Text

Application for Technical Specification Change TSTF-423, Risk Informed Modification to Selected Required Action End States for BWR Plants, Using the Consolidated Line Item Improvement Process
	ML062980149
Person / Time
Site:	LaSalle
Issue date:	10/18/2006
From:	Benyak D; Exelon Generation Co, Exelon Nuclear
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	RS-06-141
	Download: ML062980149 (91)
	v • d • e

Exelkn.

Exelon Generation www.exeloncorp.com Nuclear 4300 Winfield Road Warrenville, IL 60555 10 CFR 50.90 RS-06-141 October 18, 2006 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D.C. 20555 LaSalle County Station, Units 1 and 2 Facility Operating License Nos. NPF-1 1 and NPF-1 8 NRC Docket Nos. 50-373 and 50-374

Subject:

Application for Technical Specification Change TSTF-423, Risk Informed Modification to Selected Required Action End States for BWR Plants, Using the Consolidated Line Item Improvement Process

Reference:

TSTF-423, Revision 0, "Technical Specifications End States, NEDC-32988-A" In accordance with 10 CFR 50.90, "Application for amendment of license or construction permit," Exelon Generation Company, LLC (EGC) is requesting a change to the Technical Specifications (TS) of Facility Operating License Nos. NPF-1 1 and NPF-1 8 for LaSalle County Station (LSCS), Units 1 and 2. The proposed amendment would modify TS to risk-inform requirements regarding selected Required Action End States as provided in the referenced document.

Attachment 1 provides a description of the proposed change, the requested confirmation of applicability, and plant-specific verifications. Attachment 2 provides the existing TS pages marked up to show the proposed change. Attachment 3 provides the existing TS Bases pages marked up to show the proposed change. The TS Bases pages are provided for information only and do not require NRC approval. Attachment 4 provides a summary of the regulatory commitments made in this submittal.

Changes to TS are generally consistent with the changes outlined in the referenced document; minor deviations are discussed in Attachment 1. While the LSCS Units 1 and 2 TS are based on both NUREG-1433, "Standard Technical Specifications General Electric Plants, BWR/4," and NUREG-1434," Standard Technical Specifications General Electric Plants, BWR/6," they are not identical to either. Therefore, an adaptation of the referenced document was required.

October 18, 2006 U. S. Nuclear Regulatory Commission Page 2 EGC requests approval of the proposed license amendment by October 3 1 st, 2007, with implementation within 120 days of issuance.

This amendment request has been reviewed by the LSCS Plant Operations Review Committee and approved by the Nuclear Safety Review Board in accordance with the requirements of the EGC Quality Assurance Program.

In accordance with 10 CFR 50.91, "Notice for public comment," EGC is notifying the State of Illinois of this application for amendment by transmitting a copy of this letter and its attachments to the designated State Official.

If you have any questions concerning this letter, please contact Mr. Timothy A. Byam at (630) 657-2804.

I declare under penalty of perjury that the foregoing is true and correct. Executed on the 18 th day of October 2006.

Respectfully, Darin M. Benyak Manager - Licensing Exelon Generation Company, LLC : Description of Proposed Changes, Technical Analysis, and Regulatory Analysis : Mark-up of Proposed Technical Specification Page Changes : Mark-up of Technical Specification Bases Page Changes : List of Regulatory Commitments cc: Administrator, Region III, USNRC USNRC Senior Resident Inspector, LaSalle

ATTACHMENT 1 Description of Proposed Changes, Technical Analysis, and Regulatory Analysis

1.0 DESCRIPTION

2.0 ASSESSMENT 2.1 Applicability of Topical Report, TSTF-423, and Published Safety Evaluation 2.2 Optional Changes and Variations

3.0 REGULATORY ANALYSIS

3.1 No Significant Hazards Consideration Determination 3.2 Verification and Commitments 4.0 ENVIRONMENTAL EVALUATION 5.0 IMPACT ON PREVIOUS SUBMITTALS

6.0 REFERENCES

Page 1 of 5

ATTACHMENT 1 Description of Proposed Changes, Technical Analysis, and Regulatory Analysis

1.0 DESCRIPTION

The proposed amendment would modify Technical Specifications (TS) to risk-informed requirements regarding selected Required Action End States.

The changes are generally consistent with the Nuclear Regulatory Commission (NRC) approved Industry/Technical Specification Task Force (TSTF) TSTF-423, Revision 0, "Technical Specifications End States, NEDC-32988-A." The availability of this TS improvement was published in the FederalRegister on March 23, 2006 as part of the Consolidated Line Item Improvement Process (CLIIP).

2.0 ASSESSMENT 2.1 Applicability of Topical Report, TSTF-423, and Published Safety Evaluation Exelon Generation Company, LLC (EGC) has reviewed the General Electric (GE) topical report (i.e., Reference 1), TSTF-423 (i.e., Reference 2), and the NRC model Safety Evaluation (i.e., Reference 3) as part of the CLIIP. EGC has concluded that the information in the GE topical report and TSTF-423, as well as the safety evaluation prepared by the NRC, are applicable to LaSalle County Station (LSCS), Units 1 and 2 and provide justification for the incorporation of the changes to the LSCS Units 1 and 2 TS.

2.2 Optional Changes and Variations EGC is not proposing any variations or deviations from the GE topical report, TS changes described in the TSTF-423, Revision 0, or the NRC's model safety evaluation dated March 23, 2006.

The proposed TS changes are generally consistent with TSTF-423, Revision 0. Minor differences between the proposed changes and those contained in TSTF-423, Revision 0 include the following.

Changes were made to several paragraphs and Section numbers since the TSTF is based on NUREG-1433, "Standard Technical Specifications General Electric Plants, BWR/4," and NUREG-1434, "Standard Technical Specifications General Electric Plants, BWR/6." While the LSCS Units 1 and 2 are based on NUREG-1433 and NUREG-1434, they are not identical to either. Therefore, an adaptation of TSTF-423, Revision 0 was required.

The TS changes in TSTF-423, Revision 0 included changes to the following Standard TS (STS) sections, which are not applicable to the LSCS Units 1 and 2 TS due to deviance from applicability of technical justification (as described in Reference 1) or lack of TS in LSCS TS. Therefore they are not part of the submittal.

Page 2 of 5

ATTACHMENT 1 Description of Proposed Changes, Technical Analysis, and Regulatory Analysis 3.4.3 (BWR/4) / 3.4.4 Safety/Relief Valves (SRVs)

(BWR/6) 3.6.1.6 (BWR/4 and 6) Low-Low Set (LLS) Valves 3.6.1.7 (BWR/4) Reactor Building-to-Suppression Chamber Vacuum Breakers 3.6.1.7 (BWR/6) Residual Heat Removal (RHR) Containment Spray System 3.6.1.8 (BWR/6) Penetration Valve Leakage Control System (PVLSC) 3.6.1.9 (BWR/4 and 6) Main Steam Isolation Valve (MSIV) Leakage Control System (LCS) 3.6.5.6 (BWR/6) Drywell Vacuum Relief System 3.7.1 (BWR/6) Standby Service Water (SSW) System and Ultimate Heat Sink (UHS) 3.7.2 (BWR/4) Plant Service Water (PSW) System and Ultimate Heat Sink (UHS) 3.7.4 (BWR/4) Main Control Room Environmental Control (MCREC)

System 3.7.5 (BWR/4) Control Room Air Conditioning (AC) System 3.8.7 (BWR/4 and 6) Inverters (Operating)

3.0 REGULATORY ANALYSIS

3.1 No Significant Hazards Consideration Determination Exelon Generation Company, LLC (EGC) has reviewed the proposed No Significant Hazards Consideration Determination (NSHCD) published in the FederalRegister as part of the Consolidated Line Item Improvement Process (CLIIP). EGC has concluded that the proposed NSHCD presented in the FederalRegister notice is applicable to LaSalle County Station (LSCS) Units 1 and 2 and is hereby incorporated by reference to satisfy the requirements of 10 CFR 50.91 (a), "Notice for public comment."

Page 3 of 5

ATTACHMENT 1 Description of Proposed Changes, Technical Analysis, and Regulatory Analysis 3.2 Verification and Commitments As discussed in the notice of availability published in the FederalRegister on March 23, 2006 for this TS improvement, plant-specific verifications were performed as follows.

EGC commits to the regulatory commitments in Attachment 4. In addition, EGC has proposed TS Bases consistent with the GE topical report and TSTF-423, which provide guidance and details on how to implement the new requirements. Implementation of TSTF-423 requires that risk be managed and assessed. EGC's configuration risk management program is adequate to satisfy this requirement. The risk assessment need not be quantified, but may be a qualitative assessment of the vulnerability of systems and components when one or more systems are not able to perform their associated function. Furthermore, EGC has a Bases Control Program consistent with Section 5.5 of the Standard Technical Specifications (STS).

4.0 ENVIRONMENTAL EVALUATION The amendment affects requirements with respect to the installation or use of a facility component located within the restricted area as defined in 10 CFR 20, "Standards for Protection Against Radiation." The NRC has determined that the amendment adopting TSTF-423, Revision 0, involves no significant increases in amounts of effluents that may be released offsite, no significant changes in the types of effluents that may be released offsite, and no significant increases in the individual or cumulative occupational radiation exposure. The NRC has previously issued a proposed finding that TSTF-423, Revision 0, involves no significant hazards considerations and there has been no public comment on said finding in the Federal Register,Notice 70 FR 74037, December 14, 2005. Accordingly, the amendment meets the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9), "Criterion for categorical exclusion." Pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the issuance of this amendment.

5.0 IMPACT ON PREVIOUS SUBMITTALS The amendment seeks to execute changes on TS that currently have pending amendments. The following TS pages have the associated amendments pending.

TSTF-360, DC 3.8.4 -1 through 3.8.4 -6 Submitted 12/9/04 System/Battery ACT CSCS one time only AOT 3.8.1 -4, 3.8.1 -6 through Submitted 4/13/05 extension 3.8.1 -19 Page 4 of 5

ATTACHMENT 1 Description of Proposed Changes, Technical Analysis, and Regulatory Analysis

6.0 REFERENCES

1. NEDC-32988-A, Revision 2, "Technical Justification to Support Risk-Informed Modification to Selected Required Action End States for BWR Plants," December 2002.

2. TSTF-423, Revision 0, "Technical Specifications End States, NEDC-32988-A."

3. Federal Register, Vol. 71, No. 56, p. 14726, "Notice of Availability of Model Application Concerning Technical Specifications for Boiling Water Reactor Plants to Risk-Inform Requirements Regarding Selected Required Action End States Using the Consolidated Line Item Improvement Process, and NRC Model Safety Evaluation," March 23, 2006.

Page 5 of 5

ATTACHMENT 2 Mark-up of Proposed Technical Specification Page Changes Revised Technical Specification Pages 3.3.8.2 -2 3.5.1 -2 3.5.1 -3 3.6.1.1 -1 3.6.1.6-1 3.6.1.6 -2 3.6.2.3 -1 3.6.2.4 -1 3.6.4.1 -1 3.6.4.3 -1 3.6.4.3 -2 3.7.1 -2 3.7.4 -1 3.7.4 -2 3.7.5 -1 3.7.5 -2 3.7.6 -1 3.8.1 -6 3.8.4 -1 3.8.4 -2 3.8.7 -2 3.8.7 -3

RPS Electric Power Monitoring 3.3.8.2 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C. Required Action and C.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time of Condition A -A__

or B not met in MODE 1, 2, or 3. C.2 Be in ... [E 4. 96 .....

D. Required Action and D.1 Initiate action to Immediately associated Completion restore one electric Time of Condition A or power monitoring B not met in MODE 4 or assembly to OPERABLE 5 with RHR SDC status for inservice isolation valves open. power supply(s) supplying required instrumentation.

OR 0.2 Initiate action to Immediately isolate the RHR SDC System.

E. Required Action and E.1 Initiate action to Immediately associated Completion fully insert all Time of Condition A or insertable control B not met in MODE 5 rods in core cells with any control rod containing one or withdrawn from a core more fuel assemblies.

cell containing one or more fuel assemblies.

(continued)

LaSalle 1 and 2 3.3.8.2-2 Amendment No. 147/133

ECCS-Operating 3.5.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. High Pressure Core B.1 Verify by Immediately Spray (HPCS) System administrative means inoperable. RCIC System is OPERABLE when RCIC is required to be OPERABLE.

