Text

License Amendment, Issuance of Amendment No. 201, Revise Technical Specification 3.3.2, Engineered Safety Feature Actuation System (ESFAS) Instrumentation, for Extension of Completion Times
	ML111680536
Person / Time
Site:	Callaway
Issue date:	07/28/2011
From:	Thadani M; Plant Licensing Branch IV
To:	Heflin A; Union Electric Co
	Thadani, M C, NRR/DORL/LP4, 415-1476
References
	TAC ME2822
	Download: ML111680536 (37)
	v • d • e

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 July 28, 2011 Mr. Adam C. Heflin Senior Vice President and Chief Nuclear Officer Union Electric Company P.O. Box 620 Fulton, MO 65251

SUBJECT:

CALLAWAY PLANT, UNIT 1 - ISSUANCE OF AMENDMENT RE: COMPLETION TIME EXTENSIONS FOR TECHNICAL SPECIFICATION 3.3.2, "ENGINEERED SAFETY FEATURE ACTUATION SYSTEM (ESFAS) INSTRUMENTATION FUNCTIONS" (TAC NO. ME2822)

Dear Mr. Heflin:

The U.S. Nuclear Regulatory Commission (the Commission) has issued the enclosed Amendment No. 201 to Facility Operating License No. NPF-30 for the Callaway Plant, Unit 1.

The amendment consists of changes to the Technical Specifications (TSs) in response to your application dated November 25,2009, as supplemented by letters dated April 22, May 14, August 24, September 29, and November 4,2010, and February 23,2011.

The amendment revises TS 3.3.2, "Engineered Safety Feature Actuation System (ESFAS)

Instrumentation," to provide a 24-hour Completion Time (CT) for restoration of an inoperable Balance of Plant (BOP) ESFAS train and extends the CTs associated with individual instrument channels in the BOP ESFAS train to maintain overall consistency of related TS actions.

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

Sincerely,

~~.

Mohan C. Thadani, Senior Project Manager Plant licensing Branch IV Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-483

Enclosures:

1. Amendment No. 201 to NPF-30

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

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 UNION ELECTRIC COMPANY CALLAWAY PLANT. UNIT 1 DOCKET NO. 50-483 AMENDMENT TO FACILITY OPERATING LICENSE Amendment No. 201 License No. NPF-30

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

A. The application for amendment by Union Electric Company (UE, the licensee),

dated November 25,2009, as supplemented by letters dated April 22, May 14, August 24, September 29, and November 4,2010, and February 23,2011, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act) and the Commission's regulations set forth in 10 CFR Chapter I; B. The facility will operate in conformity with the application, the provisions of the Act, and the rules and regulations of the Commission; C. There is reasonable assurance (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commission's regulations; D. The issuance of this amendment will not be inimical to the common defense and security or to the health and safety of the public; and E. The issuance of this amendment is in accordance with 10 CFR Part 51 of the Commission's regulations and all applicable requirements have been satisfied.

Enclosure 1

-2

2. Accordingly, the license is amended by changes to the Technical Specifications as indicated in the attachment to this license amendment, and Paragraph 2.C.(2) of Facility Operating License No. NPF-30 is hereby amended to read as follows:

(2) Technical Specifications and Environmental Protection Plan*

The Technical Specifications contained in Appendix A, as revised through Amendment No. 201 and the Environmental Protection Plan contained in Appendix B, are hereby incorporated in the license. The licensee shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

3. This amendment is effective as of its date of issuance, and shall be implemented within 90 days of 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 Facility Operating License No. NPF-30 and Technical Specifications Date of Issuance: July 28,2011

ATTACHMENT TO LICENSE AMENDMENT NO. 201 FACILITY OPERATING LICENSE NO. NPF-30 DOCKET NO. 50-483 Replace the following pages of the Facility Operating License No. NPF-30 and Appendix A Technical Specifications with the attached revised pages. The revised pages are identified by amendment number and contain marginal lines indicating the areas of change.

Facility Operating License REMOVE INSERT

-3 -3 Technical Specifications REMOVE INSERT 3.3-29 3.3-29 3.3-31 3.3-31 3.3-32 3.3-32 3.3-33 3.3-33 3.3-46 3.3-46

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

C. This license shall be deemed to contain and is subject to the conditions specified in the Commission's regulations set forth in 10 CFR Chapter I and is subject to all applicable provisions of the Act and 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 UE is authorized to operate the facility at reactor core power levels not in excess of 3565 megawatts thermal (100% power) in accordance with the conditions specified herein.

(2) Technical Specifications and Environmental Protection Plan*

The Technical Specifications contained in Appendix A, as revised through Amendment No. 201 and the Environmental Protection Plan contained in Appendix B, are hereby incorporated in the license. The licensee shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

(3) Environmental Qualification (Section 3.11, SSER #3)**

Deleted per Amendment No. 169.

Amendments 133, 134, & 135 were effective as of April 30, 2000 however these amendments were implemented on April 1, 2000.

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

Amendment No. 201

ESFAS Instrumentation 3.3.2 ACTIONS (continued) i COMPLETION CONDITION REQUIRED ACTION TIME I. One channel inoperable. ------------------ NOTE ------------------

The inoperable channel may be bypassed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for surveillance testing of other channels.

1.1 Place channel in trip. 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR 1.2 Be in MODE 3. ! 78 hours9.027778e-4 days 0.0217 hours 1.289683e-4 weeks 2.9679e-5 months J. One channel inoperable. ------------------- NOTE ------------------

The inoperable channel may be bypassed for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months for surveillance testing of other channels.

J.1 Place channel in trip. 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OR J.2 Be in MODE 3. I 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months (continued)

CALLAWAY PLANT 3.3-29 Amendment No. 201

ESFAS Instrumentation 3.3.2 ACTIONS (continued)

COMPLETION CONDITION REQUIRED ACTION TIME M. Two channels inoperable. M.1 Place channels in trip. 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months AND QB AFW actuation on Trip of all M.2 Be in MODE 3.

30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months Main Feedwater Pumps maintained from one actuation train.

I N. One or more Containment N.1 Place channel(s) in trip. 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Pressure - Environmental Allowance Modifier OR channel(s) inoperable.

N.2.1 Be in MODE 3. 78 hours9.027778e-4 days 0.0217 hours 1.289683e-4 weeks 2.9679e-5 months AND N.2.2 Be in MODE 4. 84 hours9.722222e-4 days 0.0233 hours 1.388889e-4 weeks 3.1962e-5 months O. One channel inoperable. 0.1 Place channel in trip. 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months AND 0.2 Restore channel to During OPERABLE status. performance of the

! next required COT CALLAWAY PLANT 3.3-31 Amendment No. 201

ESFAS Instrumentation 3.3.2 ACTIONS (continued)

COMPLETION CONDITION REQUIRED ACTION TIME P. One or more channel(s) P.1 Declare associated Immediately inoperable. auxiliary feedwater pump(s) inoperable.

AND P.2 Declare associated Immediately steam generator blowdown and sample line isolation valve(s) inoperable.

Q One train inoperable. ------------------- NOTE ------------------

One train may be bypassed for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months for surveillance testing provided the other train is OPERABLE.

Q.1 Restore train to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OPERABLE status.

OR Q.2.1 Be in MODE 3. 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months AND Q.2.2 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months CALLAWAY PLANT 3.3-32 Amendment No. 201

ESFAS Instrumentation 3.3.2 ACTIONS (continued)

COMPLETION CONDITION REQUIRED ACTION TIME R. One or both train(s) R.1 Restore train(s) to 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months inoperable. OPERABLE status.

OR R.2.1 Be in MODE 3. 54 hours6.25e-4 days 0.015 hours 8.928571e-5 weeks 2.0547e-5 months AND R.2.2 Be in MODE 4. 60 hours6.944444e-4 days 0.0167 hours 9.920635e-5 weeks 2.283e-5 months S. One train inoperable ------------------- NOTE ------------------

One train may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing provided the other train is OPERABLE.

S.1 Restore train to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months OPERABLE status.

OR S.2.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months S.2.2 Be in MODE 4. 118 hours0.00137 days 0.0328 hours 1.951058e-4 weeks 4.4899e-5 months CALLAWAY PLANT 3.3-33 Amendment No. 201 I

ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 9 of 11)

Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE(a)

6. Auxiliary Feedwater

d. SG Water Level Low-Low (3) Not used.

