Text

Summary of Public Meeting with Exelon Generation Company, LLC, Regarding the Proposed Extended Power Uprate License Amendment Request for LaSalle County Station, Units 1 and 2
	ML13164A379
Person / Time
Site:	LaSalle
Issue date:	06/24/2013
From:	Nicholas Difrancesco; Plant Licensing Branch III
To:	;
	Nicholas DiFrancesco, NRR/DORL 415-1115
References
	TAC ME9903, TAC ME9904
	Download: ML13164A379 (55)
	v • d • e

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

June 24, 2013 LICENSEE: Exelon Generation Company, LLC FACILITY: LaSalle County Station, Units 1 and 2

SUBJECT:

SUMMARY

OF MAY 1, 2013, PUBLIC MEETING WITH EXELON GENERATION COMPANY, LLC REGARDING THE PROPOSED EXTENDED POWER UPRATE LICENSE AMENDMENT REQUEST FOR LASALLE COUNTY STATION, UNITS 1 AND 2 (TAC NOS. ME9903 AND ME9904)

On May 1, 2012, a Category 1 public meeting was held between the U.S. Nuclear Regulatory Commission (NRC) and representatives of Exelon Generation Company, LLC (EGC, the licensee), at the NRC Headquarters, Two White Flint North, 11545 Rockville Pike, Rockville, Maryland. The purpose of the meeting was to discuss a planned Extended Power Uprate (EPU) licensee amendment requested (LAR) for LaSalle County Station (LaSalle), Units 1 and 2. A list of attendees is provided as Enclosure 1.

During the meeting, EGC discussed with the NRC staff their plan to submit an EPU LAR, requesting a 12.5 percent increase in licensed thermal power for LaSalle. The targeted submittal date was May 2013. The meeting discussion focused on licensee plans to defer implementation of the EPU following NRC approval. The planned dates for EPU implementation are 2019 and 2020, for Unit 2 and Unit 1, respectively.

The licensee discussed how they would maintain control of the facility licensing and design bases and meet other regulatory requirements in the interim period between approval and implementation. Enclosure 2, Slide 8, discussed planned configuration control*enhancements associated with future revisions of the updated final safety analysis report.

During the meeting, the NRC staff advised the licensee that given current agency priorities for completing Fukushima lessons-learned activities and given the planned implementation dates, consistent with SECY-11-0137, "Prioritization of Recommended Actions to be Taken in Response to Fukushima Lessons Learned." the LaSalle EPU review may be delayed for several months.

I Subsequently on June 11, 2013, EGC announced the cancellation of the project due to economic considerations. Accordingly, the staff has closed Task Assignment-Control (TAC)

Nos. ME9903 AND. ME9904 which supported pre-appiication activities.

No regulatory decisions were made during this meeting.

The meeting notice and agenda are available under Agencywide Documents Access and Management System (ADAMS) Accession No. ML13097A002.

The public was invited to observe the meeting and several members of the public were in attendance. Two Public Meeting Feedback forms were received and reviewed by the staff.

Please direct any inquiries to me at 301-415-1115, or Nicholas.DiFrancesco@nrc.gov.

S.incerely, Nicholas DiFrancesco, Project Manager Plant Licensing Branch 111-2 Division of Operating Reactor Licensing Office of Nuclear ~eactor Regulation Docket Nos. 50-373 and 50-37 4

Enclosures:

1. List of Attendees

2. Licensee Handouts

3. -Handout of Draft LaSalle Operating License and Technical Specification Changes cc w/encl: Distribution via ListServ

LIST OF ATTENDEES May 1. 2013. PUBLIC MEETING WITH EXELON GENERATION COMPANY. LLC REGARDING LASALLE EXTENDED POWER UPRATE PRESUMBITAL MEETING Name Organization John Menninger NRC/NRR/DORL1 Jeremy Bowen NRCINRRIDORLILPL 3-2 1 Dennis Morey NRCINRRIDLRI RPB1 2 Nick DiFrancesco NRCINRRIDORL/LPL 3-2 John Bozga NRCIR-1111 DRSIEB1/

Blake Purnell NRCINRRIDORLILPL 3-2 John Jandovitz NRCIR-1111 DRPIBR5/ -

Kevin Borton Exelon Nuclear- Power Uprate John Rommel Exelon Nuclear- Power Uprate Vikram Shah Exelon Nuclear- Power Uprate Leslie Holden Exelon Nuclear- Power Uprate William Hilton Exelon Nuclear- LaSalle Station Guy Ford Exelon Nuclear- LaSalle Station James Spieler Exelon Nuclear- LaSalle Station Christopher Wilson Exelon Nuclear- License Renewal Lisa Simpson Exelon Nuclear - Corp Licensing#

Ken Anger Exelon Nuclear- Power Uprate TJ Kim Nuclear Energy Institute#

Gail Snyder Nuclear Energy Information Service#

Carol Kurz Nuclear Energy Information Service#

Brittany Theis Whitt Law LLC#

Bruce Hagemeier GE Hitachi Nuclear Energl Linda Lewison Energy Policy Consultant#

1. DORL - Division of Operating Reactor Licensing I LPL 3 Licensing Plant

2. DLR- Division of License Renewal I RPB1 -Renewal Projects Branch 1

3. R-Ill -Region Ill I DRS- Division of Reactor Safety I EB1 -Engineering Branch 1

4. R-Ill -Region Ill I DRP- Division of Reactor Projects I 85 -Branch 5

. Via Teleconference Bridgeline Enclosure

LaSalle County Generating Station Extended Power Uprate Implementation NRC Meeting- May 1, 2013

//,..

~ Exelon Generation,~

Meeting Purpose and Agenda v" Overview and Purpose v" Definitions v" OL and TS Control v" Configuration Control

- Design

- UFSAR

- 10 CFR 50.59 v" NRC Inspection Activities

..--1 1 ~ Exelon Generation.

Overview and Meeting Purpose

~ *LaSalle LAR Licensing Strategy

- Physical implementation of EPU will occur approximately four years following NRC approval:

EPU License Amendment Request (LAR) submittal May 2013

NRC requested to approve EPU LAR by February 2015

Implement EPU following completion of refueling outages at each unit

-Unit 2 *(L2R17) in February 2019

-Unit 1 (L1R18) in February 2020

-Advantages

Provides flexibility to implement sooner if economic conditions change

Avoids significant overlap of License Renewal LAR review (Submittal 2015)

Assures continuity of project knowledge and contracts

Leverages Peach Bottom EPU Review synergies

~Meeting Purpose

-Describe the Exelon processes that assure proper licensi~g and design controls between LAR approval and plant implementation 2 ~ Exelon Generation.

Definitions Current Licensed Thermal Power (CLTP) - 3546 MWt EPU Maximum Power Level - 3988 MWt Current Licensing Basis (CLB) - Consistent with 10 CFR 54.3 and 10 CFR 50.2 The CLB is the set of NRC requirements applicable to LaSalle Units 1 and 2

Exelon's written commitments

The plant specific design basis docketed and in effect

The plant specific design bases information as documented in the updated FSAR EPU Licensing Basis- The licensing basis and design bases following NRC approval

Pre-Implementation - The licensing and design basis of U1 and U2 after receipt of NRC approval of the EPU LAR, but prior to implementation

Post-Implementation -The licensing and design basis of U1 and U2 following implementation where all EPU license conditions and restrictions of the EPU OL amendments are met 3 ~ Exelon Generation.