AND B.2 Restore HPCS System 14 days to OPERABLE status.

C. Two low pressure ECCS C.1 Restore one low 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months injection/spray pressure ECCS subsystems inoperable, injection/spray subsystem to OPERABLE status.

D. ADS accumulator backup D.1 Restore ADS 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months compressed gas system accumulator backup bottle pressure compressed gas system

< 500 psig. bottle pressure

> 500 psig.

OR D.2 Declare associated 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months ADS valves inoperable.

E. Required Action and E.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time of Condition A, AND--

B, or C not met.

E.2 Be in MODE 4-. ý6 Ha..

(continued)

LaSalle 1 and 2 3.5.1-2 Amendment No. 147/133

ECCS-Operating 3.5.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME F. One required ADS valve F.1 Restore required ADS 14 days inoperable, valve to OPERABLE status.

". Roquired Action and X.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months l ass iat.d.. ,

cmpltia, Time of CGdition F AND not met.

2 Reduce reactor steam 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months OR4 dome pressure to

_ 150 psig.

Two or more required ADS valves inoperable.

,*l. HPCS and one or more 1.i Enter LCO 3.0.3. Immediately low pressure ECCS injection/spray subsystems inoperable.

OR Three or more ECCS injection/spray subsystems inoperable.

OR One or more ECCS injection/spray subsystems and one or more required ADS valves inoperable.

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

LaSalle I and 2 3.5.1-3 Amendment No. 147/133

Primary Containment 3.6.1.1 3.6 CONTAINMENT SYSTEMS 3.6.1.1 Primary Containment LCO 3.6.1.1 Primary containment shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Primary containment A.1 Restore primary 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months inoperable, containment to OPERABLE status.

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

LaSalle 1 and 2 3.6.1.1-1 Amendment No. 147/133

Suppression Chamber-to-Drywell Vacuum Breakers 3.6.1.6 3.6 CONTAINMENT SYSTEMS 3.6.1.6 Suppression Chamber-to-Drywell Vacuum Breakers LCO 3.6.1.6 Each suppression chamber-to-drywell vacuum breaker shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One suppression A.1 Restore the vacuum 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months chamber-to-drywell breaker to OPERABLE vacuum breaker status.

inoperable for opening.

,8'. One suppression 1.1 Close both manual 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months c chamber-to-drywell r- isolation valves in vacuum breaker not the affected line.

closed.

AND

ý.2 Restore the vacuum 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months mbreaker to OPERABLE status.

61'. Required Action and 9.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time of Condition-A er not met. D AND Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months (continued)

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

LaSalle 1 and 2 3.6.1.6-1 Amendment No. 147/133

Suppression Chamber-to-Drywell Vacuum Breakers 3.6.1.6 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME

/5. Two or more /.1 Enter LCO 3.0.3. Immediately

[ suppression 1 chamber-to-drywell vacuum breakers inoperable.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.1.6.1 ------------------ NOTES----------------

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

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

Verify each vacuum breaker is closed. 14 days SR 3.6.1.6.2 Perform a functional test of each vacuum 92 days breaker.

AND Within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after any discharge of steam to the suppression chamber from the safety/relief val ves (continued)

LaSalle 1 and 2 3.6.1.6-2 Amendment No. 147/133

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

APPLICABILITY: MODES 1, 2, and 3.

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

/. Two RHR suppression $.1 Restore one RHR 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months m pool cooling suppression pool

'- subsystems inoperable, cooling subsystem to OPERABLE status.

. Required Action and V.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months

[* associated Completion Time not met. AND of Condition C2 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months B. Required Action and associated B.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Completion Time of Condition A not met.

LaSalle I and 2 3.6.2.3-1 Amendment No. 147/133

RHR Suppression Pool Spray 3.6.2.4 3.6 CONTAINMENT SYSTEMS 3.6.2.4 Residual Heat Removal (RHR) Suppression Pool Spray LCO 3.6.2.4 Two RHR suppression pool spray subsystems shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3.

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

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

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

6.2 nc in MODE Q . 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months LaSalle 1 and 2 3.6.2.4-1 Amendment No. 147/133

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

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

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

B. Required Action and B.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time of Condition A -A_--

not met.

B.2 Be in1,ODE 4. 36 ,uhirs (continued)

LaSalle I and 2 3.6.4.1-1 Amendment No. 147/133

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

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

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One SGT subsystem A.1 Restore SGT subsystem 7 days inoperable, to OPERABLE status.

B. Required Action and B.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time of Condition A ___

not met in MODE 1, 2, or 3. B.2. ..B i. ..... .

4.

C. Required Action and ------------- NOTE-----------

associated Completion LCO 3.0.3 is not applicable.

Time of Condition A not met during movement of irradiated C.1 Place OPERABLE SGT Immediately fuel assemblies in the subsystem in secondary containment, operation.

during CORE ALTERATIONS, or during OR OPDRVs.

(continued)

LaSalle 1 and 2 3.6.4.3-1 Amendment No. 147/133

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

AND C.2.2 Suspend CORE Immediately ALTERATIONS.

AND C.2.3 Initiate action to Immediately suspend OPDRVs.

D. Two SGT subsystems D.1 E*t*, LCO 3.0.3. Immcdiotely inoperable in MODE 1, in MODE 3] 112hours-1Be 2, or 3.

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

inoperable during LCO 3.0.3 is not movement of irradiated applicable.

fuel assemblies in the secondary containment, during CORE Suspend movement of Immediately ALTERATIONS, or during irradiated fuel OPDRVs. assemblies in the secondary containment.

AND (continued)

LaSalle I and 2 3.6.4.3-2 Amendment No. 147/133

RHRSW System 3.7.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. --- NOTE --------- B.1 ---------NOTE--------

Only applicable to Enter applicable Unit 2 during Conditions and replacement of the Required Actions of Division 1 CSCS LCO 3.4.9, "Residual isolation valves Heat Removal (RHR) during Unit 1 Shutdown Cooling Refueling 11 while System-Hot Unit 1 is in Mode 4,5, Shutdown," for RHR or defueled. shutdown cooling subsystem made One RHRSW subsystem inoperable by RHRSW inoperable. System.

Restore RHRSW 10 days subsystem to OPERABLE status.

Both RHRSW subsystems .1 -------- NOTE--------

nD inoperable. nD Enter applicable Conditions and Required Actions of LCO 3.4.9 for RHR shutdown cooling subsystems made inoperable by RHRSW System.

Restore one RHRSW 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months subsystem to OPERABLE status.

X Required Action and 9.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 1] associated Completion Time not met. AND 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months EIooitioniý 2 Be in MODE 4.

C. Required Action and associated Be in MODE 3.

Completion Time of Conditions A or B not met. C.1 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months LaSalle 1 and 2 3.7.1-2 Amendment No. 175/161

CRAF System 3.7.4 3.7 PLANT SYSTEMS 3.7.4 Control Room Area Filtration (CRAF) System LCO 3.7.4 Two CRAF subsystems shall be OPERABLE.

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

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One CRAF subsystem A.1 Restore CRAF 7 days inoperable, subsystem to OPERABLE status.

B. Required Action and B.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Associated Completion Time of Condition A ___

not met in MODE 1, 2, or 3. B.2 Bc in , ODE,-4. ;6 heaps (continued)

LaSalle 1 and 2 3.7.4-1 Amendment No. 147/133

CRAF System 3.7.4 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C. Required Action and ------------- NOTE-----------

associated Completion LCO 3.0.3 is not applicable.

Time of Condition A not met during movement of irradiated C.1 Place OPERABLE CRAF Immediately fuel assemblies in the subsystem in secondary containment, pressurization mode.

during CORE ALTERATIONS, or during OR OPDRVs.

C.2.1 Suspend movement of Immediately irradiated fuel assemblies in the secondary containment.

AND C.2.2 Suspend CORE Immediately ALTERATIONS.

AND C.2.3 Initiate action to Immediately suspend OPDRVs.

D. Two CRAF subsystems D.1 Eite LCO 3.0.3ý-. -a'tly inoperable in MODE 1, PeinMODE3 F12hours I 2, or 3.

(continued)

LaSalle 1 and 2 3.7.4-2 Amendment No. 147/133

Control Room Area Ventilation AC System 3.7.5 3.7 PLANT SYSTEMS 3.7.5 Control Room Area Ventilation Air Conditioning (AC) System LCO 3.7.5 Two control room area ventilation AC subsystems shall be OPERABLE.

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

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One control room area A.1 Restore control room 30 days ventilation AC area ventilation AC subsystem inoperable, subsystem to OPERABLE status.

B. Required Action and B.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Associated Completion Time of Condition A ___

not met in MODE 1, 2, or 3. B.2 De in MHE 4-.

(continued)

LaSalle 1 and 2 3.7.5-1 Amendment No. 147/133

Control Room Area Ventilation AC System 3.7.5 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C. Required Action and ------------- NOTE-----------

associated Completion LCO 3.0.3 is not applicable.

Time of Condition A not met during movement of irradiated C.1 Place OPERABLE Immediately fuel assemblies in the control room area secondary containment, ventilation AC during CORE subsystem in ALTERATIONS, or during operation.

OPDRVs.

OR C.2.1 Suspend movement of Immediately irradiated fuel assemblies in the secondary containment.

AND C.2.2 Suspend CORE Immediately ALTERATIONS.

AND C.2.3 Initiate action to Immediately suspend OPDRVs.

D. Two control room area D.1 Enter LCe 3.0.3. atj

,.fflffled.

ventilation AC subsystems inoperable in MODE 1, 2, or 3.

(continued)

LaSalle 1 and 2 3.7.5-2 Amendment No. 147/133

Main Condenser Offgas 3.7.6 3.7 PLANT SYSTEMS 3.7.6 Main Condenser Offgas LCO 3.7.6 The gross gamma activity rate of the noble gases measured prior to the holdup line shall be

340,000 VtCi/second after decay of 30 minutes.

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

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

B. Required Action and B.1 Isolate all main 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion steam lines.

Time not met.

OR B.2 Isolate SJAE. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months OR B.31. Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months A*.D t=3.I I ODU 4.' 3 et-LaSalle 1 and 2 3.7.6-1 Amendment No. 147/133

AC Sources-Operating 3.8.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME F. Two required Division F.1 Restore one required 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months 1, 2, or 3 DGs DG to OPERABLE inoperable, status. OR OR 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months if Division 3 DG Division 2 DG and the is inoperable required opposite unit Division 2 DG inoperable.

G. Required Action and G.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time of Condition A, ANR-B, C, D, E, or F not met. G.2 Bt ill MODE 4. -hours H. Three or more required H.1 Enter LCO 3.0.3. Immediately AC sources inoperable.

LaSalle I and 2 3.8.1-6 Amendment No. 150/136

DC Sources-Operating 3.8.4 3.8 ELECTRICAL POWER SYSTEMS 3.8.4 DC Sources-Operating LCO 3.8.4 The Division 1 125 VDC and 250 VDC, Division 2 125 VDC, Division 3 125 VDC, and the opposite unit Division 2 125 VDC electrical power subsystems shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Division 1 or 2 A.1 Restore Division 1 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months 125 VDC electrical and 2 125 VDC power subsystem electrical power inoperable, subsystems to OPERABLE status.

,l? Division 3 DC X. Declare High Pressure Immediately M- electrical power Core Spray System Ccl subsystem inoperable, inoperable.

Division 1 250 VDC 'e1 Declare associated Immediately n] electrical power supported features subsystem inoperable, inoperable.

A* Opposite unit /.1 Restore opposite unit 7 days Division 2 DC D Division 2 DC electrical power electrical power subsystem inoperable, subsystem to OPERABLE status.

(continued)

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

LaSalle 1 and 2 3.8.4-1 Amendment No. 147/133

DC Sources-Operating 3.8.4 CONDITION REQUIRED ACTION COMPLETION TIME

. Required Action and '.I Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months

l associated Completion Time not met. AND for Condition C, D,orE /7.2 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months SURVEILLANCE REQUIREMENTS

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

1. SR 3.8.4.1 through SR 3.8.4.8 are applicable only to the given unit's DC electrical power sources.

2. SR 3.8.4.9 is applicable only to the opposite unit DC electrical power source.

SURVEILLANCE FREQUENCY SR 3.8.4.1 Verify battery terminal voltage on float 7 days charge is:

a. > 128 V for the 125 V batteries; and

b. _ 256 V for the 250 V battery.