(4) Containment 1,2,3 4 N SR 3.3.2.1 :s: 2.0 psig Pressure - SR 3.3.2.5 Environmental SR 3.3.2.9 Allowance SR 3.3.2.10 Modifier

e. Safety Injection Refer to Function 1 (Safety Injection) for all initiation functions and requirements.

f. Loss of Offsite 1,2,3 2 trains R SR 3.3.2.7 NA Power SR 3.3.2.10

g. Trip of all Main 1(v),2(n),(v) 4(U),(W) J,M SR 3.3.2.8 NA Feedwater Pumps

h. Auxiliary 1,2,3 3 0 SR 3.3.2.1 :c 20.64 psia Feedwater Pump SR 3.3.2.9 Suction Transfer SR 3.3.2.10 on Suction SR33212 Pressure - Low (a) The Allowable Value defines the limiting safety system setting except for Functions 1.e, 4.e.(1), S.c, S.e.(1), 5.e.(2),

6.d.(1), and 6.d.(2) (the Nominal Trip Setpoint defines the limiting safety system setting for these Functions). See the Bases for the Nominal Trip Setpoints.

(n) Trip function may be blocked just before shutdown of the last operating main feedwater pump and restored just after the first main feedwater pump is put into service following performance of its startup trip test.

(u) During startup of the second main feedwater pump, the following exception applies: The requirement for four OPERABLE channels is met if two required channels are OPERABLE on the associated main feedwater pump in operation supplying feedwater to the SGs and two required channels are in the tripped condition on the second main feedwater pump.

(v) During removal of the first of two operating main feedwater pumps from service, the following exception applies:

(1) LCO 3.0.3 is not applicable for up to 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months for the channels associated with the first main feedwater pump, OR (2) The requirement for four OPERABLE channels is met if two required channels are OPERABLE on the associated main feedwater pump in operation supplying feedwater to the SGs and two required channels on the main feedwater pump to be removed from service are in the tripped condition.

(w) During removal of the first of two operating main feedwater pumps from service, the following exception applies: The requirement for four OPERABLE channels is met if two required channels are OPERABLE on the associated main feedwater pump in operation supplying feedwater to the SGs and two required channels on the main feedwater pump to be removed from service are in the tripped condition.

CALLAWAY PLANT 3.3-46 Amendment No. 201

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 201 TO FACILITY OPERATING LICENSE NO. NPF-30 UNION ELECTRIC COMPANY CALLAWAY PLANT, UNIT 1 DOCKET NO. 50-483

1.0 INTRODUCTION

By application dated November 25, 2009 (Reference 1) as supplemented by letters dated April 22, May 14, August 24, September 29, and November 4,2010, and February 23,2011 (References 2, 3,4, 5,6, and 7, respectively), Union Electric Company (the licensee) requested changes to Facility Operating license No. NPF-30 for the Callaway Plant, Unit 1 (Callaway).

The amendment would revise Technical Specification (TS) 3.3.2, "Engineered Safety Feature Actuation System (ESFAS) Instrumentation" to provide a 24-hour Completion Time (CT) for restoration of an inoperable Balance of Plant (BOP) ESFAS train and to extend the CTs associated with individual instrument channels in the BOP ESFAS train to maintain overall consistency of related TS actions.

The supplemental letters dated April 22, May 14, August 24, September 29, and November 4, 2010, and February 23, 2011, provided additional information that clarified the application, did not expand the scope of the application as originally noticed, and did not change the U.S. Nuclear Regulatory Commission (NRC) staff's original proposed no significant hazards consideration determination as published in the Federal Register on May 18,2010 (75 FR 27833).

2.0 BACKGROUND

The ESFAS provides instrumentation and controls to sense accident situations and initiate the operation of necessary engineered safety features. The occurrence of a limiting fault, such as a loss-of-coolant accident (LOCA) or a steam line break, requires a reactor trip plus actuation of one or more of the engineered safety features in order to prevent or mitigate damage to the core and reactor coolant system components and ensure containment integrity.

In order to accomplish these design objectives, the engineered safety feature systems have proper and timely initiating Signals which are supplied by the sensors, transmitters, and logic components making up the various instrumentation channels of the ESFAS. These initiating signals are provided in the TS.

Enclosure 2

-2 By Reference 1 and as supplemented by References 2 through 7, the licensee requested a change to TS 3.3.2, "Engineered Safety Feature Actuation System (ESFAS) Instrumentation,"

that would modify Required Actions and CTs for Conditions "J," "0," and "Q"; add a new Condition "M"; and modify the channel description and notes of Function 6.g in TS Table 3.3.2-1.

The licensee proposed to extend the CT on Conditions "J" and "0" to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months and add a new Required Action to Condition "Q" requiring restoration of an inoperable BOP ESFAS train to operable status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months prior to initiating the remaining Required Actions. The licensee proposed a new Condition "M" to allow 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months for two channels to be inoperable on one of the two Main Feedwater (MFW) pump trip actuation logic trains which automatically start the motor-driven Auxiliary Feedwater (AFW) pumps. The licensee proposed to modify TS Table 3.3.2-1 Function 6.g "Required Channels" to "4" with additional footnotes to account for starting of the second of two MFW pumps and stopping of the first of two operating MFW pumps.

By letter dated May 5, 2010, the NRC staff approved Amendment No. 196 (Reference 8) for Callaway to change TS 3.3.2, "Engineered Safety Feature Actuation System (ESFAS)

Instrumentation," Condition "J" under Function 6.g in TS Table 3.3.2-1. The change was allowed because the NRC concluded that it was not necessary to enter TS 3.0.3 when Function 6.g in TS Table 3.3.2-1 was lost during start of the second of two MFW pumps. A licensee must enter TS 3.0.3 when a limiting condition for operation (LCO) is not met and the associated ACTIONS are not met, an associated ACTION is not provided, or if directed by the associated ACTIONS. The system design and procedure require manual blocking of the MFW pump oil low pressure trip signal to allow pump start. Function 6.g in TS Table 3.3.2-1 provides a start signal to the motor-driven AFW pumps in the event of a trip of both turbine-driven, non safety-related MFW pumps. The TS change allowed the licensee 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months to place the two trip logic channels from the same MFW pump in the trip condition, that is, one channel in each of the two actuation logic trains, when placing an MFW pump into service or removing that pump from service. Placing a channel in the trip condition enables one-half of the actuation logic.

Hence, the TS change resolved the licensee's issue on starting the second of two MFW pumps and stopping the first of two operating MFW pumps.

After the issuance of Amendment No. 196, the licensee recognized additional considerations that were not addressed by the TS change due to a restriction on separate entry conditions.

Therefore, in Reference 5, the licensee requested another revision to Condition "J" under Function 6.g in TS Table 3.3.2-1. Following discussions with the NRC staff, the licensee revised its proposed change to TS as described in Reference 7.

The licensee's TS 3.3.2 requires that the AFW auto-start function on trip of the MFW pumps be operable in MODES 1 and 2. MODE 1 is "power operation" with reactivity greater than 0.99 "K" effective (Keff) and power greater than 5 percent rated thermal power. MODE 2 is "startup" with reactivity greater than 0.99 Keff , but power less than 5 percent rated thermal power. The starting of the AFW pumps upon a trip of both MFW pumps is an anticipatory action of a loss of feedwater to ensure the intact steam generators (SGs) are provided with water to provide a heat sink for removal of reactor decay heat and sensible heat.

The licensee proposed allowing 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months to place anyone of the four trip channels associated with Function 6.g in TS Table 3.3.2-1 in trip when it becomes inoperable (Condition "J" modification), and 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months to place the second channel on the same actuation train in trip prior

-3 to having to commence a reactor shutdown (new Condition "M"). As a note in implementation of the new Condition "M" modification during higher power operations, the licensee would not put the second channel in trip, as the logic would be satisfied with an actuation signal to start the AFW pumps, and the licensee would either restore one channel or be in MODE 3 within 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months . Any further channel inoperability results in entry into TS LCO 3.0.3.

The AFW auto-start actuation is not required in MODES 3 ("hot standby"), 4 ("hot shutdown"),

and 5 ("cold shutdown"), because the turbine-driven MFW pumps are normally shut down.

Hence, an MFW pump trip would not be indicative of a condition requiring automatic AFW initiation in these modes. Footnote un" of Function 6.g in TS Table 3.3.2-1 already exists in TS 3.3.2, which allows blocking the AFW auto-start function when starting the first turbine-driven MFW pump. Footnote un" requires the restoration of the AFW auto-start function after the first turbine-driven MFW pump is put into service. Proposed Function 6.g in TS Table 3.3.2-1 footnotes "u," "v," and "w" would provide additional actions regarding starting of the second of two MFW pumps and stopping of the first of two operating MFW pumps.

2.1 Description of the Condensate and Feedwater System In the Callaway Final Safety Analysis Report (FSAR), the licensee describes that the design of the condensate and feedwater system (CFS) is to supply a sufficient quantity of feedwater to the secondary side of the four SGs during plant startup, shutdown, and normal operating conditions.

The safety function of the CFS is to provide a path for the addition of AFW to the SGs, and limit the addition of feedwater to a faulted SG.

