station (CNS). The supplemental letters dated May 4, 2015, June 9, 2015, and January 12, 2016, provided additional information that clarified the application, did not expand the scope of the application as originally noticed, and did not change the U.S.

Nuclear Regulatory Commission (NRC) staffs original proposed no significant hazards consideration determination as published in the Federal Register on March 17, 2015 (80 FR 13910).

The proposed license amendment will add a new TS Section 3.6.1.9, "Residual Heat Removal (RHR) Containment Spray." The Containment Spray requirements are currently located in the Technical Requirements Manual (TRM), a licensee-controlled document. The RHR Containment Spray function is necessary to maintain the drywell within design temperature limits during a small steamline break (SSLB) accident.

The proposed amendment would also add related containment pressure instrumentation to TS 3.3.5.1, "Emergency Core Cooling System (ECCS) Instrumentation," which provides an RHR containment spray function permissive interlock associated with the use of the containment spray. This permissive interlock instrumentation had previously resided in the TSs for CNS but was relocated to the TRM as part of the conversion to the improved TSs, as approved by License Amendment No. 178, "Conversion to Improved Technical Specifications for the Cooper Nuclear Station - Amendment No. 178 to Facility Operating License No. DPR-46 (TAC No. M98317)," dated July 31, 1998 (ADAMS Accession No. ML021410047).

Enclosure 2

Based on the requirements in Title 10 of the Code of Federal Regulations (10 CFR), Part 50, Section 50.36, "Technical specifications," the licensee has determined that the RHR containment spray and related instrumentation needs to be included in the CNS TSs.

2.0 REGULATORY EVALUATION

2.1 Regulatory Requirements and Guidance Section 182a of the Atomic Energy Act requires applicants for nuclear power plant operating licenses to include TSs as part of the license. In 10 CFR 50.36, the NRC established the regulatory requirements related to the content of TSs.

Pursuant to 10 CFR 50.36, TSs are required to include items in the following five specific categories: (1) safety limits, limiting safety system settings, and limiting control settings; (2) limiting conditions for operation (LCOs); (3) surveillance requirements (SRs); (4) design features; and (5) administrative controls. The regulation does not specify the particular requirements to be included in a plant's TSs.

The regulation in 10 CFR 50.36(c)(2)(i) states, in part, 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 until the condition can be met.

The regulation in 10 CFR 50.36(c)(3) states, Surveillance requirements are requirements relating to test, calibration, or inspection to assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met.

The Commission published a "Final Policy Statement on Technical Specifications Improvements for Nuclear Power Reactors," in the Federal Register on July 22, 1993 (58 FR 39132), which discusses the criteria to determine the items that are required to be included in the TSs as LCOs. The criteria were subsequently incorporated into the regulations by an amendment to 10 CFR 50.36 published in the Federal Register on July 19, 1995 (60 FR 36953). Specifically, 10 CFR 50.36(c)(2)(ii) requires that a TS LCO be established for each item meeting one or more of the following criteria:

Criterion 1: Installed instrumentation that is used to detect, and indicate in the control room, a significant abnormal degradation of the reactor coolant pressure boundary.

Criterion 2: A process variable; design feature, or operating restriction that is an initial condition of a design basis accident or transient analysis that either

assumes the failure of or presents a challenge to the integrity of a fission product barrier.

Criterion 3: A structure, system, or component that is part of the primary success path and which functions or actuates to mitigate a design basis accident or transient that either assumes the failure of or presents a challenge to the integrity of a fission product barrier.

Criterion 4: A structure, system, or component which operating experience or probabilistic risk assessment has shown to be significant to public health and safety.

In determining the acceptability of the proposed amendment, the NRC staff considered plant-specific licensing basis information, as well as the accumulation of generically-approved guidance in the improved Standard Technical Specifications (STS), specifically, NUREG-1433, "Standard Technical Specifications - General Electric Plants (BWR [Boiling Water Reactor]/4),"

Revision 4, Volume 1, Specifications, dated April 2012 (ADAMS Accession No. ML12104A192).