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

OR Verify battery connection resistance is

< 1.5E-4 ohm for inter-cell connections, and < 1.5E-4 ohm for terminal connections.

(continued)

LaSalle 1 and 2 3.8.4-2 Amendment No. 147/133

Distribution Systems-Operating 3.8.7 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. One or both Division 1 B.1 Restore Division 1 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months and 2 125 V DC and 2 125 V DC electrical power electrical power AND distribution distribution subsystems inoperable, subsystem(s) to 16 hours1.851852e-4 days 0.00444 hours 2.645503e-5 weeks 6.088e-6 months from OPERABLE status. discovery of failure to meet LCO 3.8.7.a

/e'One or more required---------------NOTE----------

F opposite unit Division Enter applicable Conditions 2 AC or DC electrical and Required Actions of LCO power distribution 3.8.1 when Condition C subsystems inoperable, results in the inoperability of a required offsite circuit.

/.1 Restore required 7 days 5I opposite unit Division 2 AC and DC electrical power distribution subsystem(s).

,Er Required Action and I Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SEl associated Completion Time of Condition-A--, DI AND

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

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

LaSalle 1 and 2 3.8.7-2 Amendment No. 147/133

Distribution Systems-Operating 3.8.7 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME One or both Division 3 /.1 Declare associated Immediately AC or DC electrical supported features power distribution inoperable.

subsystems inoperable.

Division 1 250 V DC /I Declare associated Immediately ML electrical power supported features subsystem inoperable, inoperable.

Two or more electrical /.i Enter LCO 3.0.3. Immediately Ml power distribution subsystems inoperable that, in combination, result in a loss of function.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.7.1 Verify correct breaker alignments and 7 days voltage to required AC and DC electrical power distribution subsystems.

LaSalle 1 and 2 3.8.7-3 Amendment No. 147/133

ATTACHMENT 3 Mark-up of Technical Specification Bases Page Changes (For Information Only)

Revised Bases Pages (Provided for Information Only)

B 3.3.8.2 -5 B 3.3.8.2 -6 B 3.3.8.2 -8 B 3.3.8.2 -9 B 3.5.1 -8 to B 3.5.1 -10 B 3.5.1 -14 B 3.6.1.1 -3 B 3.6.1.1 -4 B 3.6.1.1 -6 B 3.6.1.6 -4 to B 3.6.1.6 -6 B 3.6.2.3 -2 to B 3.6.2.3 -4 B 3.6.2.4 -3 B 3.6.2.4 -4 B 3.6.4.1 -3 B 3.6.4.1 -6 B 3.6.4.3 -3 to B 3.6.4.3 -6 B 3.7.1 -5 B 3.7.1 -6 B 3.7.4 -4 B 3.7.4 -5 B 3.7.4 -7 B 3.7.4 -8 B 3.7.5 -4 B 3.7.5 -5 B 3.7.5 -7 B 3.7.6 -2 B 3.7.6 -3 B 3.8.1 -20 B 3.8.1 -21 B 3.8.1 -26 B 3.8.1 -39 B 3.8.1 -44 B 3.8.4 -5 to B 3.8.4 -7 B 3.8.4 -9 B 3.8.4 -11 to B 3.8.4 -13 B 3.8.7 -8 to B 3.8.7 -11

RPS Electric Power Monitoring B 3.3.8.2 BASES ACTIONS A.1 (continued)

Alternatively, if it is not desired to remove the power supply(s) from service (e.g., as in the case where removing the power supply(s) from service would result in a scram or isolation), Condition C, D, E, or F as applicable, must be entered and its Required Actions taken.

B.1 If both power monitoring assemblies for an inservice power supply (MG set or alternate) are inoperable, or both power monitoring assemblies in each inservice power supply are inoperable, the system protective function is lost. In this condition, 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months is allowed to restore one assembly to OPERABLE status for each inservice power supply. If one inoperable assembly for each inservice power supply cannot be restored to OPERABLE status, the associated power supplies must be removed from service within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months (Required Action B.1). An alternate power supply with OPERABLE assemblies may then be used to power one RPS bus.

The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time is sufficient for the plant operations personnel to take corrective actions and is acceptable because it minimizes risk while allowing time for restoration or removal from service of the electric power monitoring assemblies.

Alternately, if it is not desired to remove the power supply(s) from service (e.g., as in the case where removing the power supply(s) from service would result in a scram or isolation), Condition C, D, E, or F as applicable, must be entered and its Required Actions taken.

C. 1 - .

the plantmustbe If any Required Action and associated Completion Time of brought toaMODEin Condition A or B are not met in MODE 1, 2, or 3, a-plant which overall plant risk > 5iluLduwii ,,ust be er..ed. TH. ple. the plont n a isminimized. nd4 .iti ..H o f.i.. i a! .q...pm... , pew.r.d throau.gh. the inoperable PS l..trai.c p.w.r monitoring ..s...bly(), i5

-requirod and ensures that the safety function of the RPS buc loads (e.g., era-m of coatrol rods) is not requiroel. The (continued)

LaSalle 1 and 2 B 3.3.8.2-5 Revi si on 0

RPS Electric Power Monitoring B 3.3.8.2 BASES Insert 1 ACTIONS C.-a,-7 (continued) plant shutdown is accomplished by placing the planti is MODE 3 within 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .- I..... . ........ .. .our......

allowed Completion Time/ reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

D.1 and D.2 If any Required Action and associated Completion Time of Condition A or B are not met in MODE 4 or 5 with RHR SDC isolation valves open, action must be immediately initiated to either restore one electric power monitoring assembly to OPERABLE status for the inservice power source supplying the required instrumentation powered from the RPS bus (Required Action D.1) or to isolate the RHR SDC System (Required Action D.2). Required Action D.1 is provided because the RHR SDC System may be needed to provide core cooling. All actions must continue until the applicable Required Actions are completed.

E.1 If any Required Action and associated Completion Time of Condition A or B are not met in MODE 5 with any control rod withdrawn from a core cell containing one or more fuel assemblies, the operator must immediately initiate action to fully insert all insertable control rods in core cells containing one or more fuel assemblies (Required Action E.1). This Required Action results in the least reactive condition for the reactor core and ensures that the safety function of the RPS (e.g., scram of control rods) is not required.

F.1.1, F.1.2. F.2.1, and F.2.2 If any Required Action and associated Completion Time of Condition A or B are not met during movement of irradiated fuel assemblies in the secondary containment, during CORE ALTERATIONS, or during OPDRVs, the ability to isolate the (continued)

LaSalle 1 and 2 B 3.3.8.2-6 Revision 0

RPS Electric Power Monitoring B 3.3.8.2 BASES SURVEILLANCE SR 3.3.8.2.1 (continued)

REQUIREMENTS allow for scheduling and proper performance of the Surveillance. The 184 day Frequency and the Note in the Surveillance are bas d on guidance provided in Generic Letter 91-09 (Ref ./').

SR 3.3.8.2.2 CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies that the channel responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.

The Frequency is based upon the assumption of an 24 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.

SR 3.3.8.2.3 Performance of a system functional test demonstrates that, with a required system actuation (simulated or actual) signal, the logic of the system will automatically trip open the associated power monitoring assembly circuit breaker.

The system functional test shall include actuation of the protective relays, tripping logic, and output circuit breakers. Only one signal per power monitoring assembly is required to be tested. This Surveillance overlaps with the CHANNEL CALIBRATION to provide complete testing of the safety function. The system functional test of the Class 1E circuit breakers is included as part of this test to provide complete testing of the safety function. If the breakers are incapable of operating, the associated electric power monitoring assembly would be inoperable.

The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the (continued)

LaSalle 1 and 2 B 3.3.8.2-8 Revision 0

RPS Electric Power Monitoring B 3.3.8.2 BASES SURVEILLANCE SR 3.3.8.2.3 (continued)

REQUIREMENTS Surveillance were performed with the reactor at power.

Operating experience has shown that these components usually pass the Surveillance when performed at the 24 month Frequency.

REFERENCES 1. UFSAR, Section 8.3.1.1.3.

- NRC Generic Letter 91-09, "Modification of P Surveillance Interval for the Electric Protective Assemblies in Power Supplies for the Reactor Protection System."

LaSalle 1 and 2 B 3.3.8.2-9 Revision 0

ECCS-Operating B 3.5.1 BASES ACTIONS (continued) D.1 and D.2 With the ADS accumulator backup compressed gas system bottle pressure less than the specified limit, bottle pressure must be restored within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , or the associated ADS valves must be declared inoperable. In this condition, the remaining Drywell Pneumatic System and ADS accumulators are sufficient to ensure ADS valve operation. However, overall ECCS reliability is reduced in this condition because with insufficient bottle bank pressure, the capability of ADS valves to operate for long periods of time following an accident (without the Drywell Pneumatic System) is reduced.

Each ADS valve is equipped with an individual accumulator of sufficient capacity to operate the valves in the event of a loss of air supply. The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is based on a reliability study, as provided in Reference 12.

E .I 1 If any Required Action and associated Completion Time of 3rt 11 overall plant risk Condition A, B, or C are not met, the plant must be brought is minimized.. to a MODE in which the"4'LC dos To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .a. to ._*4 hath.../The allowed Completion Time/-Aý reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

F.1 The LCO requires six ADS valves to be OPERABLE to provide the ADS function. Reference 11 contains the results of an evaluation of the effect of one required ADS valve being out of service. Per this evaluation, operation of only five ADS valves will provide the required depressurization. However, overall reliability of the ADS is reduced because a single failure in the OPERABLE ADS valves could result in a reduction in depressurization capability. Therefore, operation is only allowed for a limited time. The 14 day Completion Time is based on a reliability study (Ref. 12) and has been found to be acceptable through operating experience.

(continued)

LaSalle 1 and 2 B 3.5.1-8 Revision 19

ECCS-Operating B 3.5.1 BASES ACTIONS (continued)

G. 1- .2 If any Required Action and associated Completion Time of MODE Condition F is not met or if two or more requ*i red ADS .. ý....

overall pla~nt risk o in.tpe.able, the plant must be brought to a PAnd.4ti.P

' in isminimized. . .which -the LCO doae not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months s-a+ý4-

- c-toi steam do,, e eto .r.... .. "- . ..

. , . The allowed Completion TimeX-are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

When multiple ECCS subsystems are inoperable, as stated in Condition (, the plant is in a condition outside of the design basis. Therefore, LCO 3.0.3 must be entered immediately.

SURVEILLANCE SR 3.5.1.1 REQUIREMENTS The flow path piping has the potential to develop voids and pockets of entrained air. Maintaining the pump discharge lines of the HPCS System, LPCS System, and LPCI subsystems full of water ensures that the systems will perform properly, injecting their full capacity into the RCS upon demand. This will also prevent a water hammer following an ECCS initiation signal. One acceptable method of ensuring the lines are full is to vent at the high points. The 31 day Frequency is based on operating experience, on the procedural controls governing system operation, and on the gradual nature of void buildup in the ECCS piping.

SR 3.5.1.2 Verifying the correct alignment for manual, power operated, and automatic valves in the ECCS flow paths provides assurance that the proper flow paths will exist for ECCS operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position since these valves were verified to be in the correct position prior to locking, sealing, or securing. A valve that receives an (continued)

LaSalle 1 and 2 B 3.5.1-9 Revision 19

ECCS-Operating B 3.5.1 BASES SURVEILLANCE SR 3.5.1.2 (continued)

REQUIREMENTS initiation signal is allowed to be in a nonaccident position provided the valve will automatically reposition in the proper stroke time. This SR does not require any testing or valve manipulation; rather, it involves verification that those valves potentially capable of being mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves.

The 31 day Frequency of this SR was derived from the Inservice Testing Program requirements for performing valve testing at least once every 92 days. The Frequency of 31 days is further justified because the valves are operated under procedural control and because improper valve alignment would only affect a single subsystem. This Frequency has been shown to be acceptable through operating experience.