Operating License (OL) and Technical Specifications (TS) Control

~Following NRC approval, both U1 and U2 OL pages will be revised to reflect the approved amendment and will contain any EPU license conditions

~Upon approval three versions of TS pages will be issued - The versions will be incorporated as they apply as follows:

- Following NRC Approval and Pre-Implementation on both units The TS will reflect the CLB but an annotation will be made on each EPU-affected TS stating that it is the "Prior to EPU Implementation" version of that TS, and the bottom of each affected page will indicate the EPU amendment number

- Post-Implementation on U2 following the 2019 outage Each EPU-affected TS will have a separate TS page for each unit. The U1 TS will have an annotation stating that it is "Prior to EPU Implementation" version and the U2 TS will have an annotation stating that it is the "Following EPU Implementation" version

- Post-Implementation on both units The EPU-affected TS for U1 and U2 will be combined again with the EPU values 4 ~ Exelon Generation.

Operating License (OL) and Technical Specifications (TS) Control

,/ Technical Specifications Page Controls

- EPU LAR

EPU implementation schedule described in cover letter

Provide the final version Mark-Up of TS pages with LAR

NRC issues the OLand three versions of TS pages with the EPU amendment number on each page

The revised OLand "Prior to EPU Implementation" TS pages will be implemented within 45-60 days after receiving NRC approval

- Subsequent LARs

If subsequent change TS markups include EPU affected pages~ all three versions of EPU pages will be marked-up and submitted 5 ~ Exelon Generation.

Operating License (OL) and Technical Specifications (TS) Control

./ Advantages

- The CLB and EPU Licensing Basis are readily apparent in OLand TS

- No impact toTS page document control process

- Aligns with ITS Writer's Guide

- It will be clear to Operators which TS applies as phased EPU is implemented on each Unit

- Minimum additional Operator training required 6 ~ Exelon Generation.

Engineering Configuration Control Process Description

~Configuration control is maintained in accordance within existing processes with enhancements added for EPU

- EPU Task Reports are treated as design basis calculations and included in the pending change process,

- Pending change Impact Reviews are performed,

-A Power Uprate "Responsible Engineer" will be designated to manage and assess configuration changes against the EPU related changes, and

- Exelon will perform an annual self-assessment to ensure there are no gaps regarding station-proposed changes and EPU related changes

Configuration changes for the previous year will be reviewed to determine if EPU was properly considered for each change

If discrepancies are identified they will be entered into and addressed by the Corrective Action Program 7 ~* Exelon Generation.

UFSAR Control Process Description v'UFSAR sections requiring change as a result of EPU will be identified and posted against the UFSAR Change Log v' Additional configuration control enhancements following NRC approval and prior to EPU Implementation changes:

-The UFSAR will be updated to reflect that EPU has been approved, and sections of the UFSAR that have pending EPU changes will be identified

-A Power Up rate Responsible Engineer will be designated to manage and assess UFSAR changes for their impact on the EPU Licensing Basis

-The EPU annotated UFSAR sections will identify to future reviewers that there are EPU changes pending implementation to ensure that EPU changes are considered v'The UFSAR will be updated to reflect EPU modifications and analyses after they are implemented 8 ~ Exelon Generation.

Example- Configuration, UFSAR and 50.59 Controls In 2017 LaSalle decides to modify main steam piping to resolve plant dose issue (Mod A):

Mod A Responsible Engineer (RE) reviews pending changes (electronic system) for potential impacted design basis documents (e.g., MS calculations and UFSAR sections)

Mod A identifies that MS piping will be changed as part of EPU (added SRVs) and that EPU calculations/UFSAR sections are pending

Mod A REworks with the Power Uprate RE to determine if Mod A design impacts EPU calculations, UFSAR sections, or Technical Specifications as part of design development

- Mod A RE ensures that an "Impact Review" of Mod A is performed by Power Uprate RE and documented as part of design change for Mod A

- If Mod A impacts EPU design basis documents, calculations, or UFSAR sections, then an action tracking item is issued to track Mod A inclusion in EPU implementation

- If the Mod A 50.59 review indicates an impact to an EPU SE/TS/OL license condition and prior NRC approval is required then a License Amendment will be required before Mod A can be completed

Mod A design change completed and impacts of EPU are understood and addressed

During annual "Check-In" self-assessment, Power Up rate personnel verify that the impact of Mod A on EPU has been identified, properly documented, and captured as necessary in an UFSAR change; update as appropriate

Prior to EPU-Implementation, EPU calculations/UFSAR sections updated to reflect Mod A as appropriate

..-.-1 9 ~ Exelon Generation.

NRC Inspections

~Coordination and scope of routine or special inspections do not differ from other modification or LAR implementation activities

~Following EPU LAR Approval

- Inspections will be performed against the CLB as well as the impact of any subsequent Pre-EPU period changes to the EPU Licensing Basis

- There is a clear understanding of the design and licensing basis, including pending EPU changes (similar to today's inspections)

~ EPU Implementation

. - Implementation plan will allow NRC to coordinate inspection of any implementation activities

./ Post-EPU Implementation

- Once implemented, routine inspections will include the EPU Licensing Basis 10 ~ Exelon Generation.

Conclusions

~ Licensing Strategy Allows Flexibility

~ Operating License, TS, and UFSAR Reflect Pending Changes

./ Configuration Control is Enhanced Within Existing Processes

~ No Change to Existing NRC Inspection Activities 11 Presentation Title ~ Exelon Generation.

Handout DRAFT LaSalle OLand TS Changes .

Following NRC Approval

01128/11 License No. NPF-11 Am. 146 (4) Exelon Generation Company, LLC, pursuant to the Act and 10 CFR Parts 01/12/01 30, 40, and 70, to receive, possess, and use in amounts as required any byproduct, source or special nuclear material without restriction to chemical or physical form, for sample analysis or instrument calibration or associated with radioactive apparatus or components; and Am. 146 (5) Exelon Generation Company, LLC, pursuant to the Act and 10 CFR 01/12/01 Parts 30, 40, and 70, to possess, but not separate, such byproduct and special nuclear materials as may be produced by the operation of LaSalle County Station, Units 1 and 2.

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:

Am. 1-9& (1) Maximum Power Level 09/16/10 The licensee is authorized to operate the facility at reactor core power levels not in excess of full power (3988 megawatts thermal).

Am. tOO (2) Technical Specifications and Environmental Protection Plan 01120/11 The Technical Specifications contained in Appendix A, as revised through Amendment No. -WB, 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.

Am. 194 (3) DELETED 08/28/09 Am. 194 (4) DELETED 08/28/09 Am. 194 (5) DELETED 08/28/09 Am. 194 (6) DELETED 08/28/09 Am. 194 (7) DELETED 08/28/09

RPS Instrumentation 3.3.1.1 3.3 INSTRUMENTATION 3.3.1.1 Reactor Protection system (RPS) Instrumentation (Prior to EPU Implementation per License condition 2.C(X))

LCO 3. 3 .1.1 The RPS instrumentation for each Function in Table 3.3.1.1-1

.shall be OPERABLE.

APPLICABILITY: Prior to Extended Power Uprate (EPU) implementation, according to Table 3.3.1.1-1.

ACTIONS

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

1. separate condition entry is allowed for each channel.

