Text

Issuance of Amendment No. 242, Revise Technical Specifications to Implement a 24-Month Fuel Cycle and Adopt Technical Specification Task Force (TSTF)-493, Revision 4, Option a
	ML12251A098
Person / Time
Site:	Cooper
Issue date:	09/28/2012
From:	Lynnea Wilkins; Plant Licensing Branch IV
To:	O'Grady B; Nebraska Public Power District (NPPD)
	Wilkins L
References
	TAC ME7169
	Download: ML12251A098 (108)
	v • d • e

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 September 28, 2012 Mr. Brian J. O'Grady Vice President-Nuclear and CNO Nebraska Public Power District 72676 648A Avenue Brownville, NE 68321

SUBJECT:

COOPER NUCLEAR STATION - ISSUANCE OF AMENDMENT RE:

IMPLEMENTATION OF A 24-MONTH FUEL CYCLE AND ADOPTION OF TSTF-493, REVISION 4, OPTION A (TAC NO. ME7169)

Dear Mr. O'Grady:

The U.S. Nuclear Regulatory Commission (NRC, the Commission) has issued the enclosed Amendment No. 242 to Renewed Facility Operating License No. DPR-46 for the Cooper Nuclear Station (CNS). The amendment consists of changes to the Technical Specifications (TSs) in response to your application dated September 16, 2011, as supplemented by letters dated May 2, May 24, and September 17, 2012.

The amendment revises the CNS TSs and operating license to implement a 24-month fuel cycle and adopt TS Task Force (TSTF) Traveler TSTF-493, Revision 4, "Clarify Application of Setpoint Methodology for LSSS [Limiting Safety System Settings] Functions," Option A.

Specifically, the amendment revises certain TS Surveillance Requirement frequencies that are specified as "18 months" by changing them to "24 months" in accordance with the guidance provided in NRC Generic Letter 91-04, "Changes in Technical Specification Surveillance Intervals to Accommodate a 24-Month Fuel Cycle."

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, c(~ect Plant Licensing Branch IV Manager Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-298

Enclosures:

1. Amendment No. 242 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. 242 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 September 16, 2011, as supplemented by letters dated May 2, May 24, and September 17, 2012, 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 licens,e 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. 242, 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 Michael T. Markley, Chief Plant licensing Branch IV 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: September 28,2012

ATTACHMENT TO LICENSE AMENDMENT NO. 242 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 3 3 Technical Specifications REMOVE INSERT REMOVE INSERT 3.1-22 3.1-22 3.3.68 3.3.68 3.1-26 3.1-26 3.4-7 3.4-7 3.3-5 3.3-5 3.5-5 3.5-5 3.3-6 3.3-6 3.5-6 3.5-6 3.3-7 3.3-7 3.5-10 3.5-10 3.3-8 3.3-8 3.5-12 3.5-12 3.3-12 3.3-12 3.5-13 3.5-13 3.3-18 3.3-18 3.6-2 3.6-2 3.3-19 3.3-19 3.6-14 3.6-14 3.3-21 3.3-21 3.6-15 3.6-15 3.3-24 3.3-24 3.6-19 3.6-19 3.3-27 3.3-27 3.6-22 3.6-22 3.3-30 3.3-30 3.6-24 3.6-24 3.3-36 3.3-36 3.6-33 3.6-33 3.3-37 3.3-37 3.6-37 3.6-37 3.3-38 3.3-38 3.6-40 3.6-40 3.3-39 3.3-39 3.7-5 3.7-5 3.3-40 3.3-40 3.7-7 3.7-7 3.3-41 3.3-41 3.7-10 3.7-10 3.3-42 3.3-42 3.7-15 3.7-15 3.3-45 3.3-45 3.8-7 3.8-7 3.3-46 3.3-46 3.8-8 3.8-8 3.3-50 3.3-50 3.8-9 3.8-9 3.3-56 3.3-56 3.8-17 3.8-17 3.3-59 3.3-59 3.8-18 3.8-18 3.3-60 3.3-60 5.0-7 5.0-7 3.3-62 3.3-62 5.0-11 5.0-11 3.3-65 3.3-65 5.0-18 5.0-18

-3 (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. 242, 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.

(4) Fire Protection The licensee shall implement and maintain in effect all provisions of the approved fire protection program as described in the Cooper Nuclear Station (CNS) Updated Safety Analysis Report and as approved in the Safety Evaluations dated November 29,1977; May 23,1979; November 21,1980; April 29, 1983; April 16, 1984; June 1,1984; January 3,1985; August 21,1985; April 10, 1986; September 9, 1986; November 7, 1988; February 3,1989; August 15,1995; and July 31, 1998, subject to the following provision:

The licensee may make changes to the approved fire protection program without prior approval of the Commission only if those changes would not adversely affect the ability to achieve and maintain safe shutdown in the event of a fire.

Amendment No. 242

SLC System 3.1.7 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.1.7.6 Verify each SLC subsystem manual valve in the flow 31 days path that is not locked, sealed, or otherwise secured in positior:l, is in the correct position or can be aligned to the correct position.

SR 3.1.7.7 Verify each pump develops a flow rate> 38.2 gpm at In accordance a discharge pressure ~ 1300 psig. with the Inservice Testing Program SR 3.1.7.8 Verify flow through one SLC subsystem from pump 24 months on a into reactor pressure vessel. STAGGERED TEST BASIS SR 3.1.7.9 Verify all heat traced piping between 24 months storage tank and pump suction is unblocked.

Once within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after solution temperature is restored within the limits of Figure 3.1.7-2 Cooper 3.1-22 Amendment No. 242

SDV Vent and Drain Valves 3.1.8 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.1.8.1 -------------------------------N()TE------------------------------

Not required to be met on vent and drain valves closed during performance of SR 3.1.8.2.

Verify each SDV vent and drain valve is open. 31 days SR 3.1.8.2 Cycle each SDV vent and drain valve to the fully 92 days closed and fully open position.

SR 3.1.8.3 Verify each SDV vent and drain valve: 24 months

a. Closes in ~ 30 seconds after receipt of an actual or simulated scram signal; and

b. ()pens when the actual or simulated scram signal is reset.

Cooper 3.1-26 Amendment No. 242

RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.3.1.1.11 Perform CHANNEL FUNCTIONAL TEST. 24 months SR 3.3.1.1.12 ----------------------------N OTE S------------------------

1. Neutron detectors are excluded.

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

Perform CHANNEL CALIBRATION. 24 months SR 3.3.1.1.13 Perform LOGIC SYSTEM FUNCTIONAL TEST. 24 months SR 3.3.1.1.14 Verify Turbine Stop Valve Closure and Turbine 24 months Control Valve Fast Closure, Trip Oil Pressure Low Functions are not bypassed when THERMAL POWER is? 29.5% RTP.

SR 3.3.1.1.15 ---------------------------NOTE-------------------------

Neutron detectors are excluded.

Verify the RPS RESPONSE TIME is within limits. 24 months Cooper 3.3-5 Amendment No. 242

RPS Instrumentation 3.3.1.1 Table 3.3.1.1-1 (page 1 of 3)

Reactor Protection System Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED OTHER CHANNELS FROM SPECIFIED PER TRIP REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS SYSTEM ACTION 0.1 REQUIREMENTS VALUE Intermediate Range Monitors

a. Neutron 2 3 G SR 3.3.1 .1.1 -:: 121/125 Flux - High SR 3.3113 divisions of full SR 3.3.11.4 scale SR 331.15 SR 3.3.1 16 SR 3.311.12(a,b)

SR 3.311.13 SR 33.11.15 3 H SR 3.3.1.1.1 < 1211125 SR 33.1 1 3 divisions of full SR 331 14 scale SR 3.3 1 1 12(a.b)

SR 33.1113 SR 33.1.1.15

b. Inop 2 3 G SR 3.3.1.1.3 NA SR 331.14 SR 3.31 1 13 5(c) 3 H SR 3.3.1.1.3 NA SR 3.31.1.4 SR 3.3.1.1.13

2. Average Power Range Monitors

a. Neutron 2 2 G SR 3.3.1.1.1 -:: 14.5% RTP Flux High SR 3.3.11.3 (Startup) SR 3.3.1.1.4 SR 3.3.1.1.6 SR 3.3.11.8 SR 3.31110(a,b)

SR 3.3.11.13 SR 3.3.1.1.15

b. Neutron 2 F SR 33.1.1.1 < 0.75 W Flux-High (Flow SR 3.3.1.12 :; 62.0%

Biased) SR 3.3.1.1.4 RTP(d)

SR 33.1 1 7 SR 331 18 SR 3.3119 ( b)

SR 331110tb)

SR 3.3.1.1.12 a, SR 3.3.1.1 13 SR 3.3.1.1.15 (continued)

(a) 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.

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

(c) With any control rod withdrawn from a core cell containing one or more fuel assemblies (d) [0.75 W + 62.0% - 0.75 t:.W] RTP when reset for single loop operation per LCO 3.4.1, "Recirculation Loops Operating."

Cooper 3.3-6 Amendment No. 242

RPS Instrumentation 3.3.1.1 Table 3.3.1.1-1 (page 2 of 3)

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

2. Average Power Range Monitors (continued)

c. Neutron Flux 2 F SR 3.3.1.1.1 ~ 120.0% RTP High (Fixed) SR 3.3.1.1.2 SR 3.3.1.1.4 SR 3.3.1.1.8 SR 3.3.1.1.9 b)

SR 3.3.1.1.1 o(a, SR 3.3.1.1.13 SR 3.3.1.1.15 d, Downscale 2 F SR 3.3.1.1.4 ,::3.0%RTP SR 3.3.1,1.8( b)

SR 3.3.1.1.9 a, SR 3.3.1.1.13

e. Inop 1,2 2 G SR 3.3.1.1.4 NA SR 3.3.1.1.8 SR 3.3.1,1.9 SR 3.3.1.1.13

3. Reactor Vessel 1.2 2 G SR 3.3.1.1.4 ~ 1050 pSig Pressure High SR 3.3.1.1.9 ( b)

SR 3.3.1.1.12 a, SR 3,3.1.1.13 SR 3.3.1.1.15

4. Reactor Vessel Water 1,2 2 G SR 3.3.1.1.1 ,::3 inches Level Low (Level 3) SR 3.3.1,1.4 SR 3.3.1.1.9 ( b)

SR 3.3,1.1.12 a, SR 3.3.1,1.13 SR 3,3.1.1.15

5. Main Steam Isolation 4 F SR 3.3.1.1.4 ~ 10% closed Valve - Closure SR 3.3.1.1.9 SR 3.3.1.1.12 SR 3.3.1.1.13 SR 3.3.1.1.15

6. Drywall 1,2 2 G SR 3.3.1.1.4 ~ 1.84 psig Pressure High SR 3.3.1.1.9 ( b)

SR 3.3.1.1.12 a, SR 3.3.1.1.13 SR 3.3.1.1.15 (continued)

(a) If the as-found channel selpoint 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.

(b) The instrument channel setpoint shall be reset to a value that is within the as-left tolerance around the Limiting Trip Setpolnt (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 selpoint implemenled in Ihe Surveillance procedures (Nominal Trip Setpoint) to confirm channel performance. The Limiting Trip Selpoint and the methOdologies used to determine the as-found and the as-left tolerances are specified in the Technical Requjreme,nts Manual.

Cooper 3.3-7 Amendment No. 242

RPS Instrumentation 3.3.1.1 Table .3.3.1.1-1 (page 3 of 3)

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

7. Scram Discharge Volume Water Level - High

a. Level Transmitter 1,2 2 G SR 3.3.1.1.4 ~ 90 inches SR 3.3.1.1.9 SR 3.3.1.1.12(a,b)

SR 3.3.1.1.13 SR 3.3.1.1.15 s(c) 2 H SR 3.3.1.1.4 < 90 inches SR 3.3.1.1.9 SR 3.3.1.1.12 SR 3.3.1.1.13 SR 3.3.1.1.15

b. Level Switch 1,2 2 G SR 3.3.1.1.4 :::.90 inches SR 3.3.1.1.9 SR 3.3.1.1.12 SR 3.3.1.1.13 SR 3.3.1.1.15 5(c) 2 H SR 3.3.1.1.4 :::. 90 inches SR 3.3.1.1.9 SR 3.3.1.1.12 SR 3.3.1.1.13 SR 3.3.1.1.15

8. Turbine Stop ~29.5%RTP 2 E SR 3.3.1.1.4 ::.10% closed Valve Closure SR 3.3.1.1.9 SR 3.3.1.1.12 SR 3.3.1.1.13 SR 3.3.1.1.14 SR 3.3.1.1.15

9. Turbine Control ValVe ~29.5% RTP 2 E SR 3.3.1.1.4 ~ 1018 psig Fast Closure, DEH SR 3.3.1.1.9 ( b)

Trip Oil SR 3.3.1.1.12 a, Pressure Low SR 3.3.1.1.13 SR 3.3.1.1.14 SR 3.3.1.1.15

10. Reactor Mode 1,2 G SR 3.3.1.1.11 NA Switch Shutdown SR 3.3.1.1.13 Position S(c) H SR 3.3.1.1.11 NA SR 3.3.1.1.13

11. Manual Scram 1,2 G SR 3.3.1.1.9 NA SR 3.3.1.1.13 5(c) H SR 3.3.1.1.9 NA SR 3.3.1.1.13 (a) If the as-found channel setpoint is outside its predefined as-found tolerance, then the channel shall be evaluated to verify thai it is functioning as required before returning the channel to service.

(b) The instrument channel selpoint 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-fourJd and as-left tolerances apply to the actual setpoinl implemented in the Surveillance procedures (Nominal Trip Selpoint) 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.

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

Cooper 3.3-8 Amendment No. 242

SRM Instrumentation 3.3.1.2 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.3.1.2.4 ------------------------------N()-rE---------------------------

Not required to be met with less than or equal to four fuel assemblies adjacent to the SRM and no other fuel assemblies in the associated core quadrant.

Verify count rate is?: 3.0 cps with a signal to noise 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months during ratio?: 2: 1. C()RE ALTERATI()NS 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months SR 3.3.1.2.5 Perform CHANNEL FUNCTI()NAL TEST and 7 days determination of signal to noise ratio.

SR 3.3.1.2.6 ------------------------------N()TE---------------------------

Not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after IRMs on Range 2 or below.

Perform CHANNEL FUNCTI()NAL TEST and 31 days determination of signal to noise ratio.

SR 3.3.1.2.7 ---------------------------N()TES-----------------------------

1. Neutron detectors are excluded.

2. Not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after IRMs on Range 2 or below.

Perform CHANNEL CALIBRATI()N. 24 months Cooper 3.3-12 Amendment No. 242

Control Rod Block Instrumentation 3.3.2.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.3.2.1.5 ----------------------------N()TE-----------------7-----------

Neutron detectors are excluded.

Perform CHANNEL CALIBRATI()N. 184 days SR 3.3.2.1.6 Verify the RWM is not bypassed when THERMAL 24. months P()WER is < 9.85% RTP.

SR 3.3.2.1.7 -----------------------------N()TE----------------------------

Not required to be performed until 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months after reactor mode switch is in the shutdown position.

Perform CHANNEL FUNCTI()NAL TEST. 24 months SR 3.3.2.1.8 Verify control rod sequences input to the RWM are Prior to declaring in conformance with BPWS. RWM ()PERABLE following loading of sequence into RWM Cooper 3.3-18 Amendment No. 242

Control Rod Block Instrumentation 3.3.2.1 Table 3.3.2.1-1 (page 1 of 1)

Control Rod Block Instrumentation APPLICABLE MODES OR OTHER SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS CHANNELS REQUIREMENTS VALUE

1. Rod Block Monitor a: Low Power Range Upscale (a) 2 SR 3.3.2.1.1 (j)

SR 3.3.2.1.4(b)( )

SR 3.3.2.1.5 c

b. Intermediate Power Range Upscale (d) 2 SR 3.3.2.1.1 (j)

SR 3.3.2.1.4(b)( )

SR 3.3.2.1.5 c

e. High Power Range - Upscale (e).(f) 2 SR 3.3.2.1.1 0)

SR 3.3.2.1.4 SR 3.3.2.1.5(b)(c)

d. Inop (f).(g) 2 SR 3.3.2.1.1 NA

e. Downscale (f). (g) 2 SR 3.3.2.1.1 ~ 921125 SR 3.3.2.1.5 divisions of full scale

2. Rod Worth Minimizer SR 3.3.2.1.2 NA SR 3.3.2.1.3 SR 3.3.2.1.6 SR 3.3.2.1.8

3. Reactor Mode Switch - Shutdown Position (i) 2 SR 3.3.2.1.7 NA (a) THERMAL POWER ~ 27.5% and < 62.5% RTP and MCPR < 1.70 and no peripheral control rod selected.

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

(e) The instrument channel setpoint shall be reset to a value that is within the as-left tolerance around the Umiting Trip Setpoint (L TSP) 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 Umiting Trip Setpoint and the methodologies used to determine the as-found and the as-left tolerances are specified in the Technical Requirements Manual.

(d) THERMAL POWER ~ 62.5% and < 82.5% RTP and MCPR < 1.70 and no peripheral control rod selected.

(e) THERMAL POWER ~ 82.5% and < 90% RTP and MCPR < 1.70 and no peripheral control rod selected.

(f) THERMAL POWER ~ 90% RTP and MCPR < 1.40 and no peripheral control rod selected.

(g) THERMAL POWER ~ 27.5% and < 90% RTP and MCPR <: 1.70 and no peripheral control rod selected.

(h) With THERMAL POWER:: 9.85 RTP.

(i) Reactor mode switch in the shutdown position.

(j) Less than or equal to the Allowable Value specified in the COLR.

Cooper 3.3-19 Amenqment No. 242

Feedwater and Main Turbine High Water Level Trip Instrumentation 3.3.2.2 SURVEILLANCE REQUIREMENTS

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

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

SURVEILLANCE FREQUENCY SR 3.3.2.2.1 Perfonn CHANNEL CHECK. 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months SR 3.3.2.2.2 Perform CHANNEL CALIBRATION. The Allowable 24 months Value shall be ~ 54.0 inches.

SR 3.3.2.2.3 Perform LOGIC SYSTEM FUNCTIONAL TEST 24 months including valve actuation.

Cooper 3.3-21 Amendment No. 242

PAM Instrumentation 3.3.3.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.3.1.1 Perform CHANNEL CHECK on each required PAM 31 days Instrumentation channel.

SR 3.3.3.1.2 Perform CHANNEL CALIBRATION of the Primary 92 days Containment H2 and O2 Analyzers.

. SR 3.3.3.1.3 Perform CHANNEL CALIBRATION of each 24 months required PAM Instrumentation channel except for the Primary Containment H2 and O2 Analyzers.

Cooper 3.3-24 Amendment No. 242

Alternate Shutdown System 3.3.3.2 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.3.3.2.2 Verify each required control circuit and transfer 24 months switch is capable of performing the intended function.

SR 3.3.3.2.3 Perform CHANNEL CALIBRATION for each 24 months required instrumentation channel.

Cooper 3.3-27 Amendment No. 242

ATWS-RPT Instrumentation 3.3.4.1 SURVEILLANCE REQUIREMENTS

NOTE-:..----------------------------------------------------

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

SURVEILLANCE FREQUENCY SR 3.3.4.1.1 Perform CHANNEL FUNCTIONAL TEST. 92 days SR 3.3.4.1.2 Perform CHANNEL CALIBRATION. The Allowable 24 months Values shall be:

a. Reactor Vessel Water Level Low Low (Level 2): ::: -42 inches; and

b. Reactor Pressure High: < 1072 psig.

SR 3.3.4.1.3 Perform LOGIC SYSTEM FUNCTIONAL TEST 24 months including breaker actuation.