The CFS includes two turbine-driven MFW pumps, each approximately 67 percent capacity.

The MFW pumps operate in parallel with independent speed-control units. Steam for the pump turbines is controlled by independent speed-control units. Steam for the pump turbines is supplied from the main steam header at low loads and from the moisture separator reheater outlet during normal operation. As there is insufficient main steam pressure during startup, one 480 gallon per minute (gpm) motor-driven feedwater pump is provided to supply feedwater to the SGs during startup and shutdown conditions.

2.2 Description of the Auxiliary Feedwater System In the FSAR, the licensee describes the AFW system as a safety-related system designed to automatically supply sufficient feedwater to the SGs to remove thermal energy from the reactor coolant system in the event of a loss of the MFW supply. The AFW system can be used following a reactor shutdown in conjunction with the condenser dump valves or atmospheric relief valves, to cool the reactor coolant system via the steam generators. The AFW system is not required during normal power generation. and the pumps are maintained in standby condition. However, if the normal motor-driven feedwater pump is not available, the AFW system may be used when the reactor is below 10 percent power to maintain SG water levels during plant heatup or cooldown.

The AFW system includes two 100-percent capacity (575 gpm) motor-driven AFW pumps and one 200-percent capacity (1145 gpm) steam turbine-driven AFW (TDAFW) pump. Each of the two motor-driven AFW pumps supply two SGs, and the TDAFW pump can supply all four SGs.

-4 The design basis accidents (DBAs) that impose AFW safety function requirements are loss of normal feedwater, main feed line or main steam line break, loss of offsite power (LOOP), and small break LOCA. These design-basis events credit an automatic actuation of the AFW system upon a LOOP, a safety injection (SI) signal, or low-low SG water level.

An automatic actuation signal to start both motor-driven AFW pumps is generated from:

1) a loss of offsite power,

2) low-low level signals in anyone SG,

3) A TWS (anticipated transient without scram) Mitigation System Activation Circuitry (AMSAC),

4) a manual initiation,

5) safeguards sequence signal, or

6) trip of both MFW pumps.

The TDAFW pump is started on:

1) a loss of offsite power,

2) low-low level in any two SGs,

3) AMSAC, or

4) a manual initiation.

2.3 Start of the Motor-Driven AFW Pumps Upon Trip of Both MFW Pumps The auto-start of AFW on loss of both MFW pumps is an anticipatory safety function designed to mitigate the operational impact of loss of feedwater events and is one of the six AFW actuation signals for the motor-driven AFW pumps methods discussed earlier. The AFW start on loss of MFW pumps is not a requirement in the licensee's current design-basis accident (DBA) analyses. Even though the auto-start of motor-driven AFW pumps occurring upon a trip of both MFW pumps is listed as an ESFAS function in TS Table 3.3.2-1, Function 6.g, this function is only an anticipatory start signal, and no credit is taken in the licensee's safety analysis as described in its FSAR.

A trip of both turbine-driven MFW pumps will result in a start of both motor-driven AFW pumps.

Each turbine-driven MFW pump is equipped with two pressure switches on its high pressure oil control header for its respective turbine control system. One pressure switch for each MFW pump is powered by "separation group 1" logic actuation train and a second pressure switch for each MFW pump is powered by "separation group 4" logic actuation train. If the two pressure switches in the same separation group, one from each MFW pump, sense a low pressure, then a signal will be generated that a trip of both turbine-driven MFW pumps has occurred. A trip condition indicates that MFW is no longer being supplied to the SGs. Upon sensing a loss of both turbine-driven MFW pumps, the ESFAS instrumentation will Signal an automatic start of both motor-driven AFW pumps. This start of the motor-driven AFW pumps is an anticipatory design feature to lessen the effects of a loss of feedwater transient.

The operators are provided with a manual block of the turbine-driven MFW pump trip signal to start AFW pumps at the main control board. TS Table 3.3.2, Function 6.g, footnote un" permits the blocking of the trip function just prior to startup of the first turbine-driven MFW pump and

- 5 shutdown of the last MFW pump. This blocking feature prevents an inadvertent start of the AFW pumps during startup and shutdown of one of the turbine-driven MFW pumps. Even with the block enabled, the AFW pumps remain available to respond to a start demand from any other valid start signal as listed earlier.

Starting of a turbine-driven MFW pump requires the control switch to be placed in the "reset" condition. "Reset" allows oil to pressurize the pump control header in order to open the turbine stop valves and enable the turbine control valves to respond to a demand signal. However, while in the MFW pump start sequence, "reset" also results in pressurizing the low pressure trip switches on the header, giving an incorrect input to the ESFAS logic that the MFW pump is operating and pumping feedwater to the SGs. Therefore, when the MFW pump turbine is in "reset" prior to actual MFW pump start, both of the MFW pump turbine control header low-oil pressure switches provide a false indication of MFW pump status (Le., the MFW pump is not actively supplying flow to the SGs). If a non-operating MFW pump is in "reset" and the operating MFW pump turbine trips, then all MFW flow would physically cease to the SGs. Since the non-operating MFW pump oil control header remains pressurized, the EFSAS actuation logic would not be satisfied, and the required auto-start signal to the motor-driven AFW pumps would not be initiated.

Therefore, a channel on the turbine-driven MFW pump trip logic that auto-starts the motor driven AFW pumps is operable if the pressure switch can actuate when its corresponding MFW pump is not providing feedwater to the SGs, as sensed by a low pressure condition. Otherwise, a channel can be placed in a trip condition, fulfilling its safety function by enabling half of the actuation logic on that train to accommodate pump starts or to meet Required Actions per the applicable TS LCO.

3.0 REGULATORY EVALUATION

3.1 Applicable Regulations 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 (SSCs) that are required to protect the health and safety of the public. The requirements related to the content of the TSs are established in Title 10 of the Code of Federal Regulations (10 CFR), Section 50.36, "Technical specifications." Pursuant to 10 CFR 50.36(c)(2), TSs are required to include: (1) safety limits, limiting safety system settings, and limiting control settings; (2) LCOs; (3) surveillance requirements; (4) design features; and (5) administrative controls.

The regulations in 10 CFR 50.36(c}(2}(i} state, in part, that Limiting conditions for operation are the lowest functional capability or performance levels of equipment required for safe operation of the facility. When a limiting condition for operation of a nuclear reactor is not met, the licensee shall shut down the reactor or follow any remedial action permitted by the technical specifications until the condition can be met.

- 6 The regulations in 10 CFR 50.36(c)(2)(ii) state, in part, that A technical specification limiting condition for operation of a nuclear reactor must be established for each item meeting one or more of the following criteria:

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

(B) Criterion 2. A process variable, design feature, or operating restriction that is an initial condition of a design basis accident or transient analysis that either assumes the failure of or presents a challenge to the integrity of a fission product barrier.

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

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

3.2 Applicable Regulatory Criteria/Guidelines The regulatory guidelines and criteria on which the NRC staff based its acceptance are:

NUREG-1431, Revision 3, "Standard Technical Specifications, Westinghouse Plants" (Reference 9), provides standardized guidance, including format and content, for improvement of TSs for Westinghouse Power Plants.

NRC Regulatory Guide (RG) 1.174, Revision 1, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis, (Reference 10), describes a risk-informed approach, acceptable to the NRC, for assessing the nature and impact of proposed permanent licensing-basis changes by considering engineering issues and applying risk insights. This regulatory guide also provides risk acceptance guidelines for evaluating the results of such evaluations.

-7 NRC RG 1.177, "An Approach for Plant-Specific, Risk-Informed Decisionmaking:

Technical Specifications" (Reference 11), describes an acceptable risk-informed approach specifically for assessing proposed permanent TS changes in allowed outage times. This regulatory guide also provides risk acceptance guidelines for evaluating the results of such assessments. RG 1.177 identifies a three-tiered approach for the licensee's evaluation of the risk associated with a proposed CT TS change, as discussed below:

Tier 1 assesses the risk impact of the proposed change in accordance with acceptance guidelines consistent with the Commission's Safety Goal Policy Statement, as documented in RG 1.174 and RG 1.177. The first tier assesses the impact on operational plant risk based on the change in core damage frequency (~CDF) and change in large early release frequency (~LERF). It also evaluates plant risk while equipment covered by the proposed CT is out-of-service, as represented by incremental conditional core damage probability (lCCDP) and incremental conditional large early release probability (ICLERP). Tier 1 also addresses probabilistic risk assessment (PRA) quality, including the technical adequacy of the licensee's plant-specific PRA for the subject application.

Cumulative risk of the present TS change in light of past related applications or additional applications under review are also considered along with uncertainty/sensitivity analysis with respect to the assumptions related to the proposed TS change.