2. when Functions 2.b and 2.~ channels are inoperable due to the APRM indication not within limits, 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 if the APRM is indicatin!;J a lower power value than the calculated power, and for up to

-12 hours 1f the APRM is indicating a higher power value than the calculated power.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more required A.1 Place channel in 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months channels inoperable. trip.

9.B A.2 Place associ a ted trip 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months system in trip.

B. one or more Functions B.l Place channel in one 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months with one or more trip system in trip.

required channels inoperable in both OR trip systems.

B.2 Place one trip system 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months in trip.

(contlnued)

Lasalle 1 and 2 3.3.1.1-1 Amendment No. XXX/XXX

RPS Instrumentation 3.3.1.1 ACTIONS CONDITION REQUIREO ACTION COMPLETION TIME

c. one or more Functions c.1 Restore RPS trip 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months with RPS trip capability.

capability not maintained.

D. Required Action and D.1 Enter the condition Immediately associated completion referenced in*

Time of condition A, Table 3.3.1.1-1 for B, or c not met. the channel.

E. As required by E.1 Reduce THERMAL POWER 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Re~uired Action D.1 to <<2:s~t~If>.

an referenced in Table 3.3.1.1-1.

F. As required by F.1 Be in MODE 2. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Re~uired Action D.1 an referenced in Table 3. 3 .1.1-1.

G. As required by G.l Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Re~uired Action D.1 an referenced in Tab 1 e 3 . 3 . 1. 1-1.

H. As required by H.1 Initiate action to Immediately l

Reduired Action D.1 fully insert all an referenced in insertable control Table 3.3.1.1-1. rods in core cells containing one or more fuel assemblies.

Lasalle 1 and 2 3.3.1.1-2 Amendment No. XXX/XXX

RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS

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

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

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

SURVEILLANCE FREQUENCY SR 3. 3 .1. 1. 1 Perform CHANNEL CHECK. In accordance with the surveillance Frequency Control Program SR 3 . 3 . 1. 1. 2 ------------------NOTE-------------------

Not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after THERMAL POWER ~'7~5% R,"f~.

verify the absolute difference between In accordance the average power range monitor (APRM) with the channels and the calculated power surveillance

2% RTP while operating at 2!<11 2'5%~R'lt~. Frequency control Program SR 3 . 3 .1. 1. 3 Adjust the channel to conform to a In accordance calibrated flow signal. with the surveillance Frequency control Program (contlnued)

Lasalle 1 and 2 3.3.1.1-3 Amendment No. XXX/XXX

RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3. 3 .1. 1. 4 ------------------NOTE-------------------

Not required to be performed when entering MODE 2 from MODE 1 until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after entering MODE 2.

Perform CHANNEL FUNCTIONAL TEST. In accordance with the surveillance Frequency control Program SR 3. 3 .1. 1. 5 Perform CHANNEL FUNCTIONAL TEST. In accordance with the Surveillance Frequency control Program SR 3 . 3 .1.1. 6 verify the source range monitor (SRM) and Prior to fully intermediate range monitor (IRM) channels withdrawing overlap. SRMS SR 3 . 3 .1. 1. 7 ------------------NOTE-------------------

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

Verify the IRM and APRM channels overlap. In accordance with the surveillance Frequency control Program SR 3 . 3 .1. 1. 8 calibrate the local power range monitors. In accordance with the Surveillance Frequency Control Program ccont1nued)

Lasalle 1 and 2 3.3.1.1-4 Amendment No. 200/187

RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3 . 3 .1. 1. 9 Perform CHANNEL FUNCTIONAL TEST. In accordance with the surveill~nce Frequency control Program SR 3.3.1.1.10 Perform CHANNEL CALIBRATION. In accordance with the surveillance Frequency control Program SR . 3 . 3 . 1. 1. 11 ------------------NOTES------------------

1. Neutron detectors are excluded.

2. For Function 2.a, not required to be performed when entering MODE 2 from MODE 1 until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after entering MODE 2.

Perform CHANNEL CALIBRATION. In accordance with the surveillance Frequency control Program SR 3. 3 .1.1.12 Perform CHANNEL FUNCTIONAL TEST. In accordance with the Surveillance Frequency control Program (cont1nued)

Lasalle 1 and 2 3.3.1.1-5 Amendment No. 200/187

RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3. 3 . 1.1.13 ------------------NOTES------------------

1. Neutron detectors are excluded.

2. For Function 1.a, not required to be performed when entering MODE 2 from MODE 1 until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after entering MODE 2.

Perform CHANNEL CALIBRATION. In accordance with the surveillance Frequency Control Program SR 3 . 3 .1. 1. 14 verify the APRM Flow Biased simulated In accordance Thermal Power-upscale time constant is with the

7 seconds. surveillance Frequency Control Program SR 3.3.1.1.15 Perform LOGIC SYSTEM FUNCTIONAL TEST. In accordance with the Surveillance Frequency control Program SR 3 . 3 . 1. 1. 16 verify Turbine Stop valve-closure and In accordance Turbine control valve Fast closure, Trip with the oil Pressure-Low Functions are not surveillance bypassed when THERMAL POWER is ~~2I$~;RTP. Frequency control Program (cont1nued)

LaSalle 1 and 2 3.3.1.1-6 Amendment No. XXX/XXX

RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3. 3 .1. 1.17 ------------------NOTES------------------

1. Neutron detectors are excluded.

2. For Function 9; the RPS RESPONSE TIME is measured from start of turbine control valve fast closure.

In accordance Verify the RPS RESPONSE TIME is within with the limits. surveillance Frequency control Program LaSalle 1 and 2 3.3.1.1-7 Amendment No. 200/187

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

Reactor Protection system Instrumentation

{Prior to EPU Implementation per License Condition 2.C(X))

APPLICABLE REQUIRED CONDITIONS MODES OR OTHER CHANNELS REFERENCED SPECIFIED PER TRIP FROM REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS SYSTEM ACTION 0.1 REQUIREMENTS VALUE

1. Intermediate Range Monitors

a. Neutron Flu~*High 2 G SR 3.3.1.1.1 s 123/125 SR 3.3.1.1.4 divisions SR 3.3.1.1.6 of full SR 3.3.1.1.7 scale SR 3.3.1.1.13 SR 3. 3 .1.1.15 St*l SR 3.3.1.1.1 s; 123/125 SR 3.3.1.1.5 divisions SR 3.3.1.1.13 of full SR 3.3.1.1.15 scale

b. Inop G SR 3.3.1.1.4 NA SR 3.3.1.1.15 5(*)* H SR 3.3.1.1.5 NA SR 3.3.1.1.15

2. Average Power Range Monitors

a. Neutron Flux-High, 2 G SR 3.3.1.1.1 s,20% RTP Setdown SR 3.3.1.1.4.

SR 3.3.1.1.7 SR 3.3.1.1.8 SR 3.3.1.1.11 SR 3. 3 .1.1.15

b. Flow Biased simulated Thermal Power-upscale 1 F SR 3.3.1.1.1 SR 3.3.1.1.2 s o*.61 w":t 68*i:2%t0RTP SR 3.3.1.1.3 and *

SR 3.3.1.1.8 s us:;s%

SR 3.3.1.1.9 SR 3,3,1.1,11<0) (C) ~!-~.[~).

SR 3. 3 .1.1.14 SR 3. 3 .1.1.15

c. Fixed Neutron 1 F SR 3.3.1.1.1 s 120% RTP Flux-High SR 3.3.1.1.2 SR 3.3.1.1.8 SR 3.3.1.1.9 SR 3.3.1.1.11 SR 3. 3 .1.1.15 SR 3. 3 .1.1.17 (a) with any control rod withdrawn from a core cell containing one or more fuel assemblies.