2.2 Equipment Description As described in Chapter V, Section 2.0 of the CNS Updated Safety Analysis Report (USAR),

"Primary Containment," the CNS primary containment is a Mark I design consisting of: (1) a drywell, which is a steel pressure vessel (in the shape of an inverted light bulb) that encloses the reactor vessel; (2) a pressure-suppression chamber (also called the wetwell or suppression pool), which is a torus-shaped steel pressure vessel that is* partially filled with a large volume of water and is located below and encircling the drywell; and (3) a vent system connecting the drywell atmosphere to the suppression pool.

As described in the licensee's application dated January 15, 2015, containment spray is a mode of the RHR system, which may be initiated under post-accident conditions to reduce the temperature and pressure of the primary containment atmosphere. The licensee states, in part:

Each of the two RHR Containment Spray subsystems contain two pumps ... and one heat exchanger, which are manually initiated and independently controlled.

The two subsystems perform the Containment Spray function by circulating water from the suppression pool through the RHR heat exchangers and returning it to the drywell and suppression pool spray spargers. Both suppression pool cooling and containment spray functions are performed when the RHR Containment Spray System is initiated. RHR service water, circulating through the tube side of the heat exchangers, exchanges heat with the suppression pool water and discharges this heat to the external heat sink. Either RHR Containment Spray subsystem is sufficient to condense the steam in both the drywell and the suppression chamber airspace during the postulated OBA [design-basis accident].

The containment pressure-high instrumentation serves as an interlock permissive to allow the RHR system to be manually aligned from the low pressure coolant injection (LPCI) mode to the Containment Spray mode after containment pressure has increased above the trip

setting. The permissive ensures that containment pressure is elevated before the manual transfer is allowed. Chapter IV, Section 8.5.3.1, of the CNS USAR, "Containment Spray Subsystems," states, in part, "[t]he containment spray mode of the RHR system cannot be operated unless the drywell pressure exceeds 2.0 psig [pounds per square inch gauge] and the level inside the reactor vessel shroud is above the 2/3 core height setpoint. This water level interlock is provided to prevent the LPCI flow from being diverted to the containment spray mode unless the core is flooded." This ensures that LPCI is available to prevent or minimize fuel damage until such time that the operator determines that containment pressure control is needed.

3.0 TECHNICAL EVALUATION

3.1 Background The licensee's proposed change would revise the CNS operating license to add an LCO, Applicability, Required Actions, Completion Times and Surveillance Requirements for the RHR Containment Spray System. A new TS Section 3.6.1.9 will be added with the title "Residual Heat Removal (RHR) Containment Spray." In addition, the Containment Pressure -

High function that supports RHR Containment Spray will be relocated from the TRM to TS 3.3.5.1, "Emergency Core Cooling System (ECCS) Instrumentation." The proposed changes are consistent with the guidance in NUREG-1433, Revision 4.

The requirements for the RHR Containment Spray function are currently contained in the TRM, Section T 3.6.1, "Residual Heat Removal (RHR) Containment Spray." The requirements for the Containment Pressure - High function are currently contained in TRM Section T 3.3.2, "ECCS and RCIC [Reactor Core Isolation Cooling] Instrumentation." These TRM sections established specific guidance and criteria related to the applicability, operation, and testing for the RHR Containment Spray System. The licensee will remove the TRM requirements for the RHR Containment Spray System once the TS requirements are approved by the NRC staff.

In its application dated January 15, 2015, the licensee states, in part:

This change is being proposed because the RHR Containment Spray function is necessary to maintain the drywell within design temperature limits during a small steam line break (SSLB).

In 1998, CNS converted from custom TSs to Standard TS (NUREG-1433). At that time, it was believed that the Containment Spray system did not have a safety function. The conversion document [License Amendment No. 178]

stated, "Neither drywell spray nor suppression pool spray is credited in any OBA [Design Basis Accident] (i.e., they are not needed to function to mitigate the consequences of any design basis accident). They are considered secondary actions in the emergency procedures. Therefore, the drywell and torus sprays are not risk significant. As such, this requirement is not required to be in the Improved Technical Specifications (ITSs) to provide adequate protection of the public health and safety."