Cooper 3.3-30 Amendment No. 242

ECCS Instrumentation 3.3.5.1 SURVEILLANCE REQUIREMENTS

~-------~-~-------~-----------------~------------NOTES---------------------------------------------------

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

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

SURVEILLANCE FREQUENCY SR 3.3.5.1.1 Perform CHANNEL CHECK. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.3.5.1.2 Perform CHANNEL FUNCTIONAL TEST. 92 days SR 3.3.5.1.3 Perform CHANNEL CALIBRATION. 92 days SR 3.3.5.1.4 Perform CHANNEL CALIBRATION. 24 months SR 3.3.5.1.5 Perform LOGIC SYSTEM FUNCTIONAL TEST. 24 months Cooper 3.3-36 Amendment No. 242

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

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

1. Core Spray System

a. Reactor Vessel 1.2.3. 4(b) B SR 3.3.5.1.1 .:! -113 inches Water Level - Low SR 3.3.5.1.2( (

Low Low (Level 1) 4(a), 5(a) SR 3.3.5.1.4 c) d)

SR 3.3.5.1.5

b. Drywell Pressure- 1,2.3 4(b) B ~ 1.84 psig SR 3.35.1.2(C)(d)

High SR 3.3.5.1.4 SR 3.3.5.1.5

c. Reactor Pressure- 1,2,3 4 C SR 3.3.5.1.2 ::: 291 psig and low (injection SR 3.35.1.4 Permissive) SR 3.3.5.1.5 ~ 436 psig 4(a).5(a) 4 B SR 3.3.5.1.2 ::: 291 psig and SR 3.3.5.1.4 SR 3.3.5.1.5 :::. 436 psig d, Core Spray Pump 1,2,3, 1 per pump E SR 3,35,1.2( )(d) .:! 1370 gpm Discharge Flow - SR 3.3.5.1.4 c Low 4(a),5(a) SR 3.3.5.1.5 (Bypass)

e. Core Spray Pump 1.2,3, 1 per pump C SR 3,3.5.1.2 > 9 seconds Start-Time Delay SR 3.3.5.1.4 and Relay 4(a),5(a) SR 3.3.5.1,5 ~ 11 seconds

2. Low Pressure Coolant Injection (LPCI) System

a. Reactor Vessel 4 B SR 3,3.5.1.1 ::: -113 inches Water Level - Low SR 3,3.5.1.2( ltd)

Low Low (l.evell) SR 3.3.5.1.4 c SR 3.3.5,1.5 (continued)

(a) When associated ECCS subsystem(s) are required to be OPERABLE per LCO 3.5.2. ECCS - Shutdown.

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

(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 selpolnt shall be resel 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 Selpoint) 10 confirm channel performance. The Limiting Trip Selpoinl and the methodologies used to determine the as-found and the as-left tolerances are specified in the Technical Requirements Manual.

Cooper 3.3-37 Amendment No. 242

ECCS Instrumentation 3.3.5.1 Table 3.3.5.1-1 (page 2 of 6)

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

2. LPCI System (continued) 1,2,3 4 B SR 3.3.5.1.2(C)(d) .:: 1.84 psig

b. Drywell Pressure - SR 3.3.5.1.4 High SR 3.3.5.1.5

c. Reactor Pressure , 1,2,3 4 C SR 3.3.5.1.2 .:: 291 psig and Low (Injection SR 3.3.5.1.4 Permissive) SR 3.3.5.1.5 .:: 436 psig 4 B SR 3.3.5.1.2 ::: 291 psig and SR 3.3.5.1.4 SR 3.3.5.1.5 .:: 436 psig

d. Reactor Pressure - 4 C SR 3.3.5.1.2 .:: 199 psig and Low (Recirculation SR 3.3.5.1.4 .s 246 psig Discharge Valve SR 3.3.5.1.5 Permissive)

e. Reactor Vessel 1,2,3 2 B SR 3.3.5.1.1 ~-193.19 Shroud Level - SR 3.3.5.1.2 inches Level 0 SR 3.3.5.1.4 SR 3.3.5.1.5

f. Low Pressure 1 per pump C SR 3.3.5.1.2 Coolant Injection SR 3.3.5.1.4 Pump Start -Time SR 3.3.5.1.5 Delay Relay Pumps B,C ::: 4.5 seconds and

.:: 5.5 seconds PumpsA,D .:: 0.5 second (continued)

(a) When associated ECCS subsyslem(s) are required to be OPERABLE per LCO 3.5.2, ECCS - Shutdown.

(c) If the as-found channel selpoint 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 setpolnt 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 setpolnt implemented in the Surveillance procedures (Nominal Trip Setpolnt) to confirm channel performance. The Limiting Trip Setpolnt and the methodologies used to determine the as-found and the as-left tolerances are specified in the Technical Requirements Manual.

(el With associated recirculation pump discharge valve open.

Cooper 3.3-38 Amendment No. 242

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) 1,2,3, 1 per E SR 3.3.5.1.2 ( led) ~2107 gpm

g. Low Pressure subsystem SR 3.3.5.1.4 c Coofant Injection 4(a), 5(a) SR 3.3.5.1.5 Pump Discharge Flow-low (Bypass)

3. High Pressure Coolant Injection (HPCI) System

a. Reactor Vessel 1, 4 B SR 3.3.5.1.1 ~ -42 inches Water Level - Low SR 3.3.5.1.2 ( led)

Low (Level 2) 2(t). 3(t) SR 3.3.5.1.4 c SR 3.3.5.1.5

b. Drywell Pressure - 1, 4 B SR 3.3.5.1.2 led) .'!: 1.84 psig High SR 3.3.5.1.4(c 2lt},3 lt} SR 3.3.5.1.5

c. Reactor Vessel 1, 2 C SR 3.3.5.1.1 :=.54 inches Water Level - High SR 3.3.5.1.2 (LevelS) 2(t), 3(t) SR 3.3.5.1.4 SR 3.3.5.1.5

d. Emergency 1, 2 D SR 3.3.5.1.2 .:!:23 inches Condensate SR 3.3.5.1.3 Storage Tank 2(t), 3(t) SR 3.3.5.1,5 (ECST) Level low

e. Suppression Pool 1, 2 D SR 3.3.5.1.2 :=.4 inches Water Level - High SR 3.3.5.1.4 2(t), 3(t) SR 3.3.51.5 (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 setpeint shall be reset to a value that is within the as-left tolerance around the Limiting Trip Setpoint (L TSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable. Setpoinls 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 Selpoin!) 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.

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

Cooper 3.3-39 Amendment No. 242

ECCS In~trumentation 3.3.5.1 Table 3.3.5.1-1 (page 4 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

3. HPCI System (Continued)

1. E SR 3.3.5.1.2( (d) ::.490gpm

f. High Pressure SR 3.3.5.1.4 c)

Coolant injection 2(f). 3(f) SR 3.3.5.1.5 Pump Discharge Flow- Low

. (Bypass)

4. Automatic Depressurization System (ADS) Trip System A 1. 2 F SR 3.3.5.1.1 > -113 SR 3.3.5.1.2( led) Inches

a. Reactor Vessel 2(f).3(f) SR 3.3.5.1.4 c Water Level - Low SR 3.3.5.1.5 Low Low (Level 1)

b. Automatic 1, G SR 3.3.5.1.2 .::. 109 seconds Depressurization SR 3.3.5.1.4 System Initiation 2(f). 3(f) SR 3.3.5.1.5 Timer

c. Reactor Vessel 1, F SR 3.3.5.1.1 ~3 inches Water Level-low SR 3.3.5.1.2( led)

(Level 3) 2(f), 3(f) SR 3.3.5.1.4 c (Confirmatory) SR 3.3.5.1.5

d. Core Spray Pump 1, 2 G SR 3.3.5.1.2 ~ 108 psig and Discharge SR 3.3.5.1.4 ~ 160 pSig Pressure- High 2(f).3(f) SR 3.3.5.1.5 (continued)

(c) If the as-found channel selpolnt 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 setpolnt shatl be reset to a value that is within the as-left tolerance around the Limiting Trip Setpoint (LTSP) at the completion of the surveillance; othelWlse. the channel shall be declared inoperable. Setpoints more conservative than the l TSP 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 stearn dome pressure> 150 psig.

Cooper 3.3-40 Amendment No. 242

ECCS Instrumentation 3.3.5-1 Table 3.3.5.1-1 (page 5 of 6)

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

4. ADS Trip System A (continued)

e. Low Pressure 1, 4 G SR 3.3.5.1.2 ~ 10S psig and Coolant Injection SR 3.3.5.1.4 :: 160 pSig Pump Discharge 2(f). 3(f) SR 3.3.5.1.5 Pressure - High

5. ADS Trip System B

a. Reactor Vessel 1. 2 F SR 3.3.5.1.1 .=::. -113 inches Water Level - Low SR 3.3.5.1.2( )(d)

Low Low (Level 1) 2(t), 3(t) SR 3.3.5.1.4 c SR 3.3.5.1.5

b. Automatic 1, G SR 3.3.5.1.2 :::: 109 seconds Depressurization SR 3.3.5.1.4 System Initiation 2(t), 3(t) SR 3.3.5.1.5 Timer

c. Reactor Vessel F SR 3.3.5.1.1 !3inches Water Level - Low. " SR 3.3.5.1.2( )(d)

Level 3 2(f), 3(f) SR 3.3.5.1.4 c (Confirmatory) SR 3.3.5.1.5

d. Core Spray Pump 1, 2 G SR 3.3.5.1.2 !. 10S psig and Discharge SR 3.3.5.1.4 :: 160 psig Pressure High 2(f), 3(t) SR 3.3.5.1.5 (continued)

(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 Setpaint) 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.

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

Cooper 3.3-41 Amendment No. 242

ECCS Instrumentation 3.3.5.1 Table 3.3.5.1-1 (page 6 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

5. ADS Trip System B (continued)

e. Low Pressure 4 G SR 3.3.5.1.2 ?: 108 psig and Coolant Injection SR 3.3.5.1.4 ~ 160 psig Pump Discharge SR 3.3.5.1.5 Pressure - High (f) With reactor steam dome pressure> 150 psig.

Cooper 3.3-42 Amendment No. 242

RCIC System Instrumentation 3.3.5.2 SURVEILLANCE REQUIREMENTS

NOTE S-------------------------------------------------

1. .'Refer to Table 3.3.5.2-1 to determine which SRs apply for each RCIC Function.

2. When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed as follows: (a) for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months for Function 2; and (b) for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months for Functions 1 and 3 provided the associated Function maintains RCIC initiation capability.

SURVEILLANCE FREQUENCY SR 3.3.5.2.1 Perform CHANNEL CHECK. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.3.5.2.2 Perform CHANNEL FUNCTIONAL TEST. 92 days SR 3.3.5.2.3 Perform CHANNEL CALIBRATION. 92 days SR 3.3.5.2.4 Perform CHANNEL CALIBRATION. 24 months SR 3.3.5.2.5 Perform LOGIC SYSTEM FUNCTIONAL TEST. 24 months Cooper 3.3-45 Amendment No. 242

RCtC System Instrumentation 3.3.5.2 Table 3.3.5.2-1 (page 1 of 1)

Reactor Core isolation Cooling System Instrumentation CONDITIONS REQUIRED REFERENCED CHANNELS FROM REQUIRED SURVEILLANCE ALLOWABLE FUNCTION PER FUNCTION ACTIONA.1 REQUIREMENTS VALUE

1. Reactor Vessel Water 4 B SR 3,3.5.2.1 ~ -42 inches Level - Low Low (Level 2) SR 3.3.5.2.2( )(b)

SR 3,3.5,2.4 a SR 3.3.5.2.5 2, Reactor Vessel Water 2 C SR 3.3.5.2.1 !: 54 inches Level - High (level 8) SR 3.3.5.2.2 SR 3.3.5.2.4 SR 3.3.5.2.5

3. Emergency Condensate 2 D SR 3.3.5.2.2 ? 23 inches Storage Tank (ECSn SR 3.3.5.2.3 Level- Low SR 3.3.5.2.5 (a) 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.

(b) 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 Selpoinl) to confirm channel performance. The Limiting Trip Selpoint and the methodologies used to determine the as-found and the as-left tolerances are specified in the Technical Requirements Manual, Cooper 3.3-46 Amendment No. 242

Primary Containment Isolation Instrumentation 3.3.6.1 SURVEILLANCE REQUIREMENTS

N()TES----------.---------------------------------------------

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

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

SURVEILLANCE FREQUENCY SR 3.3.6.1.1 Perform CHANNEL CHECK. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.3.6.1.2 Perform CHANNEL FUNCTI()NAL TEST. 92 days SR 3.3.6.1.3 Perform CHANNEL CALIBRATI()N. 92 days SR 3.3.6.1.4 ----------------------------N()TE-----------------------------

For Function 2.d, radiation detectors are excluded.

Perform CHANNEL CALIBRATI()N. 24 months SR 3.3.6.1.5 Calibrate each radiation detector. 24 months SR 3.3.6.1.6 Perform L()GIC SYSTEM FUNCTI()NAL TEST. 24 months Cooper 3.3-50 Amendment No. 242

Secondary Containment Isolation Instrumentation 3.3.6.2 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.3.6.2.2 Perform CHANNEL FUNCTIONAL TEST. 92 days SR 3.3.6.2.3 Perform CHANNEL CALIBRATION. 24 months SR 3.3.6.2.4 Perform LOGIC SYSTEM FUNCTIONAL TEST. 24 months Cooper 3.3-56 Amendment No. 242

LLS Instrumentation 3.3.6.3 SURVEILLANCE REQUIREMENTS

N()TES--------------------------------------------------------

1. Refer to Table 3.3.6.3-1 to determine which SRs apply for each Function.

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

SURVEILLANCE FREQUENCY SR 3.3.6.3.1 Perform CHANNEL FUNCTI()NAL TEST for 92 days portion of the channel outside primary containment.

SR 3.3.6.3.2 ----------------N()TE------------------

()nly required to be performed prior to entering M()DE 2 during each scheduled outage> 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months when entry is made into primary containment.

Perform CHANNEL FUNCTI()NAL TEST for 92 days portions of the channel inside primary containment.

SR 3.3.6.3.3 Perform CHANNEL FUNCTI()NAL TEST. 92 days SR 3.3.6.3.4 Perform CHANNEL CALIBRATI()N. 24 months

. SR 3.3.6.3.5 Perform L()GIC SYSTEM FUNCTI()NAL TEST. 24 months Cooper 3.3-59 Amendment No. 242

LLS Instrumentation 3.3.6.3 Table 3.3.6.3-1 (page 1 of 1)

Low-Low Set Instrumentation REQUIRED CHANNELS PER SURVEILLANCE ALLOWABLE FUNCTION FUNCTION REQUIREMENTS VALUE

1. Reactor Pressure - High 1 per LLS valve SR 3.3.6.3.3 ~ 1050 psig SR 3.3.6.3.4 SR 3.3.6.3.5

2. Low-Low Set Pressure Setpoints 2 per LLS valve SR 3.3.6.3.3 Low:

SR 3.3.6.3.4 Open.:: 996.5 psig SR 3.3.6.3.5 and ~ 1010 psig Close .:: 835 psig and ~ 875.5 psig High:

Open.:: 996.5 psig and ~ 1040 psig Close .:: 835 psig and ~ 875.5 psig

3. Discharge Line Pressure Switch 1 perSRV SR 3.3.6.3.1 .::25 psig and ~ 55 psig SR 3.3.6.3.2 SR 3.3.6.3.4 SR 3.3.6.3.5 Cooper 3.3-60 Amendment No. 242

CREF System Instrumentation 3.3.7.1 SURVEILLANCE REQUIREMENTS

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

1. Refer to Table 3.3.7.1-1 to determine which SRs apply for each CREF Function.

2. When a channel is placed in an inoperable status solely for performance of required

.Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months provided the associated Function maintains CREF initiation capability.

SURVEILLANCE FREQUENCY SR 3.3.7.1.1 Perform CHANNEL CHECK. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.3.7.1.2 Perform CHANNEL FUNCTIONAL TEST. 92 days SR 3.3.7.1.3 Perform CHANNEL CALIBRATION. 24 months SR 3.3.7.1.4 Perform LOGIC SYSTEM FUNCTIONAL TEST. 24 months Cooper 3.3-62 Amendment No. 242

LOP Instrumentation 3.3.8.1 SURVEILLANCE REQUIREMENTS

.----NOTES------------------------------------------------

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

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

SURVEILLANCE I I ,EQUENCY SR 3.3.8.1.1 Perform CHANNEL FUNCTIONAL TEST. 31 days SR 3.3.8.1.2 Perform CHANNEL CALIBRATION. 24 months SR 3.3.8.1.3 Perform LOGIC SYSTEM FUNCTIONAL TEST. 24 months Cooper 3.3-65 Amendment No. 242

RPS Electric Power Monitoring 3.3.8.2 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME D. Required Action and D.1 Initiate action to fully insert Immediately associated Completion all insertabJe control rods Time of Condition A in core cells containing or B not met in MODE 5 one or more fuel with any control rod assemblies.

withdrawn from a core cell containing one or more fuel assemblies.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.8.2.1 Perform CHANNEL CALIBRATION. The Allowable 24 months Values shall be:

a. Overvoltage ~ 131 V with time delay set to

-::.3.8 seconds.

b. Undervoltage.::: 109 V, with time delay set to

.::: 3.8 seconds.

c. Underfrequency.::: 57.2 Hz, with time delay set to :c::: 3.8 seconds.

I SR 3.3.8.2.2 Perform a system functional test. ! 24 months Cooper 3.3-68 Amendment No. 242

SRVs and SVs 3.4.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.3.1 Verify the safety function lift setpoints of the SRVs In accordance and SVs are as follows: with the Inservice Testing Program Number of Setpoint SRVs (psig) 2 1080 +/- 32.4 3 1090 +/- 32.7 3 1100 +/- 33.0 Number of Setpoint SVs (psig) 3 1240 +/- 37.2 Following testing, lift settings shall be within +/- 1%.

SR 3.4.3.2 -----------------------------N OTE---------------------

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

Verify each SRV opens when manually actuated. 24 months Cooper 3.4-7 Amendment No. 242

ECCS - Operating 3.5.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.5.1.6 Verify the following ECCS pumps develop the specified In accordance flow rate against a system head corresponding to the with the specified reactor pressure. Inservice SYSTEM HEAD Testing NO. CORRESPONDING Program OF TO A REACTOR SYSTEM FLOW RATE PUMPS PRESSURE OF Core Spray ?: 4720 gpm 1 .?: 113 psig LPCI ?: 15,000 gpm 2 ?: 20 psig SR 3.5.1.7 -------------NOTE-----------------

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

Verify, with reactor pressure::: 1020 and?: 920 psig, the 92 days HPCI pump can develop a flow rate?: 4250 gpm against a system head corresponding to reactor pressure.

SR 3.5.1.8 ---------------------NOTE-----------------------

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

Verify, with reactor pressure::: 165 psig, the HPCI pump 24 months can develop a flow rate?: 4250 gpm against a system head corresponding to reactor pressure.

(continued)

Cooper 3.5-5 Amendment No. 242

ECCS - Operating 3.5.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.5.1.9 ---------------------------------NOT ES------------. --.-------------.

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

2. Vessel injection/spray may be excluded.

Verify each ECCS injection/spray subsystem actuates 24 months on an actual or simulated automatic initiation signal.

SR 3.5.1.10 ------. --------. -----------------NOT E-----------.-----------. -----

Valve actuation may be excluded.

Verify the ADS actuates on an actual or simulated 24 months automatic initiation signal.

SR 3.5.1.11 ---------------------------------NOTE-------------------------------

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

Verify each ADS valve opens when manually actuated. 24 months Cooper 3.5-6 Amendment No. 242

ECCS - Shutdown 3.5.2 FREQUENCY SR 3.5.2.4 Verify each required ECCS pump develops the specified In accordance flow rate against a system head corresponding to the with the specified reactor pressure. Inservice SYSTEM HEAD Testing NO. CORRESPONDING Program OF TO A REACTOR SYSTEM FLOW RATE PUMPS PRESSURE OF CS ~4720 gpm 1 ~ 113 psig LPCI > 7700gpm 1 ~ 20 psig SR 3.5.2.5 ---------------------------------NOTE-------------------------------

Vessel injection/spray may be excluded.

Verify each required ECCS injection/spray subsystem 24 months actuates on an actual or simulated automatic initiation signal.

Cooper Amendment No. 242

RCIC System 3.5.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.5.3.1 Verify the RCIC System piping is filled with water 31 days from the pump discharge valve to the injection valve.

SR 3.5.3.2 Verify each RCIC System manual, power operated, 31 days and automatic valve in the flow path, that is not locked, sealed, or otherwise secured in position, is in the correct position.

SR 3.5.3.3 -------------------------------N()TE------------------------------

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

Verify, with reactor pressure ~ 1020 psig and 92 days

~ 920 psig. the RCIC pump can develop a flow rate

~ 400 gpm against a system head corresponding to reactor pressure.

SR 3.5.3.4 -------------------------------N()TE------------------------------

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

Verify, with reactor pressure ~ 165 pSig, the RCIC 24 months pump can develop a flow rate ~ 400 gpm against a system head corresponding to reactor pressure ..

(continued)

Cooper 3.5-12 Amendment No. 242

RCIC System 3.5.3 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE I F=REQUENCY SR 3.5.3.5 ---------------------------------N()TES--------------------------

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

2. Vessel injection may be excluded.

Verify the RCIC System actuates on an actual or 24 months simulated automatic initiation signal.

Cooper 3.5-13 Amendment No. 242

Primary Containment 3.6~1.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.1.1.1 Perform required visual examinations and leakage In accordance rate testing except for primary containment air lock with the Primary testing. in accordance with the Primary Containment Containment Leakage Rate Testing Program. Leakage Rate Testing Program SR 3.6.1.1.2 Verify drywell to suppression chamber bypass 24 months leakage is equivalent to a hole < 1.0 inch in diameter.