(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 returnin9 the channel to service.

(c) The instrument channel setpoint shall be reset to a value that is with1n the as-left tolerance around the nominal trip setpoint (NTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable. Setpoints more conservative than the NTSP are acceptable provided that the as*found and as-left tolerances apply to the actual setpoint implemented in the surveillance procedures (field setting) to confirm channel performance. The NTSP and the methodologies used to determine the as-found and the as-left tolerance,s a,r,_e specified in the Technical Requirements Manual.

(d) Allowable value is !;;%o,:S,4,[,w:&:;:>,zs5J!if9%?A:fi> and s 112.3% RTP when reset for single loop operation per LCO 3.4.1, "Recirculation' Loops Operating."

Lasalle 1 and 2 3.3.1.1-8 Amendment No. XXX/XXX

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 PER TRIP REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS SYSTEM ACTION D.1 REQUIREMENTS VALUE

2. Average Power Range Monitors (continued)

d. Inop 1,2 2 G SR 3.3.1.1.8 NA SR 3.3.1.1.9 SR 3.3.1.1.15

3. Reactor Vessel Steam Dome 1,2 2 G SR 3.3.1.1.9 ~ 1059.0 psig Pressure-High SR 3. 3.1.1.10 SR 3. 3 .1.1.15

4. Reactor vessel water 1,2 2 G SR 3.3.1.1.1 "?: 11.0 inches Level-Low, Level 3 SR 3.3.1.1.9 SR 3.3.1.1.13 SR 3. 3 .1.1.15 SR 3.3.1.1.17

5. Main steam Isolation 1 8 F SR 3.3.1.1.9 < 13.7% closed valve-closure SR 3.3.1.1.13 SR 3.3.1.1.15 SR 3. 3 .1.1.17

6. Drywell Pressure-High 1,2 G SR 3.3.1.1.9 <, 1. 93 psig SR 3.3.1.1.13 SR 3.3.1.1.15

7. Scram oischar~e volume water Leve 1-1-tlgh

a. Transmitter/Trip unit 1,2 2 G SR 3.3.1.1.9 ::; 767 ft:

SR 3.3.1.1.13 8.55 inches SR 3.3.1.1.15 elevation 5'*1 2 H SR 3.3.1.1.9 ~; 767 ft SR 3.3.1.1.13 8.55 inches SR 3.3.1.1.15 elevation (a) with any control rod withdrawn from a core cell containing one or more fuel assemblies.

Lasalle 1 and 2 3.3.1.1-9 Amendment No. 200/187

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 ACTION D.1 REgUIREMENTS VALUE

7. scram Discharge volume water Level-High (continued)

b. Float switch 1,2 2 G SR 3.3.1.1.9 ~ 767 ft SR 3.3.1.1.13 8. 55 inches SR 3.3.1.1.15 elevation 5£*) 2 H SR 3.3.1.1.9 s 767 ft SR 3.3.1.1.13 8.55 inches SR 3. 3 .1.1.15 elevation

8. Turbine Stop valve- ? 25% RTP 4 E SR 3.3.1.1.9 s8.9% closed closure SR 3.3.1.1.13 SR 3. 3 .1.1.15 SR 3. 3 .1.1.16 SR 3. 3 .1.1.17

9. Turbine Control valve C! 25% RTP 2 E SR 3.3.1.1.9 ~ 425.5 psig Fast Closure, Trip Oil SR 3.3.1.1.13 Pressure**Low SR 3. 3 .1.1.15 SR 3. 3 .1.1.16 SR 3. 3 .1.1.17

10. Reactor Mode 1,2 G SR 3.3.1.1.12 NA switch-shutdown Position SR 3.3.1.1.15 Sta) H SR 3. 3 .1.1.12 NA SR 3. 3 .1.1.15

11. Manual scram 1, 2 'G SR 3.3.1.1.5 NA SR 3. 3 .1.1.15 S<al H SR 3.3.1.1.5 NA SR 3. 3 .1.1.15 (a) With any control rod withdrawn from a core cell containing one or more fuel assemblies.

LaSalle 1 and 2 3. 3.1.1-10 Amendment No. 200/187

Handout DRAFT LaSalle TS Changes Following Unit 2 Implementation

RPS Instrumentation 3.3.1.1 3.3 INSTRUMENTATION 3.3.1.1 Reactor Protection system (RPS) Instrumentation (unit 1 only Prior to EPU Implementation per License condition 2.C(X))

LCO 3. 3 .1.1 The RPS instrumentation for each Function in Table 3.3.1.1-1 shall be OPERABLE.

APPLICABILITY: Prior to Extended Power Uprate (EPU) implementation, according to Table 3.3.1.1-1.

ACTIONS

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

1. Separate condition entry is allowed for each channel.

2. When Functions 2.b and 2.c channels are inoperable due to the APRM indication not within limits, 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 if the APRM is indicatin9 a lower power value than the calculated power, and for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 1f the APRM is indicating a higher power value than the

~=~~:==~-~~~=~:

CONDITION REQUIRED ACTION COMPLETION TIME A. one or more required A.1 Place channel in 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months channels inoperable. trip.

OR A.2 Place associated trip 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months system in trip.

B. One or more Functions B.1 Place channel in one 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months with one or more trip system in trip.

required channels inoperable in both OR, trip systems.

B.2 place one trip system 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months in trip.

(contlnued)

LaSalle 1 3.3.1.1-1 Amendment No. XXX

RPS Instrumentation 3.3.1.1 3.3 INSTRUMENTATION 3.3.1.1 Reactor Protection system (RPS) Instrumentation (Unit 2 only -

Following EPU Implementation per License condition 2.C (X))

LCO 3. 3 .1.1 The RPS instrumentation for each Function in Table 3.3.1.1-1 shall b~ OPERABLE.

APPLICABILITY: Following Extended Power uprate (EPU) implementation, according to Table 3.3.1.1-1.

ACTIONS

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

1. separate condition *entry is allowed for each channel.

\

2. when Functions 2.b and 2.c channels are inoperable due to the APRM indication not within limits, 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 if the APRM is indicatin9 a lower power value than the calculated power, and for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 1f the APRM is indicating a higher power value than the calculated power.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more required A.1 Place channel in 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months channels inoperable. trip.

OR A.2 Place associated trip 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months system in trip.

B. one or more Functions B.l Place channel in one 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months with one or more trip system in trip.

required channels inoperable in both OR trip systems.

8.2 Place one trip system 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months in trip.

(cont1nued)

LaSalle 2 3. 3.1.1-1 Amendment No. XXX

RPS Instrumentation 3.3.1.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME

c. one or more Functions C.1 Restore RPS trip 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months with RPS trip capability.

capability not maintained.

D. Required Action and D.1 Enter the Condition Immediately associated Completion referenced in Time of condition A, Table 3.3.1.1-1 for B, or c not met. the channel.

E. As required by E.1 Reduce THERMAL POWER 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Reduired Action D.1 to :< :25%;:~1;'?,.

an referenced in Table 3.3.1.1-1.

F. As required by F.1 Be in MODE 2. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Reduired Action D.1 an referenced in Table 3.3.1.1-1.

G. As required by G.l Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Reduired Action D.1 an referenced in Table 3.3.1.1-1.