Tier 2 identifies and evaluates any potential risk-significant plant equipment outage configurations that could result if equipment, in addition to that associated with the proposed license amendment, is taken out-of service simultaneously, or if other risk-significant operational factors, such as concurrent system or equipment testing, are also involved. The purpose of this evaluation is to ensure that there are appropriate restrictions in place such that risk-significant plant eqUipment outage configurations will not occur when equipment associated with the proposed CT is implemented.

Tier 3 addresses the licensee's overall configuration risk management program (CRMP) to ensure that adequate programs and procedures are in place for identifying risk-significant plant configurations resulting from maintenance or other operational activities and appropriate compensatory measures are taken to avoid risk significant configurations that may not have been considered when the Tier 2 evaluation was performed.

Compared with Tier 2, Tier 3 provides additional coverage to ensure risk significant plant equipment outage configurations are identified in a timely manner and that the risk impact of out of service equipment is appropriately evaluated prior to performing any maintenance activity over extended periods of plant operation. Tier 3 guidance can be satisfied by the Maintenance Rule (10 CFR 50.65(a)(4)), which requires a licensee to assess and manage the increase in risk that may result from activities such as surveillance testing and corrective and preventive maintenance,

-8 subject to the guidance provided in RG 1.177, Section 2.3.7.1, and the adequacy of the licensee's program and PRA model for this application.

The CRMP is to ensure that equipment removed from service prior to or during the proposed extended CT will be appropriately assessed from a risk perspective.

NRC RG 1.200, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities" (Reference 12), describes an acceptable approach for determining whether the quality of the PRA, in total or the parts that are used to support an application, is sufficient to provide confidence in the results, such that the PRA can be used in regulatory decision making for light water-reactors.

Guidance on evaluating PRA technical adequacy is provided in Chapter 19.1, "Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities," of the NRC Standard Review Plan (SRP), NUREG-0800 (Reference 13). More specific guidance related to risk-informed TS changes is provided in SRP Section 16.1, "Risk-Informed Decisionmaking: Technical Specifications" (Reference 14), which includes CT changes as part of risk-informed decision making. General guidance for evaluating the technical basis for proposed risk-informed changes is provided in Chapter 19.2, "Review of Risk Information Used to Support Permanent Plant-Specific Changes to the Licensing Basis: General Guidance" (Reference 15). Chapter 19.2 of the SRP states that a risk-informed application should be evaluated to ensure that the proposed changes meet the following key principles:

The proposed change meets the current regulations, unless it explicitly relates to a requested exemption or rule change.

The proposed change is consistent with the defense-in-depth philosophy.

The proposed change maintains sufficient safety margins.

When proposed changes increase core damage frequency or risk, the increase(s) should be small and consistent with the intent of the Commission's Safety Goal Policy Statement.

The impact of the proposed change should be monitored using performance measurement strategies.

4.0 TECHNICAL EVALUATION

The NRC staff has reviewed the licensee's analysis in support of its proposed license amendment, which are described in the original submittal in Reference 1 and as supplemented in References 2 through 7.

4.1 Review Methodology Per SRP Chapter 19.2 and Section 16.1 (References 14 and 15), the NRC staff reviewed the submittal using the three-tiered approach and the five key principles of risk-informed decision

-9 making presented in RG 1.174 and RG 1.177 (References 10 and 11). The key information for the traditional, deterministic engineering analysis was contained in Reference 1 for the modifications to TS 3.3.2 Conditions "0" and "Q" and Reference 7 for the additions and modifications to TS 3.3.2 Conditions "J" and "M" and Table 3.3.2-1, Function 6.g with accompanying footnotes. The key information used in the staff's risk-informed review was contained in Attachment 1, Section 4.0 of Reference 1 and Reference 10.

4.2 Comparison against Regulatory Criteria/Guidelines The NRC staff's evaluation of the licensee's proposed changes to TS 3.3.2 is presented in the following sections.

4.2.1 Key Principle 1: Compliance with Current Regulations The regulations in 10 CFR 50.36(c)(2)(i) require when an LCO is not met, that the licensee shut down the reactor or follow remedial action until the condition can be met. The NRC staff evaluated the licensee's proposed changes to the remedial action for the following section of TS Table 3.3.2-1:

4.2.1.1 Condition "Q" In Reference 1, the licensee proposed changes to Condition "Q," One train inoperable, associated with Function 6.c in TS Table 3.3.2-1. Current Condition "Q" Required Actions and CTs state:

Q.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months AND Q.2 Be in MODE 4. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Revised Condition "Q" Required Actions and CTs would state:

Q.1 Restore train to OPERABLE status. 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OR Q.2.1 Be in MODE 3. 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months AND Q.2.2 Be in MODE4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months

NRC Staff Evaluation

Function 6.c in TS Table 3.3.2-1 pertains to the AFW automatic actuation logic and actuation relays for BOP ESFAS. Two redundant trains are required to be operable in MODES 1, 2, and 3 to satisfy the LCO. The actuation logic receives process inputs from various systems and

- 10 initiates starting AFW pumps and repositions valves as required. With one train inoperable, the redundant train remains available to perform the required safety functions.

The regulations in 10 CFR 50.36{c){2){i) require a licensee to shut down the reactor when an LCO is not met, or follow specified remedial actions. The licensee is changing the allowed CT for one inoperable train to allow 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months to restore the train to operable status prior to having to shut down the reactor. Currently, Condition "Q" of TS 3.3.2 for Function 6.c of Table 3.3.2-1 requires the licensee to restore an inoperable channel or be in MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . The licensee provided a risk-informed submittal justifying the extension of the allowed CT to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . The NRC staff evaluated the risk impact upon the plant using a three-tiered approach presented in RG 1.177 and found the risk acceptable since the redundant train remains available to perform the required safety functions with one train inoperable.

The NRC staff concludes that the licensee's proposed revision to Condition "Q" provides an acceptable remedial action when the LCO is not met; therefore, the licensee will continue to meet the requirements of 10 CFR 50.36{c){2){i).

4.2.1.2 Condition "0" In Reference 1, the licensee proposed a change to Condition "0" associated with Function 6.h in TS Table 3.3.2-1. Current Condition "0" Required Action and CTs state:

0.1 Place channel in trip. 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months AND 0.2 Restore channel to OPERABLE During performance of the status. next required COT Revised Condition "0" Required Action and CTs would state:

0.1 Place channel in trip. 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 0.2 Restore channel to OPERABLE During performance of the status. next required COT

NRC Staff Evaluation

Function 6.h in TS Table 3.3.2-1 pertains to the AFW pump suction transfer on suction pressure. There are three (3) required channels, and the LCO is applicable in MODES 1, 2, and

3. A low pressure signal sensed by any two of the three switches will align the AFW pumps suction to the safety-related essential service water system. With one channel inoperable, the other two channels are sufficient to perform the required function.

The regulations in 10 CFR 50.36(c)(2)(i) require a licensee to shut down the reactor when an LCO is not met, or follow specified remedial actions. The licensee is changing the allowed CT

- 11 for one inoperable channel to allow 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months to restore the channel to operable status prior to having to shut down the reactor. Currently, Condition "0" requires the licensee to restore an inoperable channel within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . The licensee provided a risk-informed submittal justifying extending the allowed CT from 1 to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . The NRC staff evaluated the risk impact upon the plant using a three-tiered approach presented in RG 1.177 and found the risk acceptable since the other two channels are sufficient to perform the required function if one channel is inoperable.

The NRC staff concludes that the licensee's proposed revision to Condition "0" provides an acceptable remedial action when the LCD is not met; therefore, the licensee will continue to meet the requirements of 10 CFR 50.36(c)(2)(i).

4.2.1.3 Condition "J" In Reference 7, the licensee proposed the following changes to Condition "J" associated with Function 6.g in TS Table 3.3.2-1:

Current Condition "J" states:

One or more Main Feedwater Pumps trip channel(s) inoperable.

Revised Condition "J" would state:

One channel inoperable.

Current Condition "J" Required Actions and CTs state:

J.1 Place channel(s) in trip. 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months OR J.2 Be in MODE 3. 7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months Revised Condition "J" Required Actions and CTs would state:

J.1 Place channel in trip. 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OR J.2 Be in MODE 3. 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months

NRC Staff Evaluation

A trip of both MFW pumps indicates a loss of MFW and the subsequent need for AFW. A low pressure signal from either of two pump oil pressure switches indicates a pump trip. A signal from two channels (one channel on each pump) in the same train initiates an actuation signal and starts the motor-driven AFW pumps.