SR 3.5.1.3 Verification every 31 days that ADS accumulator supply header pressure is Ž 150 psig assures adequate pneumatic pressure for reliable ADS operation. The accumulator on each ADS valve provides pneumatic pressure for valve actuation. The ADS valve accumulators are sized to provide two cycles of the ADS valves upon loss of the nitrogen supply (Ref.'Y-+. The ECCS safety analysis assumes only one actuation to achieve the depressurization required for operation of the low pressure ECCS. The accumulator supply header pressure verification may be accomplished by monitoring control room alarms. The 31 day Frequency takes into consideration alarms for low pneumatic pressure.

SR 3.5.1.4 Verification every 31 days that ADS accumulator backup compressed gas system bottle pressure is Ž 500 psig assures availability of an adequate backup pneumatic supply to the ADS accumulators following a loss of the drywell pneumatic supply. The 31 day frequency is adequate because each ADS bottle- bank is monitored by a low pressure alarm. Also, unless the normal drywell pneumatic supply is lost, the only expected losses from the bottles are due to leakage, which is minimal.

(continued)

LaSalle 1 and 2 B 3.5.1-10 Revision 19

ECCS-Operating B 3.5.1 BASES REFERENCES (continued) 12. Memorandum from R.L. Baer (NRC) to V. Stello, Jr.

(NRC), "Recommended Interim Revisions to LCO's for ECCS Components," December 1, 1975.

14 XZ. UFSAR, Section 7.3.1.2.

LaSalle 1 and 2 B 3.5.1-14 Revision 3

Primary Containment B 3.6.1.1 BASES LCO design limits. Compliance with this LCO will ensure a (continued) primary containment configuration, including equipment hatches, that is structurally sound and that will limit leakage to those leakage rates assumed in the safety analysis. Individual leakage rates specified for the primary containment air locks are addressed in LCO 3.6.1.2.

APPLICABILITY In MODES 1, 2, and 3, a DBA could cause a release of radioactive material to primary containment. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES. Therefore, primary containment is not required to be OPERABLE in MODES 4 and 5 to prevent leakage of radioactive material from primary containment.

ACTIONS A.1 In the event that primary containment is inoperable, primary containment must be restored to OPERABLE status within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time provides a period of time to correct the problem that is commensurate with the importance of maintaining primary containment OPERABILITY during MODES 1, 2, and 3. This time period also ensures that the probability of an accident (requiring primary containment OPERABILITY) occurring during periods where primary containment is inoperable is minimal.

B.1-i"--2 If primary containment cannot be restored to OPERABLE status overall plant risk is within the associated Coi letion Time, the plant must be nse minimized. brought to a MODE in which ... d.....

.... . +-p-B-). To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months t 49F ithim 36 houi-s. hest allowed Completion Timef-&-'-e- reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

(continued)

LaSalle 1 and 2 B 3.6.1.1-3 Revision 0

Primary Containment B 3.6.1.1 BASES (continued)

SURVEILLANCE SR 3.6.1.1.1 REQUIREMENTS Maintaining the primary containment OPERABLE requires compliance with the visual examinations and leakage rate test requirements of the Primary Containment Leakage Rate Testing Program. Failure to meet air lock leakage testing limit (SR 3.6.1.2.1), or main steam isolation valve leakage limit (SR 3.6.1.3.10) does not necessarily result in a failure of this SR. The impact of the failure to meet these SRs must be evaluated against the Type A, B, and C acceptance criteria of the Primary Containment Leakage Rate Testing Program.

As left leakage prior to the first startup after performing a required Primary Containment Leakage Rate Testing Program leakage test is required to be < 0.6 L, for combined Type B and C leakage, and

0.75 L, for overall Type A leakage. At all other times between required leakage rate tests, the acceptance criteria is based on an overall Type A leakage limit of < 1.0 L,. At

1.0 L, the offsite dose consequences are bounded by the assumptions of the safety analysis. The Frequency is required by the Primary Containment Leakage Rate Testing Program.

SR 3.6.1.1.2 The structural integrity of the primary containment is ensured by the successful completion of the Inservice Inspection Program for Post Tensioning Tendons and by associated visual inspections of the steel liner and penetrations for evidence of deterioration or breach of integrity. This ensures that the structural integrity of the primary containment will be maintained in accordance with the provisions of the Inservice Inspection Program for Post Tensioning Tendons. Testing and Frequency are consistent with the recommendations of 10 CFR 50.55a l....... Rf. ), except that the Unit 1 and 2 primary containments shall be treated as twin containments even though the Initial Structural Integrity tests were not within two years of each other.

(continued)

LaSalle 1 and 2 B 3.6.1.1-4 Revision 1

Primary Containment B 3.6.1.1 BASES SURVEILLANCE SR 3.6.1.1.4 (continued)

REQUIREMENTS developed considering it is prudent that this Surveillance be performed during a unit outage.

The SR is modified by a Note stating that performance of SR 3.6.1.1.3 satisfies this Surveillance Requirement. This is acceptable since drywell to suppression chamber vacuum relief valve leakage is included in the measurement of the drywell to suppression chamber bypass leakage required by SR 3.6.1.1.3.

SR 3.6.1.1.5 Maintaining the pressure suppression function of the primary containment requires limiting the leakage form the drywell to the suppression chamber. Thus, if an event were to occur that pressurizes the drywell, the steam would be directed through the downcomers into the suppression pool. This SR determines the total drywell to suppresssion chamber vacuum relief valve bypass leakage to ensure that the leakage paths that would bypass the suppression pool are within allowable limits.

Satisfactory performance of this SR can be achieved by summing the individual drywell to suppression chamber vacuum relief valve bypass leakage form SR 3.6.1.1.4 and verifying that the measured bypass leakage is < 3.0% of the acceptable A/IvR design value of 0.030 ft 2 . The acceptable bypass leakage of this Surveillance is performed every 24 months.

The 24 month Frequency was developed considering it si prudent that this Surveillance be performed during a unit outage.

The SR is modified by a Note stating that performance of SR 3.6.1.1.3 satisfies this Surveillance Requirement. This is acceptable since drywell to suppression chamber vacuum relief valve leakage is included in the measurement of the drywell to suppression chamber bypass leakage required by SR 3.6.1.1.3.

REFERENCES 1. UFSAR, Section 6.2.

2. UFSAR, Section 15.6.5.

3. 10 CFR 50, Appendix J, Option B.

4. UFSAR, Section 6.2.6.1.

- 10 CFR 50.55a.

LaSalln 1 and 2 B 3. 6 .1. 1-6 Revision 2

Suppression Chamber-to-Drywell Vacuum Breakers B 3.6.1.6 BASES ACTIONS A.1 (continued) with one of the four vacuum breakers inoperable, 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is allowed to restore the inoperable vacuum breaker to OPERABLE status so that plant conditions are consistent with those assumed for the design basis analysis. The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is considered acceptable due to the low probability of an event in which the remaining vacuum breaker capability would not be adequate.

NA.l and 2 With one vacuum breaker not closed, communication between the drywell and suppression chamber airspace exists, and, as a result, there is the potential for primary containment overpressurization due to this bypass leakage if a LOCA were to occur. Therefore, both manual isolation valves in the affected vacuum breaker line must be closed. A short time is allowed to close the manual valves due to the low probability of an event that would pressurize primary containment. The required 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time is considered adequate to perform this activity. With both manual isolation valves closed, the vacuum breaker is not capable of performing the vacuum relief function. While the remaining three OPERABLE vacuum breakers are capable of providing the vacuum relief function, the overall reliability is reduced because a single failure in one of the remaining vacuum breakers could result in an excessive suppression chamber-to-drywell differential pressure during a DBA. Therefore, under this condition, 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is allowed to restore the inoperable vacuum breaker to OPERABLE status so that the plant conditions are consistent with those assumed for the design basis analysis. The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is considered acceptable due to the low probability of an event in which the remaining vacuum breaker capability would not be adequate.

nD

[Ej,.-1 and .2 Iff u~req2 lkzp.j ,.ida----eiate pletian-e-nnat be

-met-, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and to MODE 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are (continued)

LaSalle 1 and 2 B 3.6.1.6-4 Revision 0

Suppression Chamber-to-Drywell Vacuum Breakers B 3.6.1.6 BASES ACTIONS H .1 and[.2 (continued) reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

With two or more vacuum breakers inoperable, an excessive suppression chamber-to-drywell differential pressure could occur during a DBA. Therefore, an immediate plant shutdown in accordance with LCO 3.0.3 is required.

SURVEILLANCE SR 3.6.1.6.1 REQUIREMENTS Each vacuum breaker is verified closed to ensure that this potential large bypass leakage path is not present. This Surveillance is performed by observing the vacuum breaker position indication or by verifying that a differential pressure of 0.25 psid between the suppression chamber and drywell is maintained for 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months without makeup. The 14 day Frequency is based on engineering judgment, is considered adequate in view of other indications of vacuum breaker status available to operations personnel, and has been shown to be acceptable through operating experience.

Two Notes are added to this SR. The first Note allows suppression chamber-to-drywell vacuum breakers opened in conjunction with the performance of a Surveillance to not be considered as failing this SR. These periods of opening vacuum breakers are controlled by plant procedures and do not represent inoperable vacuum breakers. The second Note is included to clarify that vacuum breakers open due to an actual differential pressure are not considered as failing this SR.

SR 3.6.1.6.2 Each vacuum breaker must be manually cycled to ensure that it opens adequately to perform its design function and returns to the fully closed position. This ensures that the safety analysis assumptions are valid. The 92 day Frequency of this SR was developed, based on Inservice Testing Program (continued)

LaSalle 1 and 2 B 3.6.1.6-5 Revision 0

Suppression Chamber-to-Drywell Vacuum Breakers B 3.6.1.6 BASES SURVEILLANCE SR 3.6.1.6.2 (continued)

REQUIREMENTS requirements to perform valve testing at least once every 92 days. In addition, this functional test is required within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after a discharge of steam to the suppression chamber from the safety/relief valves.

SR 3.6.1.6.3 Verification of the vacuum breaker opening setpoint of 5 0.5 psid from the closed position is necessary to ensure that the safety analysis assumption regarding vacuum breaker full open differential pressure of 1.0 psid is valid. The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. The 24 month Frequency has been shown to be acceptable, based on operating experience, and is further justified because of other surveillances performed at shorter Frequencies that convey the proper functioning status of each vacuum breaker.

REFERENCES 1. UFSAR, Section 6.2.1.

2. FSAR, Response to NRC Question 021.4.

LaSalle 1 and 2 B 3.6.1.6-6 Revision 0

RHR Suppression Pool Cooling B 3.6.2.3 BASES APPLICABLE suppression pool temperature is calculated to remain below SAFETY ANALYSES the design limit.

(continued)

The RHR Suppression Pool Cooling System satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii).

LCO During a DBA, a minimum of one RHR suppression pool cooling subsystem is required to maintain the primary containment peak pressure and temperature below the design limits (Ref. 1). To ensure that these requirements are met, two RHR suppression pool cooling subsystems must be OPERABLE.

Therefore, in the event of an accident, at least one subsystem is OPERABLE, assuming the worst case single active failure. An RHR suppression pool cooling subsystem is OPERABLE when the pump, a heat exchanger, and associated piping, valves, instrumentation, and controls are OPERABLE.

APPLICABILITY In MODES 1, 2, and 3, a DBA could cause both a release of radioactive material to primary containment and a heatup and pressurization of primary containment. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations in these MODES. Therefore, the RHR Suppression Pool Cooling System is not required to be OPERABLE in MODE 4 or 5.

ACTIONS A.1 With one RHR suppression pool cooling subsystem inoperable, the inoperable subsystem must be restored to OPERABLE status within 7 days. In this condition, the remaining RHR suppression pool cooling subsystem is adequate to perform the primary containment cooling function. However, the overall reliability is reduced because a single failure in the OPERABLE subsystem could result in reduced primary containment cooling capability. The 7 day Completion Time is acceptable in light of the redundant RHR suppression pool cooling capabilities afforded by the OPERABLE subsystem and the low probability of a DBA occurring during this period.