H. As required by H.1 Initiate action to Immediately Reduired Action D.1 fully insert all an referenced in insertable control Tab 1e 3 . 3 . 1. 1-1. rods in core cells containing one or more fuel assemblies.

Lasalle 1 3.3.1.1-2 Amendment No. XXX

RPS Instrumentation 3.3.1.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME

c. one or more Functions C.l Restore RPS trip 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months with RPS trip capability.

capability not maintained.

D. Required Action and D.l Enter the condition Immediately associated completion referenced in Time of condition A, Table 3.3.1.1-1 for B, or c not met. the channel.

E. As required by E.1 Reduce THERMAL POWER 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Reduired Action.D.1 to < 23% RTP.

an referen*ced 1 n Table 3.3.1.1-1.

F. As required by F.l Be in MODE 2. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Reduired Action D.l an referenced in Table 3.3.1.1-1.

G. As required by G.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Reduired Action o.l an referenced in Table 3.3.1.1-1.

H. As required by H.1 Initiate action to Immediately Reduired Action D.l fully insert all an referenced in insertable control Table 3.3.1.1-1. rods in core cells containing one or more fuel assemblies.

Lasalle 2 3.3.1.1-2 Amendment No. XXX

RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS

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

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

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

SURVEILLANCE FREQUENCY SR 3. 3. 1. 1. 1 Perform CHANNEL CHECK. In accordance with the surveillance Frequency control Program SR 3. 3 .1.1. 2 ------------------NOTE-------------------

Not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after THERMAL POWER ~l~l5%:;;,~;f;'~.

verify the absolute difference between rn accordance the average power range monitor (APRM) with the*

channels and the calculated power surveillance s 2% RTP whi 1 e operating at ~~t:?*s%'1R:fP.r: Frequency control Program SR 3 . 3 .1. 1. 3 Adjust the channel to conform to a In accordance calibrated flow signal. with the surveillance Frequency control Program (contlnued)

Lasalle 1 3.3.1.1-3 Amendment No. XXX

RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS

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

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

2. When a channel is placed in an inoperable status solely for performance of required surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months s-provided the associated Function maintains RPS trip capability.

SURVEILLANCE FREQUENCY SR 3 . 3 . 1. 1. 1 Perform CHANNEL CHECK. In accordance with the surveillance Frequency control Program SR 3 . 3 . 1. 1. 2 ------------------NOTE-------------------

Not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after THERMAL POWER ~ 23% RTP.

Verify the absolute difference between In accordance the average power range monitor (APRM) with the channels and the calculated power surveillance

~ 2% RTP while operating at ~ 23% RTP.

Frequency control Program SR 3 . 3 . 1. 1. 3 Adjust the channel td conform to a In accordance calibrated flow signal. with the surveillance Frequency control Program (contlnued)

LaSalle 2 3.3.1.1-3 Amendment No. XXX

RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3 . 3 .1. 1. 4 ------------------NOTE-------------------

Not required to be performed when entering MODE 2 from MODE 1 until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after entering MODE 2.

Perform CHANNEL FUNCTIONAL TEST. In accordance with the surveillance Frequency control Program SR 3. 3 .1.1.5 Perform CHANNEL FUNCTIONAL TEST. In accordance with the surveillance Frequency control Program SR 3. 3 .1. 1. 6 verify the source range monitor (SRM) and Pri or to fu 11 y intermediate range monitor (IRM) channels withdrawing overlap. SRMs SR 3. 3 .1. 1. 7 ------------------NOTE-------------------

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

verify the IRM and APRM channels overlap. In accordance with the surveillance Frequency control Program SR 3 . 3 . 1. 1. 8 calibrate the local power range monitors. In accordance with the surveillance Frequency control Program (contlnued)

Las a11 e 1,"arjdk2 3.3.1.1-4 Amendment No.. ~-O.Ol;J,Jlj

RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3 . 3 . 1. 1. 9 Perform CHANNEL FUNCTIONAL TEST. In accordance with the surveillance Frequency control Program SR 3 . 3 . 1. 1. 10 Perform CHANNEL CALIBRATION. In accordance with the surveillance Frequency control Program SR 3.3.1.1.11 ------------------NOTES------------------

1. Neutron detectors are excluded.

2. For Function 2.a, not required to be performed when entering MODE 2 from MODE 1 until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after entering MODE 2.

Perform CHANNEL CALIBRATION. In accordance with the surveillance Frequency control Program SR 3 . 3 .1. 1. 12 Perform CHANNEL FUNCTIONAL TEST. In accordance with the surveillance Frequency control Program (cont1nued) 3'.3.1.1-5 Amendment No. ~0QX~~:'l

RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3 . 3 . 1. 1. 13 ------------------NOTES------------------

1. Neutron detectors are excluded.

2. For Function 1:a, not required to be performed when entering MODE 2 from MODE 1 until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after entering MODE 2.

Perform CHANNEL CALIBRATION. In accordance with the surveillance Frequency Control Program SR 3 . 3 .1. 1. 14 verify the APRM Flow Biased simulated In accordance Thermal Power-Upscale time constant is with the

7 seconds. surveillance Frequency control Program SR 3 . 3 .1. 1. 15 Perform LOGIC SYSTEM FUNCTIONAL TEST. In accordance with the surveillance Frequency control Program SR 3 . 3 .1. 1. 16 Verify Turbine Stop Valve-closure and In accordance Turbine control valve Fast Closure, Trip with the oil Pressure-Low Functions are not . surveillance bypassed when THERMAL POWER cis ;

!: '25%ti~TP. Frequency Control Program (contlnued)

Lasalle l 3.3.1.1-6 Amendment No. XXX

RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE . FREQUENCY SR 3.3.1.1.13 ------------------NOTES------------------

1. Neutron detectors are excluded.

2. For Function 1.a, not required to be performed when entering MODE 2 from MODE 1 until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after entering MODE 2.

Perform CHANNEL CALIBRATION. In accordance with the surveillance Frequency control Program SR 3.3.1.1.14 verify the APRM Flow Biased Simulated In accordance Thermal Power-Upscale time constant is with the

s; 7 seconds. surveillance Frequency control Program SR 3.3.1.1.15 Perform LOGIC SYSTEM FUNCTIONAL TEST. In accordance with the surveillance Frequency Control Program SR ' 3. 3 .1.1. 16 verify Turbine stop valve-closure and In accordance Turbine control valve Fast closure, Trip with the oil Pressure-Low Functions are not Surveillance bypassed when THERMAL POWER is ~ 23% RTP. Frequency control Program (cont1nued)

LaSalle 2 3.3.1.1-6 Amendment No. XXX

RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3. 3 .1.1.17 ------------------NOTES------------------

1. Neutron detectors are excluded.

2. For Function 9, the RPS RESPONSE TIME is*measured from start of turbine control valve fast closure.

In accordance Verify the RPS RESPONSE TIME is within with the 1 i mi ts. surveillance Frequency control Program Las a 11 e l!:;and:.:2 3.3.1.1-7 Amendment No. ZQ.Q/:187

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

Reactor Protection system Instrumentation (Unit 1 Only Prior to EPU Implementation per License condition 2.C(X))

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

1. . Intermediate Range Monitors

a. Neutron Flux-High 2 G SR 3.3.1.1.1 ~ 123/125 SR 3.3.1.1.4 divisions SR 3.3.1.1.6 of full SR 3.3.1.1.7 scale SR 3. 3.1.1.13 SR 3. 3 .1.1.15 Sf*J H SR 3.3.1.1.1 s 123/125 SR 3.3.1.1.5 divisions SR 3.3.1.1.13 of full SR 3.3.1.1.15 scale

b. rnop 2 G SR 3.3.1.1.4 NA SR 3. 3 .1.1.15 S!Jl 3 H SR 3.3.1.1.5 NA SR 3. 3 .1.1.15

2. Average Power Range Monitors

a. Neutron Flux-High, 2 2 G SR 3.3.1.1.1 sii?O'%:!R1:P Setdown SR 3.3.1.1.4 SR 3. 3 .1.1..7 SR . 3.3.1.1.8 SR 3.3.1.1.11 SR 3.3.1.1.15

b. Flow Biased Simulated 1 2 F SR 3.3.1.1.1 *,s,,,=o~~lnt~:w~~-t!