In 2000, a concern was entered into the corrective action program that identified a discrepancy between the containment peak temperature utilized by the Environmental Qualification (EQ) program and the SSLB peak temperature documented in the Plant Unique Analysis Report. This root cause determined that in 1985 the EQ program owner made a technical error in utilizing the DBA Loss of Coolant Accident (LOCA) for the most severe design basis event in the drywell.

The licensee cited General Electric report (GE-NE-T23-00786-00-02, "Cooper Nuclear Station Containment Analysis Project-Small Steam Line Break Analysis"), that confirmed that containment spray is required to prevent the drywell liner from exceeding temperature limits in certain SSLB scenarios. The licensee states that, given that containment spray is actuated, assuming a 10-minute delay in operator manual action when conditions are met that require containment spray per emergency operating procedures, the drywell temperature limits will not be exceeded.

In its application dated January 15, 2015, the licensee states, in part:

The root cause initiated an action to develop Engineering Evaluation (EE)01-035

[Cooper Station Engineering Evaluation 01-035, "EQ Temperature Profile in Containment Based on Small Steam Line Break and DBA-LOCA,"] ... which determined that the Containment Spray function of RHR was necessary for limiting drywell temperature following a design basis SSLB. The EE 01-035 determined that Containment Spray would be added to the TRM based on 10 CFR 50.36{c){2)(iii) which states, "A licensee is not required to propose to modify technical specifications that are included in any license issued before August 18, 1995, to satisfy the criteria in paragraph (c)(2)(ii) of this section."

Since CNS' Operating License was issued January 18, 1974, it was believed that

[10 CFR 50.36(c)(2)(iii)] provided an exemption from adding RHR Containment Spray to the TS.

In 2014, during a review of external operating experience, it was noted that a utility had identified the same issue of mitigating a small break LOCA at one of its nuclear facilities and was pursuing a license amendment to move Drywell Spray from the TRM to TS. This operating experience was placed in the CNS corrective action program for evaluation. As part of this evaluation, a conference call with the [Office of] Nuclear Reactor Regulation TS Branch was conducted. The discussion determined that CNS was misapplying the requirement of 10 CFR 50.36(c)(2)(iii). It did not provide an exemption as CNS had thought and compliance with 10 CFR 50.36(c)(2)(ii) was necessary.

As such, the licensee concluded that the RHR Containment Spray meets the requirements of Criterion 3 of 10 CFR 50.36(c)(2)(ii), as it is needed to maintain the drywell within design temperature limits during a SSLB. Accordingly, the licensee requested that the requirements for the RHR Containment Spray function be established in the CNS TS.

3.2 Licensee's Proposed TS Changes In its application dated January 15, 2015, as modified by letter dated May 4, 2015, the licensee proposed to revise TS 3.3.5.1, "Emergency Core Cooling System (ECCS) Instrumentation."

The specific change is the addition of a new Function 2.h, LPCI System - Containment Pressure - High in Table 3.3.5.1-1. Table 3.3.5.1-1 specifies operability requirements for ECCS instrumentation. The new Function 2.h would require 4 channels of containment pressure instrumentation to be operable in MODES 1, 2, and 3, with an Allowable Value of greater than or equal to(~) 2 psig. The licensee proposed to associate the following SRs already contained in the TSs with Function 2.h: 1 SURVEILLANCE FREQUENCY SR 3.3.5.1.2 Perform Channel Functional Test 92 days SR 3.3.5.1.4 Perform Channel Calibration 24 months SR 3.3.5.1.5 Perform Looic System Functional Test 24 months The new proposed TS LCO 3.6.1.9 would require two RHR containment spray subsystems to be OPERABLE in MODES 1, 2, and 3. The ACTIONS to be taken if the LCO is not met would be as follows:

CONDITION REQUIRED ACTION COMPLETION TIME A. One RHR A.1 Restore RHR 7 days containment spray containment spray subsystem subsystem to inoperable. OPERABLE status.