- 12 The proposed change would extend the current 1-hour CT to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months for the licensee to put an inoperable channel in a trip condition. Since this channel is the only inoperable channel, then the two channels on the redundant train are fully capable of sensing a loss of feedwater and will initiate an auto-start of AFW pumps. The proposed 24-hour CT is within the recommended completion time in NUREG-1431 (Reference 9). The NRC staff concludes that extending the proposed CT to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months to place an inoperable channel in trip is acceptable, based upon the redundant train being fully operable and the proposed CT is within the guidance provided in standard TS for this item. The licensee's proposed revision to Condition "J" provides an acceptable remedial action when the LCO is not met; therefore, the licensee will continue to meet the requirements of 10 CFR 50.36(c)(2)(i).

4.2.1.4 Condition "M" In Reference 7, the licensee proposed the following new Condition "M" associated with Function 6.g in TS Table 3.3.2-1:

M. Two channels inoperable. M.1 Place channels in trip. 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months AFW actuation on Trip M.2 Be in MODE 3. 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months of all Main Feedwater Pumps maintained from one actuation train.

NRC Staff Evaluation

In the event two channels become inoperable in the same train, the licensee would not elect to take the Required Action of putting the second channel in trip to implement Condition "M" during higher power operations since taking this action would satisfy the actuation logic to start the AFW pumps. The licensee clarified this position in the Condition M proposed TS Bases. The licensee would either choose to restore one channel or be in MODE 3 within 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months . A condition of two channels inoperable on one actuation train has the same functional consequences as one channel inoperable, which was previously evaluated as acceptable above. The NRC staff concludes that the proposed Condition "M" with a CT of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is acceptable for two channels inoperable on one actuation train, because the redundant train would be fully operable. The NRC staff concludes that the licensee's proposed revision to Condition "M" provides an acceptable remedial action when the LCO is not met; therefore, the licensee will continue to meet the requirements of 10 CFR 50.36(c)(2)(i).

4.2.1.5 Function 6.g In Reference 7, the licensee proposed to change the Required Channels for Function 6.g in TS Table 3.3.2-1 from "2 per pump" to "4," to represent four channels.

- 13

NRC Staff Evaluation

The licensee explains this change will better represent the design logic and facilitate an easier implementation of conditional statements should any channels become inoperable. The change does accurately depict the number of channels available to perform the safety function. The proposed change to four channels is different from standard TS in NUREG-1431 (Reference 9).

However, the NRC staff agrees that due to the uniqueness of the deSign, the specification would better represent the design by requiring "4" channels rather than "2 per pump."

Based on the above, the NRC staff concludes that the change to "4" channels is acceptable, because the "4" channels provides a more accurate description of the available channels the licensee can credit to perform this safety function. Therefore, the licensee's proposed TS change will continue to meet the requirements of 10 CFR 50.36( c)(2)(i).

4.2.1.6 Table 3.3.2-1, Function 6.9 Footnotes The licensee recognizes that a TS compliance conflict occurs during the starting of the second turbine-driven MFW pump and the stopping of the first of two operating turbine-driven MFW pumps. When a turbine-driven MFW pump is placed in "reset" condition, the pump is not providing flow to the SGs; however, both low-oil pressure trip channels for that pump are pressurized. In the reset condition, the MFW pump low-oil pressure trip channels are not giving an accurate signal to EFSAS system that the MFW pump is not providing flow to the SG.

Therefore, both channels on a pump in reset must be considered inoperable. With both channels on one pump inoperable, both trains of the actuation logiC cannot perform their safety function. This condition is prohibited by TS, and the licensee must enter TS 3.0.3. In order to accommodate the MFW pump's configuration during plant startup and shutdown, the licensee is proposing to add notes (v) to the applicable MODE 1, to add notes (n) and (v) to MODE 2, and notes (u) and (w) to the required channels associated with Function 6.g in TS Table 3.3.2-1.

Current footnote (n) in TS Table 3.3.2-1, Function 6.g, which applies only to MODE 2, states:

(n) Trip function may be blocked just before shutdown of the last operating main feedwater pump and restored just after the first main feedwater pump is put into service following performance of its status trip test.

New footnote (v) in TS Table 3.3.2-1, Function 6.g would apply to MODES 1 and 2 and would state:

(v) During removal of the first of two operating main feedwater pumps from service, the following exception applies:

(1) LCO 3.0.3 is not applicable for up to 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months for the channels associated with the first main feedwater pump, OR (2) The requirement for four OPERABLE channels is met if two required channels are OPERABLE on the associated main feedwater pump in operation supplying feedwater to the SGs and two required channels on the main feed water pump to be removed from service are in the tripped condition.

- 14 New footnotes (u) and (w) in TS Table 3.3.2-1, Function 6.g would apply to the required channels and would state:

(u) During startup of the second main feedwater pump, the following exception applies: The requirement for four OPERABLE channels is met if two required channels are OPERABLE on the associated main feedwater pump in operation supplying feedwater to the SGs and two required channels are in the tripped condition on the second main feedwater pump.

(w) During removal of the first of two operating main feedwater pumps from service, the following exception applies: The requirement for four OPERABLE channels is met if two required channels are OPERABLE on the associated main feedwater pump in operation supplying feedwater to the SGs and two required channels on the main feed water pump to be removed from service are in the tripped condition.

NRC Staff Evaluation

To account for the starting of the second of two turbine-driven MFW pumps, the licensee proposed footnote (u). During the starting of the second pump, the licensee can put the pump's two low-oil, pressure-sensing channels of the pump in a trip condition, which will enable one-half of the logic on both logic actuation trains. This condition will allow operators to start the second turbine-driven MFW pump, while still maintaining the AFW pump start logic in the event the operating turbine-driven MFW pump trips.

To account for the stopping of one of two operating turbine-driven MFW pumps during power reductions, the licensee proposed footnotes (v) and (w). To stop the first turbine-driven MFW pump, the licensee is proposing two options.

Option 1 allows the licensee to put the turbine-driven MFW pump two low-oil, pressure-sensing channels in a trip condition, which will enable one-half of the logic on both actuation trains. This condition will allow operators to ramp down pump flow in order to secure the first turbine-driven MFW pump, while still maintaining the AFW pump start logic in the event the operating turbine driven MFW pump trips.

Option 2 is an exception to entering TS 3.0.3 for 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months when one of two operating turbine driven MFW pumps is removed from service. During the time the pump is not flowing to the SG, both low-oil pressure sensors will remain pressurized for a period of time following pump operation as per procedure, which defeats the safety function on both logic trains to actuate AFW in the event the turbine-driven MFW pump providing flow to the SGs trips. If the MFW pump that is supplying the SG trips during this period, then AFW pumps would receive a start upon low low level in the SG, which is the credited start of the AFW pumps in the licensee accident analyses. During a public meeting held on January 25, 2011 (Reference 16), the licensee explained that per procedure, the operators will gradually ramp one turbine-driven MFW pump down to minimal flow while assuring the second MFW pump increases flow correspondingly. After the operators are assured the second MFW pump has the required flow

- 15 capacity to minimize any fluctuation in the flow rate to the SGs, the operators would secure the first turbine-driven MFW pump which results in actuating both low-oil pressure sensors on that MFW pump satisfying half the AFW actuation logic on both trains. During the time the pump is not flowing to the SG with the low-oil pressure switch pressurized, both trains of logic to start AFW upon turbine-driven MFW pump trip are inoperable; however, the AFW pumps remain capable to start on receipt of any other valid start demand signal.

In its letter dated February 23, 2011 (Reference 7), the licensee describes other combinations of channel inoperability that may occur that are not covered by the proposed TS condition. For example, two channels may become inoperable on the same MFW pump, making one channel inoperable on each train. The licensee states that these cases are not expected to occur as part of normal plant operation or during preventive maintenance. If such a condition should occur, then the licensee would enter TS 3.0.3, and shutdown the reactor.

The NRC staff has reviewed the proposed footnotes and concludes that the licensee's proposed footnotes are acceptable. With Option 1, during an MFW pump start or stop, if the licensee puts the starting pump pressure switches in trip, then the AFW pumps would still get a valid start signal from either of the two operable actuation trains, upon a loss of main feedwater flow should the operating turbine-driven MFW trip. Therefore, the function to start AFW upon loss of MFW is not lost but is degraded.

With Option 2, if the licensee does not place the two channels in trip and enacts the 1-hour exemption from entering TS 3.0.3, then the safety function to auto-start AFW pumps upon an MFW pump trip (TS Table 3.3.2-1, Function 6.g) is lost during the time the first turbine-driven MFW pump is operating but not providing flow. During this time, operators put one of the turbine-driven MFW pump in manual and ramp down to minimal or no flow. If the operating turbine-driven MFW pump should trip during this time, then the AFW auto-start logic would not actuate due to Function 6.g in TS Table 3.3.2-1 because the non-flowing pump oil pressure headers remain pressurized. With one pump oil header remaining pressurized, the AFW auto start logic only senses a half trip condition. Therefore, an AFW auto-start actuation would not occur. The licensee deems the short duration is acceptable based upon the low probability of a loss of feedwater during this 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , and that the AFW pumps would automatically start if feedwater was lost upon low SG level.