Thermal Power Upscale SR 3.3.1.1.2 68.2% RTP SR 3.3.1.1.3 and SR 3.3.1.1.8 ~:h\~:Ls;s%

SR 3.3.1.1.9 RTP,(d,?.

SR 3. 3.1.1.11i'l (<)

SR 3. 3 .1.1.14 SR 3.3.1.1.15

c. Fixed Neutron F SR 3.3.1.1.1 S 120% RTP Flux-High SR 3.3.1.1.2 SR 3.3.1.1.8 SR 3.3.1.1.9 SR 3.3.1.1.11 SR 3.3.1.1.15 SR 3. 3 .1.1.17 (a) With any control rod withdrawn from a core cell conta1n1ng one or more fuel assemblies.

(b) rf 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.

(c) The instrument channel setpoint shall be rese1: .l:o a value 1:ha1: is with1n t:he as-left: tolerance around t:he nominal trip setpoint (NTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable. setpoints more conservative than the NTSP are acceptable provided that the as-found and as-left tolerances apply to the actual setpoint implemented in the surveillance procedures (field setting) to confirm channel performance. The NTSP and the methodologies used to determine the as-found and the as-1 eft tolerance~. ~respecified in the Technical Requirements Manual.

(d) Allowable value iss Oi54'Y:w::+::Ps'5;!9%'~RTP and s 112.3% RTP when reset for single loop operation per LCO 3. 4 .1, "Reci rcul ati on Loops operating."

Lasalle 1 3.3.1.1-8 Amendment No. XXX

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

Reactor Protection System Instrumentation unit 2 only, Following EPU Implementation per License condition 2.C(X)

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

1. Intermediate Range Monitors

a. Neutron Flux*-High 2 G SR 3.3.1.1.1 ,.; 123/125 SR 3. 3.1.1.4 di visions SR 3. 3.1.1.6 of full SR 3.3.1.1.7 scale SR 3. 3.1.1.13 SR 3. 3 .1.1.15 5<*) H SR 3.3.1.1.1 ,; 123/125 SR 3.3.1.1.5 divisions SR 3.3.1.1.13 of full SR 3. 3.1.1.15 scale

b. Inop G SR 3.3.1.1.4 NA SR 3. 3 .1.1.15 5(*) H SR 3.3.1.1.5 NA SR 3. 3 .1.1.15

2. Average Power Range ~onitors

a. Neutron Flux High, G SR 3.3.1.1.1 5 22.6% RTP Setdqwn SR 3.3.1.1.4 SR 3.3.1.1.7 SR 3.3.1.1.8 SR 3.3.1.1.11 SR 3. 3.1.1.15

b. Flow Biased Simulated 1 2 F SR 3.3.1.1.1 $0.55W+

Thermal Power upscale SR 3.3.1.1.2 63.5% RTP SR 3.3.1.1.3 and SR 3.3.1.1.8 ,; 118.0%

SR 3.3.1.1.9 RTPidl SR 3. 3 .1.1.11'bl ,,,

SR 3. 3 .1.1.14 SR. 3. 3.1.1.15

c. Fixed Neutron 1 2 F SR 3.3.1.1.1 $ 120~~ RTP Flux** High SR 3.3.1.1.2 SR 3.3.1.1.8 SR 3.3.1.1.9 SR 3.3.1.1.11 SR 3.3.1.1.15 SR 3. 3 .1.1.17 (a) with any control rod withdrawn from a core cell containing one or more fuel assemblies.

(b) rf 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 returninQ the channel to service.

(c) The instrument channel setpoint shall be reset to a value that is with1n the as-left tolerance around the nominal trip setpoint (NTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable. Setpoints more conservative than the NTSP are acceptable provided that the as-found and as-left tolerances apply to the actual setpoint implemented in the surveillance procedures (field setting) to confirm channel performance. The NTSP and the methodologies used to determine the as~found and the as-left tolerances are specified in the Technical Requirements Manual.

(d) Allowable value is ~* 0.48 W + 49.6% RTP and s 112.3% RTP when reset for single loop operation per LCO 3.4.1, "Recirculation Loops Operating."

Lasalle 2 3.3.1.1-8 Amendment No. XXX

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 PER TRIP REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS SYSTEM ACTION D.1 REQUIREMENTS VALUE

2. Average Power Range Monitors (continued)

d. Inop 1,2 2 G SR 3.3.1.1.8 NA SR 3.3.1.1.9 SR 3.3.1.1.15

3. Reactor Vessel Steam Dome 1,2 2 G SR 3.3.1.1.9 <: 1059.0 psig Pressure-High SR 3. 3 .1.1.10 SR 3. 3 .1.1.15

4. Reactor vessel water 1,2 G SR 3.3.1.1.1 ~ 11.0 inches Level-Low, Level 3 SR 3.3.1.1.9 SR 3.3.1.1.13 SR 3.3.1.1.15 SR 3.3.1.1.17

5. Main Steam Isolation 1 8 SR 3.3.1.1.9 !: 13.7% closed valve-closure SR 3.3.1.1.13 SR 3.3.1.1.15 SR 3.3.1.1.17

6. Drywell Pressure**High 1,2 G SR 3.3.1.1.9 s 1. 93 psig SR 3.3.1.1.13 SR 3. 3 .1.1.15

7. Scram Dischar~e volume water Level H1gh

a. Transmitter/Trip unit l,l 2 G SR 3.3.1.1.9 $ 767 ft SR 3.3.1.1.13 8.55 inches SR 3. 3 .1.1.15 elevation 5{-J) 2 H SR 3.3.1.1.9 ~ 767 ft SR 3.3.1.1.13 8.55 inches SR 3. 3 .1.1.15 elevation (a) With any control rod withdrawn from a core cell containing one or more fuel assemblies.

3.3.1.1-9 Amendment No. 2mi>:I~;I:8,Z

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 ACTION D.1 REQUIREMENTS VALUE

7. scram Discharge Volume water Level-High (continued)

b. Float switch 1,2 G SR 3. 3 .1.1. 9 !'{ 767 ft SR 3. 3. 1. 1.13 8.55 inches SR 3.3.1.1.15 elevation 2 H SR 3.3.1.1.9 !£ 767 ft SR 3.3.1.1.13 8.55 inches SR 3.3.1.1.15 elevation

8. Turbine Stop valve- :, 25% RTP 4 E SR 3.3.1.1.9 ~ 8.9% closed Closure SR 3.3.1.1.13 SR 3.3.1.1.15 SR 3.3.1.1.16 SR 3.3.1.1.17

9. Turbine control Valve ~ 25':;; RTP 2 E SR 3.3.1.1.9 ?. 425.5 psig Fast closure, Trip oil SR 3. 3 .1.1.13 Pressure-Low SR 3.3.1.1.15 SR 3. 3.1.1.16 SR 3 . 3 .1. 1. 17

10. Reactor Mode 1,2 2 G SR 3.3.1.1.12 NA switch-shutdown Position SR 3.3.1.1.15 2 H SR 3.3.1.1.12 NA SR 3. 3 .1.1.15

11. Manual scram 1,2 2 G SR 3.3.1.1.5 NA SR 3. 3 . 1.1.15 2 H SR 3.3.1.1.5 NA SR 3.3.1.1.15 (a) with any control rod withdrawn from a core cell containing one or more fuel assemblies.