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

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

C.2 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months 1 In its letter dated May 4, 2015, the licensee revised its proposed SRs associated with Function 2.h by eliminating footnotes (c) and (d), as discussed at the end of Section 3.3.2 of this SE.

The SRs for TS 3.6.1.9 would be as shown in the following table:

SURVEILLANCE FREQUENCY SR 3.6.1.9.1 Verify each RHR containment spray subsystem 31 days 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 or can be aligned to the correct position.

SR 3.6.1.9.2 Verify each required RHR pump develops a flow In accordance with the rate of> 7700 gpm through the associated heat lnservice Testing exchanger while operating in the suppression pool Program cooling mode.

SR 3.6.1.9.3 Verify each spray nozzle is unobstructed. Following maintenance which could result in nozzle blockaae 3.3 NRC Staff Evaluation 3.3.1 Containment Spray System In the licensee's application dated January 15, 2015, Attachment 1, Section 3.4, "Technical Justification of Proposed Changes," it was stated that the EQ program was utilizing the OBA LOCA profile for qualification of equipment to satisfy 10 CFR 50.49, "Environmental qualification of electric equipment important to safety for nuclear power plants." Subsequently, the licensee determined that the limiting primary containment temperature response occurs during an SSLB, and that a plant specific realistic model was developed to determine drywell airspace temperature response.

As a result of the analysis, the licensee determined that, since the RHR Containment Spray is needed to mitigate the impact of an SSLB, an LCO was required consistent with the requirements in Criterion 3 of 10 CFR 50.36(c)(2)(ii).

The licensee concluded that an SSLB will result in more severe containment temperatures than the previously considered OBA LOCA. Specifically, the licensee stated that the drywell structural design temperature limit for CNS is 281 degrees Fahrenheit (°F). The licensee's calculations predicted that the peak drywell air space temperature is 332.1 °F, and the peak drywell structural (wall/liner) temperature is 271.1 °F (less than the design limit) for the most limiting SSLB, if credit is taken for drywell sprays. Without containment spray, the licensee's calculations predicted that for the most limiting SSLB, the peak drywell structural temperature exceeds the design limit of 281 °F, and reaches to a temperature as high as 287.1 °F.

To compare with the OBA-LOCA results, the peak drywell air space temperature for OBA-LOCA is 301.4 °F, and it does not raise the drywell structural temperature above the design value of 281 °F, even if no credit is taken for drywell sprays. The analytical result presented by the licensee documents the need for containment spray to mitigate temperature effects of a SSLB to maintain the containment structural temperature below the design value of 281 °F, and that it

quantifies the magnitude of the increase above the design temperature, which may be expected without containment spray.

The results presented above confirm that SSLB is the limiting event for drywell temperature, not the DBA-LOCA as previously thought, and that the containment spray function is required for the design basis SSLB in order to maintain the drywell structural temperature below the design limit.

As described in Section 2.1 of this safety evaluation (SE), Criterion 3 of 10 CFR 50.36(c)(2)(ii) requires that a TS LCO be established for a "structure, system, or component that is part of the primary success path and which functions or actuates to mitigate a design basis accident or transient that either assumes the failure of or presents a challenge to the integrity of a fission product barrier." Since the peak drywell temperatures are higher for an SSLB than the DBA-LOCA, and the RHR Containment Spray function must be credited in the design basis to limit peak drywell temperature following an SSLB inside the drywell, the NRC staff agrees with the licensee's determination that an LCO for the RHR Containment Spray function is required per the requirements in Criterion 3 of 10 CFR 50.36(c)(2)(ii).

As described above, the RHR Containment Spray function meets Criterion 3 of 10 CFR 50.36(c)(2)(ii). Therefore, the CNS TSs must contain an LCO for this function. Furthermore, consistent with the requirements in 10 CFR 50.36(c)(3), the CNS TSs must contain SRs to provide the necessary requirements to assure that the LCO will be met.