-> (continued)

LaSalle 1 and 2 B 3.6.2.3-2 Revi si on 0

RHR Suppression Pool Cooling B 3.6.2.3 BASES ACTIONS RE -

(continued)

With two RHR suppression pool cooling subsystems inoperable, one subsystem must be restored to OPERABLE status within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months . In this condition, there is a substantial loss of the primary containment pressure and temperature mitigation function. The 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months Completion Time is based on this loss of function and is considered acceptable due to the low probability of a DBA and the potential avoidance of a plant shutdown transient that could result in the need for the RHR suppression pool cooling subsystems to operate. FConditionCl nD D Iand 2 If any Required Action and associated Completion Time cannot be met, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and to MODE 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.6.2.3.1 REQUIREMENTS Verifying the correct alignment for manual and power operated valves in the RHR suppression pool cooling mode flow path provides assurance that the proper flow path exists for system operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position since these valves were verified to be in the correct position prior to being locked, sealed, or secured.

A valve is also allowed to be in the nonaccident position, provided it can be aligned to the accident position within the time assumed in the accident analysis. This is acceptable, since the RHR suppression pool cooling mode is manually initiated. This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of being mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves.

(continued)

LaSalle 1 and 2 B 3.6.2.3-3 Revision 0

RHR Suppression Pool Cooling B 3.6.2.3 BASES SURVEILLANCE SR 3.6.2.3.1 (continued)

REQUIREMENTS The Frequency of 31 days is justified because the valves are operated under procedural control, improper valve position would affect only a single subsystem, the probability of an event requiring initiation of the system is low, and the system is a manually initiated system. This Frequency has been shown to be acceptable, based on operating experience.

SR 3.6.2.3.2 Verifying each required RHR pump develops a flow rate

Ž 7200 gpm, while operating in the suppression pool cooling mode with flow through the associated heat exchanger, ensures that peak suppression pool temperature can be maintained below the design limits during a DBA (Ref. 1).

The flow verification is also a normal test of ce trifugal rol pump performance required by ASME Section XI (Ref.'-2). This LJ test confirms one point on the pump design curve, and the results are indicative of overall performance. Such inservice tests confirm component OPERABILITY and detect incipient failures by indicating abnormal performance. The Frequency of this SR is in accordance with the Inservice Testing Program.

REFERENCES 1. UFSAR, Section 6.2.

J l . ASME, Boiler and Pressure Vessel Code, Section XI.

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RHR Suppression Pool Spray B 3.6.2.4 BASES ACTIONS B.1 (continued)

With both RHR suppression pool spray subsystems inoperable, at least one subsystem must be restored to OPERABLE status within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months . In this condition, there is a substantial loss of the primary containment bypass leakage mitigation function. The 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months Completion Time is based on this loss of function and is considered acceptable due to the low probability of a DBA and because alternative methods to reduce pressure in the primary containment are available.

C. 1 -- *t"--

If any Required Action and associated Completion Time cannot overallplant be met, the plant must be brought to a MODE in which the-EO-risk is minimized. -doee-1+6+tappl. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and MODE " "li

-a6-htntis-* The allowed Completion TimeX-aai--, reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.6.2.4.1 REQUIREMENTS Verifying the correct alignment for manual and power operated valves in the RHR suppression pool spray mode flow path provides assurance that the proper flow paths will exist for system operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position since these valves were verified to be in the correct position prior to locking, sealing, or securing. A valve is also allowed to be in the nonaccident position provided it can be aligned to the accident position within the time assumed in the accident analysis. This is acceptable since the RHR suppression pool spray mode is manually initiated. This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of being mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves.

The Frequency of 31 days. is justified because the valves are operated under procedural control, improper valve position would affect only a single subsystem, the probability of an (continued)

LaSalle 1 and 2 B 3.6.2.4-3 Revision 0

RHR Suppression Pool Spray B 3.6.2.4 BASES SURVEILLANCE SR 3.6.2.4.1 (continued)

REQUIREMENTS event requiring initiation of the system is low, and the subsystem is a manually initiated system. This Frequency has been shown to be acceptable based on operating experience.

SR 3.6.2.4.2 Verifying each required RHR pump develops a flow rate

> 450 gpm through the spray sparger while operating in the suppression pool spray mode helps ensure that the primary containment pressure can be maintained below the design limits during a DBA (Ref. 1). The normal test of centrifugal pump performance required by Section XI of the ASME Code (Ref.V--2) is covered by the requirements of LCO 3.6.2.3, "RHR Suppression Pool Cooling." The Frequency of this SR is in accordance with the Inservice Testing Program.

REFERENCES 1. UFSAR, Section 6.2.1.1.3.

f/Z ASME, Boiler and Pressure Vessel Code, Section XI.

LaSalle 1 and 2 B 3.6.2.4-4 Revision 0

Secondary Containment B 3.6.4.1 BASES (continued)

ACTIONS A. 1 If secondary containment is inoperable, it must be restored to OPERABLE status within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time provides a period of time to correct the problem that is commensurate with the importance of maintaining secondary containment during MODES 1, 2, and 3. This time period also ensures that the probability of an accident (requiring secondary containment OPERABILITY) occurring during periods where secondary containment is inoperable is minimal.

B. 1and If the secondary containment cannot be restored to OPERABLE overallplantrisk status within the required Coin letion Time, the plant must minimzed.be brought to -a -MODE in which 1,8 -q- ý. To achieve this status, the plant must be brought to at least nser1 isMODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . V...1 61 ,

ULJL ýu ý hours. T allowed Completion Time reasonable, based on operating

-t-re-experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

C.1. C.2. and C.3 Movement of irradiated fuel assemblies in the secondary containment, CORE ALTERATIONS, and OPDRVs can be postulated to cause fission product release to the secondary containment. In such cases, the secondary containment is the only barrier to release of fission products to the environment. CORE ALTERATIONS and movement of irradiated fuel assemblies must be immediately suspended if the secondary containment is inoperable.

Suspension of these activities shall not preclude completing an action that involves moving a component to a safe position. Also, action must be immediately initiated to suspend OPDRVs to minimize the probability of a vessel draindown and subsequent potential for fission product release. Actions must continue until OPDRVs are suspended.

(continued)

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Secondary Containment B 3.6.4.1 BASES SURVEILLANCE SR 3.6.4.1.3 and SR 3.6.4.1.4 (continued)

REQUIREMENTS steady state conditions. The primary purpose of the SRs is to ensure secondary containment boundary integrity. The secondary purpose of these SRs is to ensure that the SGT subsystem being tested functions as designed. There is a separate LCO with Surveillance Requirements that serves the primary purpose of ensuring OPERABILITY of the SGT System.

These SRs need not be performed with each SGT subsystem.

The SGT subsystem used for these Surveillances is staggered to ensure that in addition to the requirements of LCO 3.6.4.3, either SGT subsystem will perform this test.

The inoperability of the SGT System does not necessarily constitute a failure of these Surveillances relative to secondary containment OPERABILITY. Operating experience has shown the secondary containment boundary usually passes these Surveillances when performed at the 24 month Frequency. Therefore the Frequency was concluded to be acceptable from a reliability standpoint.

REFERENCES 1. UFSAR, Section 15.6.5.

2. UFSAR, Section 15.7.4.

LaSalle 1 and 2 B 3. 6. 4. 1-6 Revision 0

SGT System B 3.6.4.3 BASES APPLICABILITY other situations under which significant releases of (continued) radioactive material can be postulated, such as during operations with a potential for draining the reactor vessel (OPDRVs), during CORE ALTERATIONS, or during movement of irradiated fuel assemblies in the secondary containment.

ACTIONS A. 1 With one SGT subsystem inoperable, the inoperable subsystem must be restored to OPERABLE status within 7 days. In this condition, the remaining OPERABLE SGT subsystem is adequate to perform the required radioactivity release control function. However, the overall system reliability is reduced because a single failure in the OPERABLE subsystem could result in the radioactivity release control function not being adequately performed. The 7 day Completion Time is based on consideration of such factors as the availability of the OPERABLE redundant SGT subsystem and the low probability of a DBA occurring during this period.

B.1 -and-W If the SGT the subsystem cannot be Time restored to OPERABLE is minimizeds within required Completion in MODE 1, 2, or status 3, the plant must be brought to a MODE in which th -

deX fo

-app4l. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ... #,- ..... thin

a9 y .VThe allowed Completion Times -treasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

C.t. C.2.1, C.2.2, and C.2.3 During movement of irradiated fuel assemblies in the secondary containment, during CORE ALTERATIONS, or during OPDRVs, when Required Action A.1 cannot be completed within the required Completion Time, the OPERABLE SGT subsystem should be immediately placed in operation. This Required Action ensures that the remaining subsystem is OPERABLE, that no failures that could prevent automatic actuation will occur, and that any other failure would be readily detected.

(continued)

LaSalle 1 and 2 B 3.6.4.3-3 Revision 0

SGT System B 3.6.4.3 BASES ACTIONS C.l. C.2.1, C.2.2. and C.2.3 (continued)

An alternative to Required Action C.1 is to immediately suspend activities that represent a potential for releasing radioactive material to the secondary containment, thus placing the unit in a condition that minimizes risk. If applicable, CORE ALTERATIONS and movement of irradiated fuel assemblies must be immediately suspended. Suspension of these activities shall not preclude completion of movement of a component to a safe position. Also, if applicable, action must be immediately initiated to suspend OPDRVs to minimize the probability of a vessel draindown and subsequent potential for fission product release. Action must continue until OPDRVs are suspended.

The Required Actions of Condition C have been modified by a Note stating that LCO 3.0.3 is not applicable. If moving irradiated fuel assemblies while in MODE 4 or 5, LCO 3.0.3 would not specify any action. If moving irradiated fuel assemblies while in MODE 1, 2, or 3, the fuel movement is independent of reactor operations. Therefore, in either case, inability to suspend movement of irradiated fuel assemblies would not be a sufficient reason to require a reactor shutdown.

D.1 If both SGT subsystems are inoperable in MODE 1, 2, or 3, the SGT system may not be capable of supporting the required radioactivity release control function. TheFrfor, acit-H--

E.1, E.2, and E.3 When two SGT subsystems are inoperable, if applicable, CORE ALTERATIONS and movement of irradiated fuel assemblies in the secondary containment must be immediately suspended.

Suspension of these activities shall not preclude completion of movement of a component to a safe position. Also, if applicable, action must. be immediately initiated to suspend OPDRVs to minimize the probability of a vessel draindown and subsequent potential for fission product release. Action must continue until OPDRVs are suspended.

(continued)

LaSalle 1 and 2 B 3.6.4.3-4 Revision 0

SGT System B 3.6.4.3 BASES ACTIONS E.l. E.2, and E.3 (continued)

Required Action E.1 has been modified by a Note stating that LCO 3.0.3 is not applicable. If moving irradiated fuel assemblies while in MODE 4 or 5, LCO 3.0.3 would not specify any action. If moving irradiated fuel assemblies while in MODE 1, 2, or 3, the fuel movement is independent of reactor operations. Therefore, in either case, inability to suspend movement of irradiated fuel assemblies would not be a sufficient reason to require a reactor shutdown.

SURVEILLANCE SR 3.6.4.3.1 REQUIREMENTS Operating (from the control room) each SGT subsystem for

Ž 10 continuous hours ensures that both subsystems are OPERABLE and that all associated controls are functioning properly. It also~ensures that blockage, fan or motor failure, or excessive vibration can be detected for corrective action. Operation with the heaters on for

Ž 10 continuous hours every 31 days eliminates moisture on the adsorbers and HEPA filters. The 31 day Frequency was developed in consideration of the known reliability of fan motors and controls and the redundancy available in the system.

SR 3.6.4.3.2 This SR verifies that the required SGT filter testing is performed in accordance with the Ventilation Filter Testing Program (VFTP). The SGT System filter tests are in accordance with ANSI/ASME N510-1989 (Ref Y). The VFTP includes testing HEPA filter performance, charcoal adsorber efficiency, minimum system flow rate, and the physical properties of the activated charcoal (general use and following specific operations). Specified test frequencies and additional information are discussed in detail in the VFTP.

(continued)

LaSalle 1 and 2 B 3.6.4.3-5 Revision 0

SGT System B 3.6.4.3 BASES SURVEILLANCE SR 3.6.4.3.3 REQUIREMENTS (continued) This SR requires verification that each SGT subsystem starts upon receipt of an actual or simulated initiation signal.