The NRC staff accepts the licensee justification for allowing 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months for this condition, based upon the very short CT, the AFW pumps would automatically start upon low SG level, and that the auto-start of AFW upon a loss of both MFW pumps being only an anticipatory function not credited in the licensee's DBA analyses. The licensee's proposed footnotes un," "u," "v," and "w" provides an acceptable remedial action when the LCO is not met; therefore, the licensee will continue to meet the requirements of 10 CFR 50.36(c)(2)(i).

- 16 4.2.2 Key Principle 2: Evaluations of Defense-in-Depth The NRC staff assessed the following elements of the defense-in-depth philosophy as described in RG 1.177 (Reference 11).

A reasonable balance among prevention of core damage, prevention of containment failure, and consequence mitigation is preserved.

The licensee attributes preservation of one operable train of BOP ESFAS to maintaining an adequate defense in depth. The licensee is not required to postulate a single failure of the redundant train while the plant is in an applicable TS required action. The licensee assesses there will not be any impact on core damage, containment release, or consequence mitigation, while the unit is in action statement, as long as the operable train functions as required. Based on the above, the NRC staff concludes that a reasonable balance among prevention of core damage, prevention of containment failure, and consequence mitigation is preserved.

Over-reliance on programmatic activities to compensate for weaknesses in plant design is avoided.

The licensee does not propose any additional programs or activities to compensate when a single train is inoperable outside the required actions of the applicable TS. Therefore, the NRC staff concludes that the proposed TS change would not involve an over-reliance on programmatic activities.

System redundancy, independence, and diversity are maintained commensurate with the expected frequency and consequences of challenges to the system.

The licensee maintains that the remaining operable train of BOP ESFAS will be available to perform the design safety function. Therefore, the NRC staff concludes that system redundancy, independence, and diversity will be maintained.

Defenses against potential common cause failures are maintained and the potential for the introduction of new common cause failure mechanisms is assessed.

The licensee's assessment revealed no new common cause failure modes will be introduced for the affected equipment. The licensee states one BOP ESFAS train will always be maintained in an operable status. Therefore, the NRC staff concludes that a common cause failure of both trains not to be credible.

Independence of physical barriers is not degraded.

The licensee states that proposed licensing amendment does not involve any modifications that would affect or degrade the independence of the fuel cladding, reactor coolant pressure boundary, or containment. Therefore, the NRC staff

- 17 concludes that physical barriers to radioactive release, such as the fuel cladding, reactor coolant piping, and the containment, will be maintained.

Defenses against human errors are maintained.

The licensee will not implement any specific compensatory measures to reduce the risk of human errors. The licensee contends that operator training will adequately inform the operating staff of these changes to the TS CTs.

Therefore, the NRC staff concludes that the licensee's actions are adequate to maintain a defense against human errors.

The intent of the General Design Criteria (GDC) in Appendix A to Title 10 of the Code of Federal Regulations, Part 50, is maintained.

The licensee does not modify the plant design of the BOP ESFAS system in the extension of CT for one train of BOP EFSAS inoperable to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . Therefore, NRC staff concludes that the intent of the General Design Criteria is maintained.

Based on the above evaluation of the individual elements, the NRC staff concludes that the proposed changes will remain consistent with the defense-in-depth philosophy.

4.2.3 Key Principle 3: Evaluation of Safety Margins The proposed change involves extensions of the CTs associated with BOP ESFAS functions identified in current TS 3.3.2 Condition "J," Condition "0," and Condition HQ," and a new Condition "M" and Function 6.g in TS Table 3.3.2-1 channel description change with additional footnotes. The licensee contends that existing safety margins will be maintained based upon "the operable BOP ESFAS train will continue to be capable of performing the necessary safety functions consistent with accident analysis assumptions." With a fully operable redundant train, the NRC staff agrees that the existing safety margins in the licensing basis will be maintained.

The licensee's evaluation of existing analyses in FSAR Chapter 15 determined there were no impacts on the assumptions or inputs into the safety analysis by the proposed changes. The licensee's evaluation of the proposed TS changes does not modify or otherwise impact codes and standards for the applicable BOP systems. In addition, the licensee proposes no physical changes to any of the BOP systems.

The NRC staff concludes that the proposed increase in CTs will not result in an unreasonable decrease in the availability of the safety function. During the time one train of BOP ESFAS is inoperable, the redundant train remains fully operable, therefore, the system retains the ability to solely provide the intended safety function. Therefore, based on the staff's assessment of the impact of the proposed TS changes on the established safety margins, the staff concludes that the existing safety margins will not be adversely affected, and the licensee will maintain the current margins of safety.

- 18 4.2.4 Key Principle 4: Evaluation of Core Damage Frequency (CDF) or Risk The evaluation presented below addresses the NRC staff's philosophy of risk-informed decision making, that when the proposed changes result in a change in CDF or risk, the increase should be small and consistent with the intent of the Commission's Safety Goal Policy Statement.

4.2.4.1 Tier 1: PRA Capability and Insights The first tier evaluates the impact of the proposed changes on plant operational risk. The NRC staffs Tier 1 review involves two aspects: (1) evaluation of the validity of the Callaway PRA mOdels and their application to the proposed changes, and (2) evaluation of the PRA results and insights based on the licensee's proposed application.

PRA Quality - Internal Events Model The objective of the PRA quality review is to determine whether the Callaway PRA used in evaluating the proposed changes to TS 3.3.2 CTs is of sufficient scope, level of detail, and technical adequacy for this application. The NRC staff's review evaluated the PRA quality information provided by the licensee in its submittals, including industry peer reviews results and self-assessments performed by the licensee.

The Callaway PRA model, identified as the Fourth PRA Update completed in April 2006, addresses both CDF and LERF for internal events, but excludes internal fires and floods.

Truncation levels applied to generate cutset results for this application have been demonstrated to be sufficiently low such that the results are not sensitive to changes in truncation level.

The licensee has administrative procedures and processes for configuration control of the PRA model, which includes monitoring of plant changes to the plant equipment and procedures. The licensee stated that no outstanding plant changes, implemented but not yet incorporated into the PRA models, were identified that would affect the analysis performed in support of this amendment request.

The licensee identified appropriate surrogate basic events to address the impact of an inoperable BOP ESFAS train, such that the Callaway model can be applied to assess the risk impact of the proposed change.

In November 2000, the Westinghouse Owners Group (WOG) performed a peer review of the Callaway PRA model. Since the completion of the peer review, all significant facts and observations have been addressed except for four items, which were dispositioned by the licensee as having minimal impact on the risk assessment supporting this application. A second peer review of the Callaway PRA was conducted by Scientech, Inc., using the American SOciety of Mechanical Engineers (ASME) PRA Standard ASME-RA-S-2002, ASME-RA-Sa-2003, and ASME-RA-Sb-2005, which is endorsed per RG 1.200, Revision 1. Capability category 11 of the standard was evaluated. The results of this self-assessment involving any failure to meet a supporting requirement at capability category II were identified and dispositioned by the licensee for this application.

- 19 The NRC staff's review of the licensee's basis for technical adequacy of the internal events PRA model determined that it is acceptable commensurate with the application. Specifically:

The licensee has developed and continues to maintain its PRA model consistent with plant configuration changes and with industry standards and consensus modeling approaches.

The licensee has performed technical reviews of its PRA model and has made appropriate changes based on those reviews.

The licensee has followed the process identified in staff-endorsed PRA standards to assess the technical adequacy of its model.

The risk impact of the BOP ESFAS is minimal given that it supports actuation logic which is able to be recovered by manual operator response, or by other actuation functions which provide diverse capabilities.

For this BOP ESFAS application, the risk impact is only the unavailability of one of the two trains of the actuation signals for BOP and the NRC staff has not identified any relevant PRA deficiencies. Based on these considerations, the NRC staff concludes that the quality of the Callaway internal events PRA is sufficient to support the risk evaluation provided by the licensee in support of the proposed license amendment.

PRA Quality - Internal Fires Model The licensee quantitatively evaluated internal fires using data and methods generally based on its Individual Plant Examination of External Events (IPEEE).

A comprehensive listing of all fire areas in the plant was provided, and screening criteria were applied to eliminate areas from further consideration where the impact of unavailable BOP ESFAS equipment would be negligible. This would be the case where a fire had minimal impact on any mitigation equipment, or where the damaged equipment was of such significance that the unavailability of BOP ESFAS would not significantly impact the conditional core damage probability for the area. The NRC staff reviewed the licensee's assessment of each fire area and agreed with the method applied and the screening results.