.-----NOTE-------

Only required after two consecutive tests fail and continues until two consecutive tests pass 9 months Cooper 3.6-2 Amendment No. 242

PCIVs 3.6.1.3 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.6.1.3.6 Verify the isolation time of each MSIV is In accordance

> 3 seconds and ~ 5 seconds. with the Inservice Testing Program SR 3.6.1.3.7 Verify each automatic PCIV actuates to the 24 months isolation position on an actual or simulated isolation signal.

SR 3.6.1.3.8 Verify a representative sample of reactor 24 months instrumentation line EFCVs actuate to the isolation position on an actual or simulated instrument line break.

SR 3.6.1.3.9 Remove and test the explosive squib from each 24 months on a shear isolation valve of the TIP System. STAGGERED TEST BASIS SR 3.6.1.3.10 Verify leakage rate through each Main Steam line In accordance is.::: 106 scfh when tested at? 29 psig. with the Primary Containment Leakage Rate Testing Program (continued)

Cooper 3.6-14 Amendment No. 242

PCIVs 3.6.1.3 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.6.1.3.11 Verify each inboard 24 inch primary containment 24 months purge and vent valve is blocked to restrict the maximum valve opening angle to 60°.

SR 3.6.1.3.12 Verify leakage rate through the Main Steam In accordance Pathway is ::::. 212 seth when tested at ~ 29 psig. with the Primary Containment Leakage Rate Testing Program Cooper 3.6-15 Amendment No. 242

LLS Valves 3.6.1.6 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.1.6.1 -----------------------------NOTE-----------------------

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

Verify each LLS valve opens when manually 24 months actuated.

SR 3.6.1.6.2 ---------------------------NOTE--------------------------

Valve actuation may be excluded.

Verify the LLS System actuates on an actual or 24 months simulated automatic initiation signal.

Cooper 3.6-19 Amendment No. 242

Reactor Building-to-Suppression Chamber Vacuum Breakers 3.6.1.7 FREQUENCY SR 3.6.1.7.3 Verify the full open setpoint of each vacuum 24 months breaker is::: 0.5 psid.

Cooper 3.6-22 Amendment No. 242

Suppression Chamber-to-Drywell Vacuum Breakers 3.6.1.8 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.1.8.1 ------------------------------N()TE---------------------------

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

Verify each vacuum breaker is closed. 14 days SR 3.6.1.8.2 Perform a functional test of each required vacuum 31 days breaker.

SR 3.6.1.8.3 Verify the opening setpoint of each required 24 months vacuum breaker is < 0.5 psid.

Cooper 3.6-24 Amendment No. 242

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

> 0.25 inch of vacuum water gauge.

SR 3.6.4.1.2 Verify all secondary containment equipment 31 days hatches 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 24 months on a 2:: 0.25 inch of vacuum water gauge in the STAGGERED secondary containment for 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months at a flow rate TEST BASIS

1780 cfm.

Cooper 3.6~33 Amendment No. 242

SCIVs 3.6.4.2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.4.2.1 -----------------------------N()TES---------------------------

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 31 days manual 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 Inservice Testing Program SR 3.6.4.2.3 Verify each automatic SCIV actuates to the 24 months isolation position on an actual or simulated actuation signal.

Cooper 3.6-37 Amendment No. 242

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

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.4.3.1 Operate each SGT subsystem for? 1 0 continuous 31 days hours with heaters operating.

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

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

Cooper 3.6-40 Amendment No. 242

SW System and UHS 3.7.2 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.7.2.3 ---------------------------------N()1rE----------------------------

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

Verify each SW subsystem manual, power operated, 31 days and automatic valve in the flow paths servicing safety related systems or components, that is not locked, sealed, or otherwise secured in position, is in the correct position.

SR 3.7.2.4 Verify each SW subsystem actuates on an actual or 24 months simulated initiation signal.

Cooper 3.7-5 Amendment No. 242

REC System 3.7.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.3.1 -------------------------N0 TE S----------------------

1. SR 3.0.1 is not applicable when both Service Water backup subsystems are OPERABLE.

2. REC system leakage beyond limits by itself is only a degradation of the REC system and does not result in the REC system being inoperable.

Verify the REC system leakage is within limits. 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months SR 3.7.3.2 Verify the temperature of the REC supply water is 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months

< 100°F.

SR 3.7.3.3 -----------------------NOTE----------------------

Isolation of flow to individual components does not render REC System inoperable.

Verify each REC subsystem manual, power 31 days operated, and automatic valve in the flow paths servicing safety related cooling loads, that is not locked, sealed, or otherwise secured in position, is in the correct position.

SR 3.7.3.4 Verify each REC subsystem actuates on an 24 months actual or simulated initiation signal.

Cooper 3.7-7 Amendment No. 242

CREF System 3.7.4 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.4.1 Operate the CREF System for::: 15 minutes. 31 days SR 3.7.4.2 Perform required CREF filter testing in accordance In accordance with the Ventilation Filter Testing Program (VFTP). with the VFTP.

SR 3.7.4.3 Verify the CREF System actuates on an actual or 24 months simulated initiation signal.

SR 3.7.4.4 Perform required CRE unfiltered air inleakage testing In accordance in accordance with the Control Room Envelope with the Control Habitability Program. Room Envelope Habitability Program Cooper 3.7-10 Amendment No. 242

Main Turbine Bypass System 3.7.7 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.7.1 Verify operation of each main turbine bypass valve. 31 days SR 3.7.7.2 Perform a system functional test. 24 months SR 3.7.7.3 Verify the TURBINE BYPASS SYSTEM RESPONSE 24 months TIME is within limits.

Cooper 3.7-15 Amendment No. 242

AC Sources Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.8.1.7 -----------------------------NOTE-----------------------------

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

Verify each DG starts from standby condition and 184 days achieves, in .:! 14 seconds, voltage ~ 3950 V and frequency ~ 58.8 Hz, and after steady state conditions are reached, maintains voltage ~ 3950 V and.:! 4400 V and frequency ~ 58.8 Hz and.:! 61.2 Hz.

SR 3.8.1.8 -------------------------NOTE---------------------------

This Surveillance shall not be performed in MODE 1 or 2. However, credit may be taken for unplanned events that satisfy this SR Verify automatic and manual transfer of unit power 24 months supply from the normal offsite circuit to the alternate offsite circuit.

(continued)

Cooper 3.8-7 Amendment No. 242

AC Sources Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.8.1.9 --~-------~~---~----*---------~-NOTES --------------------------

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

2. This Surveillance shall not be performed in MODE 1 or 2. However, credit may be taken for unplanned events that satisfy this SR.

3. If performed with DG synchronized with offsite power, the surveillance shall be performed at a power factor .:5 0.89. However, jf grid conditions do not permit, the power factor limit is not required to be met. Under this condition the power factor shall be maintained as close to the limit as practicable.

Verify each DG operates for ~ 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months s: 24 months

a. For ~ 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months loaded ~ 4200 kW and .:5 4400 kW; and

b. For the remaining hours of the test loaded ~

3600 kW and.:5 4000 kW.

SR 3.8.1.10 --------------------------------NOTES --------------------------

This Surveillance shall not be performed in MODE 1, 2 or 3. However, credit may be taken for unplanned events that satisfy this SR.

Verify interval between each sequenced load is within 24 months

+/-. 10% of nominal timer setpoint.

(continued)

Cooper 3.8-8 Amendment No. 242

AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS continued)

S URVEI LLANCE FREQUENCY SR 3.8.1.11 -------------------------------N()TES----------------------------

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

2. This Surveillance shall not be performed in M()DE 1, 2, or 3. However, credit may be taken for unplanned events that satisfy this SR.

Verify, on an actual or simulated loss of offsite power 24 months signal in conjunction with an actual or simulated ECCS initiation signal:

a. De-energization of emergency buses;

b. Load shedding from emergency buses; and

c. DG auto-starts from standby condition and:

1. energizes permanently connected loads in < 14 seconds,

2. energizes auto-connected emergency loads through the timed logic sequence,

3. maintains steady state voltage:::. 3950 V and~4400V,

4. maintains steady state frequency:::. 58.8 Hz and ~ 61.2 Hz, and

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

. 5 minutes.

Cooper 3.8-9 Amendment No. 242

DC Sources - Operating 3.8.4 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.4.1 Verify battery terminal voltage on float charge is: 7 days

a. > 125.9 V for the 125 V batteries; and

b. ?:. 260.4 V for the 250 V batteries.

SR 3.8.4.2 Verify no visible corrosion at battery terminals and 92 days connectors.

Verify battery connection resistance meets the limits specified in Table 3.8.4-1.

SR 3.8.4.3 Verify battery cells, cell plates, and racks show no 18 months visual indication of physical damage or abnormal deterioration that degrades battery performance.

SR 3.8.4.4 Remove visible corrosion and verify battery cell to 18 months cell and terminal connections are coated with anti-corrosion material.

SR 3.8.4.5 Verify battery connection resistance meets the limits 18 months specified in Table 3.8.4-1.

SR 3.8.4.6 Verify: 24 months a Each required 125 V battery charger supplies>

200 amps at.:: 125 V for.:: 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months ; and

b. Each required 250 V battery charger supplies>

200 amps at .:: 250 V for? 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

(continued)

Cooper Amendment No. 242

DC Sources - Operating 3.8.4 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.8.4.7 --------------------------NOTES---------------------------

1. The modified performance discharge test in SR 3.8.4.8 may be performed in lieu of the service test in SR 3.8.4.7 once per 60 months.

2. This Surveillance shall not be performed in MODE 1, 2. or 3. However, credit may be taken for unplanned events that satisfy this SR.

Verify battery capacity is adequate to supply, and 24 months maintain in OPERABLE status, the required emergency loads for the design duty cycle when subjected to a battery service test.

SR 3.8.4.8 -----------------------------N()TE-----------------------------

This Surveillance shall not be performed in MODE 1, 2, or 3. However, credit may be taken for unplanned events that satisfy this SR.

Verify battery capacity is > 90% of the manufacturer's 60 months rating when subjected to a performance discharge test or a modified performance discharge test. AND 12 months when battery shows degradation or has reached 85%

of expected life with capacity

< 100% of manufacturer's rating 24 months when battery has reached 85% of the expected life with capacity

~ 100% of manufacturer's rating Cooper 3.8-18 Amendment No. 242

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.1 Offsite Dose Assessment Manual (ODAM) (continued) markings in the margin of the affected pages, clearly indicating the area of the page that was changed. and shall indicate the date (i.e., month and year) the change was implemented.

5.5.2 Systems Integrity Monitoring Program This program provides controls to minimize leakage from those portions of systems outside containment that could contain highly radioactive fluids during a serious transient or.accident to levels as low as practicable. The systems include the Core Spray. High Pressure Coolant Injection, Residual Heat Removal, and Reactor Core Isolation Cooling. The program shall include the following:

a. Preventive maintenance and periodic visual inspection requirements; and

b. Integrated leak test requirements for each system at 24 month intervals or less.

The provisions of SR 3.0.2 and SR 3.0.3 are applicable at the 24 month Frequency for performing system leak test activities.

5.5.3 Post Accident Sampling This program provides controls that ensure the capability to obtain and analyze reactor coolant, radioactive gases, and particulates in plant gaseous effluents and containment atmosphere samples under accident conditions. The program shall include the following:

a. Training of personnel;

b. Procedures for sampling and analysis; and

c. Provisions for maintenance of sampling and analysis equipment.

(continued)

Cooper 5.0-7 Amendment No. 242

Programs and Manuals 5.5 5.5 Programs and Manuals (continued) 5.5.7 Ventilation Filter Testing Program (VFTP)

The VFTP shall establish the required testing of Engineered Safety Feature (ESF) filter ventilation systems. Tests described in Specifications 5.5.7.a, 5.5.7.b, and 5.5.7.c shall be performed once per 24 months for standby service or after 720 hours0.00833 days 0.2 hours 0.00119 weeks 2.7396e-4 months of system operation; and, following significant painting, fire, or chemical release concurrent with system operation in any ventilation zone communicating with the system.

Tests described in Specifications 5.5.7.a and 5.5.7.b shall be performed after each complete or partial replacement of the HEPA filter train or charcoal adsorber filter; and after any structural maintenance on the system housing.

Tests described in Specifications 5.5.7.d and 5.5.7.e shall be performed once per 24 months.

The provisions of SR 3.0.2 and SR 3.0.3 are applicable to the VFTP test frequencies.

a. Demonstrate for each of the ESF systems that an inplace test of the HEPA filters shows a penetration and system bypass < 1% when tested in accordance with Regulatory Guide 1.52, Revision 2, Section C.5.c, and ASME N510-1989 at the system conditions specified below.

ESF Ventilation System Flowrate (cfm)

SGT System 1602 to 1958 Control Room Emergency 810 to 990 Filter System

b. Demonstrate for each of the ESF systems that an inplace test of the charcoal adsorber shows a penetration and system bypass < 1% when tested in accordance with Regulatory Guide 1.52, Revision 2, Section C.5.d, and ASME N510-1989 at the system conditions specified below.

ESF Ventilation System Flowrate (cfm)

SGT System 1602 to 1958 Control Room Emergency 810 to 990 Filter System (continued)

\,

Cooper 5.0-11 Amendment No. 242

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.13 Control Room Envelope Habitability Program (continued) personnel receiving radiation exposures in excess of either (a) 5 rem whole body or its equivalent to any part of the body for the duration of the loss-of-coolant accident, or (b) 5 rem total effective dose equivalent (TEDE) for the duration of the fuel handling accident. The program shall include the following elements:

a. The definition of the CRE and CRE boundary.

b. Requirements for maintaining the CRE boundary in its design condition including configuration control and preventive maintenance.

c. Requirements for (i) determining the unfiltered air inleakage past the CRE boundary into the CRE in accordance with the testing methods and at the Frequencies specified in Sections C.1 and C.2 of Regulatory Guide 1.197, "Demonstrating Control Room Envelope Integrity at Nuclear Power Reactors,"

Revision 0, May 2003, and (ii) assessing CRE habitability at the Frequencies specified in Sections C.1 and C.2 of Regulatory Guide 1.197, RevisionO. No exceptions to Sections C.1 and C.2 of Regulatory Guide 1.197, Revision 0, are proposed.

d. Measurement, at designated locations, of the CRE pressure relative to all external areas adjacent to the CRE boundary during the pressurization mode of operation by the CREF System, operating at the flow rate required by the Ventilation Filter Testing Program, at a Frequency of 24 months. The results shall be trended and used as part of the periodic assessment of the CRE boundary.

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

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

Cooper 5.0-18 Amendment No. 242

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 242 TO RENEWED FACILITY OPERATING LICENSE NO. DPR-46 NEBRASKA PUBLIC POWER DISTRICT COOPER NUCLEAR STATION DOCKET NO. 50-298

1.0 INTRODUCTION

By letter dated September 16, 2011 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML11264A165), and supplemented by letters dated May 2, May 24, and September 17,2012 (ADAMS Accession Nos. ML121290449, ML12151A132, and ML12268A168, respectively), Nebraska Public Power District (NPPD, the licensee) requested an amendment to the Technical Specifications (TSs) for the Cooper Nuclear Station (CNS).

Specifically, the change addresses certain TS Surveillance Requirement (SR) frequencies that are specified as "18 months" by changing them to "24 months" in accordance with the guidance provided in U.S. Nuclear Regulatory Commission (NRC) Generic Letter (GL) 91-04, "Changes in Technical Specification Surveillance Intervals to Accommodate a 24-Month Fuel Cycle," dated April 2, 1991 (ADAMS Accession No. ML031140501). Portions of the letter dated May 2,2012, contain sensitive unclassified non-safeguards information (proprietary) and, accordingly, those portions have been withheld from public disclosure. Additionally, NPPD proposed to adopt TS Task Force (TSTF) Traveler TSTF-493, Revision 4, "Clarify Application of Setpoint Methodology for LSSS [Limiting Safety System Settings] Functions," Option A The supplemental letters dated May 2, May 24, and September 17,2012, provided additional information that clarified the application, did not expand the scope of the application as originally noticed, and did not change the NRC staffs original proposed no significant hazards consideration determination as published in the Federal Register on March 6,2012 (77 FR 13371).

A longer fuel cycle increases the time interval between refueling outages and the performance of the associated TS SRs that are performed during outages. The licensee addresses SR changes to accommodate a 24-month fuel cycle for those surveillances that are performed at each 18-month or other refueling outage interval.

Enclosure 2

- 2 Additionally, the proposed change will resolve operability determination issues associated with potentially non-conservative TS Allowable Values (AVs)1 calculated using methods in the industry standard Instrument Society of America (ISA)-S67.04-1994 Part 2, "Methodologies for the Determination of Setpoints for Nuclear Safety-Related Instrumentation." The concern is that when these values are used to assess instrument channel performance during testing, non conservative decisions about the equipment operability may result. The proposed change will also resolve operability determination issues related to relying on AVs associated with TS limiting safety system settings (LSSSS)2 to ensure that TS requirements, not plant procedures, will be used for assessing instrument channel operability.

TSTF-493, Revision 4, Attachment A contains Functions related to those variables that have a significant safety function as defined in Title 10 of the Code of Federal Regulations (10 CFR) paragraph 50.36(c)(1 )(ii)(A). The licensee stated that the application is consistent with Option A of the NRC-approved Revision 4 to TSTF-493, with some proposed variations or deviations from the TS changes described in the traveler. CNS's TSs are based on an earlier version of NUREG-1433, "Standard Technical Specifications - General Electric Plants, BWRl4." The level of detail and content of the CNS Bases for TS 3.3.1 are different from that provided in NUREG-1433, Revision 3 (ADAMS Accession No. ML041910194), requiring modification of the Bases changes in TSTF-493, Revision 4, Option A NPPD proposed TS Bases changes that are consistent with the intent of TSTF-493, Revision 4. The availability of this TS improvement was announced in the Federal Register on May 11, 2010 (75 FR 26294).

The proposed change would revise the CNS TSs to be consistent with the NRC-approved TSTF-493, Revision 4, Option A Under Option A, two surveillance Notes would be added to SRs in the Surveillance Requirement column of the Function Tables for TS 3.3.1.1, "Reactor Protection System Instrumentation," TS 3.3.2.1, "Control Rod Block Instrumentation,"

TS 3.3.5.1, "Emergency Core Cooling System (ECCS) Instrumentation," and TS 3.3.5.2, "Reactor Core Isolation Cooling (RCIC) System Instrumentation." Specifically, surveillance Notes would be added to SRs that require verifying trip setpoint setting values (Le., channel calibration and channel functional test SRs). The affected instrument Functions are listed in to the license amendment request (LAR) dated September 16, 2011.

The instrument setting "Allowable Value" is a limiting value of an instrument's as-found trip setting used during surveillances. The AV is more conservative than the Analytical Limit (AL) to account for applicable instrument measurement errors consistent with the plant-specific setpoint methodology. If during testing, the actual instrumentation setting is less conservative than the AV, the channel is declared inoperable and actions must be taken consistent with the TS requirements.

2 The regulations in 10 CFR 50.36(c)(1)(ii)(A) state, in part, that Limiting safety system settings for nuclear reactors are settings for automatic protective devices related to those variables having significant safety functions.

- 3 For instrument Functions not required to have the surveillance Notes described above or for Functions in other instrumentation TSs not described above, TSTF-493, Revision 4, Option A, revised the TS Bases for SRs which verify setpoint setting values to state that the required surveillance ensures that the instruments are functioning as required. The revised TS Bases state, in part, that There is a plant-specific program which verifies that the instrument channel(s) will function as required by verifying the as-left setting and as-found trip values are consistent with those established by the setpoint methodology.

NPPD has included this statement in the CNS TS Bases for all SRs which verify setpoint setting values for instrument Functions not required to have the surveillance Notes.

2,0 REGULATORY EVALUATION 2.1 System Description Plant protective systems are designed to initiate reactor trips (scrams) or other protective actions before selected unit parameters exceed ALs assumed in the safety analysis in order to prevent violation of the reactor core safety limits (SLs) and reactor coolant system (RCS) pressure SL from postulated antiCipated operational occurrences (AOOs) and to assist the engineered safety features (ESF) systems in mitigating accidents. The reactor core SLs and RCS pressure SL ensure that the integrity of the reactor core and RCS is maintained.

Instrumentation required by the TSs has been designed to assure that the applicable safety analysis limits will not be exceeded during accidents and AOOs, This is achieved by specifying nominal trip setpoints (NTSPs), including testing requirements to assure the necessary quality of systems, in terms of parameters directly monitored by the applicable instrumentation systems for LSSSs, as well as specifying limiting conditions for operations (LCOs) on other plant parameters and equipment in accordance with 10 CFR 50.36(c)(2), "Limiting conditions for operations."

2.2 Regulatory Requirements Section 182a of the Atomic Energy Act requires applicants for nuclear power plant operating licenses to include TSs as part of the license. The TSs ensure the operational capability of structures, systems, and components that are required to protect the health and safety of the public. The NRC's regulatory requirements related to the content of the TSs are contained in 10 CFR Section 50.36, "Technical specifications," which requires that the TSs include items in the following specific categories: (1) safety limits, limiting safety systems settings, and limiting control settings; (2) LCOs; (3) SRs; (4) design features; and (5) administrative controls.