The LOGIC SYSTEM FUNCTIONAL TEST in LCO 3.3.6.2, "Secondary Containment Isolation Instrumentation," overlaps this SR to provide complete testing of the safety function. While this Surveillance can be performed with the reactor at power, operating experience has shown these components usually pass the Surveillance when performed at the 24 month Frequency, which is based on the refueling cycle. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

REFERENCES 1. 10 CFR 50, Appendix A, GDC 41.

2. UFSAR, Section 6.5.1.

3. UFSAR, Section 15.6.5.

4. UFSAR, Section 15.7.4 ANSI/ASME N510-1989.

LaSalle 1 and 2 B 3.6.4.3-6 Revision 0

RHRSW System B 3.7.1 BASES ACTIONS B.1 (continued)

Completion Time is based upon a risk-informed assessment that concluded that the associated risk with the unit in the specified configuration is acceptable (Ref. 5).

The Required Action is modified by a Note indicating that the applicable Conditions of LCO 3.4.9, be entered and Required Actions taken if the inoperable RHRSW subsystem results in inoperable RHR shutdown cooling. This is an exception to LCO 3.0.6 and ensures the proper actions are taken for these components.

With both RHRSW subsystems inoperable (e.g., both subsystems with inoperable pump(s) or flow paths, or one subsystem with an inoperable pump and one.subsystem with an inoperable flow path), the RHRSW System is not capable of performing its intended function. At least one subsystem must be restored to OPERABLE status within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months . The 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months Completion Time for restoring one RHRSW subsy~stem to OPERABLE status, is based on the Completion Times provided for the RHR suppression pool cooling and spray functions.

The Required Action is modified by a Note indicating that the applicable Conditions of LCO 3.4.9, be entered and Required Actions taken if the inoperable RHRSW subsystem results in inoperable RHR shutdown cooling. This is an exception to LCO 3.0.6 and ensures the proper actions are taken for these components.

,41* 1 and 7. 2 If any Required Action and associated Completion Time of 1 Coondit1on r riot nA,, met, the unit must be placed in a MODE in which the LCO does not apply. To achieve this status, the unit must be placed in at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in MODEQý within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Time/ -a--reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.

(continued)

LaSalle 1 and 2 B 3.7.1-5 Revision 21

RHRSW System B 3.7.1 BASES (continued)

SURVEILLANCE SR 3.7.1.1 REQUIREMENTS Verifying the correct alignment for each manual, power operated, and automatic valve in each RHRSW subsystem flow path provides assurance that the proper flow paths will exist for RHRSW operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position, since these valves are verified to be in the correct position prior to locking, sealing, or securing. A valve is also allowed to be in the nonaccident position, and yet considered in the correct position, provided it can be realigned to its accident position. This is acceptable because the RHRSW System is a manually initiated system.

This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of being mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves.

The 31 day Frequency is based on engineering judgment, is consistent with the procedural controls governing valve operation, and ensures correct valve positions.

REFERENCES 1. UFSAR, Section 9.2.1.

2. UFSAR, Chapter 6.

3. UFSAR, Chapter 15.

4. UFSAR, Section 6.2.2.3.1.

5. Risk Management Document SA-1354, Rev. 0, "LaSalle Division 1 and 2 CSCS Valve Replacement Project -

Temporary Extension of Technical Specification

>mCompletion Times", December 02, 2004.

LaSalle 1 and 2 B 3.7.1-6 Revi si on 21

CRAF System B 3.7.4 BASES APPLICABILITY b. During CORE ALTERATIONS; and (continued)

c. During operations with a potential for draining the reactor vessel (OPDRVs).

ACTIONS A.1 With one CRAF subsystem inoperable, the inoperable CRAF subsystem must be restored to OPERABLE status within 7 days.

With the unit in this condition, the remaining OPERABLE CRAF subsystem is adequate to perform control room radiation protection. However, the overall reliability is reduced because a single failure in the OPERABLE subsystem could result in loss of CRAF System function. The 7 day Completion Time is based on the low probability of a DBA occurring during this time period, and that the remaining subsystem can provide the required capabilities.

B.1 aind 2.2 In MODE 1, 2, or 3, if the inoperable CRAF subsystem cannot be restored to OPERABLE status within the associated vr- Completion Time, the unit must be placed in a MODE that mlnlmizesRrisk. To achieve this status, the unit must be llnr placed in at leasý MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in MODE 4 withim973 h 85 'Vr.The allowed Completion Time/ ae- <----

reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.

C.1, C.2.1, C.2.2. and C.2.3 LCO 3.0.3 is not applicable while in MODE 4 or 5. However, since irradiated fuel assembly movement can occur in MODE 1, 2, or 3, the Required Actions of Condition C are modified by a Note indicating that LCO 3.0.3 does not apply. If moving irradiated fuel assemblies while in MODE 1, 2, or 3, the fuel movement is independent of reactor operations.

Entering LCO 3.0.3 while in MODE 1, 2, or 3 would require the unit to be shutdown, but would not require immediate suspension of movement of irradiated fuel assemblies. The (continued)

LaSalle 1 and 2 B 3.7.4-4 Revision 0

CRAF System B 3.7.4 BASES ACTIONS C.1. C.2.1, C.2.2, and C.2.3 (continued)

Note to the ACTIONS, "LCO 3.0.3 is not applicable," ensures that the actions for immediate suspension of irradiated fuel assembly movement are not postponed due to entry into LCO 3.0.3.

During movement of irradiated fuel assemblies in the secondary containment, during CORE ALTERATIONS, or during OPDRVs, if the inoperable CRAF subsystem cannot be restored to OPERABLE status within the required Completion Time, the OPERABLE CRAF subsystem may be placed in the pressurization mode. This action ensures that the remaining subsystem is OPERABLE, that no failures that would prevent automatic actuation will occur, and that any active failure will be readily detected.

An alternative to Required Action C.1 is to immediately suspend activities that present a potential for releasing radioactivity that might require isolation of the control room area. This places the unit in a condition that minimizes risk.

If applicable, CORE ALTERATIONS and movement of irradiated fuel assemblies in the secondary containment must be suspended i.mmediately. Suspension of these activities shall not preclude completion of movement of a c-Qnmponent to a safe position. A1sp, if applicabhe, action must-.e.i4-iated immediately to suspeId OPDRV, to minimize the -p 4-iy of a vessel draindown and subsequent potential for fission product release. Action must continue until the OPDRVs are suspended.

D.1 If both CRAF subsystems are inoperable in MODE 1, 2, or 3, the CRAF System may not be capable of performing the intended function and the unit ic in a eendi* týoid. of hte accideot ool yse5, Thepeforo, LCD 3.0.3 mu.t be*

.e.t.ed i(contditnYu.

(continued)

LaSalle 1 and 2 B 3.7.4-5 Revision 0

CRAF System B 3.7.4 BASES SURVEILLANCE SR 3.7.4.1 (continued)

REQUIREMENTS

Ž 10 continuous hours during system operation dries out any moisture accumulated in the charcoal from humidity in the ambient air. Furthermore, the 31 day Frequency is based on the known reliability of the equipment and the two subsystem redundancy available.

SR 3.7.4.2 This SR verifies that flow can be manually realigned through the CRAF System recirculation filters and maintained for

Ž 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months . Standby systems should be checked periodically to ensure that they function. Monthly operation dries out any moisture accumulated in the charcoal from humidity in the ambient air. Furthermore, the 31 day Frequency is based on the known reliability of the equipment and two subsystem redundancy available.

SR 3.7.4.3 This SR verifies that the required CRAF testing is performed in accordance with Specification 5.5.8, "Ventilation Filter Testing Program (VFTP)." The CRAF filter tests are in accordance with ANSI/ASME N510-1989 (Ref.%). The VFTP includes testing HEPA filter performance, charcoal adsorber efficiency, system flow rate, and the physical properties of the activated charcoal (general use and following specific operations). Specific test frequencies and additional information are discussed in detail in the VFTP.

SR 3.7.4.4 This SR verifies that each CRAF subsystem automatically switches to the pressurization mode of operation on an actual or simulated air intake radiation monitors initiation signal. The LOGIC SYSTEM FUNCTIONAL TEST in SR 3.3.7.1.4 overlaps this SR to provide complete testing of the safety function. Operating experience has shown that these components normally pass the SR when performed at the 24 month Frequency. Therefore, the Frequency was found to be acceptable from a reliability standpoint.

(continued)

LaSalle 1 and 2 B 3.7.4-7 Revision 0

CRAF System B 3.7.4 BASES SURVEILLANCE SR 3.7.4.5 REQUIREMENTS (continued) This SR verifies the integrity of the control room area and the assumed inleakage rates of potentially contaminated air.

The control room area positive pressure, with respect to potentially contaminated adjacent areas, is periodically tested to verify proper function of the CRAF System. During the pressurization mode of operation, the CRAF System is designed to slightly pressurize the control room area to

> 0.125 inches water gauge positive pressure with respect to adjacent areas to prevent unfiltered inleakage. The CRAF System is designed to maintain this positive pressure at a flow rate of _<4000 cfm to the control room area in the pressurization mode. This test also requires manual initiation of flow through the control room and AEER recirculation filters line when the CRAF System is in the pressurization mode of operation. The Frequency of 24 months is consistent with industry practice and other filtration system SRs.

REFERENCES 1. UFSAR, Section 6.4.

2. UFSAR, Section 6.5.1.

3. UFSAR, Section 9.4.1.

4. UFSAR, Chapter 6.

5. UFSAR, Chapter 15.

ANSI/ASME N510-1989.

LaSalle 1 and 2 B 3.7.4-8 Revision 0

Control Room Area Ventilation AC System B 3.7.5 BASES ACTIONS A.1 (continued) on the low probability of an event occurring requiring operation of the CRAF System in the pressurization mode and the consideration that the remaining subsystem can provide the required protection.

B. Iard 2 In MODE 1, 2, or 3, if the inoperable control room area ventilation AC subsystem cannot be restored to OPERABLE status within the associated Com letion Time, the unit must ee p ace in a MODE that minimize-risk. To achieve this status the unit must be placed in at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 4 ,d 4 1. ... . T he allowed is Completion TimeX -ae-reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.

C.1. C.2.1. C.2.2. and C.2.3 LCO 3.0.3 is not applicable while in MODE 4 or 5. However, since irradiated fuel assembly movement can occur in MODE 1, 2, or 3, the Required Actions of Condition C are modified by a Note indicating that LCO 3.0.3 does not apply. If moving irradiated fuel assemblies while in MODE 1, 2, or 3, the fuel movement is independent of reactor operations.

Entering LCO 3.0.3 while in MODE 1, 2, or 3 would require the unit to be shutdown, but would not require immediate suspension of movement of irradiated fuel assemblies. The Note to the ACTIONS, "LCO 3.0.3 is not applicable," ensures that the actions for immediate suspension of irradiated fuel assembly movement are not postponed due to entry into LCO 3.0.3.

During movement of irradiated fuel assemblies in the secondary containment, during CORE ALTERATIONS, or during OPDRVs, if Required Action A.1 cannot be completed within the required Completion Time, the OPERABLE control room AC subsystem may be placed immediately in operation.

(continued)

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Control Room Area Ventilation AC System B 3.7.5 BASES ACTIONS C.1, C.2.1, C.2.2, and C.2.3 (continued)

This action ensures that the remaining subsystem is OPERABLE, that no failures that would prevent actuation will occur, and that any active failure will be readily detected.

An alternative to Required Action C.1 is to immediately suspend activities that present a potential for releasing radioactivity that might require isolation of the control room. This places the unit in a condition that minimizes risk.

If applicable, CORE ALTERATIONS and movement of irradiated fuel assemblies in the secondary containment must be suspended immediately. Suspension of these activities shall not preclude completion of movement of a component to a safe position. Also, if applicable, action must be initiated immediately-to suspend OPDRVs to minimize the probability of a vessel draindown and subsequent potential for fission product release. Action must continue until the OPDRVs are suspended.

D.1 If both control room area ventilation AC subsystems are inoperable in MODE 1, 2, or 3, the Control Room Area Ventilation AC System may not be capable of performing the intended function. Therefore, LCE 3.0.3 must be entered E.1. E.2, and E.3 The Required Actions of Condition E.1 are modified by a Note indicating that LCO 3.0.3 does not apply. If moving irradiated fuel assemblies while in MODE 1, 2, or 3, the fuel movement is independent of reactor operations.