Twenty-five areas remained after the screening evaluation, and these areas were further evaluated for this application. In order to assess the risk of fire in these areas, the licensee developed a change in conditional probability based on the availability status of one AFW actuation train, and applied this conditional probability change to the frequency of fire in each area. The NRC staff notes that this approach conservatively assumes that the unavailability of the AFW system results directly in core damage.

The licensee analysis determined for each analyzed fire scenario whether a particular fire scenario causes direct damage to the AFW system components and cables, or significant damage to a particular safety train, and then developed unique conditional core damage probabilities to apply to these scenarios.

- 20 Based on the conservative treatment of fire risk, and considering the relatively minor impact calculated from risk associated with fire events for this application, the NRC staff concludes that the quality of the fire PRA and methods applied is sufficient to support the risk evaluation provided by the licensee in support of the proposed license amendment.

PRA Quality - Internal Floods Model The licensee quantitatively evaluated internal floods using data and methods generally based on its IPEEE.

A comprehensive listing of all flood areas in the plant was provided, and screening criteria were applied to eliminate areas from further consideration where the impact of unavailable BOP ESFAS equipment would be negligible. This would be the case where a flood had minimal impact on any mitigation equipment, or where the damaged equipment was of such significance that the unavailability of BOP ESFAS would not significantly impact the conditional core damage probability for the area. The NRC staff reviewed the licensee's assessment of each area and agreed with the method applied and the screening results.

Twenty-six areas remained after the screening evaluation, and these areas were further evaluated for this application. In order to assess the risk of internal floods in these areas, the licensee developed a change in conditional probability of failure of the AFW system, based on the availability status of one AFW actuation train and on the effect of the internal flood initiator, which fails a single train of either AFW or Emergency Service Water (ESW), which in turn fails the associated AFW train. The difference in the failure probability of AFW with the opposite actuation train of the BOP ESFAS also unavailable is used as the conditional core damage probability to be applied to the flooding initiators. The NRC staff notes that this approach conservatively assumes that the unavailability of the AFW system results directly in core damage. For four flood scenarios outside the normal power block, all AFW capability can be restored once the flood is isolated and normal service water restored, so a separate conditional probability of AFW failure was developed and applied to these scenarios.

Based on the conservative treatment of internal flood mitigation, and considering the relatively minor impact calculated from risk associated with internal flood events for this application, the NRC staff concludes that the quality of the internal flood PRA model and methods applied is sufficient to support the risk evaluation provided by the licensee in support of the proposed license amendment.

PRA Risk Results and Insights The unavailability of the BOP ESFAS train can be explicitly modeled in the internal events PRA and, as described above for fires and floods, in the AFW unavailability logic. The internal events PRA directly calculates a change in the core damage frequency. The fire and internal flooding analysis conservatively assume that the unavailability of AFW directly leads to core damage.

The licensee identified that the BOP ESFAS impact on LERF is minimal. The impact of the BOP ESFAS outage is limited to the containment purge supply and exhaust valves, which are required to be closed per TS 3.3.6 Condition B upon failure of a BOP ESFAS train. Other PRA

- 21 modeled containment isolation valves are not impacted by the BOP ESFAS. A bounding evaluation was made considering the potential that the containment purge valves, if open when a BOP ESFAS train outage occurs, may not close. This bounding evaluation was then applied to the core damage sequences to determine a LERF metric for this application.

The licensee assumed, for the calculation of the 6CDF and 6LERF metric, that the extended CT is applied once per year. Although more frequent application is not prohibited by the proposed TS, there is significant margin available to accommodate additional unplanned use of the CT.

Therefore, the 6CDF and 6LERF are numerically equivalent to the ICCDP and ICLERP probabilities.

The licensee's methodology is consistent with the guidance of RG 1.177, Section 2.3.4 and Section 2.4 and is, therefore, acceptable to the NRC staff.

The licensee presented risk results for internal events, including fires and floods. The results are as follows:

Risk Measure Internal Events Internal Fires Iinternal Floods Total ICCDP 7.2E-9 4.6E-8 3.2E-9 5.6E-8 ICLERP 2.6E-10 9.6E-11 6.7E-12 3.6E-10 Per RG 1.177, the acceptance guidelines for ICCDP and ICLERP are 5E-7 and 5E-8, respectively, applicable to permanent changes to the TS. Per RG 1.174, the acceptance guidelines for .:lCDF and .:lLERF are 1E-6/year and 1E-7/year, respectively, for very small changes in risk, also applicable to permanent changes. Assuming the extended CT would be entered once per year, the .:lCDF and .:lLERF are numerically equivalent to the ICCDP and ICLERP. The licensee's estimates of internal events and fire risk are thus consistent with these acceptance guidelines. The NRC staff notes that the calculated change in risk provides significant margin to accommodate entry into the TS condition more frequently than once per year without challenging the RG 1.174 acceptance guidance for very small changes in risk.

Based on the above. the NRC staff concludes that the risk impact of the proposed TS change is acceptable.

Evaluation of Seismic Risk The Callaway seismic design is robust, in that the original, generic Standardized Nuclear Unit Power Plant System (SNUPPS) design incorporated additional design conservatism to accommodate a number of different plant sites. A seismic margins assessment was conducted for the IPEEE which screened out all but twenty-two components, none of which are part of the BOP ESFAS or AFW system. Based on the above, the NRC staff concludes that seismic risk is not a significant contributor to the risk during a BOP ESFAS outage and is, therefore, acceptable.

Qualitative Evaluation of External Hazards Callaway conforms to the Standard Review Plan requirements with regards to external hazards, as discussed in the IPEEE submittal. Therefore, no vulnerabilities to other external events exist

- 22 at Callaway. Based on the conformance of the plant to the SRP, the NRC staff concludes that the risk contribution from other external hazards is not significant for this application.

Shutdown Risk The licensee's submittal did not specifically address shutdown risk in the tier one risk evaluation, and the proposed change to TS is not applicable to shutdown conditions.

Uncertainty Analysis The licensee provided uncertainty sensitivity analyses discussed above relevant to the assumption of availability of motor-driven AFW pumps during fire events. The significant margins to the acceptance guidance calculated for this application accommodate uncertainties inherent in the PRA, and no further detailed quantitative evaluation is necessary.

4.2.4.2 Tier 2: Avoidance of Risk-Significant Plant Configuration The licensee stated that no credit was taken for any compensatory measures in the risk evaluation supporting this application. Credit was taken for TS required actions related to the containment purge valves, discussed above in the LERF calculations, and the proposed TS extended CTs only apply to configurations where at least one BOP ESFAS train is operable. No other tier 2 restrictions were identified. Since the configuration is not risk-significant, the NRC staff concludes this is acceptable.

4.2.4.3 Tier 3: Risk-Informed Configuration Risk Management The licensee stated that its Configuration Risk Management Program (CRMP), implemented through applicable plant procedures, ensures that the risk impact of equipment out of service is appropriately evaluated prior to performing any maintenance activity. The program provides for proceduralized risk-informed assessment of equipment unavailability. Administrative controls are implemented based on the level of risk.

4.2.5 Key Principle 5: Performance Measurement Strategies - Implementation and Monitoring Program RG 1.174 and RG 1.177 establish the need for an implementation and monitoring program to ensure that extensions to TS CTs do not degrade operational safety over time and that no adverse degradation occurs due to unanticipated degradation or common cause mechanisms.

An implementation and monitoring program is intended to ensure that the impact of the proposed TS change continues to reflect the reliability and availability of SSCs impacted by the change. RG 1.174 states that monitoring performed in conformance with the Maintenance Rule, 10 CFR 50.65, can be used when the monitoring performed is sufficient for the SSCs affected by the risk-informed application.

5.0

SUMMARY

The NRC staff concludes that extending the proposed CT to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months to place an inoperable channel in trip and allowing 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months for two inoperable channels on the same actuation logic

- 23 train is acceptable, because the redundant train would be fully operable. The NRC staff also concludes that this change provides an acceptable remedial action per 10 CFR 50.36(c){2){i) and that the proposed CT is consistent with the guidance provided in standard TS for this item.

The NRC staff agrees that due to Callaway's design, TS 3.3.2, Function 6.g, "Trip of all main feedwater pumps," would be better represented by the required channels proposed terminology of four channels rather than two per pump. The NRC staff has reviewed the proposed footnotes and concludes the licensee's proposed footnotes to be acceptable.

The NRC staff has reviewed the traditional engineering aspects of the licensee's evaluation related to the proposed changes to TSs. Based on the results of the evaluation of traditional engineering considerations, the staff concludes that the proposed changes are consistent with current regulations, defense-in-depth attributes, and maintenance of adequate safety margins.