However, the regulation does not specify the particular requirements to be included in TSs.

The regulations in 10 CFR 50,36(c)(1)(i)(A) state, in part, that Safety limits for nuclear reactors are limits upon important process variables that are found to be necessary to reasonably protect the integrity of certain of the physical barriers that guard against the uncontrolled release of radioactivity.

-4 The regulations in 10 CFR 50.36(c)(1)(ii)(A) state, in part, that Limiting safety system settings for nuclear reactors are settings for automatic protective devices related to those variables having significant safety functions.

Where a limiting safety system setting is specified for a variable on which a safety limit has been placed, the setting must be so chosen that automatic protective action will correct the abnormal situation before a safety limit is exceeded. If, during operation, it is determined that the automatic safety system does not function as required, the licensee shall take appropriate action, which may include shutting down the reactor.

The regulations in 10 CFR 50.36( c)(2) , "Limiting conditions for operation," 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 until the condition can be met.

The regulations in 10 CFR 50.36(c)(3), "Surveillance requirements," state that 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 regulations in 10 CFR 50.36(c)(5), "Administrative controls," state, in part, that Administrative controls are the provisions relating to organization and management, procedures, recordkeeping, review and audit, and reporting necessary to assure the operation of the facility in a safe manner.

CNS's construction predated the issuance of Appendix A 3 , "General Oesign Criteria for Nuclear Power Plants," to 10 CFR Part 50. CNS is designed to conform to the proposed general design criteria (GOC) published in the Federal Register on July 11, 1967 (32 FR 10213), except where commitments were made to specific 1971 GOC. The Atomic Energy Commission accepted CNS's conformance with the proposed GOC. CNS's conformance to the draft GOC is specified in Appendix F to the CNS Updated Safety Analysis Report (USAR).

3 The 1967 Proposed GDC as described in the CNS Updated Safety Analysis Report, Appendix F, are the licensing basis for CNS; however, the NRC staff concluded in its 1973 Safety Evaluation Report for CNS that the intent of the 1971 Final Rule for 10 CFR Part 50, Appendix A, had also been met.

- 5 CNS's USAR Appendix F discussion of Criterion 12, "Instrumentation and Control Systems" is as follows:

The necessary station controls, instrumentation, and alarms for safe and orderly operation are located in the control room. These instruments and systems allow complete monitoring control of the facility throughout normal operating range and through startup and shutdown. Sufficient instrumentation is provided to allow monitoring of variables necessary for effective station control.

CNS's USAR Appendix F discussion of Criterion 14, "Core Protection Systems," is as follows:

The reactor protection system, described in Section VII-2 in association with other safety systems, automatically senses and limits conditions which could lead to unacceptable fuel damage. This system acts independently of, and overrides, other controls over control rod movement to initiate the necessary protective action. Evaluation of the protective action is given in the safety analysis.

The regulation in 10 CFR Part 50, Appendix A, GDC 13, "Instrumentation and control,"

states:

Instrumentation shall be provided to monitor variables and systems over their anticipated ranges for normal operation, for anticipated operational occurrences, and for accident conditions as appropriate to assure adequate safety, including those variables and systems that can affect the fission process, the integrity of the reactor core, the reactor coolant pressure boundary, and the containment and its associated systems. Appropriate controls shall be provided to maintain these variables and systems within prescribed operating ranges.

The regulation in 10 CFR Part 50, Appendix A, GDC 20, "Protection system functions,"

states:

The protection system shall be designed (1) to initiate automatically the operation of appropriate systems including the reactivity control systems, to assure that specified acceptable fuel design limits are not exceeded as a result of anticipated operational occurrences and (2) to sense accident conditions and to initiate the operation of systems and components important to safety.

The regulation in 10 CFR 50.65, "Requirements for monitoring the effectiveness of maintenance at nuclear power plants," requires that preventive maintenance activities must not reduce the overall availability of the systems, structures, and components.

2.3 Regulatory Guidance In addition to the regulatory requirements stated above, the NRC staff considered the previously approved guidance in NUREG-1433, Revision 3, "Standard Technical Specifications, General Electric Plants, BWRl4," dated June 2004, and NRC Regulatory Guide (RG) 1.105, Revision 3, "Setpoints for Safety-Related Instrumentation," December 1999 (ADAMS Accession No. ML993560062), for determining the acceptability of revising instrumentation TS

- 6 requirements. RG 1.105, Revision 3, describes a method acceptable to the NRC staff for complying with the NRC's regulations for ensuring that setpoints for safety-related instrumentation are initially within and remain within the TS limits. The RG endorses Part 1 of ISA-S67.04-1994, "Setpoints for Nuclear Safety-Related Instrumentation," subject to NRC staff clarifications. The ISA standard provides a basis for establishing setpoints for nuclear instrumentation for safety systems and addresses known contributing errors in the channel.

Part 1 establishes a framework for ensuring that setpoints for nuclear safety-related instrumentation are established and maintained within specified limits.

In addition, GL 91-04 provides generic guidance for evaluating a 24-month surveillance test interval for TS SRs that are currently performed at an 18-month interval. For extension of all non-calibration SRs, the GL 91-04 states, in part, that For other 18-month surveillances, licensees should evaluate the effect on safety of the change in surveillance intervals to accommodate a 24-month fuel cycle.

This evaluation should support a conclusion that the effect on safety is small. In addition, licensees should confirm that historical maintenance and surveillance data do not invalidate this conclusion. Licensees should confirm that the performance of surveillances at the bounding surveillance interval limit provided to accommodate a 24-month fuel cycle would not invalidate any assumption in the plant licensing basis.

GL 91-04 also stipulates that the licensee should evaluate the following criteria for calibration related frequency changes:

1. Confirm that instrument drift as determined by as-found and as-left calibration data from surveillance and maintenance records has not, except on rare occasions, exceeded acceptable limits for a calibration interval.

2. Confirm that the values of drift for each instrument type (make, model, and range) and application have been determined with a high probability and a high degree of confidence. Provide a summary of the methodology and assumptions used to determine the rate of instrument drift with time based upon historical plant calibration data.

3. Confirm that the magnitude of instrument drift has been determined with a high probability and a high degree of confidence for a bounding calibration interval of 30 months for each instrument type (make, model number, and range) and application that performs a safety function.

Provide a list of the channels by TS section that identifies these instrument applications.

4. Confirm that a comparison of the projected instrument drift errors has been made with the values of drift used in the setpoint analysis. If this results in revised setpoints to accommodate larger drift errors, provide proposed TS changes to update trip setpoints. If the drift errors result in a revised safety analysis to support existing setpoints, summarize the

-7 updated analysis conclusions to confirm that safety limits and safety analysis assumptions are not exceeded.

5. Confirm that the projected instrument errors caused by drift are acceptable for the control of plant parameters to affect a safe shutdown with the associated instrumentation.

6. Confirm that all conditions and assumptions of the setpoint and safety analyses have been checked and are appropriately reflected in the acceptance criteria of plant surveillance procedures for channel checks, channel functional tests, and channel calibrations.

7. Provide a summary description of the program for monitoring and assessing the effects of increased calibration surveillance intervals on instrument drift and on safety.

Similar license amendment requests were approved by the NRC staff for Browns Ferry Nuclear Plant, Unit 1, on September 28,2006 (ADAMS Accession No. ML062170002), Clinton Power Station, Unit 1, on October 21, 2005 (ADAMS Accession No. ML052940480), Monticello Nuclear Generating Plant on September 30, 2005 (ADAMS Accession No. ML052700252), and River Bend Station, Unit 1, on August 31, 2010 (ADAMS Accession No. ML102350266).

3.0 TECHNICAL EVALUATION

3.1 Proposed Changes The licensee proposed revising the following SR frequencies to 24 months:

SR 3.1.7.8 SR 3.3.3.2.2 SR 3.3.6.3.5 SR 3.5.3.5 SR 3.7.2.4 SR 3.1.7.9 SR 3.3.3.2.3 SR 3.3.7.1.3 SR 3.6.1.1.2 SR 3.7.3.4 SR 3.1.8.3 SR 3.3.4.1.2 SR 3.3.7.1.4 SR 3.6.1.3.7 SR 3.7.4.3 SR 3.3.1.1.11 SR 3.3.4.1.3 SR 3.3.8.1.2 SR 3.6.1.3.8 SR 3.7.7.2 SR 3.3.1.1.12 SR 3.3.5.1.4 SR 3.3.8.1.3 SR 3.6.1.3.9 SR 3.7.7.3 SR 3.3.1.1.13 SR 3.3.5.1.5 SR 3.3.8.2.1 SR 3.6.1.3.11 SR 3.8.1.8 SR 3.3.1.1.14 SR 3.3.5.2.4 SR 3.3.8.2.2 SR 3.6.1.6.1 SR 3.8.1.9 SR 3.3.1.1.15 SR 3.3.5.2.5 SR 3.4.3.2 SR 3.6.1.6.2 SR 3.8.1.10 SR 3.3.1.2.7 SR 3.3.6.1.4 SR 3.5.1.8 SR 3.6.1.7.3 SR 3.8.1.11 SR 3.3.2.1.6 SR 3.3.6.1.5 SR 3.5.1.9 SR 3.6.1.8.3 SR 3.8.4.6 SR 3.3.2.1.7 SR 3.3.6.1.6 SR 3.5.1.10 SR 3.6.4.1.4 SR 3.8.4.7 SR 3.3.2.2.2 SR 3.3.6.2.3 SR 3.5.1.11 SR 3.6.4.2.3 SR 3.8.4.8 SR 3.3.2.2.3 SR 3.3.6.2.4 SR 3.5.2.5 SR 3.6.4.3.3 SR 3.3.3.1.3 SR 3.3.6.3.4 SR 3.5.3.4 SR 3.6.4.3.4

- 8 The licensee proposed revising the following to accommodate a 24-month fuel cycle.

TS 3.3.5.1, Table 3.3.5.1-1, Emergency Core Cooling System Instrumentation

TS 3.3.6.3, Table 3.3.6.3-1, Low-Low Set Instrumentation

TS 5.5.2, Systems Integrity Monitoring Program

TS 5.5.7, Ventilation Filter Testing Program (VFTP)

TS 5.5.13, Control Room Envelope Habitability Program The licensee also proposed adding TSTF-493, Revision 4, Option A, TS surveillance Notes with changes to setpoint values to CNS instrumentation Functions.

3.2 Instrumentation and Controls Improved reactor fuels allow licensees to consider an increase in the duration of the fuel cycle for their facilities. The NRC staff has reviewed requests for individual plants to modify TS surveillance intervals to be compatible with a 24-month fuel cycle. The staff issued GL 91-04 to provide generic guidance to licensees for preparing such LARs. The licensee provided the GL 91-04 evaluation for the proposed TS amendments in Section 3.0 of Enclosure 1 of the LAR.

The proposed TS changes related to GL 91-04 test interval extensions were divided into two categories. The categories are: (A) changes to surveillances other than channel calibrations, identified as "Non-calibration Changes," and (B) changes involving the channel calibration frequency, identified as "Calibration Changes." The licensee stated that for each component having a surveillance interval extended, historical surveillance test data and associated maintenance records were reviewed in evaluating the effect on safety. The licensee further stated that the licensing basis was reviewed for functions associated with each revision to ensure it was not invalidated. Based on the results of these reviews, the licensee concluded that there is no adverse effect on plant safety due to increasing the surveillance test intervals from 18 months to 24 months, with the continued application of SR 3.0.2, which allows an extension of the time interval to 1.25 times the interval specified in the frequency (i.e., grace period up to 30 months) to SR frequencies.

3.2.1 Non-Calibration Changes In its LAR submittal dated September 16,2011, the licensee provided the following evaluation of the non-calibration changes:

STEP 1: Licensees should evaluate the effect on safety of an increase in 18-month surveillance intervals to accommodate a 24-month fuel cycle. This evaluation should support a conclusion that the effect on safety is small.

- 9 EVALUATION:

Each non-calibration SR frequency being changed has been evaluated with respect to the effect on plant safety. The methodology utilized to justify the conclusion that extending the testing interval has a minimal effect on safety was based on the fact that the functionlfeature is:

(1) Tested on a more frequent basis during the operating cycle by other plant programs; (2) Designed to have redundant counterparts or be single failure proof; or (3) Highly reliable.

A summary of the evaluation of the effect on safety for each non-calibration SR frequency being changed is presented in Attachment 5 [of the LAR).

STEP 2: Licensees should confirm that historical plant maintenance and surveillance data support this conclusion.

EVALUATION:

The surveillance test history of the affected SRs has been evaluated. This evaluation consisted of a review of available surveillance test results and associated maintenance records for at least five cycles of operation. This included SRs performed up to and including the Fall 2009 refueling outage; although in some cases SRs performed in 2010 and 2011 were also included in the evaluation when older records could not be readily retrieved. With the extension of the testing frequency to 24 months, there will be a longer period between each surveillance performance. If a failure that results in the loss of the associated safety function should occur during the operating cycle, and would only be detected by the performance of the 18-month TS SR, then the increase in the surveillance testing interval could reduce the associated function availability.

In addition to evaluating these surveillance failures, potential common failures of similar components tested by different surveillances were also evaluated. This additional evaluation determined whether there is evidence of repetitive failures among similar plant components. These common component failures have been further evaluated to determine if there was an impact on plant reliability. The evaluation determined that current plant programs are adequate to ensure system reliability. The surveillance failures that are detailed in Attachment 5 [of the LAR) exclude failures that:

(a) Did not impact a TS safety function or TS operability; (b) Are detectable by required testing performed more frequently than the 18-month surveillance being extended; or (c) The cause can be attributed to an associated event such as a preventative maintenance task, human error, previous modification, or previously existing design deficiency; or that were subsequently re performed successfully with no intervening corrective maintenance (e.g.,

- 10 plant conditions or malfunctioning measurement and test equipment may have caused aborting the test performance).

These categories of failures are not related to potential unavailability due to testing interval extension, and are therefore not listed or further evaluated in this submittal. This review of surveillance test history validated the conclusion that the impact, if any, on system availability will be minimal as a result of the change to a 24-month testing frequency. Specific SR test failures, and justification for this conclusion, are discussed in Attachment 5 [of the LAR].

STEP 3: Licensees should confirm that assumptions in the plant licensing basis would not be invalidated on the basis of performing any surveillance at the bounding surveillance interval limit provided to accommodate a 24-month fuel cycle.

EVALUATION:

As part of the evaluation of each affected SR, the impact of the changes against the assumptions in the CNS licensing basis was reviewed. In general, testing interval changes have no impact on the plant licensing basis. In some cases, the change to a 24-month fuel cycle may require a change to licensing basis information as described in the Updated Safety Analysis Report (USAR).

However, since no changes requiring NRC review and approval have been identified, the USAR changes associated with fuel cycle extension to 24 months will be drafted in accordance with CNS procedures that implement 10 CFR 50.59, "Changes, tests and experiments," and will be submitted in accordance with 10 CFR 50.71, "Maintenance of records, making of reports,"

paragraph (e).

The performance of surveillances extended for a 24-month fuel cycle will be trended as a part of the Maintenance Rule Program. Degradation in performance will be evaluated to verify that the degradation is not due to the extension of surveillance or maintenance activities.

The NRC staff reviewed the above evaluation from Attachment 1 of the LAR together with the associated qualitative safety analysis and failure history review in Attachment 5 of the LAR. The staff concludes that the evaluation and associated analyses adequately addressed the guidance for non-calibration changes in GL 91-04. The NRC staff also concludes that there is no impact to the plant safety analysis, and the licensee's commitment to trend and evaluate the proposed surveillance extensions met the criteria of GL 91-04.

- 11 In Attachment 5 to its letter dated September 16, 2011, the licensee identifies the following logic system functional tests and selected channel functional tests:

1. LOGIC SYSTEM FUNCTIONAL TESTS (LSFT) and SELECTED CHANNEL FUNCTIONAL TESTS TS 3.3.1.1. Reactor Protection System (RPS) Instrumentation SR 3.3.1.1.11 Perform CHANNEL FUNCTIONAL TEST.

SR 3.3.1.1.13 Perform LOGIC SYSTEM FUNCTIONAL TEST.

TS 3.3.2.1. Control Rod Block Instrumentation SR 3.3.2.1.7 Perform CHANNEL FUNCTIONAL TEST.

TS 3.3.2.2. Feedwater and Main Turbine High Water Level Trip Instrumentation SR 3.3.2.2.3 Perform LOGIC SYSTEM FUNCTIONAL TEST including valve actuation.

TS 3.3.3.2, Alternate Shutdown System SR 3.3.3.2.2 Verify each required control circuit and transfer switch is capable of performing the intended functions.

TS 3.3.4.1. Anticipated Transient Without Scram recirculation Pump Trip (ATWS-RPT) Instrumentation SR 3.3.4.1.3 Perform LOGIC SYSTEM FUNCTIONAL TEST including breaker actuation.

TS 3.3.5.1. Emergency Core Cooling System (ECCS) Instrumentation SR 3.3.5.1.5 Perform LOGIC SYSTEM FUNCTIONAL TEST.

TS 3.3.5.2. Reactor Core Isolation Cooling (RCIC) System Instrumentation SR 3.3.5.2.5 Perform LOGIC SYSTEM FUNCTIONAL TEST.

TS 3.3.6.1. Primarv Containment Isolation Instrumentation SR 3.3.6.1.6 Perform LOGIC SYSTEM FUNCTIONAL TEST.

TS 3.3.6.2. Secondary Containment Isolation Instrumentation SR 3.3.6.2.4 Perform LOGIC SYSTEM FUNCTIONAL TEST.

TS 3.3.6.3, Low-Low Set (LLS) Instrumentation SR 3.3.6.3.5 Perform LOGIC SYSTEM FUNCTIONAL TEST.

TS 3.3.7.1. Control Room Emergency Filter (CREF) System Instrumentation SR 3.3.7.1.4 Perform LOGIC SYSTEM FUNCTIONAL TEST.

TS 3.3.8.1! Loss of Power (LOP) Instrumentation SR 3.3.8.1.3 Perform LOGIC SYSTEM FUNCTIONAL TEST.

TS 3.3.8.2. Reactor Protection System (RPS) Electric Power Monitoring SR 3.3.8.2.2 Perform a system functional test.

- 12

2. RESPONSE TIME TESTS TS 3.3.1.1, Reactor Protection System (RPS) Instrumentation SR 3.3.1.1.15 Verify the RPS RESPONSE TI ME is within limits.

TS 3.3.2.1, Control Rod Block Instrumentation SR 3.3.2.1.6 Verify the RWM is not bypassed when THERMAL POWER is

< 9.85% RTP.

Based on the review of the licensee's evaluation on impact to safety, the validating failure history review, and the commitment to trend and evaluate the extended surveillances, the NRC staff concludes that the effect on plant safety is small, that the change does not invalidate any assumption in the plant design basis, and that the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency for the above non calibration changes.

3.2.2 Calibration Changes As stated in Section 2.3 of this safety evaluation, GL 91-04 guidance describes seven criteria that the licensee must evaluate for each proposed calibration-related 24-month surveillance extension. The NRC staff verified that the licensee's proposed changes met these criteria by reviewing Attachments 1, 5, and 6, and Enclosure 1 of the LAR submittal dated September 16, 2011; Enclosure 2, NEDC 92-050L Rev. 2, "Calculation of Calibration Values for Low-Low Set Pressure Switches," dated April 30, 2012 (proprietary), and Enclosure 4, NEDC 11-109, Rev. 0, "Instrument Drift Analysis for NBI-PS-51A1B/CID (Barksdale B2T-M12SS)," dated October 3, 2011 (ADAMS Accession No. ML12129A319), of the licensee's letter dated May 2,2012 (ADAMS Accession No. ML121290449), in response to the NRC staff's request for additional information (RAI) dated April 3, 2012 (ADAMS Accession No. ML120860054).

1. Similar to the non-calibration changes, the evaluation of calibration changes must demonstrate that instrument drift for a given device has performed as expected through its service life. The licensee performed an analysis on the failure history and summarized that analysis in Attachment 5 of the LAR submittal dated September 16,2011. The NRC staff evaluated the CNS analysis for the calibration-related SR changes and concludes that the history and CNS analysis supports the extended surveillance interval and met the criteria of GL 91-04.

2. The drift analysis for each instrument type should demonstrate that the drift value has been determined with a high degree of probability and high degree of confidence. The licensee submitted its drift analysis methodology, "Instrument Drift Analysis Design Guide," as Enclosure 1 of the LAR submittal dated September 16,2011. The licensee stated that the methodology had been updated to require 30 samples to ensure statistically significant results. The NRC staff reviewed Enclosure 1 of the LAR and concludes that the method is acceptable. To verify that the licensee appropriately applied the methodology, the staff reviewed Enclosure 4, calculation number NEDC 11-109, Rev. 0, of the licensee's letter dated May 2,2012. The NRC staff concludes that the licensee appropriately followed the method and the drift value was determined with a high

- 13 degree of probability and high degree of confidence (95/95) and met the criteria of GL 91-04.