Therefore, inability to suspend movement of irradiated fuel assemblies is not sufficient reason to require a reactor shutdown.

During movement of irradiated fuel assemblies in the secondary containment, during CORE ALTERATIONS, or during (continued)

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Control Room Area Ventilation AC System B 3.7.5 BASES SURVEILLANCE SR 3.7.5.2 REQUIREMENTS (continued) Verifying proper breaker alignment and power available to the control room area ventilation AC subsystems provides assurance of the availability of the system function. The 7 day Frequency is appropriate in view of other administrative controls that assure system availability.

REFERENCES 1. UFSAR, Section 6.4.

2. UFSAR, Section 9.4.1.

3. UFSAR, Section 9.4.1.1.1.1.

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Main Condenser Offgas B 3.7.6 BASES (continued)

APPLICABILITY The LCO is applicable when steam is being exhausted to the main condenser and the resulting noncondensibles are being processed via the Main Condenser Offgas System. This occurs during MODE 1, and during MODES 2 and 3 with any main steam line not isolated and the SJAE in operation. In MODES 4 and 5, main steam is not being exhausted to the main condenser and the requirements are not applicable.

ACTIONS A.1 If the offgas radioactivity rate limit is exceeded, 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is allowed to restore the gross gamma activity rate to within the limit. The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is reasonable, based on engineering judgment considering the time required to complete the Required Action, the large margins associated with permissible dose and exposure limits, and the low probability of a Main Condenser Offgas System rupture occurring.

B.1, B. 2,B.3j1, and B.3.2 If the gross gamma activity rate is not restored to within the limits within the associated Completion Time, all main steam lines or the SJAE must be isolated. This isolates the Main Condenser Offgas System from significant sources of radioactive steam. The main steam lines are considered isolated if at least one main steam isolation valve in each main steam line is closed, and at least one main steam line drain valve in each drain line is closed. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Completion Time is reasonable, based on operating experience, to perform the actions from full power conditions in an orderly manner and without challenging unit systems.

overall plant An alternative to Required Actions B.1 and B.2 is to place riskis the unit in a MODE in which theL'CD dcc: ngot apply. To minimized.

achieve this status, the unit must be placed in at least rs--l -MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in MODE 4 within 36 houerb. The allowed Completion Time$Na-&ý-reasonable, based on operating insert1 experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.

(continued)

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Main Condenser Offgas B 3.7.6 BASES (continued)

SURVEILLANCE SR 3.7.6.1 REQUIREMENTS This SR, on a 31 day Frequency, requires an isotopic analysis of a representative offgas sample taken prior to the holdup line to ensure that the required limits are satisfied. The noble gases to be sampled are Xe-133, Xe-135, Xe-135m, Xe-138, Kr-85m, Kr-87, and Kr-88. If the measured rate of radioactivity increases significantly (by

Ž 50% after correcting for expected increases due to changes in THERMAL POWER), an isotopic analysis is also performed within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months after the increase is noted (as indicated by the offgas pre-treatment noble gas activity monitor), to ensure that the increase is not indicative of a sustained increase in the radioactivity rate. The 31 day Frequency is adequate in view of other instrumentation that continuously monitor the offgas, and is acceptable based on operating experience.

This SR is modified by a Note indicating that the SR is not required to be performed until 31 days after any main steam line is not isolated and the SJAE is in operation. Only in this condition can radioactive fission gases be in the Main Condenser Offgas System at significant rates.

REFERENCES 1. UFSAR, Section 15.7.1.

s-T1 2. >i_

10 CFR 100.

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AC Sources-Operating B 3.8.1 BASES ACTIONS F.1 (continued)

In the event the required opposite unit Division 2 DG is inoperable in conjunction with a unit Division 2 DG inoperable, the opposite unit Division 2 subsystems (e.g.,

SGT subsystem) could be declared inoperable at the end of the 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Completion Time (see Applicability Note 2) and this Condition could be exited with only one required unit DG remaining inoperable. However, with the given unit Division 2 DG remaining inoperable and the opposite unit Division 2 subsystems declared inoperable, redundant required feature failures exist, according to Required Action C.2.

overall plant G.1 risk is Iminimized.

sources cannot be i If the inoperable AC electrical power restored to OPERABLE status within the associated Compýletion Time, the unit must be brought to a MODE in which the +/-6V -

doe: rat apply To achieve this status, the unit must be brought to MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months And 'A MODE 4 withmi-36--h s.V The allowed Completion Time ape reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

H.1 Condition H corresponds to a level of degradation in which all redundancy in the AC electrical power supplies has been lost. At this severely degraded level, any further losses in the AC electrical power system will cause a loss of function. Therefore, no additional time is justified for continued operation. The unit is required by LCO 3.0.3 to commence a controlled shutdown.

SURVEILLANCE The AC sources are designed to permit inspection and REQUIREMENTS testing of all important areas and features, especially 9 those that have a standy function, in accordance with 10 CFR 50, GDC 18 (Ref.,,). Periodic component tests are supplemented by extensive functional tests during refueling (continued)

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AC Sources-Operating B 3.8.1 BASES SURVEILLANCE outages under simulated accident conditions. The SRs for REQUIREMENTS demonstrating the OPERABILITY of the DGs are consistent with (continued) the recommendations of Regulatory Guide 1.9 (Ref. 3) and Regulatory Guide 1.137 (Ref.A.

The Surveillances are modified by two Notes to clearly identify how the Surveillances apply to the given unit and opposite unit's Division 2 DGs. Note 1 states that SR 3.8.1.1 through SR 3.8.1.20 are applicable only to the given unit AC electrical power sources and Note 2 states that SR 3.8.1.21 is applicable to the opposite unit's Division 2 DG. These Notes are necessary since the opposite unit AC electrical power source is not required to meet all of the requirements of the given unit AC electrical power sources (e.g., the opposite unit DG is not required to start on the opposite unit's ECCS initiation signal to support OPERABILITY of the given unit).

Where the SRs discussed herein specify voltage and frequency tolerances, the following summary is applicable. The minimum steady state output voltage of 4010 V is greater than 90% of the nominal 4160 V output voltage. This value, H_ which is conservative with respect to the value specified in ANSI C84.1 (Ref. ), allows for voltage drop to the terminals of 4000 V motors whose minimum operating voltage is specified as 90%, or 3600 V. It also allows for voltage drops to motors and other equipment down through the 120 V level where minimum operating voltage is also usually specified as 90% of name plate rating. The specified maximum steady state output voltage of 4310 V is within the maximum operating voltage of 110% specified for 4000 V motors. It ensures that for a lightly loaded distribution system, the voltage at the terminals of 4000 V motors is no more than the maximum rated operating voltages. The specified minimum and maximum frequencies of the DG are 58.8 Hz and 61.2 Hz, respectively. These values are equal to +/- 2% of the 60 Hz nominal frequency and are derived from the recommendations given in Regulatory Guide 1.9 (Ref. 3).

(continued)

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AC Sources-Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.5 (continued)

REQUIREMENTS fuel oil day tanks once every 31 days eliminates the necessary environment for bacterial survival. This is most effective means in controlling microbiological fouling. In addition, it eliminates the potential for water entrainment in the fuel oil during DG operation. Water may come from any of several sources, including condensation, rain water, contaminated fuel oil, and breakdown of the fuel oil by bacteria. Frequent checking for and removal of accumulated water minimizes fouling and provides data regarding the watertight integrity of the fuel oil system. The Surveillance Frequency is established by Regulatory Guide 1.137 (Ref.'*1- ). This SR is for preventive maintenance. The presence of water does not necessarily represent a failure of this SR provided that accumulated water is removed during performance of this Surveillance.

SR 3.8.1.6 This Surveillance demonstrates that each required fuel oil transfer pump operates and automatically transfers fuel oil from its associated storage tank to its associated day tank.

It is required to support the continuous operation of standby power sources. This Surveillance provides assurance that the fuel oil transfer pump is OPERABLE, the fuel oil piping system is intact, the fuel delivery piping is not obstructed, and the controls and control systems for automatic fuel transfer systems are OPERABLE.

The Frequency for this SR corresponds to the testing requirements for pumps as contained in the ASME Boiler and Pressure Vessel Code, Section XI (Ref.

SR 3.8.1.8 Transfer of each Division 1 and 2 4.16 kV emergency bus power supply from the normal offsite circuit to the alternate offsite circuit demonstrates the OPERABILITY of the alternate circuit distribution network to power the Division 1 and 2 shutdown loads. The 24 month Frequency of the Surveillance is based on engineering judgment taking (continued)

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AC Sources-Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.16 (continued)

REQUIREMENTS assessment shall, as a minimum, consider the potential outcomes and transients associated with a failed Surveillance, a successful Surveillance, and a perturbation of the offsite or onsite system when they are tied together or operated independently for the Surveillance; as well as the operator procedures available to cope with these outcomes. These shall be measured against the avoided risk of a plant shutdown and startup to determine that plant safety is maintained or enhanced when the Surveillance is performed in MODE 1 or 2. Risk insights or deterministic methods may be used for this assessment. Credit may be taken for unplanned events that satisfy this SR.

SR 3.8.1.17 Consistent with Regulatory Guide 1.9 (Ref. 3), paragraph C.2.2.13, demonstration of the parallel test mode override ensures that the DG availability under accident conditions is not compromised as the result of testing. Interlocks to the LOCA sensing circuits cause the Divisions 1 and 2 DGs to automatically reset to ready-to-load operation if an ECCS initiation signal is received during operation in the test mode. Ready-to-load operation is defined as the DG running at rated speed and voltage with the DG output breaker open.

These provisions for automatic switchover are required by IEEE-308 (Ref. Z), paragraph 6.2.6(2).

The Division 3 DG overcurrent trip of the SAT feeder breaker to the respective Division 3 emergency bus demonstrates the ability of the Division 3 DG to remain connected to the emergency bus and supplying the necessary loads.

The 24 month Frequency takes into consideration plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.

This SR has been modified by a Note. The reason for the Note is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems. This restriction from normally performing the (continued)

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AC Sources-Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.21 (continued)

REQUIREMENTS required by the given unit Specification. SR 3.8.1.12, SR 3.8.1.13, SR 3.8.1.17, SR 3.8.1.18, and SR 3.8.1.19 are excepted since these SRs test the opposite unit's ECCS initiation signal, which is not required for the AC electrical power sources to be OPERABLE on a given unit.

The Frequency required by the applicable opposite unit SR also governs performance of that SR for the given unit.

As noted, if the opposite unit is in MODE 4 or 5, or moving irradiated fuel assemblies in secondary containment, SR 3.8.1.3, SR 3.8.1.9 through SR 3.8.1.11, and SR 3.8.1.14 through SR 3.8.1.16 are not required to be performed. This ensures that a given unit SR will not require an opposite unit SR to be performed, when the opposite unit Technical Specifications exempts performance of an opposite unit SR (however, as stated in the opposite unit SR 3.8.2.1 Note 1, while performance of an SR is exempted, the SR must still be met).

REFERENCES 1. 10 CFR 50, Appendix A, GDC 17.

2. UFSAR, Chapter 8.

3. Regulatory Guide 1.9.

4. UFSAR, Chapter 6.

5. UFSAR, Chapter 15.

6. Regulatory Guide 1.93.

7. Generic Letter 84-15, July 2, 1984.

10 CFR 50, Appendix A, GDC 18.

FT . Regulatory Guide 1.137.

WlJ2. ANSI C84.1, 1982.

[i]/1A. ASME, Boiler and Pressure Vessel Code, Section XI.

ELK*. IEEE Standard 308.

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DC Sources-Operating B 3.8.4 BASES ACTIONS A.1 (continued) a subsequent worst case single failure could, however, result in the loss of minimum necessary DC electrical subsystems, continued power operation should not exceed 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months . The 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Completion Time is based on Regulatory Guide 1.93 (Ref. 7) and reflects a reasonable time to assess unit status as a function of the inoperable DC electrical power subsystem and, if the DC electrical power subsystem is not restored to OPERABLE status, to prepare to effect an orderly and safe unit shutdown.

E~BI1 With the Division 3 DC electrical power subsystem inoperable, the HPCS System may be incapable of performing its intended function and must be immediately declared inoperable. This declaration also requires entry into applicable Conditions and Required Actions of LCO 3.5.1, "ECCS-Operating."