The risk impact of the proposed 24-hour CT for the BOP ESFAS, as reflected in ACDF, ALERF, ICCDP, and ICLERP, is consistent with the acceptance guidelines specified in RG 1.174, RG 1.177, and staff guidance outlined in Chapter 16.1, "Risk-Informed Decisionmaking:

Technical Specifications," of NUREG-0800. The Tier 2 evaluation was conducted to identify any applicable risk-significant plant equipment outage configurations to be avoided, and appropriate TS controls are in place to assure these restrictions are in place. The licensee's CRMP satisfies the requirements of RG 1.177. Therefore, the NRC staff concludes that the risk analysis methodology and approach used by the licensee to estimate the risk impacts and manage configuration risk are reasonable and of sufficient quality.

The NRC staff concludes that the proposed changes to TS 3.3.2, "Engineered Safety Features Actuation System (ESFAS) Instrumentation," meet the requirements of 10 CFR 50.36 and the guidelines provided in RG 1.177. Therefore, the staff concludes the proposed changes are acceptable.

6.0 STATE CONSULTATION

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

7.0 ENVIRONMENTAL CONSIDERATION

The amendment changes a requirement with respect to the installation or use of a facility component located within the restricted area as defined in 10 CFR Part 20. The NRC staff has determined that the amendment involves no significant increase in the amounts, and no significant change in the types, of any effluents that may be released offsite, and that there is no significant increase in individual or cumulative occupational radiation exposure. The Commission has previously issued a proposed finding that the amendment involves no significant hazards consideration and there has been no public comment on such finding published in Federal Register on May 18, 2010 (75 FR 27833). 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.

- 24

8.0 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) 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.

9.0 REFERENCES

1. Sandbothe, S., AmerenUE, letter to U.S. Nuclear Regulatory Commission, "Docket Number 50-483, Callaway Plant, Union Electric Co., Application for Amendment to Facility Operating License NFP-30 (LCDN-09-0039), Completion Time Extensions for TS 3.3.2 Engineered Safety Feature Actuation System (ESFAS) Instrumentation Functions," dated November 25, 2009 (Agencywide Documents Access and Management System (ADAMS)

Accession No. ML093290318).

2. Maglio, S. A., AmerenUE, letter to U.S. Nuclear Regulatory Commission, "Docket Number 50-483, Callaway Plant, Union Electric Co., Application for Amendment to Facility Operating License NFP-30, Completion Time Extensions for TS 3.3.2 Engineered Safety Feature Actuation System (ESFAS) Instrumentation Functions, TAC No. ME2822 (LDCN 09-0039)," dated April 22, 2010 (ADAMS Accession No. ML101120991).

3. Maglio, S. A., AmerenUE, letter to U.S. Nuclear Regulatory Commission, "Docket Number 50-483, Callaway Plant, Union Electric Co., Application for Amendment to Facility Operating License NFP-30, Completion Time Extensions for TS 3.3.2 Engineered Safety Feature Actuation System (ESFAS) Instrumentation Functions, TAC No. ME2822 (LDCN 09-0039)," dated May 14, 2010 (ADAMS Accession No. ML101370252).

4. Sandbothe, S., AmerenUE, letter to U.S. Nuclear Regulatory Commission, "Docket Number 50-483, Callaway Plant, Union Electric Co., Application for Amendment to Facility Operating License NFP-30, Completion Time Extensions for TS 3.3.2 Engineered Safety Feature Actuation System (ESFAS) Instrumentation Functions, TAC No. ME2822 (LDCN 09-0039 Supplement)," dated August 24,2010 (ADAMS Accession No. ML102371010).

5. Maglio, S., AmerenUE, letter to U.S. Nuclear Regulatory Commission, "Docket Number 50-483, Callaway Plant, Union Electric Co., Application for Amendment to Facility Operating License NFP-30, Completion Time Extensions for TS 3.3.2 Engineered Safety Feature Actuation System (ESFAS) Instrumentation Functions, TAC No. ME2822 (LDCN 09-0039 Supplement)," dated September 29,2010 (ADAMS Accession No. ML102730351).

6. Maglio, S., AmerenUE, letter to U.S. Nuclear Regulatory Commission, "Docket Number 50-483, Callaway Plant, Union Electric Co., Application for Amendment to Facility Operating License NFP*30, Completion Time Extensions for TS 3.3.2 Engineered Safety Feature Actuation System (ESFAS) Instrumentation Functions, TAC No. ME2822 (LDCN 09-0039)," dated November 4, 2010 (ADAMS Accession No. ML103090331).

- 25

7. Maglio, S., AmerenUE, letter to U.S. Nuclear Regulatory Commission, "Docket Number 50-483, Callaway Plant Unit 1, Union Electric Co., Facility Operating License NFP-30, Completion Time Extensions for TS 3.3.2 Engineered Safety Feature Actuation System (ESFAS) Instrumentation Functions, TAC No. ME2822 (LDCN 09-0039 Supplement),"

dated February 23, 2011 (ADAMS Accession No. ML110540543).

8. Thadani, M. C., U.S. Nuclear Regulatory Commission, letter to A. C. Heflin, Union Electric Company, "Callaway Plant, Unit 1 -Issuance of Amendment Re: Revision to Technical Specification 3.3.2, 'Engineered Safety Feature Actuation System Instrumentation,'

Function 6.G, Condition J (Exigent Circumstances) (TAC No. ME3595)," dated May 5, 2010 (ADAMS Accession No. ML101100665).

9. NUREG-1431, Revision 3, "Standard Technical Specifications Westinghouse Plants" (ADAMS Accession No. ML041830612).

10. U.S. Nuclear Regulatory Commission, Regulatory Guide 1.174, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis," Revision 1, November 2002 (ADAMS Accession No. ML023240437).

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

12. U.S. Nuclear Regulatory Commission, Regulatory Guide 1.200, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk Informed Activities," Revision 2, March 2009 (ADAMS Accession No. ML090410014).

13. U.S. Nuclear Regulatory Commission, NUREG-0800, Standard Review Plan 19.1, "Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk Informed Activities," Revision 1, September 2006 (ADAMS Accession No. ML062510220).

14. U.S. Nuclear Regulatory Commission, NUREG-0800, Standard Review Plan 16.1, "Risk Informed Decisionmaking: Technical Specifications," Revision 0, August 1998 (ADAMS Accession No. ML042520260).

- 26

15. U.S. Nuclear Regulatory Commission, NUREG-0800, Standard Review Plan 19.2, "Review of Risk Information Used to Support Permanent Plant-Specific Changes to the Licensing Basis: General Guidance," Revision 0, June 2007 (ADAMS Accession No. ML071700658).

16. Thadani, M. C., U.S. Nuclear Regulatory Commission, "Summary of January 25,2011, Meeting with Union Electric Company on Responses to the U.S. Nuclear Regulatory Commission Staffs Questions Raised during the Previous Public Meeting on November 18, 2010 (TAC No. ME2822)," dated February 22, 2011 (ADAMS Accession No. ML110400166).

Principal Contributors: A. Howe S. Gardocki Date: July 28, 2011

ML111680536 'SE memo dated

~R/LPL4/PM c==='"

OFFICE NRR/LPL4/PM NRR/LPL4/LA NRR/DRA/APLAlBC NRR/DSS/SBPB JPolickoski (LWilkins MThadani (LWilkins NAME for) for) JBurkhardt DHarrison* GCasto* Ii DATE 6/22/11 6/22/11 6/20/11 1212/10 4120/11 II

~ICE NRR/DIRS/ITSB/BC OGC NLO NRR/LPL4/BC NRR/LPL4/PM RElliolt (CSchulten MThadani NAME for) DRoth MMarkley (NKalyanam for)

DATE 16/24/11 7115111 7/28/11 7/28/11

v t e Letter Sequence Approval
TAC:ME2822, (Approved, Closed)
Initiation Request, Request, Request Acceptance Supplement, Supplement, Supplement Administration Questions 23 April 2010 7 September 2010 7 September 2010 20 October 2010 20 October 2010 25 October 2010 25 October 2010 5 November 2010 16 December 2010 12 January 2011 22 February 2011 Answers Results Approval Other:
MONTHYEAR2010-04-23 [Table View]

ML111680536

Text

SUBJECT:

Dear Mr. Heflin:

Enclosures:

Attachment:

1.0 INTRODUCTION

2.0 BACKGROUND

3.0 REGULATORY EVALUATION

4.0 TECHNICAL EVALUATION

NRC Staff Evaluation

NRC Staff Evaluation

NRC Staff Evaluation

NRC Staff Evaluation

NRC Staff Evaluation

NRC Staff Evaluation

SUMMARY

6.0 STATE CONSULTATION

7.0 ENVIRONMENTAL CONSIDERATION

8.0 CONCLUSION

9.0 REFERENCES

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