3. The third criterion is to confirm that the magnitude of instrument drift has been determined with a high probability and a high degree of confidence for a bounding calibration interval of 30 months for each instrument type (make, model number, and range) and application that performs a safety function. The licensee must provide a list of the channels by TS section that identifies these instrument applications. The licensee stated in Attachment 1 that it had completed all the drift calculations for the instruments addressed in the LAR.

The NRC staff reviewed Attachment 6 of the LAR and concludes that it listed by TS surveillance and TS function, each instrument including make, model, range and the corresponding calculation. The staff reviewed the drift analysis methodology, "Instrument Drift Analysis Design Guide," Enclosure 1 of the LAR.

To verify that the licensee appropriately applied the methodology, the staff reviewed Enclosure 2, calculation number NEDC 11-109, Rev. 0, of the licensee's letter dated May 2, 2012. The staff concludes that the licensee appropriately followed the method and the drift value was determined with a high degree of probability and high degree of confidence (95/95) and met the criteria of GL 91-04.

4. The next GL 91-04 criterion is to confirm the projected drift error does not exceed the drift in the current setpoint calculation. Where setpoints must be changed, verify the safety analysis assumptions are not exceeded. The licensee updated all calculations for the requested TS changes and identified two setpoint changes that resulted from the extended surveillance interval which are described in Sections 3.1.3 and 3.1.4 in Attachment 1 of the LAR.

CNS identified the following AV changes to support the longer surveillance interval of 24-month fuel cycle:

TS 3.3.5.1. Emergency Core Cooling System (ECCS) Instrumentation Table 3.3.5.1-1 Function 2.d, Reactor Pressure - Low (Recirculation Discharge Valve Permissive), requires a change to the upper limit TS Allowable Value. The TS Allowable Value (in pounds per square inch gauge (psig)) is being changed from "< 221 psig" to u< 246 psig."

TS 3.3.6.3. Low-Low Set (LLS) Instrumentation Table 3.3.6.3-1 Function 2, Low-Low Set Pressure Setpoints, requires changes to the Low and High opening and closing TS Allowable Values. The Low opening pressure is changed from "> 995 psig and < 1035 psig" to "> 996.5 psig and < 1010 psig." The Low closing pressure is changed from u> 855 psig and

< 895 psig" to "> 835 psig and < 875.5 psig." The High opening pressure is changed from u> 1005 psig and < 1045 psig" to "> 996.5 psig and < 1040 psig."

The High clOSing pressure is changed from u> 855 psig and < 895 psig" to

"> 835 psig and < 875.5 psig."

- 14 The NRC staff review of the calibration changes focused on the drift analysis and setpoint calculations. No issues were identified in the failure analysis of calibration-related changes. By letter dated May 2, 2012, the licensee submitted a detailed drift analysis and associated full setpoint calculation for Table 3.3.6.3-1 Function 2, Low-Low Set Pressure. The NRC staff performed a detailed review of the docketed drift analysis and the associated full calculation for Low-Low Set Pressure and concludes the calculation is acceptable. The staff verified that the licensee followed NEDC-31336P-A, "General Electric Instrument Setpoint Methodology," September 1996, which was previously approved by the NRC staff (a non-proprietary version, designated as NEDO-31336-A, September 1996 is publicly available at ADAMS Accession No. ML073450560).

To verify adherence, the NRC staff performed a detailed review of the proprietary NEDC 92-050L Rev. 2, "Calculation of Calibration Values for Low-Low Set Pressure Switches." The NRC staff also verified that the updated AVs for both proposed setpoint changes have not exceeded the analytical limits. The staff concludes that the licensee met this criterion of GL 91-04 and the criteria of RG 1.105, Revision 3.

5. Confirm that the projected instrument errors caused by drift are acceptable for the control of plant parameters to affect a safe shutdown with the associated instrumentation. The licensee stated in Section 3.1.2 of Attachment 1 of the LAR, "STEP 5," in part, that As discussed in the previous sections, the calculated drift values have been compared to drift allowances in the CNS design basis.

For instrument loops that provide process variable indication only, an evaluation was performed as described in Attachment 5 to verify that the instruments can still be effectively utilized to perform a plant safe shutdown. In no cases were changes to safe shutdown analyses required to support any change to a 24-month frequency.

As noted above, the NRC staff has confirmed that the licensee has verified the calculation and comparison of drift values by performing a detailed review of a drift analysis and the corresponding setpoint calculation. The staff has also reviewed the evaluation in Attachment 5 of the LAR and confirms that the licensee met this criterion of GL 91-04.

- 15

6. Confirm that all conditions and assumptions of the setpoint and safety analyses have been checked and are appropriately reflected in the acceptance criteria of plant surveillance procedures for channel checks, channel functional tests, and channel calibrations. The licensee stated in Section 3.1.2 of Attachment 1 of the LAR that plant procedures require checking of the safety analysis and proper update of the surveillance procedures. In Section 3.1.2, "STEP 6," the licensee stated, in part, that, Applicable surveillance test procedures are being reviewed and acceptance criteria updated to incorporate the necessary changes resulting from any revision to setpoint calculations.

Although no updated plant procedures were docketed with the LAR, the licensee stated that, "revisions to CNS setpoint calculations have been developed, and affected calibration and functional test procedures will be revised as part of implementation, to reflect the new 3D-month drift values." The NRC staff has reviewed updated (strikeout and clean) versions of the TS updates and verified the surveillance interval changes as well as the two setpoint AV changes. The staff concludes that the licensee has not fully met this criterion of the LAR because there is no evidence the procedures are correctly updated; however, the licensee has stated that any necessary changes resulting from the reviews will be incorporated into the instrument surveillance procedures as part of implementation of the 24-month surveillance test frequency. The NRC staff concludes that this is acceptable since the critical information changes in the TS that correlate to the procedures have been verified by the staff.

7. Provide a summary description of the program for monitoring and assessing the effects of increased calibration surveillance intervals on instrument drift and on safety. The licensee states in Section 3.1.2, "STEP 7," of Attachment 1 of the LAR, in part, that Instruments with TS calibration surveillance frequencies extended to 24 months will be monitored and trended.

Additionally, the licensee has proposed to adopt TSTF-493, Revision 4, Option A which dictates surveillance criteria. The NRC staff reviewed the LAR regarding adoption of TSTF-493 and monitoring and assessing the effects of increased surveillance intervals and concludes that the licensee met the criteria of GL 91-04. A more detailed review is provided in Section 3.4 of this safety evaluation.

- 16 The NRC staff reviewed the licensee's analyses, evaluations, and calculations for the proposed calibration-related 24-month surveillance extensions as documented in Attachments 1, 5, and 6 and Enclosure 1 of the LAR as well as Enclosures 2 and 4 of the May 2, 2012, RAI response letter. The staff concludes that they met the criteria of GL 91-04 and RG 1.105, Revision 3, and provided adequate justification for the proposed increased surveillance intervals of the following instrument channels:

TS 3.3.1.1, Reactor Protection System (RPS) Instrumentation SR 3.3.1.1.12 Perform CHANNEL CALIBRATION.

- Function 1.a, Intermediate Range Monitors, Neutron Flux - High

- Function 2.b, Average Power Range Monitors, Neutron Flux - High (Flow Biased)

- Function 3, Reactor Vessel Pressure - High

- Function 4, Reactor Vessel Water Level - Low (Level 3)

- Function 5, Main Steam Isolation Valve - Closure

- Function 6, Drywell Pressure - High

- Function 7.a, Scram Discharge Volume Water Level - High, Level Transmitter

- Function 7.b, Scram Discharge Volume Water Level- High, Level Switch

- Function 8, Turbine Stop Valve - Closure

- Function 9, Turbine Control Valve Fast Closure, DEH [Digital ElectrO-Hydraulic]

Trip Oil Pressure - Low SR 3.3.1.1.14 Verify Turbine Stop Valve - Closure and Turbine Control Valve Fast Closure, Trip Oil Pressure - Low Functions are not bypassed when THERMAL POWER is > 29.5% RTP [Rated Thermal Power].

TS 3.3.1.2, Source Range Monitor (SRM) Instrumentation SR 3.3.1.2.7 Perform CHANNEL CALIBRATION.

TS 3.3.2.2, Feedwater and Main Turbine High Water Level Trip Instrumentation SR 3.3.2.2.2 Perform CHANNEL CALIBRATION. The Allowable Value shall be

< 54.0 inches.

TS 3.3.3.1, Post Accident Monitoring (PAM) Instrumentation SR 3.3.3.1.3 Perform CHANNEL CALIBRATION of each required PAM Instrumentation channel except for the Primary Containment H2 and O2 Analyzers.

TS 3.3.3.2, Alternate Shutdown System SR 3.3.3.2.3 Perform CHANNEL CALIBRATION for each required instrumentation channel.

TS 3.3.4.1, Anticipated Transient Without Scram Recirculation Pump Trip (ATWS-RPT)

Instrumentation SR 3.3.4.1.2 Perform CHANNEL CALIBRATION. The Allowable Values shall be:

- a. Reactor Vessel Water Level - Low Low (Level 2): > -42 inches; and

- b. Reactor Pressure - High: < 1072 psig.

- 17 TS 3.3.5.1. Emergency Core Cooling System (ECCS) Instrumentation SR 3.3.5.1.4 Perform CHANNEL CALIBRATION.

- Function 1.a, 2.a, 4.a, 5.a, Reactor Vessel Water Level - Low Low Low (Level 1)

- Function 1.b, 2.b, 3.b, Drywell Pressure - High

- Function 1.c, 2.c, Reactor Pressure - Low (Injection Permissive)

- Function 1.d, Core Spray Pump Discharge Flow - Low (Bypass)

- Function 1.e, Core Spray Pump Start - Time Delay Relay

- Function 2.d, Reactor Pressure - Low (Recirculation Discharge Valve Permissive)

- Function 2.e, Reactor Vessel Shroud Level - Level 0

- Function 2.f, Low Pressure Coolant Injection Pump Start - Time Delay Relay

- Function 2.g, Low Pressure Coolant Injection Pump Discharge Flow - Low (Bypass)

- Function 3.a, Reactor Vessel Water Level - Low Low (Level 2)

- Function 3.c, Reactor Vessel Water Level - High (Level 8)

- Function 3.e, Suppression Pool Water Level - High

- Function 3.f, High Pressure Coolant Injection Pump Discharge Flow - Low (Bypass)

- Function 4.b, 5.b, Automatic Depressurization System Initiation Timer

- Function 4.c, 5.c, Reactor Vessel Water Level - Low (Level 3) (Confirmatory)

- Function 4.d, 5.d, Core Spray Pump Discharge Pressure - High

- Function 4.e, 5.e, Low Pressure Coolant Injection Pump Discharge Pressure High TS 3.3.5.2. Reactor Core Isolation Cooling (RCIC) System Instrumentation SR 3.3.5.2.4 Perform CHANNEL CALIBRATION.

- Function 1, Reactor Vessel Water Level - Low Low (Level 2)

- Function 2, Reactor Vessel Water Level - High (Level 8)

TS 3.3.6.1. Primary Containment Isolation Instrumentation SR 3.3.6.1.4 Perform CHANNEL CALIBRATION.

- Function 1.a, 2.e, Reactor Vessel Water Level - Low Low Low (Level 1)

- Function 1.c, Main Steam Line Flow - High

- Function 1.e, Main Steam Tunnel Temperature - High

- Function 2.a, 6.b, Reactor Vessel Water Level- Low (Level 3)

- Function 2.b, Drywell Pressure - High

- Function 2.c, Reactor Building Ventilation Exhaust Plenum Radiation - High

- Function 2.d, Main Steam Line Radiation - High

- Function 3.a, HPCI [High Pressure Cooling Injection] Steam Line Flow - High

- Function 3.b, HPCI Steam Line Flow - Time Delay Relays

- Function 3.c, HPCI Steam Supply Line Pressure - Low

- Function 3.d, HPCI Steam Line Space Temperature - High

- Function 4.a, RCIC Steam Line Flow - High

- Function 4.b, RCIC Steam Line Flow - Time Delay Relays

- Function 4.c, RCIC Steam Supply Line Pressure - Low

- Function 4.d, RCIC Steam Line Space Temperature - High

- Function 5.a, RWCU [Reactor Water Cleanup] Flow - High

- Function 5.b, RWCU System Space Temperature - High

-18

- Function 5.d, Reactor Vessel Water Level - Low Low (Level 2)

- Function 6.a, Reactor Pressure - High SR 3.3.6.1.5 Calibrate each radiation detector.

- Function 2.d, Main Steam Line Radiation - High TS 3.3.6.2. Secondary Containment Isolation Instrumentation SR 3.3.6.2.3 Perform CHANNEL CALIBRATION.

- Function 1, Reactor Vessel Water Level - Low Low (Level 2)

- Function 2, Drywell Pressure - High

- Function 3, Reactor Building Ventilation Exhaust Plenum Radiation - High TS 3.3.6.3. Low-Low Set (LLS) Instrumentation SR 3.3.6.3.4 Perform CHANNEL CALIBRATION.

- Function 1, Reactor Pressure - High

- Function 2, Low-Low Set Pressure Setpoints

- Function 3, Discharge Line Pressure Switch TS 3.3.7.1. Control Room Emergency Filter (CREF) System Instrumentation SR 3.3.7.1.3 Perform CHANNEL CALIBRATION.

- Function 1, Reactor Vessel Water Level - Low Low (Level 2)

- Function 2, Drywell Pressure - High

- Function 3, Reactor Building Ventilation Exhaust Plenum Radiation - High TS 3.3.8.1. Loss of Power (LOP) Instrumentation SR 3.3.8.1.2 Perform CHANNEL CALIBRATION.

- Function 1.a, 4.16 kV Emergency Bus Undervoltage (Loss of Voltage) - Bus Undervoltage

- Function 1.b, 4.16 kV Emergency Bus Undervoltage (Loss of Voltage) - Time Delay

- Function 2.a, 4.16 kV Emergency Bus Normal Supply Undervoltage (Loss of Voltage) Bus - Tie Undervoltage

- Function 2.b, 4.16 kV Emergency Bus Normal Supply Undervoltage (Loss of Voltage) Time Delay

- Function 3.a, 4.16 kV Emergency Bus ESST [Emergency Station Service Transformer] Supply Undervoltage (Loss of Voltage) Bus - Tie Undervoltage

- Function 3.b, 4.16 kV Emergency Bus ESST Supply Undervoltage (Loss of Voltage) Time Delay

- Function 4.a, 4.16 kV Emergency Bus Undervoltage (Degraded Voltage) - Bus Undervoltage

- Function 4.b. 4.16 kV Emergency Bus Undervoltage (Degraded Voltage) - Time Delay (LOCA [Loss-of-Coolant Accident])

- Function 4.c. 4.16 kV Emergency Bus Undervoltage (Degraded Voltage) - Time Delay (Non-LOCA)

- Function 5.a, 4.16 kV Emergency Bus ESST Supply Undervoltage (Degraded Voltage) Bus Undervoltage

- Function 5.b. 4.16 kV Emergency Bus ESST Supply Undervoltage (Degraded Voltage) Time Delay

- 19 TS 3.3.8.2. Reactor Protection System (RPS) Electric Power Monitoring SR 3.3.8.2.1 Perform CHANNEL CALIBRATION.

- Function a, Overvoltage

- Function b, Undervoltage

- Function c, Underfrequency 3.3 TS 3.1.7. Standby Liquid Control (SLC) System - SRs 3.1.7.8 and 3.1.7.9 The licensee proposes to increase the surveillance test interval of these SRs from once every 18 months to once every 24 months, for a maximum interval of 30 months including the allowed 1.25 times the interval specified in the frequency. The flow path through one SLC subsystem is verified per SR 3.1.7.8 during every refueling outage on a staggered test basis. The heat-traced piping between the storage tank and pump suction is verified unblocked per SR 3.1.7.9 every refueling outage. Since these tests could inadvertently cause a reactor transient if performed with the unit operating, they are performed during outage conditions in order to decrease the potential impact of the tests.

The licensee stated that the SLC pumps are tested in accordance with the In-service Testing (1ST) Program per SR 3.1.7.7 to verify operability. Similarly, the temperature of the sodium pentaborate solution in the storage tank and the temperature of the pump suction piping are verified to be within limits every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months in accordance with SR 3.1.7.2 and SR 3.1.7.3 to preclude precipitation of the boron solution. In addition, an installed backup heater (automatically controlled) is used to maintain solution temperature above the saturation point (51 degrees Fahrenheit (OF) to 63 OF). SR 3.1.7.4 also verifies the continuity of the charge in the explosive valves. These more frequent tests ensure that the SLC system remains operable during the operating cycle. A review of the surveillance history verified that this subsystem had no previous failures of the TS functions that would have been detected solely by the periodic performance of these SRs.

The NRC staff concludes that due to the subsystem testing required by the TS surveillances and the history of the subsystem performance, the impact of this change on safety is minimal.

Based on the above, the NRC staff concludes that the proposed changes are acceptable based on (1) consistency with the guidance provided in the GL 91-04, (2) historical plant maintenance and surveillance data supporting the conclusion, and (3) that the assumptions in the plant licensing basis would not be invalidated as a result of this revision.

3.4 TS 3.1.8. Scram Discharge Volume (SDV) Vent and Drain Valves - SR 3.1.8.3 The licensee proposes to increase the surveillance test interval of this SR from once every 18 months to once every 24 months, for a maximum interval of 30 months including the allowed 1.25 times the interval specified in the frequency. This SR confirms that the SDV vent and drain valves close in less than 30 seconds after scram initiation, and open when the scram signal is reset.

The licensee stated that SR 3.1.8.2 requires that the SDV vent and drain valves be cycled fully closed and fully open every 92 days during the operating cycle, which ensures that the mechanical components and a portion of the valve logic remain operable. The licensee further stated that it has been previously accepted that the failure rate of components is dominated by the mechanical components, not by the logic systems. A review of the applicable plant

- 20 surveillance history demonstrated that the logic subsystem for the scram discharge volume vent and drain valves had no previous failures of the TS function that would have been detected solely by the periodic performance of this SR.

The NRC staff concludes that because of the manual cycling of the valves to ensure that the valves are operable, as required by SR 3.1.8.2, and the history of the logic subsystem performance, the impact of this change on safety is minimal. Based on the above, the NRC staff concludes that the proposed changes are acceptable based on (1) consistency with the guidance provided in the GL 91-04, (2) historical plant maintenance and surveillance data supporting the conclusion, and (3) that the assumptions in the plant licensing basis would not be invalidated as a result of this revision.

3.5 TS 3.4.3. Safety/Relief Valves (SRVs) and Safety Valves (SVs) - SR 3.4.3.2 SRVs are required to actuate automatically upon receipt of specific initiation signals. A manual actuation of each required SRV per SR 3.4.3.2 is performed to verify that the valve is functioning properly, and no blockage exists in the valve discharge line. The licensee proposes to increase the surveillance test interval of this SR from once every 18 months to once every 24 months, for a maximum interval of 30 months, including the allowed 1.25 times the interval specified in the frequency.

The licensee has stated that a review of the applicable CNS surveillance history has demonstrated that the SRVs had no previous failures of the TS function that would have been detected solely by the periodic performance of this SR. Based on the above, the NRC staff concludes that the effect on plant safety is small. The NRC staff concludes that the proposed changes are acceptable based on (1) consistency with the guidance provided in the GL 91-04, (2) historical plant maintenance and surveillance data supporting the conclusion, and (3) that the assumptions in the plant licensing basis would not be invalidated as a result of this revision.

3.6 TS 3.5.1, ECCS - Operating - SRs 3.5.1.8 - 3.5.1.11 and TS 3.5.2, ECCS - Shutdown - SR 3.5.2.5 The licensee proposes to increase the surveillance test interval of these SRs from once every 18 months to once every 24 months, for a maximum interval of 30 months including the allowed 1.25 times the interval specified in the frequency. These ECCS and Automatic Depressurization System (ADS) functional tests ensure that a system initiation signal will cause the systems or subsystems to operate as designed.

The licensee stated that the HPCI System tests are performed at two different pressure ranges.

This tests the system's capability to provide rated flow against a system head corresponding to reactor pressure at both the higher and lower operating ranges of the system. Adequate reactor pressure must be available and adequate steam flow must be passing through the main turbine or turbine bypass valves to continue to control reactor pressure when the HPCI System diverts steam flow. The note in the SR identifies that the test should be performed after adequate pressure and flow are achieved.

The licensee stated that the ECCS network has built-in redundancy so that no single failure could prevent the safety function of the ECCS. The pumps and valves are tested quarterly in accordance with the 1ST Program per SR 3.5.1.6 to verify operability. The tests proposed to be

- 21 extended need to be performed during outage conditions since they have the potential to initiate an unplanned transient if performed during operating conditions. A review of the applicable plant surveillance history demonstrated that ECCS had a handful of previous failures of the TS functions that would have been detected solely by the periodic performance of these SRs.