Las a11 e 1~2ar)d ,2 3. 3.1.1-10 Amendment No. 2.00j;l.87:

Handout DRAFT LaSalle TS Changes Final- Following Uland U21mplementation

\

RPS Instrumentation 3.3.1.1 3.3 INSTRUMENTATION 3.3.1.1 Reactor Protection system (RPS) Instrumentation LCO 3. 3 .1.1 The RPS instrumentation for each Function in Table 3.3.1.1-1 shall be OPERABLE.

APPLICABILITY: According to Table 3.3.1.1-1.

ACTIONS

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

1. separate condition entry is allowed for each channel.

2. when Functions 2.b and 2.c channels are.inoperable due to the APRM indication not within limits, 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 if the APRM is indicatin~ a lower power value than the calculated power, and for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 1f the APRM is indicating a higher power value than the calculated power.

CONDITION REQUIRED ACTION COMPLETION TIME A. one or more required A.1 Place channel in 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months channels inoperable. trip.

OR A.2 Place associated trip 11 hours1.273148e-4 days 0.00306 hours 1.818783e-5 weeks 4.1855e-6 months system in trip.

B. one or more Functions B.1 Place channel in one 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months with one or more trip system in trip.

required channels inoperable in both OR trip systems.

8.2 Place one trip system 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months in trip.

(cont1nued)

Lasalle 1 and 2 3.3.1.1-1 Amendment No. XXX/XXX

RPS Instrumentation 3.3.1.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME

c. one or more Functions C.l Restore RPS trip 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months With RPS trip capability.

capability not maintained.

D. Required Action and 0.1 Enter the condition Immediately associated Completion referenced in Time of condition A, Tab 1e 3 . 3 . 1. 1-1 for B, or c not met. the channel.

E. As required by E.l Reduce THERMAL POWER 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Re~uired Action 0.1 to < 23% RTP.

an referenced in Table 3.3.1.1-1.

F. As required by F.1 Be in MODE 2. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Re~uired Action D.1 an referenced in Table 3. 3 .1.1-1.

G. As required by G.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Re~uired Action D.1 an referenced in Table 3. 3 .1.1-1.

H. As required by H.l Initiate action to Immediately Re~uired Action D.1 fully insert all an referenced in insertable control Table 3. 3 .1.1-1. rods in core cells containing one or more fuel assemblies.

LaS a 11 e 1 and 2 3.3.1.1-2 Amendment No. XXX/XXX

RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS

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

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

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

SURVEILLANCE FREQUENCY SR 3 . 3 . 1. 1. 1 Perform CHANNEL CHECK. In accordance with the surveillance Frequency control Program SR 3 . 3 . 1. 1. 2 ------------------NOTE-------------------

Not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after THERMAL POWER ~ 23% RTP.

verify the absolute difference between In accordance the average power range monitor (APRM) with the channels and the calculated power surveillance

~ 2% RTP while operating at ~ 23% RTP.

Frequency control Program SR 3 . 3 . 1.1. 3 Adjust the channel to conform to a In accordance calibrated flow signal. with the surveillance Frequency control Program (contlnued)

Lasalle 1 and 2 3.3.1.1-3 Amendment No. XXX/XXX

RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3 . 3 . 1. 1. 4 ------------------NOTE-------------------

Not required to be performed when entering. MODE 2 from MODE 1 unti 1 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after entering MODE 2.

Perform CHANNEL FUNCTIONAL TEST. In accordance with the surveillance Frequency control Program SR 3 . 3 . 1. 1. 5 Perform CHANNEL FUNCTIONAL TEST. In accordance with the su rvei 11 ance Frequency control Program SR 3. 3 .1.1. 6 verify the source range monitor (SRM) and Prior to fully intermediate range monitor (IRM) channels withdrawing overlap. SRMs SR 3 . 3 . 1. 1. 7 ------------------NOTE-------------------

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

verify the IRM and APRM channels overlap. In accordance with the surveillance Frequency control Program SR 3.. 3.1.1.8 calibrate the local power range monitors. In accordance with the surveillance Frequency control Program ccont1nued)

Lasalle l:::arfcf::2 3.3.1.1-4 Amendment No. ~QPZr487

RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3. 3 .1.1. 9 . Perform CHANNEL FUNCTIONAL TEST. In accordance with the surveillance Frequency control Program SR 3.3.1.1.10 Perform CHANNEL CALIBRATION. In accordance with the surveillance Frequency control Program SR 3.3.1.1.11 ------------------NOTES------------------

1. Neutron detectors are excluded.

2. For Function 2.a, not required to be performed when entering MODE 2 from

. MODE 1 until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after entering MODE 2.

Perform CHANNEL CALIBRATION. In accordance with the surveillance Frequency control Program SR 3. 3. 1. 1.12 Perform CHANNEL FUNCTIONAL TEST. In accordance

with the surveillance Frequency control Program (cont1nued) 3.3.1.1-5 Amendment No. ?OO/Jl87

RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3 . 3 . 1. 1. 13 ------------------NOTES------------------

1. Neutron detectors are excluded.

2. For Function 1.a, not required to be performed when entering MODE 2 from MODE 1 until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after entering MODE 2.

Perform CHANNEL CALIBRATION. In accordance with the surveillance Frequency control Program SR 3. 3 .1.1. 14 Verify the APRM Flow Biased Simulated In accordance Thermal Power-Upscale time constant is with the

~ 7 seconds. surveillance Frequency Control Program SR 3.3.1.1.15 Perform LOGIC SYSTEM FUNCTIONAL TEST. In accordance with the surveillance Frequency control Program SR 3. 3 .1. 1. 16 verify Turbine Stop valve-closure and In accordance Turbin~ control valve Fast closure, Trip with the oil Pressure-Low Functions are not surveillance bypassed when THERMAL POWER is ~ 23% RTP. Frequency control Program (cont1nued)

Lasalle 1 and 2 3.3.1.1-6 Amendment No. XXX/XXX

RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3. 3 .1. 1. 17 ------------------NOTES------------------

1. Neutron detectors are excluded.

2. For Function 9, the RPS RESPONSE TIME is measured from start of turbine control valve fast closure.

In accordance Verify the RPS RESPONSE TIME is within with the limits. surveillance Frequency control Program 3.3.1.1-7