As described in 10 CFR 50.36(c)(2), LCOs are the lowest functional capability or performance level of equipment required for safe operation of the facility. When LCOs are not met, the licensee shall shut down the reactor or follow any remedial action permitted by the TSs until the LCO can be met.

As described in 10 CFR 50.36(c)(3), SRs are requirements relating to test, calibration, or inspection to assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the LCOs will be met.

The NRC staff evaluated the proposed LCO, including its applicability and actions with respect to the requirements in 10 CFR 50.36(c)(2). The staff also reviewed the proposed SRs with respect to the requirements in 10 CFR 50.36(c)(3). As part of this evaluation, the staff reviewed the proposed TS Bases for TS 3.3.5.1, as well as TS 3.6.1.9 for the RHR Containment Spray function. The staff also referred to NUREG-1433, Revision 4, as guidance.

The LCO Actions require that, with one RHR containment spray system inoperable, the subsystem must be restored to operable status within 7 days. The LCO Actions also require that with two RHR containment spray systems inoperable, one subsystem must be restored within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months . With either of the Required Actions not met, the plant must 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 . The NRC staff finds that the Actions, including the associated Completion Times, that the licensee has proposed, as listed in Section 3.2 of this SE, are reasonable actions until the LCO can be met.

3.3.2 Containment Spray Instrumentation The TS requirements for containment spray instrumentation, including the containment spray permissive interlock instrumentation, were included in the CNS TS prior to the ITS conversion in 1998. The NRC staff approved the CNS conversion to ITSs in License Amendment No. 178, dated July 31, 1998. As indicated in Section 3.1 of this SE, the licensee stated that the containment spray instrumentation was not associated with any OBA or with any safety-related function and therefore, the associated permissive interlock instrumentation for manual use of containment spray was not included in the ITS conversion. Therefore, after the conversion, the TS requirements for this instrumentation were relocated to the TRM.

The containment spray mode is manually initiated, if needed, after the LPCI cooling requirements are satisfied. The containment pressure containment spray interlock prevents the operator from inadvertently initiating containment spray when not required to reduce containment pressure during a LOCA. Also, the interlock functions to preclude inadvertent containment spray initiation at other times (i.e., non-LOCA conditions). The permissive ensures that the containment pressure is elevated before manual transfer is allowed. The ability to manually actuate containment spray is a limiting event for control of drywell temperature during an SSLB. The containment spray function is required for the design basis SSLB in order to maintain the drywell structural temperature below the design limit. Consequently, the associated interlock permissive for the containment spray is also required to be OPERABLE if containment spray is to be used. The containment spray instrumentation is part of the primary success path, which must function to allow actuation of the containment spray and meets Criterion 3 of 10 CFR 50.36(c)(2)(ii). Therefore, the CNS TSs must contain an LCO for this instrumentation. Furthermore, consistent with the requirements in 10 CFR 50.36(c)(3), the CNS TSs must contain SRs to provide the necessary requirements to assure that the LCO will be met. Consequently, the licensee has moved the related containment spray permissive interlock instrumentation requirements, which are currently located in the TRM, back into the CNS TSs.

The specific changes include the addition of a new Function 2.h, LPCI System - Containment Pressure - High in Table 3.3.5.1-1. Table 3.3.5.1-1 specifies operability requirements for ECCS instrumentation. The new Function 2.h would require 4 channels of containment pressure instrumentation to be operable in Modes 1, 2, and 3, with an Allowable Value of~ 2 psig. The permissive interlock required channels, applicable Modes, and allowable value of 2 psig for containment high pressure are not being changed, and had been previously established and approved in the current CNS licensing basis for this safety-related function.

As described in 10 CFR 50.36(c)(3), SRs are requirements relating to test, calibration, or inspection to assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the LCOs will be met. The licensee has provided SRs for the containment spray instrumentation that are currently in the CNS TRM and are consistent with other CNS technical specification LPCI ECCS instrumentation requirements that already exist in the CNS TSs.