By letter dated May 24, 2012, the licensee concluded that the failures were unique and nonrecurring (including resolution through modification), or that the failures would not have prevented the required technical specification safety function, or that the failed components are subject to more frequent testing and would have been identified.

The NRC staff reviewed the proposed change and the licensee's justification for the change, and determined that because of the frequent testing of the system and the history of the system performance, the impact of this change on safety is minimal. Based on the above, the NRC staff concludes that the proposed changes are acceptable based on (1) consistency with the guidance provided in the GL 91-04, (2) historical plant maintenance and surveillance data supporting the conclusion, and (3) that the assumptions in the plant licensing basis would not be invalidated as a result of this revision.

3.7 TS 3.5.3, RCIC System - SRs 3.5.3.4 and 3.5.3.5 The licensee proposes to increase the surveillance test interval of these SRs from once every 18 months to once every 24 months, for a maximum interval of 30 months including the allowed 1.25 times the interval specified in the frequency. These RCIC functional tests ensure that the system will operate as designed.

The licensee stated that the pumps and valves are tested quarterly in accordance with the 1ST Program to verify operability and some valves may have independent relief to be tested at a different frequency. This testing ensures that the major components of the systems are capable of performing their design function. A review of the applicable plant surveillance history demonstrated that RCIC had no previous failures of these TS functions that would have been detected solely by the periodic performance of these SRs.

The NRC staff reviewed the proposed change and the licensee's justification for the change, and determined that because of the frequent testing of the system and the history of the system performance, the impact of this change on safety is minimal. Based on the above, the NRC staff concludes that the proposed changes are acceptable based on (1) consistency with the guidance provided in the GL 91-04, (2) historical plant maintenance and surveillance data supporting the conclusion, and (3) that the assumptions in the plant licensing basis would not be invalidated as a result of this revision.

3.8 TS 3.3.6.1, Primary Containment Isolation Instrumentation 3.8.1 SR 3.6.1.1.2 The licensee proposes to increase the surveillance test interval of this SR from once every 18 months to once every 24 months, for a maximum interval of 30 months including the TS SR 3.0.2 allowed 1.25 times the interval specified in the frequency. The licensee stated that the surveillance interval for this test was developed with a determination that performance during a unit outage was prudent and that other primary containment SRs would identify component

- 22 failures that could affect the results of this test. The licensee also stated that its review of the surveillance test history showed no failures of TS functions that could have been detected solely by performance of this SR. The licensee stated that the impact of the interval extension on system availability and unit safety is small.

The NRC staff concludes that extending this SR to once per 24 months is acceptable based on other tests and inspections that provide some indication of containment conditions that could affect the results of this test and the infrequency of SR failures, which provide reasonable assurance that plant safety would not be affected.

3.8.2 SR 3.6.1.3.7 The licensee proposes to increase the surveillance test interval of this SR from once every 18 months to once every 24 months, for a maximum interval of 30 months including the TS SR 3.0.2 allowed 1.25 times the interval specified in the frequency. An SR exists for exercising these valves and verifying acceptable stroke times in accordance with the 1ST Program. For most primary containment isolation valves (PCIVs) this is performed quarterly. These tests provide information about the condition of the PCIVs and much of the actuation circuitry. Most PCIVs are a redundant barrier in a containment penetration. The licensee stated that review of surveillance test history verified no previous failures of the TS functions that would have been detected solely by the periodic performance of this SR for PCIVs and the impact of this change on system availability and unit safety is small.

The NRC staff concludes that extending this SR frequency to once per 24 months is acceptable based on (1) the redundancy of the components involved, (2) the other, more frequent tests that provide some indication of PCIV and actuation circuitry condition, (3) the infrequency of SR failure, (4) the associated maintenance history of the PCIVs, and (5) the associated actuation circuitry, which provide reasonable assurance that plant safety would not be affected.

3.8.3 SR 3.6.1.3.8 The licensee proposes to increase the surveillance test interval of this SR from once every 18 months to once every 24 months, for a maximum interval of 30 months including the TS SR 3.0.2 allowed 1.25 times the interval specified in the frequency. The excess flow check valve (EFCV) testing interval is based on the need to perform the surveillance under the conditions that apply during a plant outage and the potential for unplanned system or plant transients if the surveillance were performed with the reactor at power. Surveillance performance consists of testing a representative sample of EFCVs such that the total population is tested every 10 years. Therefore, each valve is tested at least once every 10 years. The licensee stated that review of surveillance test history verified no previous failures of the TS functions that would have been detected solely by the periodic performance of this SR for EFCVs and the impact of this change on system availability and unit safety is small.

The NRC staff concludes that extending this SR frequency to once per 24 months is acceptable, because the sample testing nature of the surveillance and the infrequency of SR failures provides reasonable assurance that plant safety would not be affected.

- 23 3.8.4 SR 3.6.1.3.9 The licensee proposes to increase the surveillance test interval of this SR from once every 18 months on a staggered test basis to once every 24 months on a staggered test basis, for a maximum interval of 30 months including the TS SR 3.0.2 allowed 1.25 times the interval specified in the frequency. The Traversing Incore Probe (TIP) shear valve testing interval of 18 months has been considered adequate given the administrative controls on replacement charges and the more frequent (31-day) checks of explosive charge circuit continuity (SR 3.6.1.3.4). Surveillance performance consists of testing at least one of the four installed TIP shear valve squibs with all being tested over a 4-interval time period. The licensee stated that review of surveillance test history verified no previous failures of the TS functions that would have been detected solely by the periodic performance of this SR for TIP shear valves and the impact of this change on system availability and unit safety is small.

The NRC staff concludes that extending this SR frequency to once per 24 months is acceptable based on (1) the essentially sample testing nature of the surveillance, (2) more frequent check of explosive charge circuit continuity, and (3) the infrequency of SR failures, which provide reasonable assurance that plant safety would not be affected.

3.8.5 SR 3.6.1.3.11 The licensee proposes to increase the surveillance test interval of this SR from once every 18 months to once every 24 months, for a maximum interval of 30 months including the TS SR 3.0.2 allowed 1.25 times the interval specified in the frequency. The 24-inch primary containment purge and vent valve surveillance test, SR 3.6.1.3.11, is scheduled to be performed on a refueling outage frequency because the valves may have been unblocked to support refueling outage activities, so the SR verifies that the blocks have been reinstalled prior to entering a plant mode requiring containment integrity. The licensee stated that review of surveillance test history verified no previous failures of the TS functions that would have been detected solely by the periodic performance of this SR for the 24-inch primary containment purge and vent valves and the impact of this change on system availability and unit safety is small.

The NRC staff concludes that extending this SR frequency to once per 24 months is acceptable based on (1) the redundancy of the components involved, (2) the infrequency of SR failure, and (3) associated maintenance history of these valves, which provide reasonable assurance that plant safety would not be affected.

3.9 TS 3.6.1.6, low-low Set (llS) Valves - SRs 3.6.1.6.1 and 3.6.1.6.2 The licensee proposes to increase the surveillance test interval of this SR from once every 18 months to once every 24 months, for a maximum interval of 30 months including the allowed 1.25 times the interval specified in the frequency. The licensee stated that the frequency for SR 3.6.1.6.1 is based on the SRV tests required by the American Society of Mechanical Engineers Boiler and Pressure Vessel Code (ASME Code),Section XI. Operating experience has shown that these components usually pass the surveillance when performed at this frequency. Therefore, the licensee stated that the frequency was concluded to be acceptable from a reliability standpoint. Additionally, the licensee stated that extending the surveillance test

- 24 interval for SR 3.6.1.6.2 is acceptable because the functions are verified to be operating properly by the performance of more frequent Channel Functional Tests per SR 3.3.6.3.3.

This more frequent testing ensures that a major portion of the circuitry is operating properly and will detect significant failures within the instrument loop. Additionally, the LLS valves (Le., SRVs assigned to the LLS logic) are designed to meet applicable reliability, redundancy, single failure, and qualification standards and regulations as described in the CNS USAR. As such, these functions are designed to be highly reliable. The licensee has stated that a review of surveillance test history verified that the LLS valves had no previous failures of the TS functions that would have been detected solely by the periodic performance of these SRs.

Based on the review of the licensee's evaluation on impact to safety, the NRC staff concludes that the effect on plant safety is small. Based on the above, the NRC staff concludes that the proposed changes are acceptable based on (1) consistency with the guidance provided in the GL 91-04, (2) historical plant maintenance and surveillance data supporting the conclusion, (3) the inaccessibility of the SRVs during power operation, and (4) that the assumptions in the plant licensing basis would not be invalidated as a result of this revision.

3.10 TS 3.6.1.7! Reactor Building-to-Suppression Chamber Vacuum Breakers - SR 3.6.1.7.3, and TS 3.6.1.8, Suppression-Chamber-to-Drywell Vacuum Breakers - SR 3.6.1.8.3 3.10.1 SR 3.6.1. 7.3 The licensee proposes to increase the surveillance test interval of this SR from once every 18 months to once every 24 months, for a maximum interval of 30 months including the TS SR 3.0.2 allowed 1.25 times the interval specified in the frequency. The 18-month Frequency was based on the need to perform the surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the surveillance were performed with the reactor at power. SR 3.6.1.7.2 is performed at a shorter interval (92-day) and demonstrates in large part the proper functioning status of each reactor building-to-suppression chamber vacuum breaker. The licensee stated that review of surveillance test history verified no previous failures of the TS functions that would have been detected solely by the periodic performance of this SR for these vacuum breaker valves and the impact of this change on unit safety is small.

Based on the above, the NRC staff concludes that extending this SR frequency to once per 24 months is acceptable based on (1) the redundancy of the components involved, (2) the infrequency of SR failure, and (3) more frequently performed surveillance test that demonstrate functional status, which provide reasonable assurance that plant safety would not be affected.

3.10.2 SR 3.6.1.8.3 The licensee proposes to increase the surveillance test interval of this SR from once every 18 months to once every 24 months, for a maximum interval of 30 months including the TS SR 3.0.2 allowed 1.25 times the interval specified in the frequency. The 18-month Frequency was based on the need to perform the surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the surveillance were performed with the reactor at power. SR 3.6.1.7.2 is performed at a shorter interval (31-day) and demonstrates in large part the proper functioning status of each suppression chamber-to-drywell vacuum breaker. The licensee stated that review of surveillance test history verified no previous failures

- 25 of the TS functions that would have been detected solely by the periodic performance of this SR for these vacuum breaker valves and the impact of this change on unit safety is small.

Based on the above, the NRC staff concludes that extending this SR frequency to once per 24 months is acceptable based on (1) the redundancy of the components involved, (2) the infrequency of SR failure, and (3) more frequently performed surveillance test that demonstrate functional status, which provide reasonable assurance that plant safety would not be affected.

3.11 TS 3.6.4.1. Secondary Containment - SR 3.6.4.1.4 The licensee proposes to increase the surveillance test interval of this SR from once every 18 months on a staggered test basis to once every 24 months on a staggered test basis, for a maximum interval of 30 months including the TS SR 3.0.2 allowed 1.25 times the interval specified in the frequency. The surveillance test demonstrates that the secondary containment provides a sufficiently tight ventilation boundary to ensure retention and treatment of primary containment leakage during a design basis accident using one train of the standby gas treatment on an alternating basis. Surveillance tests SR 3.6.4.1.1 (24-hour), SR 3.6.4.1.2 (31 day), and SR 3.6.4.1.3 (31-day) provide more frequent assurance that secondary containment boundary remains sufficiently tight. The licensee stated in the LAR that a review of the applicable CNS surveillance history demonstrated that the secondary containment had one previous failure of the TS functions that would have been detected solely by the periodic performance of this SR. On January 30,2005, the differential pressure value was found outside the operability limit. Investigation determined that motor-operated valves were leaking. The test was subsequently re-performed satisfactorily. The identified failure was not associated with a time-based failure mechanism and thus not particularly relevant to the consideration of surveillance interval extension. Based on other more frequent testing of the system, and the history of system performance, the impact of this change on safety, if any, is small.

Based on the above, the NRC staff concludes that extending this SR frequency to once per 24 months is acceptable based on (1) the redundancy of the components involved, (2) the infrequency of SR failure, and (3) more frequently performed surveillance test that demonstrate secondary containment functional status, which provide reasonable assurance that plant safety would not be affected.

3.12 TS 3.6.4.2. Secondary Containment Isolation Valves (SCIVs) - SR 3.6.4.2.3 The licensee proposes to increase the surveillance test interval of this SR from once every 18 months to once every 24 months, for a maximum interval of 30 months including the TS SR 3.0.2 allowed 1.25 times the interval specified in the frequency. During the operating cycle, SR 3.6.4.2.2 requires that each power-operated automatic SCIV isolation time be tested (I.e.,

stroke timed to the closed position, generally on a quarterly basis) in accordance with the 1ST Program. The stroke testing of these SCIVs tests a portion of the circuitry and the mechanical function, and provides more frequent testing to detect failures. The licensee stated in the LAR that a review of surveillance test history verified that SCIVs had no previous failures of the TS function that would have been detected solely by the periodic performance of this SR and impact of the surveillance frequency change on system availability and safety is small.

Based on the above, the NRC staff concludes that extending this SR frequency to once per 24 months is acceptable based on the infrequency of SR failure and more frequently performed

- 26 surveillance test that demonstrate secondary containment functional status, which provide reasonable assurance that plant safety would not be affected.

3.13 TS 3.6.4.3, Standby Gas Treatment (SGT) System - SRs 3.6.4.3.3 and 3.6.4.3.4 3.13.1 SR 3.6.4.3.3 The licensee proposes to increase the surveillance test interval of this SR from once every 18 months to once every 24 months, for a maximum interval of 30 months including the TS SR 3.0.2 allowed 1.25 times the interval specified in the frequency. More frequent verification of portions of the SGT function is accomplished by operating each SGT subsystem and heaters every 31 days per SR 3.6.4.3.1. The licensee stated in the LAR that a review of the applicable CNS surveillance history demonstrated that the SGT System had no previous failures of the TS functions that would have been detected solely by the periodic performance of these SRs. The licensee further stated that any impact of the proposed interval change on system availability is minimal and that the impact on unit safety is small.

Based on the above, the NRC staff concludes that extending this SR frequency to once per 24 months is acceptable based on (1) the redundancy of SGT trains, (2) the infrequency of SR failures, and (3) more frequently performed surveillance test demonstrating SGT component functional status, which provide reasonable assurance that plant safety would not be affected.

3.13.2 SR 3.6.4.3.4 The licensee proposes to increase the surveillance test interval of this SR from once every 18 months to once every 24 months, for a maximum interval of 30 months including the TS SR 3.0.2 allowed 1.25 times the interval specified in the frequency. More frequent verifications of portions of the SGT function are accomplished by operating each SGT subsystem and heaters every 31 days per SR 3.6.4.3.1. The licensee stated in the LAR that a review of the applicable CNS surveillance history demonstrated that the SGT System had no previous failures of the TS functions that would have been detected solely by the periodic performance of these SRs. The licensee further stated that any impact of the proposed interval change on system availability is minimal and that the impact on unit safety is small.

Based on the above, the NRC staff concludes that extending this SR frequency to once per 24 months is acceptable based on (1) the redundancy of SGT trains, (2) the infrequency of SR failures, and (3) more frequently performed surveillance test demonstrating SGT component functional status, which provide reasonable assurance that plant safety would not be affected.

3.14 TS 3.7.2, Service Water (SW) System and Ultimate Heat Sink (UHS) - SR 3.7.2.4 The licensee proposes to increase the surveillance test interval of this SR from once every 18 months to once every 24 months, for a maximum interval of 30 months including the allowed 1.25 times the interval specified in the frequency. This SR verifies that the automatic isolation valves of the SW system will automatically switch to the safety or emergency position to provide cooling water exclusively to the safety-related equipment during an accident. This SR also verifies the automatic start capability of one of the two SW pumps in each subsystem. The SW subsystems are redundant so that no single failure prevents accomplishing the safety function of providing the required cooling.

- 27 The safety objective of the SW system is to provide a heat sink for the reactor equipment cooling (REC), residual heat removal (RHR), and diesel generator cooling systems under transient and accident conditions.

The licensee stated that the SW system pumps and valves are tested quarterly in accordance with the 1ST Program (some valves may have independent relief justifying less frequent testing).

This testing ensures that the major components of the systems are capable of performing their design function. Additionally, valves in the flow path are verified to be in the correct position every 31 days by SR 3.7.2.3. Since most of the components and associated circuits are tested on a more frequent basis, this testing would indicate any degradation to the SW system which would result in an inability to start based on a demand signal. The licensee's review of the applicable CNS surveillance history demonstrated that the SW system had no previous failures of the TS functions that would have been detected solely by the periodic performance of these SRs. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency.

Based on the review of the licensee's evaluation on the impact to safety, the NRC staff concludes that the effect on plant safety is small. Based on the above, the NRC staff concludes that the proposed changes are acceptable based on (1) consistency with the guidance provided in the GL 91-04, (2) historical plant maintenance and surveillance data supporting the conclusion, (3) subsystem testing required by the 1ST Program, and (4) that the assumptions in the plant licensing basis would not be invalidated as a result of this revision.

3.15 TS 3.7.3, Reactor Equipment Cooling (REG) System - SR 3.7.3.4 The licensee proposes to increase the surveillance test interval of this SR from once every 18 months to once every 24 months, for a maximum interval of 30 months, including the allowed 1.25 times the interval specified in the frequency. This SR verifies that the automatic isolation valves of the REC system will automatically switch to the safety or emergency position to provide cooling water exclusively to the safety-related equipment during an accident event. The safety objective of the REC system is to provide cooling to the ECCS areas.

The licensee stated that the REC system is designed with sufficient redundancy so that no single-active system component failure prevents accomplishing the safety function of providing the required cooling. The REC system pumps and valves are tested quarterly in accordance with the 1ST Program (some valves may have independent relief justifying less frequent testing).

This testing ensures that the major components of the systems are capable of performing their design function. Additionally, valves in the flow path are verified to be in the correct position every 31 days by SR 3.7.3.3. Since most of the components and associated circuits are tested on a more frequent basis, this testing would indicate any degradation to the REC system which would result in an inability to start based on a demand signal. The licensee's review of the applicable CNS surveillance history demonstrated that the REC system had no previous failure of the TS functions that would have been detected solely by the periodic performance of these SRs.

Based on the review of the licensee's evaluation on impact to safety, the NRC staff concludes that the effect on plant safety is small. Based on the above, the NRC staff

- 28 concludes that the proposed changes are acceptable based on (1) consistency with the guidance provided in the GL 91-04, (2) historical plant maintenance and surveillance data supporting the conclusion, (3) subsystem testing required by the 1ST Program, and (4) that the assumptions in the plant licensing basis would not be invalidated as a result of this revision.

3.16 TS 3.7.4. Control Room Emergency Filtration (CREF) System - SR 3.7.4.3 The licensee proposes to increase the surveillance test interval of this SR from once every 18 months to once every 24 months, for a maximum interval of 30 months including the TS SR 3.0.2 allowed 1.25 times the interval specified in the frequency. More frequent verification of portions of the control room emergency filter (control room emergency filtration) function is accomplished by operating the control room emergency filtration system (CREFS) every 31 days per SR 3.7.4.1. The licensee stated in the LAR that a review of the applicable CNS surveillance history demonstrated that the CREFS had no previous failures of the TS functions that would have been detected solely by the periodic performance of this SR. The licensee stated that any impact of the proposed interval change on system availability is minimal and that the impact on unit safety is small.

Based on the above, the NRC staff concludes that the proposed changes are acceptable based on the infrequency of SR failure and the more frequently performed surveillance test demonstrating CREFS component functional status, which provides reasonable assurance that plant safety would not be affected.

3.17 TS 3.7.7. The Main Turbine Bypass System - SRs 3.7.7.2 and 3.7.7.3 The main turbine bypass system dissipates the energy of main steam generated by the reactor, which cannot be utilized by the turbine. The turbine bypass system is designed to control reactor pressure, during reactor heatup to rated pressure, while the turbine is brought up to speed and synchronized, during power operation when the reactor steam generation exceeds the transient turbine steam requirements and limitations, and when cooling down the reactor. The turbine bypass system capacity is based on 25 percent of the turbine design flow. The licensee proposes to increase the surveillance test interval of this SR from once every 18 months to once every 24 months, for a maximum interval of 30 months, including the allowed 1.25 times the interval specified in the frequency.

3.17.1 SR 3.7.7.2 SR 3.7.7.2 requires testing to ensure that on increasing main steam line pressure events, the main turbine bypass system will operate as deSigned. More frequent verification of portions of the main turbine bypass system is accomplished by SR 3.7.7.1, which requires that each main turbine bypass valve be cycled through at least half of one cycle of full travel once every 31 days. This test demonstrates that the valves are mechanically operable, and detects significant failures affecting system operation.