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

Reactor Protection system Instrumentation APPLICABLE REQUIRED CONDITIONS MODES OR OTHER CHANNELS REFERENCED SPECIFIED PER TRIP FROM REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS SYSTEM ACTION 0.1 REQUIREMENTS VALUE 1, Intermediate Range Monitors

a. Neutron Flux--High 2 3 G SR 3.3.1.1.1 ~ 123/125 SR 3.3.1.1.4 divisions SR 3.3.1.1.6 of full SR 3.3.1.1.7 scale SR 3.3.1.1.13 SR 3.3.1.1.15 H SR 3.3.1.1.1 5 123/125 SR 3.3.1.1.5 divisions SR 3.3.1.1.13 of full SR 3. 3.1.1.15 scale

b. Inop G SR 3.3.1.1.4 NA SR 3. 3 .1.1.15 H SR 3.3.1.1.5 NA SR 3. 3 .1.1.15

2. Average Power Range Monitors

a. Neutron Flux-High, 2 G SR 3.3.1.1.1 ,;: 22.6~ RTP Set down SR .3. 3 .1.1. 4 SR 3. 3 .1.1. 7 SR 3. 3. 1. 1. 8 SR 3. 3 .1.1.11 SR 3. 3 .1.1.15

b. Flow Biased Simulated 2 F SR 3. 3 .1.1.1 $ 0.55 w +

Thermal Power*U~scale SR 3.3.1.1.2 63.5% RTP SR 3. 3 .1.1. 3 and SR 3.3.1.1.8 $ 118.0%

SR 3.3.1.1.9 RTP(dl SR 3.3.1.1.11~1 Ul SR 3.3.1.1.14 SR 3.3.1.1.15

c. Fixed Neutron 2 F SR 3 . 3. 1. 1. 1 S 120% RTP Flux High SR 3

3. 1. 1. 2 SR 3. 3. 1. 1. 8 SR 3. 3. 1. 1. 9 SR 3. 3 .1.1.11 SR 3. 3 .1.1.15 SR 3.3.1.1.17 (a) With any control rod withdrawn from a core cell containing one or more fuel assemblies.

(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 returnin~ the channel to service.

(c) The instrument channel setpoint shall be reset to a value that is withln the as-left tolerance around the nominal trip setpoint (NTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable. Setpoints more conservative than the NTSP are acceptable provided that the as-found and as-left tolerances apply to the actual setpoint implemented in the surveillance procedures (field.

setting) to confirm channel performance. The NTSP and the methodologies used to determine the as-found and the as-left tolerances are specified in the Technical Requirements Manual.

(d) Allowable value is ~; 0.48 w + 49.6S RTP and s 112.3% RTP when reset for single loop operation per LCD 3.4.1, "Recirculation Loops Operating."

Lasalle 1 and 2 3.3.1.1-8 Amendment No. XXX/XXX

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 PER TRIP REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS SYSTEM ACTION 0.1 REQUIREMENTS VALUE

2. Average Power Range Monitors (continued)

d. Inop 1,2 2 G SR 3.3.1.1.8 NA SR 3.3.1.1.9 SR 3.3.1.1.15

3. Reactor vessel Steam Dome 1, 2 2 G SR 3.3.1.1.9 s 1059.0 psig Pressure****Hi gh SR 3. 3 .1.1.10 SR 3. 3 .1.1.15

4. Reactor vessel water 1, 2 .2 G SR 3.3.1.1.1 ?: 11.0 inches Level-Low, Level 3 SR 3.3.1.1.9 SR 3.3.1.1.13 SR 3. 3 .1.1.15 SR 3.3.1.1.17

5. Main Steam isolation 1 8 SR 3.3.1.1.9 s 13.7% closed valve-closure SR 3.3.1.1.13 SR 3.3.1.1.15 SR 3.3.1.1.17

6. Drywell Pressure**High 1,2 G SR 3.3.1.1.9 ~ 1.93 psig SR 3. 3.1.1.13 SR 3.3.1.1.15

7. scram oischar~e volume water Level*Hlgh

a. Transmitter/Trip unit 1.2 G SR 3.3.1.1.9 ~ 767 ft SR 3.3.1.1.13 8.55 inches SR 3. 3 .1.1.15 elevatio~

5L<t) 2 H SR 3.3.1.1.9 !; 767 ft SR 3.3.1.1.13 8.55 inches SR 3. 3 .1.1.15 elevation (a) With any control rod withdrawn from a core cell containing one or more fuel assemblies.

Lasalle 1 and 2 3.3.1.1-9 Amendment No. 200/187

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 ACTION D.1 REgUIREMENTS VALUE

7. scram Discharge volume water Level-High (continued)

b. Float switch 1,2 G SR 3.3.1.1.9 ~ 767 ft SR 3.3.1.1.13 8.55 inches SR 3. 3 .1.1.15 elevation 5<*> 2 H SR 3.3.1.1.9 !: 767 ft SR 3.3.1.1.13 8.55 inches SR 3. 3 .1.1.15 elevation

8. Turbine stop va 1ve-- ?: 23% RTP 4 E SR 3.3:1.1.9 ,;; 8.9% closed closure SR 3.3.1.1.13 SR 3. 3 .1.1.15 SR 3. 3 .1.1.16 SR 3. 3 .1.1.17

9. Turbine control valve ~ 23% RTP 2 E SR 3.3.1.1.9 ~ 425.5 psig Fast closure, Trip oil SR 3.3.1.1.13 Pressure-Low SR 3. 3.1.1.15 SR 3. 3.1.1.16 SR 3. 3 .1.1.17

10. Reactor Mode 1,2 2 G SR 3. 3 .1.1.12 NA switch-shutdown Position SR 3. 3 .1.1.15 sr*' 2 H SR 3. 3 .1.1.12 NA SR 3. 3 .1.1.15

11. Manu a 1 Scram 1, 2 2 G SR 3.3.1.1.5 NA' SR 3. 3 .1.1.15 5(*l 2 H SR 3.3.1.1.5 NA SR 3.3.1.1.15 (a) with any control rod withdrawn from a core cell containing one or more fuel assemblies.

Lasalle 1 and 2 3. 3.1.1-10 Amendment No. 200/187

The meeting notice and agenda are available under Agencywide Documents Access and

Management System (ADAMS) Accession No. ML13097A002.

The public was invited to observe the meeting and several members of the public were in attendance. Two Public Meeting Feedback forms were received and reviewed by the staff.

Please direct any inquiries to me at 301-415-1115, or Nicholas.DiFrancesco@nrc.gov.

Sincerely, IRA I Nicholas DiFrancesco, Project Manager Plant Licensing Branch 111-2 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket Nos. 50-373 and 50-374

Enclosures:

1. List of Attendees

2. Licensee Handouts

3. Handout of Draft LaSalle Operating License and Technical Specification Changes cc w/encl:. Distribution via ListServ DISTRIBUTION:

PUBLIC RidsNrrDorllpl3-2 Resource RidsRgn3MaiiCenter Resource LPL3-2 R/F RidsNrrPMLasalle Resource John Bozga Rill RidsNrrAdro Resource RidsOgcMaiiCenter Resource RidsNrrDorl Resource RidsOpaMail Resource EDO Doug Huyck Accession Number: ML13164A379 OFFICE DORLILPL3-2 PM DORL/LPL3-21LA DORLILPL3-21BC DORLILPL3-21PM NAME NDiFrancesco SRohrer JBowen NDiFrancesco DATE 6119/13 6/17/13 6120113 6/24/13 OFFICIAL RECORD COPY

v t e Letter Sequence Meeting
TAC:ME9903, (Open) TAC:ME9904, (Open)
Initiation Acceptance... Administration Meeting, Meeting Questions Answers Results Approval... Other:
MONTHYEAR2013-04-17 [Table View]

ML13164A379

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