The Conditions, Required Actions, Completion Times and Surveillances proposed for LCO 3.3.5.1, Function 2.h, Containment Pressure - High TS, are consistent with other comparable instrumentation TSs that use a one-out-of-two taken twice logic. The licensee cited the James A. FitzPatrick Nuclear Power Plant (FitzPatrick) Containment Spray Containment Pressure - High instrumentation TS as a precedent for changes proposed by CNS. The NRC

staff finds that the CNS proposed TS changes are consistent with the FitzPatrick precedence with the exception that CNS has an additional surveillance for performing a channel functional test that is a carryover from the TRM requirements.

Table 3.3.5.1-1 contains footnotes (c) and (d) for other functions in the table that were added by License Amendment No. 242, "Cooper Nuclear Station - Issuance of Amendment Re:

Implementation of a 24-Month Fuel Cycle and Adoption of TSTF-493, Revision 4, Option A" (ADAMS Accession No. ML12251A098). As the licensee explained in its May 4, 2015 letter, it is not adding these footnotes (c) and (d) for the proposed Function 2.h because this function is for manual operation and is not related to any limiting safety system settings. The NRC staff finds this acceptable because footnotes (c) and (d) are relevant to the TSTF-493 amendment, but not to the current amendment.

3.4 Technical Evaluation Conclusion Based on the NRC staff's evaluation of the proposed changes, the staff concludes that the proposed addition of a new TS 3.6.1.9 , Residual Heat Removal (RHR) Containment Spray, and related containment pressure instrumentation Function 2.h in TS 3.3.5.1, Emergency Core Cooling System (ECCS) Instrumentation, satisfies the requirements in 10 CFR 50.36(c)(2) and 10 CFR 50.36(c)(3).

The NRC staff's review concludes that the licensee used methods consistent with the regulatory requirements and guidance identified in Section 2.1 of this SE.

TS pages 3.3-31, 3.3-39, 3.6-25, and 3.6-26 have been revised to reflect the changes described above. TS pages 3.6-27 through 3.6-42 have been revised for this license amendment for pagination purposes only. In addition, page ii of the TS Table of Contents has been revised to conform to the pagination changes. Since these page changes are purely administrative, they are acceptable.

Based on the evaluation in Section 3.3 of this SE, the NRC staff concludes that the proposed amendment relocating the containment spray technical information from the TRM to the TSs is conservative and therefore, acceptable.

4.0 STATE CONSULTATION

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

5.0 ENVIRONMENTAL CONSIDERATION

The amendment changes a requirement with respect to installation or use of a facility component located within the restricted area as defined in 10 CFR Part 20, and adds surveillance requirements. 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 March 17, 2015 (80 FR 13910). Accordingly, the amendment meets the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9). Pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the issuance of the amendment.

6.0 CONCLUSION

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

Principal Contributors: M. Razzaque M. Chernoff S. Mazumdar Date: January 22, 2016

ML15343A301 *see previous **via memo OFFICE NRR/DORULPL4-2/PM NRR/DORL/LPL4-1 /LA NRR/DSS/STSB/BC NRR/DSS/SRXB/BC**

NAME WHuffman* PBlechman* RElliott* CJackson DATE 01 /06/16 01/06/16 01/08/16 10/05/2015 OFFICE NRR/DE/EICB/BC OGC-NLO NRR/DORL/LPL4-2/BC NRR/DORL/LPL4-1 /PM NAME MWaters* Ylindell* MKhanna* TWengert DATE 01/07/16 01/14/16 01/19/16 1/22/16

v t e Letter Sequence Approval
CAC:MF5584, Clarify Application of Setpoint Methodology for LSSS Functions (Approved, Closed)
Initiation Request, Request Acceptance... Administration Questions Answers Results Approval Other:
MONTHYEAR2016-01-12 [Table View]

ML15343A301

Text

SUBJECT:

Dear Mr. Limpias:

Enclosures:

Attachment:

1.0 INTRODUCTION

2.0 REGULATORY EVALUATION

3.0 TECHNICAL EVALUATION

4.0 STATE CONSULTATION

5.0 ENVIRONMENTAL CONSIDERATION

6.0 CONCLUSION

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