- 29 The licensee stated in the LAR, in part, that A review of the applicable CNS surveillance history demonstrated that the main turbine bypass system had one previous failure of the TS functions that would have been detected solely by the periodic performance of these SRs:

On March 7, 2009, as-found voltage values for TG-XD/MW Loop Data Rack 01 K2, Slot R, TP-13 & TP-14, Rack 011 K6, Slot R, TP-38, and A Panel Display were out-of tolerance. The values were adjusted to within acceptable limits.

The licensee concluded that the identified failure is unique and does not occur on a repetitive basis and is not associated with a time-based failure mechanism. The licensee also concluded that this failure will have no impact on an extension to a 24-month surveillance interval. Based on the review of the licensee's evaluation on impact to safety, the NRC staff concludes that the effect on plant safety is small. Based on the above, the NRC staff concludes that the proposed changes are acceptable, based on other more frequent testing of the system and the history of system performance.

3.17.2 SR 3.7.7.3 The licensee stated in the LAR that extending the interval between response time tests is acceptable because the functions are verified to be operating properly throughout the operating cycle by the performance of Channel Checks and Channel Functional Tests (for SR 3.3.1.1.15) or by verifying proper operation of each bypass valve (for SR 3.7.7.3). This testing ensures that a significant portion of the circuitry is operating properly and will detect significant failures of this circuitry. The licensee also stated that additional justification for extending the surveillance test interval is that these functions, including the actuating logic, are designed to be single failure proof and, therefore, are highly reliable. In addition, the CNS TS Bases (as well as NUREG-1433, "Standard Technical Specifications BWRl4,") states that the frequency of response time testing is based, in part, "upon plant operating experience, which shows that random failures of instrumentation components causing serious response time degradation, but not channel failure, are infrequent occurrences."

The licensee stated in the LAR a review of the applicable CNS surveillance history demonstrated that the logic systems for these functions had the following nine failures of TS-required system response times that would have been detected solely by the periodic performance of these SRs:

a) On May 4, 2008, MS-LMS-A086A(A) RPS/Green Light was found out-of tolerance and outside the TS limit. The switch was adjusted to within satisfactory limits. SR 3.3.1.1.15}

b) On August 15, 2007, the RPS logic failed to initiate and reset as expected. CR-CNS-2007-05545 stated that IRM D did not have an INOP or UPSCALE TRIP as expected. WO 4583315 replaced relays K1B, K4B and K19B. (SR 3.3.1.1.15)

- 30 c) On February 8, 2006, three of the APRM [Average Power Range Monitor] C Flow Trip Setpoint values were found to be out-of-tolerance high exceeding the instrument, TRM [Technical Requirements Manual],

and TS limits. CR-CNS-2006-00994 documented the issue and the values were adjusted in tolerance. (SR 3.3.1.1.15) d) On January 25, 2005, Square Root Converter Board 1 (Z8) (NMF-SQRT 152A) was found out-of-tolerance. The Square Root Converter Card was replaced by WO 4423227 with as-left values satisfactorily. (SR 3.3.1.1.15) e) On April 6, 2004, three of the APRM E Flow Trip Setpoint values were found to be out-of-tolerance high exceeding the instrument limits.

Notification 10306116 stated that the values were adjusted in tolerance.

(SR 3.3.1.1.15) f) On April 4, 2003, transmitter RR-FT-11 OC could not be adjusted, causing numerous readings to be out-of-tolerance. Notification 10236953 was written to document the issue. The resolution to the Notification documented that the module was repaired. (SR 3.3.1.1.15) g) On November 20, 2002, APRM C did not perform correctly. A half-scram occurred during performance of the surveillance when it was not supposed to occur. Notification 10209105 was written to document the issue. Troubleshooting per WO 4279450 resulted in the replacement of a faulty relay. (SR 3.3.1.1.15) h) On December 23, 2001, MS-LMS-A086A(A) RPS/Green Light was found out-of tolerance and outside the TS Limit The switch was adjusted to within limits. (SR 3.3.1.1.15) i) On December 12,2001, NMF-SQRT-152D was found out-of-tolerance and would not hold its adjustment. Notification 10129473 was written to document the issue. WO 4213392 replaced NMF-SQRT-152D.

(SR 3.3.1.1.15)

In the LAR, the licensee stated, in part, that for the issues above:

The May 4, 2008, and December 23, 2001 issues involved Namco EA 180-32302 switches. There were a total of two failures identified relative to Namco EA180-32302 over the review period. In each case, the as-found closure time exceeded the TS limit.

The August 15,2007, February 8,2006, and April 6, 2004 issues involved APRM system events. There were a total of three failures identified relative to the APRM system over the review period. In each case, the as-found flow data values exceeded the instrument and/or TS limit.

- 31 In regards to the January 25, 2005, April 4, 2003, November 20, 2002, and December 12, 2001 events, no similar failures are identified. Therefore, the failures were not repetitive in nature.

The licensee concluded that the failures were not repetitive in nature. No time-based mechanisms were apparent. Therefore, the licensee concluded that these failures were unique, and any subsequent failures would not result in a significant impact on system or component availability.

Based on the review of the licensee's evaluation on impact to safety, the NRC staff concludes that the effect on plant safety is small. Based on the above, the NRC staff concludes that the proposed changes are acceptable based on (1) consistency with the guidance provided in the GL 91-04, (2) the history of logic system performance, (3) the corrective action for relay failures, and (4) that the assumptions in the plant licensing basis would not be invalidated as a result of this revision.

3.18 Electrical In Attachment 1, Section 3.1 of the LAR, the licensee stated that it has reviewed historical surveillance test data and associated maintenance records in evaluating the effect on safety for each component having a surveillance interval extended. Furthermore, the licensee stated that the licensing basis was reviewed for functions associated with each revision to ensure it was not invalidated. The licensee concluded that the results of these reviews demonstrate that the effect on plant safety is small and that the impact, if any, on system availability is minimal due to increasing the surveillance test intervals from 18 months to 24 months. The licensee also stated that the performance of surveillance extended for a 24 month fuel cycle will be trended as a part of the Maintenance Rule Program and any degradation in performance will be evaluated to verify that the degradation is not due to the extension of surveillance on maintenance activities.

The licensee proposes to extend the following surveillance intervals related to the electrical systems from 18 to 24 months in the CNS TSs.

3.18.1 TS 3.8.1, AC [Alternating Current] Sources - Operating - SRs 3.8.1.8 - 3.8.1.11 3.18.1.1 SR 3.8.1.8 This SR verifies automatic and manual capability to transfer of unit power supply from the normal offsite circuit to the alternate offsite circuit. A note to this SR states that this surveillance shall not be performed in MODE 1 or 2. However, credit may be taken for unplanned events that satisfy this SR.

3.18.1.2 SR 3.8.1.9 This SR verifies that each diesel generator (DG) operates for 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months or more under specified load conditions. Note 1 to this SR states that momentary transients outside the load and power factor ranges do not invalidate the test. Note 2 to this SR states that this surveillance shall not be performed in MODE 1 or 2. However, credit may be taken for unplanned events that satisfy this SR. Note 3 to this SR states that if performed with DG synchronized with offsite power the

- 32 power factor should be maintained at 0.89 or less than or equal to this limit as allowed by the grid conditions.

3.18.1.3 SR3.8.1.10 This SR verifies that the interval between each sequenced load is within +/-10 percent of the nominal timer setpoint. A note to this SR states that this surveillance shall not be performed in MODE 1, 2, or 3. However, credit may be taken for unplanned events that satisfy this SR.

3.18.1.4 SR 3.8.1.11 This SR verifies capability of each DG during an actual or simulated loss-of-offsite power signal coincident with an ECCS initiation. Note 1 to this SR states that the DG starts may be preceded by an engine prelube period. Note 2 to this SR states that this surveillance shall not be performed in MODE 1, 2, or 3. However, credit may be taken for unplanned events that satisfy this SR.

The surveillance test interval for the above SRs is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months including allowed 1.25 times the interval specified in the frequency. The CNS Class 1E distribution system supplies electrical power to two divisional load groups, with each division powered by an independent Class 1E 4.16 kiloVolt (kV) Engineered Safety Feature (ESF) bus. Each ESF bus has connections to two qualified offsite power sources and a single dedicated onsite DG. The ESF system of one of the two divisions provide for the minimum safety functions necessary to shut down the unit and maintain it in a safe shutdown condition. This design provides redundancy in AC power sources. The DGs are infrequently operated; therefore, the risk of wear-related degradation is minimal. Historical testing and surveillance testing during operation prove the ability of the diesel engines to start and operate under various conditions.

The licensee stated in Section 2 of the LAR that more frequent testing of the AC sources is performed as follows:

Verifying correct breaker alignment and indicated power availability for each required offsite circuit every 7 days (SR 3.8.1.1);

Verifying the DG starting and load carrying capability is demonstrated every 31 days (SR 3.8.1.2 and 3.8.1.3), and ability to continuously supply makeup fuel oil is also demonstrated every 92 days per (SR 3.8.1.6);

Verifying the ability of each DG to reach rated voltage and frequency within required time limits every 184 days (SR 3.8.1.7) will provide prompt identification of any substantial DG degradation or failure; Verifying the necessary support for DG start and operation (SRs 3.8.1.4, 3.8.1.5, 3.8.3.1, 3.8.3.2, 3.8.3.4 and 3.8.3.4.5) are required every 31 days;

- 33 Verifying fuel oil properties of new and stored fuel oil are tested in accordance with, and maintained within the limits of, the Diesel Fuel Oil Testing Program.

The licensee has identified five previous failures of the TS functions that would have been detected solely by the periodic performance of the listed SRs. The licensee stated that no similar failures were identified and concluded that these failures were not repetitive in nature, and no time-based mechanism were apparent. The licensee also stated that these failures were unique and subsequent failures would not be expected to significantly impact on system/component availability. The licensee stated that based on the above more frequent testing of the system, and the history of system performance, the impact of this change on safety, if any, is small.

The first criterion of GL 91-04 requires the licensee to evaluate the effect on safety due to the change to a 24-month fuel cycle. The NRC staff has reviewed the licensee's evaluation of SR 3.8.1.8, SR 3.8.1.9, SR 3.8.1.10, and SR 3.8.1.11 and verified that the impact of this change on safety, if any, is small. The second criterion of GL 91-04 requires the licensee to evaluate historical maintenance and surveillance data. The staff has reviewed the licensee's evaluation of the five previous failures connected to these SRs and agrees with the licensee's conclusion that these failures were unique and subsequent failures would not be expected to significantly impact system/component availability. The third criterion requires the licensee to evaluate the effects of performing the surveillances at the bounding interval. The staff confirmed that the licensee evaluated the effects of increasing the surveillance test intervals from 18 months to 24 months with the allowed 1.25 times the interval specified in the frequency. Based on the above, the NRC concludes that the proposed changes are consistent with GL 91-04 and are, therefore, acceptable.

3.18.2 TS 3.8.4. DC [Direct Current] Sources - Operating - SRs 3.8.4.6 and 3.8.4.7 3.18.2.1 SR 3.8.4.6 This SR requires verification that each required 125 Volt (V) and 250 V battery charger supplies a specified current for greater or equal to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

3.18.2.2 SR 3.8.4.7 This SR requires verification that battery capacity is adequate to supply, and maintain in OPERABLE status, the required emergency loads for the design duty cycle when subjected to a battery service test. Note 1 to this SR states that SR 3.8.4.8 may be performed in lieu of SR 3.8.4.7 once per 60 months. Note 2 to this SR states that this surveillance shall not be performed in MODE 1, 2, or 3. However, credit may be taken for unplanned events that satisfy this SR.

The surveillance test interval for these SRs is being increased from once every 18 months to once every 24 months for a maximum interval of 30 months, including the allowed 1.25 times the interval specified in the frequency. The DC power systems (125/250 V for power and control) supply DC power to station emergency equipment and selected safeguard system loads. The 125 V DC switchgear buses receive their power from either a station battery or a

- 34 battery charger. The redundant battery charger sources and the division of critical loads between buses yield a system that provides reliability.

The licensee stated in the LAR that more frequent testing of the DC sources is performed as follows:

Verifying 125 V and 250 V battery terminal voltage, and battery pilot cell electrolyte level, float voltage, and specific gravity, respectively every 7 days (SR 3.8.4.1 and SR 3.8.6.1);

Verifying connected cell electrolyte level, float voltage, and specific gravity, and average electrolyte temperature for representative cells every 92 days (SR 3.8.6.2 and SR 3.8.6.3);

Verifying no visible battery terminal/connector corrosion or high resistance every 92 days (SR 3.8.4.2).

The licensee identified one previous failure of the TS functions that would have been detected solely by the periodic performance of the listed SRs. The licensee stated that the identified failure is unique and does not occur on a repetitive basis and is not associated with a time based failure mechanism. Therefore, the licensee concluded that this failure will have no impact on an extension to a 24-month surveillance interval. The licensee further stated that based on more frequent testing of the system and the history of system performance, the impact of this change on safety, if any, is small.

The first criterion of GL 91-04 requires the licensee to evaluate the effect on safety due to the change to a 24-month fuel cycle. The NRC staff reviewed the licensee's evaluation of SR 3.8.4.6 and SR 3.8.4.7 and verified that the impact of this change on safety is small. The second criterion of GL 91-04 requires the licensee to evaluate historical maintenance and surveillance data. The staff reviewed the licensee's evaluation of the one previous failure connected to these SRs and agrees with the licensee's conclusion that this failure was unique and does not occur on a repetitive basis and is not associated with a time-based failure mechanism. The third criterion requires the licensee to evaluate the effects of performing the surveillances at the bounding interval. The staff confirmed that the licensee evaluated the effects of increasing the surveillance test intervals from 18 months to 24 months with the allowed 1.25 times the interval specified in the frequency. Based on the above, the NRC concludes that the proposed changes are consistent with GL 91-04 and are, therefore, acceptable.

3.18.3 Other Considerations - SR 3.8.4.8 This SR verifies that the battery capacity is greater than or equal to 90 percent of the manufacturer rating when subjected to a performance discharge test.

In Attachment 1 of the LAR, the licensee stated that it found that SR 3.8.4.8 was not eligible to be extended from 18 months to 24 months, and it will be maintained at 18 months. It is the NRC staff's position that SR 3.8.4.8 should be consistent with industry standard Institute of Electrical and Electronics Engineers, Inc. (IEEE) 450-1955 - "Recommended Practice for

- 35 Maintenance, Testing and Replacement of Vented Lead-Acid Batteries for Stationary Applications," Section 5.2 (c) which recommends, in part, that:

Annual performance tests of battery capacity should be made on any battery that shows signs of degradation or has reached 85 percent of the service life expected for the application. Degradation is indicated when the battery capacity drops more than 10 percent from its capacity on the previous performance test, or is below 90 percent of the manufacturer's rating.

By letter dated licensee May 24,2012, the licensee modified its request to revise SR 3.8.4.8 frequency of 18 months to 12 months, consistent with IEEE 450-1995.

3.18.4 Conclusion Based on the above, the NRC staff concludes that the proposed changes to surveillance intervals from 18 months to 24 months to the TS SRs related to AC Sources - Operating and DC Sources - Operating, are consistent with GL 91-04 and, therefore, are acceptable. The proposed changes will not impact the licensee's compliance with the regulatory requirements of 10 CFR 50.35(c)(3) and 10 CFR 50.55.

3.19 TS 5.5.2, Systems Integrity Monitoring Program This specification requires a program with the intent of minimizing leakage from portions of systems extending outside primary containment that could contain high levels of radioactive materials during transients or accidents. These include the ECCS core spray, HPCI, RHR, and RCIC. The specification indicates that this program shall include the requirement to perform an integrated leak test of each system at a frequency of 18 months consistent with the provision of SR 3.0.2. The licensee proposes to increase the surveillance test interval of this SR from once every 18 months to once every 24 months, for a maximum interval of 30 months including the TS SR 3.0.2 allowed 1.25 times the interval specified in the frequency. By letter dated September 17,2012, the licensee stated that the CNS designllicensing basis maximum allowable ECCS leakage criteria is 3000 cc/minute, that the licensee established an administrative limit of 800 cc/min total ECCS leakage to provide margin to that design value, and that the ECCS leakage had not exceeded the 800 cc/min limit. In the LAR, the licensee stated that most portions of the subject systems are walked down frequently and visually observed during routine plant operations, during plant system/component testing and/or operator/system engineer periodic walkdowns. Housekeeping/safety walkdowns would also serve to detect any gross leakage. If leakage is observed from these systems, corrective actions will be taken to repair the leakage. In addition, routine plant radiological surveys could potentially help identify any sources of leakage. The licensee stated that any impact of the proposed interval change on system availability is minimal and that the impact on unit safety is small.

Based on the above, the NRC staff concludes that extending this SR frequency to once per 24 months is acceptable based on the infrequency of SR failure and the more frequently performed visual inspections of these systems and area radiological contamination surveys that would detect any developing leakage, which provides reasonable assurance that plant safety would not be affected.

- 36 3.20 TS 5.5.7. Ventilation Filter Testing Program (VFTP)

The ventilation filter testing program establishes the required testing of engineered safety feature (ESF) filter ventilation systems (SGT and CREF). Specification 5.5.7a requires an in-place test of the HEPA filters for penetration and system bypass when tested in accordance with NRC Regulatory Guide (RG) 1.52, Revision 2, "Design, Inspection, and Testing Criteria for Air Filtration and Adsorption Units of Post-Accident Engineered-Safety-Feature Atmosphere Cleanup Systems in Light-Water-Cooled Nuclear Power Plants," March 1978 (ADAMS Accession No. ML003740139), Section C.5.c, and ASME N510-1989, "Testing of Nuclear Air-Cleaning Systems." SpeCification 5.5.7b requires an in-place penetration and system bypass test of the charcoal adsorbers in accordance with Regulatory Guide 1.52, Revision 2, Section C.5.d, and ASME N510-1989. Specification 5.5.7c requires a laboratory test for methyl iodide penetration of a sample of the charcoal adsorbers, when obtained as described in Regulatory Guide 1.52, Revision 2, Section C.6.b, when tested in accordance with the American Society for Testing and Materials (ASTM) D3803-1989, "Standard Test Methods for Nuclear Grade Activated Carbon." Specification 5.5.7d requires a test for pressure drop across the combined high-efficiency particulate air (HEPA) filters, the prefilters, and the charcoal adsorbers. Specification 5.5.7e requires heaters for the SGT System dissipate 7.8 kW when tested in accordance with ASME N510-1989, Section 14.5.1. These surveillance tests are required by Specification 5.5.7 to be performed at least once each 18 months. With the proposed change, the testing interval is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months, including the allowed 1.25 times the interval specified in the frequency provided by TS SR 3.0.2. The licensee stated in the LAR that a review of the applicable CNS surveillance history demonstrated that the ESF ventilation systems had one previous failure of the TS functions that would have been detected solely by the periodic performance of these SRs. The CREFS charcoal adsorber iodine penetration test exceeded the allowed limit in January of 2003 and the charcoal was subsequently replaced.

This was identified as resulting from a time-based failure mechanism but having occurred only once and with test results trended is judged unlikely to recur. The licensee further stated that the impact of extending the testing interval from 18 months to 24 months on unit safety was small.

Based on the above. the NRC staff concludes that extending the frequency of these surveillance tests to once per 24 months is acceptable based on the infrequency of surveillance test failures and the general acceptability of the 24-month interval for these tests recognized by incorporation in RG 1.52, Revision 3, June 2001 (ADAMS Accession No. ML011710176).

3.21 TS 5.5.13. Control Room Envelope Habitability Program Specification 5.5.13d Control Room Envelope (CRE) Habitability Program requires measurement of CRE pressure relative to all external areas adjacent to the CRE boundary during the pressurization mode of operation by the CREFS at a frequency of 18 months. With the proposed change, the testing interval is increased from once every 18 months to once every 24 months, for a maximum interval of 30 months, including allowed 1.25 times the interval specified in the frequency provided by TS SR 3.0.2. This program was placed in the CNS TSs as part of Amendment No. 230 dated May 12, 2008 (ADAMS Accession No. ML081220273),

which adopted TSTF-448, Revision 3, "Control Room Habitability," using the consolidated line item improvement process. The TSTF proposed a frequency for this particular surveillance in brackets, intended to allow for selection of an appropriate interval, typically that of the reactor

- 37 refueling cycle. The results of this test are trended and used as part of the periodic assessment of the CRE boundary and no acceptance criterion is identified in the TS. The licensee stated in the LAR that the impact of extending the testing interval from 18 months to 24 months on unit safety was small.

Based on the above, the NRC staff concludes that extending the frequency of this surveillance test to once per 24 months is acceptable based on the general acceptability of the 24-month interval for this test as recognized in TSTF-448, Revision 3.

3.22 TSTF-493, Revision 4, Option A 3.22.1 Background 3.22.1.1 Limiting Trip Setpoints The licensee added the term limiting trip setpoint (LTSP) as terminology for the setpoint value calculated by means of the plant-specific setpoint methodology documented in the Technical Requirements Manual.

The licensee stated that the LTSP is more conservative than the AV and is the least conservative value to which the instrument channel is adjusted following surveillance testil1g.

The LTSP is the limiting setting for the channel trip setpoint considering all credible instrument errors associated with the instrument channel. The nominal trip setpoint (NTSP) is the LTSP with margin added. The NTSP is as conservative as or more conservative than the LTSP. The LTSP is the least conservative value (with an as-left tolerance (ALT>> to which the channel must be reset at the conclusion of periodic testing to ensure that the AL will not be exceeded during an anticipated operational occurrence (AOO) or accident before the next periodic surveillance or calibration. It is impossible to set a physical instrument channel to an exact value, so a calibration tolerance is established around the LTSP. Therefore, an instrument adjustment is considered successful if the LTSP is within the ALT (i.e., a range of values around the LTSP).

The AVs are included in the CNS TSs. The AVs indicate the least conservative value that the as-found trip point may have during testing for the channel to be operable. The AVs listed in the TS satiSfy the 10 CFR 50.36 requirements that the LSSS be in the TSs. Additionally, to ensure proper use of the AV, LTSP, and NTSP, the methodology for calculating the AL T and as-found tolerances (AFT) are specified in the Technical Requirements Manual which is incorporated by reference in the USAR and listed in surveillance Note 2 as discussed in Section 3.22.1.2, below.

3.22.1.2 Addition of Surveillance Notes to TS Functions Setpoint calculations calculate an LTSP based on the AL of the safety analysis to ensure that trips or protective actions will occur prior to exceeding the process parameter value assumed by the safety analysis calculations. These setpoint calculations may also calculate an allowable limit of change to be expected (Le., the AFT) between performance of the surveillance tests for assessing the value of the setpoint setting. The least conservative as-found instrument setting value that a channel can have during calibration without requiring performance of a TS remedial action is the setpoint AV. Discovering an instrument setting to be less conservative than the setting AV indicates that there may not be sufficient margin between the LTSP setting and the AL. TS channel calibrations and channel functional tests (with setpoint verification) are

- 38 performed to verify channels are operating within the assumptions of the setpoint methodology used to calculate the LTSP and that channel settings have not exceeded the TS AVs. When the measured as-found setpoint is non-conservative with respect to the AV, the channel is inoperable and the actions identified in the TSs must be taken.

The license proposed two surveillance Notes for TS Table 3.3.1.1-1, Reactor Protection System Instrumentation, TS Table 3.3.2.1-1, Control Rod Block Instrumentation, TS Table 3.3.5.1-1, Emergency Core Cooling System Instrumentation, and TS Table 3.3.5.2-1, Reactor Core Isolation Cooling System Instrumentation. Proposed surveillance Note 1 would state:

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.

Proposed surveillance Note 1 requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is outside its AFT but conservative with respect to the AV. Evaluation of channel performance will verify that the channel will continue to function in accordance with safety analysis assumptions and the channel performance assumptions in the CNS setpoint methodology and establishes a high confidence of acceptable channel performance in the future. Because the AFT allows for both conservative and non conservative deviation from the LTSP, changes in channel performance that are conservative with respect to the LTSP will also be detected and evaluated for possible effects on expected performance. The purpose of the assessment is to ensure confidence in the channel performance prior to returning the channel to service. For channels determined to be OPERABLE but degraded, after returning the channel to service the channels will be evaluated under the CNS Corrective Action Program (CAP). Entry into the CAP will ensure required review and documentation of the condition to establish a reasonable expectation for continued operability.

Verifying that a trip setting is conservative with respect to the AV when a surveillance is performed does not by itself verify the instrument channel will operate properly in the future because setpoint drift is a concern. Although the channel was operable during the previous surveillance interval, if it is discovered that channel performance is outside the performance predicted by the plant setpoint calculations for the test interval, then the design basis for the channel may not be met, and proper operation of the channel for a future demand cannot be assured. The surveillance Note 1 formalizes the establishment of the appropriate AFT for each channel. This AFT is applied about the LTSP or about any other more conservative NTSP. The as-found setting tolerance ensures that channel operation is consistent with the assumptions or design inputs used in the setpoint calculations and establishes a high confidence of acceptable channel performance in the future. Because the setting tolerance allows for both conservative and non-conservative deviation from the LTSP, changes in channel performance that are conservative with respect to the LTSP will also be detected and evaluated for possible effects on expected performance.

Implementation of the surveillance Note 1 requires the licensee to calculate an AFT. The licensee calculated the AFT using as-found versus as-left calibration data analysis. The as-found versus as-left calibration data analysis is based on calculating drift by subtracting the previous as-left component setting from the current as-found setting. Each calibration point is treated as an independent set of data for purposes of characterizing drift across the full,

- 39 calibrated span of the component/loop. By evaluating as-found versus as-left data for a component/loop or a similar group of componentslloops, the following information may be obtained:

The typical component/loop drift between calibrations (Random in nature)

Any tendency for the component/loop to drift in a particular direction (Bias)

Any tendency for the component/loop drift to increase in magnitude over time (Time Dependency)

Confirmation that the selected setting or calibration tolerance is appropriate or achievable for the componentlloop The as-found versus the as-left data includes several sources of uncertainty over and above component drift. The difference between as-found and previous as-left data encompasses a number of instrument uncertainty terms in addition to drift. The drift is not assumed to encompass the errors associated with temperature effect, since the temperature difference between the two calibrations is not quantified, and is not anticipated to be significant. The following possible contributors could be included within the measured variation, but are not necessarily considered as such.

Accuracy errors present between any two consecutive calibrations

Measurement and test equipment error between any two consecutive calibrations

Personnel-induced or human-related variation or error between any two consecutive calibrations

Normal temperature effects due to a difference in ambient temperature between any two consecutive calibrations

Power supply variations between any two consecutive calibrations

Environmental effects on component performance, e.g., radiation, humidity, vibration, etc., between any two consecutive calibrations that cause a shift in component output

Misapplication, improper installation, or other operating effects that affect component calibration between any two consecutive calibrations

True drift representing a change, time-dependent or otherwise, in component/loop output over the time period between any two consecutive calibrations

- 40 The license proposed the following surveillance Note 2, which would state:

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.

Proposed surveillance Note 2 requires that the as-left setting for the channel be returned to within the ALT of the LTSP. Where a setpoint more conservative than the LTSP is used in the plant surveillance procedures, the ALT and AFT, as applicable, will be applied to the surveillance procedure setpoint. This will ensure that sufficient margin to the safety limit (SL) and AL is maintained. If the as-left channel setting cannot be returned to a setting within the AL T of the LTSP, then the channel would be declared inoperable. The second surveillance Note also requires that the LTSP and the methodologies for calculating the AL T and the AFT be included in the Technical Requirements Manual.

To implement surveillance Note 2, the ALT for some instrumentation Function channels is established to ensure that realistic values are used that do not mask instrument performance.

The licensee stated that setpoint calculations assume that the instrument setpoint is left at the LTSP within a specific AL T (e.g., 25 psig + 2 psig). A Tolerance is necessary because it is not possible to read and adjust a setting to an absolute value due to the readability and/or accuracy of the test instruments or the ability to adjust potentiometers. The licensee stated that the ALT is normally as small as possible considering the tools and the objective to meet an as low as reasonably achievable calibration setting of the instruments. The AL T is considered in the setpoint calculation. Failure to set the actual plant trip setpoint to the LTSP and within the AL T would invalidate the assumptions in the setpoint calculation because any subsequent instrument drift would not start from the expected as-left setpoint.

3.22.1.3 Functions Not Annotated with Surveillance Notes TSTF-493, Revision 4, Option A, as adopted by the licensee, states that for Functions not requiring the two surveillance Notes, the TS Bases are revised to reflect that a determination that the instrument is functioning as required will be performed prior to returning the channel to service when the channel is found conservative with respect to the AV but outside the predefined tolerance, AFT. This determination considers whether the instrument is degraded or is capable of being reset and performing its specified safety function. If the channel is determined to be functioning as required (i.e., the channel can be adjusted to within the ALT and is determined to be functioning normally based on the determination performed prior to returning the channel to service), then the channel is Operable and can be restored to service.

The licensee enters the as-found setting values condition into the CAP for further analysis and trending.

- 41 3.22.1.4 Evaluation of Exclusion Criteria Exclusion criteria are used to determine which Functions do not need to receive the additional surveillance test requirements. Instruments are excluded from the additional requirements when their functional purpose can be described as (1) a manual actuation circuit, (2) an automatic actuation logic circuit, or (3) an instrument function that derives input from contacts which have no associated sensor or adjustable device. Many permissives or interlocks are excluded if they derive input from a sensor or adjustable device that is tested as part of another TS function. The list of affected Functions in Table 2 of Attachment 1 of the LAR was developed by the licensee on the principle that all Functions in the affected TSs are included unless one or more of the exclusions that follow apply. In general, CNS excluded the following functions from additional surveillance testing requirements applied as surveillance Notes:

1. The two surveillance Notes are not applied to Functions which utilize manual actuation circuits, automatic actuation logic circuits, or to instrument functions that derive input from contacts which have no associated sensor or adjustable device (I.e., limit switches, breaker position switches, manual actuation switches, float switches, proximity detectors, etc.). In addition, the two surveillance Notes do not apply to those permissives and interlocks that derive input from a sensor or adjustable device that is tested as part of another TS function.

The two surveillance Notes are not applied to Functions which utilize mechanical components to sense the trip setpoint, or to manual initiation circuits (the latter are not explicitly modeled in the accident analysis) because current functional SRs, which have no setpoint verifications, adequately demonstrate the operability of these Functions. Surveillance Note 1 requires a comparison of the periodic SR results to provide an indication of channel (or individual device) performance.

This comparison is not valid for most mechanical components. While it is possible to verify that a limit switch performs its function at a point of travel, a change in the surveillance result is likely caused by the mechanical properties of the limit switch, for example, not that the input/output relationship has changed.

Therefore, a comparison of SR results would not provide an indication of the channel or component performance.

2. The two surveillance Notes are not applied to TSs associated with mechanically operated SRVs. The performance of these components is already controlled (i.e., trended with ALT and AFT) under the American Society of Mechanical Engineers (ASME) Code for Operation and Maintenance of Nuclear Power Plants testing program.

3. The two surveillance Notes are not normally applied to Functions and SRs, which test only digital components. Digital components, such as actuation logic circuits, relays, and input/output modules are not expected to exhibit drift characteristics; therefore, a change in result between surveillances or any test result other than the identified TS surveillance acceptance criteria would cause the digital component to be declared inoperable. However, where separate AL Ts and AFTs are established for digital component SRs, the Note requirements would apply.

- 42 The licensee has applied exclusion criteria to the following functions in the following TS Tables:

TS Table 3.3.1.1-1! "Reactor Protection System Instrumentation" Functions

1. Intermediate Range Monitors

b. Inop (Interlock)

2. Average Power Range Monitors

e. Inop (Interlock)

5. Main Steam Isolation Valve -- Closure (Mechanical component)

7. Scram Discharge Volume Water Level- High

b. Level Switch (Mechanical component)

8. Turbine Stop Valve - Closure (mechanical component)

10. Reactor Mode Switch - Shutdown Position (Manual actuation)

11. Manual Scram (Manual actuation)

TS Table 3.3.2.1-1! "Control Rod Block Instrumentation" Functions

1. Rod Block Monitor

d. Inop (Interlock)

e. Downscale (Not part of RPS or ECCS)

2. Rod Worth Minimizer (Not part of RPS or ECCS)

3. Reactor Mode Switch - Shutdown Position (Manual actuation)

TS Table 3.3.5.1-1, "Emergency Core Cooling System Instrumentation" Functions

1. Core Spray System

c. Reactor Pressure - Low (Injection Permissive) (Automatic actuation logic circuit)

d. Core Spray Pump Start-Time Delay Relay (Mechanical component)

2. Low Pressure Coolant Injection (LPCI) System

c. Reactor Pressure - Low (Injection Permissive) (Automatic actuation logic circuit)

d. Reactor Pressure - Low (Recirculation Discharge Valve Permissive)(Automatic actuation logic circuit)

e. Reactor Vessel Shroud Level -- Level 0 (Automatic actuation logic circuit)

f. Low Pressure Coolant Injection Pump Start-Time Delay Relay Pumps B, C (Interlock)

Pumps A, D (Interlock)

3. High Pressure Coolant Injection (HPCI) System

c. Reactor Vessel Water Level - High (Level 8) (This function is not assumed to function in the CNS Safety Analyses)

d. Emergency Condensate Storage Tank (ECST) Level- Low (mechanical component)

e. Suppression Pool Water Level - High (Mechanical component)

- 43

4. Automatic Depressurization System (ADS) Trip System A

b. Automatic Depressurization System Initiation Timer (Automatic actuation logic circuit)

d. Core Spray Pump Discharge Pressure - High (Automatic actuation logic circuit)

e. Low Pressure Coolant Injection Pump Discharge Pressure - High (Automatic actuation logic circuit)

5. ADS Trip System B

b. Automatic Depressurization System Initiation Timer (Automatic actuation logic circuit)

d. Core Spray Pump Discharge Pressure - High (Automatic actuation logic circuit)

e. Low Pressure Coolant Injection Pump Discharge Pressure - High (Automatic actuation logic circuit)

TS Table 3.3.5.2-1. "Reactor Core Isolation Cooling System Instrumentation" Functions

2. Reactor Vessel Water Level.:... High (Level 8) (This function is not assumed to function in the CNS Safety Analyses)

3. Emergency Condensate Storage Tank (ECST) Level - Low (Mechanical component)

The NRC staff reviewed the list of excluded TS functions and concludes that the above list is acceptable.

3.22.2 Technical Evaluation 3.22.2.1 Addition of Surveillance Notes to TS Functions The licensee has added surveillance Notes to the following TS instrumentation specifications:

TS 3.3.1.1, "Reactor Protection System Instrumentation," TS 3.3.2.1, "Control Rod Block Instrumentation," TS 3.3.5.1, "Emergency Core Cooling System Instrumentation," and TS 3.3.5.2, "Reactor Core Isolation Cooling System Instrumentation." The licensee stated that the determination to include surveillance Notes for specific Functions in these TS Tables is based on these functions being automatic protective devices related to variables having significant safety functions as delineated by 10 CFR 50.36(c)(1 )(ii)(A). Furthermore, the licensee stated that if during calibration testing the setpoint is found to be conservative with respect to the AV but outside its predefined AFT band, then the channel shall be brought back to within its predefined calibration tolerance before returning the channel to service. The calibration tolerances are specified in the licensee-controlled Technical Requirements Manual.

Changes to the values are controlled under the criteria of 10 CFR 50.59. The licensee has applied surveillance Notes to the following functions in the following TS Tables:

TS Table 3.3.1.1-1. "Reactor Protection System Instrumentation" Functions

1. Intermediate Range Monitors

a. Neutron Flux - High

- 44

2. Average Power Range Monitors

a. Neutron Flux - High (Startup)

b. Neutron Flux - High (Flow biased)

c. Neutron Flux - High (Fixed)

d. Downscale

3. Reactor Vessel Pressure - High

4. Reactor Vessel Water Level- Low (Level 3)

5. Drywell Pressure - High

7. Scram Discharge Volume Water Level- High

a. Level Transmitter

9. Turbine Control Valve Fast Closure, DEH (digital electro-hydraulic) Trip Oil Pressure - Low TS Table 3.3.2.1-1! "Control Rod Block Instrumentation" Functions

1. Rod Block Monitor

a. Low Power Range - Upscale

b. Intermediate Power Range - Upscale

c. Low Power Range - Upscale TS Table 3.3.5.1-1! "Emergency Core Cooling System Instrumentation" Functions

1. Core Spray System

a. Reactor Vessel Water Level - Low Low Low (Level 1)

b. Drywell Pressure - High

c. Core Spray Pump Discharge Flow - Low (Bypass)

2. Low Pressure Coolant Injection (LPCI) System

a. Reactor Vessel Water Level - Low Low Low (Level 1)

b. Drywell Pressure - High

g. Low Pressure Coolant Injection Pump Discharge Flow - Low (Bypass)

3. High Pressure Coolant Injection (HPCI) System

a. Reactor Vessel Water Level - Low Low (Level 2)

b. Drywell Pressure - High

f. High Pressure Coolant Injection Pump Discharge Flow - Low (Bypass)

4. Automatic Depressurization System (ADS) Trip System A

a. Reactor Vessel Water Level - Low Low Low (Level 1)

c. Reactor Vessel Water Level- Low (Level 3) (confirmatory)

5. ADS Trip System B

a. Reactor Vessel Water Level - Low Low Low (Level 1)

c. Reactor Vessel Water Level- Low (Level 3) (confirmatory)

- 45 TS Table 3.3.5.2-1, "Reactor Core Isolation Cooling System Instrumentation" Functions

1. Reactor Vessel Water Level - Low Low (Level 2)

The proposed surveillance notes will add the requirement to address operability of the subject functions in the TS as discussed in TSTF-493, Revision 4, Option A. The NRC staff reviewed the list of affected TS functions.

3.22.2.2 Evaluation of Surveillance Notes to TS Functions The proposed surveillance notes will ensure instrument operability will be maintained and that uncertainties will be included in the AFT calculations in an acceptable manner. By establishing the TS requirements in the surveillance notes, the licensee will ensure that there will be a reasonable expectation that these instruments will perform their safety function, if required.

Based on the above, the NRC staff concludes the addition of the notes to be acceptable. The NRC staff further concludes that the proposed TS changes are acceptable since they meet the requirements of 10 CFR 50.36(c)(3), in that the SRs will ensure that the necessary quality of systems are maintained, that the facility will be maintained within safety limits, and the LCOs will continue to be met.

3.23 NRC Staff Conclusion Based on the above evaluation, the NRC staff concludes that the proposed changes to the TS SRs to support the implementation of a 24-month fuel cycle for CNS are acceptable. The proposed LAR was evaluated by the NRC staff to determine whether applicable regulations and requirements continue to be met. The NRC staff concludes that the proposed changes do not require any exemptions or relief from regulatory requirements, other than the TS. Applicable regulatory requirements will continue to be met, adequate defense-in-depth will be maintained, and sufficient safety margins will be maintained. In addition, the NRC staff concludes that the adoption of TSTF-493, Revision 4, is acceptable. The licensee noted two deviations from the model safety evaluation. One is based on use of General Electric setpoint methodology instead of the industry standard guidance endorsed in TSTF-493. This deviation is acceptable since the GE setpoint methodology has been reviewed and accepted by the NRC staff as noted in Section 3.3 of this safety evaluation. The proposed changes will not impact the licensee's compliance to regulatory requirements as stated in Section 2.0 of this safety evaluation.

4.0 REGULATORY COMMITMENTS In its letter dated May 2, 2012, the licensee made the following regulatory commitment:

NPPD will supplement the 24-Month Cycle License Amendment Request to revise the SR 3.8.4.8 18-month frequency to 12 months, consistent with IEEE 450-1995. [NLS2012033-01]

By letter dated May 24, 2012, the licensee fulfilled the commitment.

- 46

5.0 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.

6.0 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. 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 6.2012 (77 FR 13371). 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.

Principal Contributors: Jerome Bettie Kristy Bucholtz Jennifer Gall Sergiu Basturescu Lynnea Wilkins Stephen Wyman Date: September 28,2012

ML12251A098 *by memo dated OFFICE NRRlDORULPL4/PM NRRlDORULPL4/LA NRRlDSSJSTSB/BC NRRlDE/EEEB/BC NRRlDSS/SRXB/BC NRRlDSS/SCVB/BC NAME LWilkins FLyon for JBurkhardt RElliolt' JAndersen* AUlses* SMiranda for RDennig' HWalker for DATE 9/12112 9/10/12 12/30/11 616/12 716112 7123112 OFFICE NRRlDE/EICB/BC SS/SBPB/BC NRRlDSS/SNPB/BC OGC -NLO NRRlDORULPL4/BC NRRlDORULPL4/PM NAME JThorp' GCasto AMendiola RWelsman MMarkley LWilkins DATE 8/30112 09/26/12 09/27/12 9125112 09/28/12 09/28/12

v t e Letter Sequence Approval
TAC:ME7169, Clarify Application of Setpoint Methodology for LSSS Functions (Approved, Closed)
Initiation Request Acceptance Supplement Administration Meeting, Meeting, Meeting Questions 2 March 2012 2 March 2012 3 April 2012 6 September 2012 Answers 17 September 2012 Results Approval, Approval Other:
MONTHYEAR2012-11-21 [Table View]

ML12251A098

Text

SUBJECT:

Dear Mr. O'Grady:

Enclosures:

Attachment:

1.0 INTRODUCTION

3.0 TECHNICAL EVALUATION

5.0 STATE CONSULTATION

6.0 ENVIRONMENTAL CONSIDERATION

7.0 CONCLUSION

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