With the Division 1 250 VDC electrical power subsystem inoperable, the RCIC System and the RCIC DC powered PCIVs may be incapable of performing their intended functions and must be immediately declared inoperable. This declaration also requires entry into applicable Conditions and Required Actions of LCO 3.5.3, "RCIC System," and LCO 3.6.1.3, "PCIVs."

If the opposite unit Division 2 125 VDC electrical power subsystem is inoperable (e.g., inoperable battery, inoperable charger, or inoperable battery charger and associated battery), certain redundant Division 2 features (e.g., a standby gas treatment subsystem) will not function if a design basis event were to occur. Therefore, a 7 day Completion Time is provided to restore the opposite unit Division 2 125 VDC electrical power subsystem to (continued)

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DC Sources-Operating B 3.8.4 BASES ACTIONS [9lk_. I (continued)

OPERABLE status. The 7 day Completion Time takes into account the capacity and capability of the remaining DC electrical power subsystems, and is based on the shortest restoration time allowed for the systems affected by the inoperable DC electrical power subsystem in the respective system specifications.

and Efl.2 If the DC electrical power subsystem cannot be restored to OPERABLE status within the associated Completion Time, the unit must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and to MODE 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. The Completion Time to bring the unit to MODE 4 is consistent with the time specified in Regulatory Guide 1.93 (Ref. 7).

SURVEILLANCE The Surveillances are modified by two Notes to clearly REQUIREMENTS identify how the Surveillances apply to the given unit and opposite unit DC electrical power sources. Note 1 states that SR 3.8.4.1 through SR 3.8.4.8 are applicable only to the given unit DC electrical power sources and Note 2 states that SR 3.8.4.9 is applicable to the opposite unit DC electrical power sources. These Notes are necessary since opposite unit DC electrical power sources are not required to perform all of the requirements of the given unit DC electrical power sources (e.g., the opposite unit battery is not required to perform SR 3.8.4.6, SR 3.8.4.7, and 3.8.4.8 under certain conditions when not in MODE 1, 2, or 3).

SR 3.8.4.1 Verifying battery terminal voltage while on float charge helps to ensure the effectiveness of the charging system and the ability of the batteries to perform their intended function. Float charge is the condition in which the (continued)

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DC Sources-Operating B 3.8.4 BASES SURVEILLANCE SR 3.8.4.1 (continued)

REQUIREMENTS charger is supplying the continuous charge required to overcome the internal losses of a battery and maintain the battery in a fully charged state. The voltage requirements are based on the nominal design voltage of the battery and are conservative when compared with the initial voltages assumed in the battery sizing calculations. The 7 day Frequency is consistent with manufacturers recommendations and IEEE-450 (Ref. /.

SR 3.8.4.2 Visual inspection to detect corrosion of the battery cells and connections, or measurement of the resistance of each inter-cell and terminal connection, provides an indication of physical damage or abnormal deterioration that could potentially degrade battery performance.

The connection resistance limits established for this SR are within the values established by industry practice. The connection resistance limits of this SR are related to the resistance of individual bolted connections, and do not include the resistance of conductive components (e.g.,

cables or conductors located between cells, racks, or tiers).

The Surveillance Frequency for these inspections, which can detect conditions that can cause power losses due to resistance heating, is 92 days. This Frequency is considered acceptable based on operating experience related to detecting corrosion trends.

SR 3.8.4.3 Visual inspection of the battery cells, cell plates, and battery racks provides an indication of physical damage or abnormal deterioration that could potentially degrade battery performance.

The presence of physical damage or deterioration does not necessarily represent a failure of this SR, provided an evaluation determines that the physical damage or (continued)

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DC Sources-Operating B 3.8.4 BASES SURVEILLANCE SR 3.8.4.6 REQUIREMENTS (continued) Battery charger capability requirements are based on the design capacity of the chargers (Ref. 4). According to Regulatory Guide 1.32 (Ref Y.), the battery charger supply is required to be based on the largest combined demands of the various steady state loads and the charging capacity to restore the battery from the design minimum charge state to the fully charged state, irrespective of the status of the unit during these demand occurrences. The minimum required amperes and duration ensure that these requirements can be sati sfi ed.

The Surveillance Frequency is acceptable, given the administrative controls existing to ensure adequate charger performance during these 24 month intervals. In addition, this Frequency is intended to be consistent with expected fuel cycle lengths.

SR 3.8.4.7 A battery service test is a special test of the battery's capability, as found, to satisfy the design requirements (battery duty cycle) of the DC electrical power system. The discharge rate and test length correspond to the design duty cycle requirements as specified in Reference 4.

The Surveillance Frequency of 24 months is acceptable, given unit conditions required to perform the test and the other requirements existing to ensure adequate battery performance during these 24 month intervals. In addition, this Frequency is intended to be consistent with expected fuel cycle lengths.

This SR is modified by two Notes. Note 1 allows the performance of a modified performance discharge test in lieu of a service test provided the modified performance discharge test completely envelops the service test. This substitution is acceptable because a modified performance discharge test represents a more severe test of battery capacity than SR 3.8.4.7. The reason for Note 2 is that performing the Surveillance would remove a required 125 VDC electrical power subsystem from service, perturb the (continued)

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DC Sources-Operating B 3.8.4 BASES SURVEILLANCE SR 3.8.4.8 (continued)

REQUIREMENTS continues to envelope the duty cycle of the service test.)

Since the ampere-hours removed by a rated one minute discharge represents a very small portion of the battery capacity, the test rate can be changed to that for the performance test without compromising the results of the performance discharge test. The battery terminal voltage for the modified performance discharge test should remain above the minimum battery terminal voltage specified in the battery service test for the duration of time equal to that of the service test.

A modified performance discharge test is a test of the battery capacity and its ability to provide a high rate, short duration load (usually the highest rate of the duty cycle). This will often confirm the battery's ability to meet the critical period of the load duty cycle,-in addition to determining its percentage of rated capacity. Initial conditions for the modified performance discharge test should be identical to those specified for a service test when the modified performance discharge test is performed in lieu of a service test. Either the battery performance discharge test or the modified performance discharge test is acceptable for satisfying SR 3.8.4.8; however, only the modified performance discharge test may be used to satisfy SR 3.8.4.8 while satisfying the requirements of SR 3.8.4.7 at the same time.

The acceptance crite ia for this Surveillance is consistent with IEEE-450 (Ref." ý8) and IEEE-485 (Ref. 11). These references recommend that the battery be replaced if its capacity is below 80% of the manufacturer's rating, since IEEE-485 (Ref. 11) recommends using an ageing factor of 125%

in the battery sizing calculation. A capacity of 80% shows that the battery rate of deterioration is increasing, even if there is ample capacity to meet the load requirements.

The Surveillance Frequency for this test is normally 60 months. If the battery shows degradation, or if the battery has reached 85% of its expected life and capacity is

< 100% of the manufacturers rating, the Surveillance Frequency is reduced to 12 months. However, if the battery shows no degradation but has reached 85% of its expected life, the Surveillance Frequency is only reduced to 24 months for batteries that retain capacity ; 100% of the (continued)

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DC Sources-Operating B 3.8.4 BASES SURVEILLANCE SR 3.8.4.8 (continued)

REQUIREMENTS manufacturers ratiq. Degradation is indicated, consistent with IEEE-450 (Ref. 8), when the battery capacity drops by more than 10% relative to its capacity on the previous performance test or when it is Ž 10% below the manufacturers rating. The 12 month and 60 month Frequencies are consistent with the recommendations in IEEE-450 (Ref.'Z)")

The 24 month Frequency is derived from the recommendations of IEEE-450 (Ref. ).

This SR is modified by a Note. The reason for the Note is that performing the Surveillance would remove a required 125 VDC electrical power subsystem from service, perturb the electrical distribution system, and challenge safety systems. This restriction from normally performing the Surveillance in MODE 1 or 2 is further amplified to allow portions of the Surveillance to be performed for the purpose of reestablishing OPERABILITY (e.g., post work testing following corrective maintenance, corrective modification, deficient or incomplete surveillance testing, and other unanticipated OPERABILITY concerns) provided an assessment determines plant safety is maintained or enhanced. This assessment shall, as a minimum, consider the potential outcomes and transients associated with a failed partial Surveillance, a successful partial Surveillance, and a perturbation of the offsite or onsite system when they are tied together or operated independently for the partial Surveillance; as well as the operator procedures available to cope with these outcomes. These shall be measured against the avoided risk of a plant shutdown and startup to determine that plant safety is maintained or enhanced when portions of the Surveillance are performed in MODE 1 or 2.

Risk insights or deterministic methods may be used for this assessment. Credit may be taken for unplanned events that satisfy this SR.

SR 3.8.4.9 With the exception of this Surveillance, allother Surveillances of this Specification (SR 3.8.4.1 through 3.8.4.8) are applied to the given unit DC sources. This Surveillance is provided to direct that appropriate Surveillances for the required opposite unit DC source are governed by the applicable opposite unit Technical (continued)

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DC Sources-Operating B 3.8.4 BASES SURVEILLANCE SR 3.8.4.9 (continued)

REQUIREMENTS Specifications. Performance of the applicable opposite unit Surveillances will satisfy the opposite unit requirements as well as satisfy the given unit Surveillance Requirement.

The Frequency required by the applicable opposite unit SR also governs performance of that SR for the given unit.

As noted, if the opposite unit is in MODE 4 or 5, or moving irradiated fuel assemblies in secondary containment, SR 3.8.4.6, SR 3.8.4.7, and SR 3.8.4.8 are not required to be performed. This ensures that a given unit SR will not require an opposite unit SR to be performed, when the opposite unit Technical Specifications exempts performance of an opposite unit SR (however, as stated in the opposite unit SR 3.8.5.1 Note 1, while performance of an SR is exempted, the SR must still be met).

REFERENCES 1. 10 CFR 50, Appendix A, GDC 17.

2. Regulatory Guide 1.6, March 10, 1971.

3. IEEE Standard 308, 1971.

4. UFSAR, Section 8.3.2.

5. UFSAR, Chapter 6.

6. UFSAR, Chapter 15.

7. Regulatory Guide 1.93, December 1974.

IEEE Standard 450, 1995.

rO9l. Regulatory Guide 1.32, August 1972.

11I . IEEE Standard 485, 1978.

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Distribution Systems-Operating B 3.8.7 BASES ACTIONS B.1 (continued)

The second Completion Time for Required Action B.1 establishes a limit on the maximum time allowed for any combination of required distribution subsystems to be inoperable during any single contiguous occurrence of failing to meet LCO 3.8.7.a. If Condition B is entered while, for instance, an AC electrical power distribution subsystem is inoperable and subsequently returned OPERABLE, LCO 3.8.7.a may already have been not met for up to 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months .

This situation could lead to a total duration of 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months , since initial failure of LCO 3.8.7.a, to restore the DC electrical power distribution system. At this time, an AC electrical power distribution subsystem could again become inoperable, and DC electrical power distribution subsystem could be restored OPERABLE. This could continue indefinitely.

This Completion Time allows for an exception to the normal "time zero" for beginning the allowed outage time "clock."

This allowance results in establishing the "time zero" at the time LCO 3.8.7.a was initially not met, instead of the time Condition B was entered. The 16 hour1.851852e-4 days 0.00444 hours 2.645503e-5 weeks 6.088e-6 months Completion Time is an acceptable limitation on this potential of failing to meet LCO 3.8.7.a indefinitely.

With one or more required opposite unit Division 2 AC or DC electrical power distribution subsystems inoperable and a loss of function has not yet occurred, certain redundant Division 2 features (e.g., a standby gas treatment subsystem) will not function if a design basis event were to occur. Therefore, a 7 day Completion Time is provided to restore the required opposite unit Division 2 AC and DC electrical power distribution subsystems to OPERABLE status.

The 7 day Completion Time takes into account the capacity and capability of the remaining AC and DC electrical power distribution subsystems, and is based on the shortest restoration time allowed for the systems affected by the inoperable AC and DC electrical power distribution subsystems in the respective system specifications.

(continued)

LaSalle 1 and 2 B 3.8.7-8 Revi si on 0

Distribution Systems-Operating B 3.8.7 BASES ACTIONS F/-.1 (continued)

The Required Action is modified by a Note indicating that the applicable Conditions of LCO 3.8.1 be entered and Required Actions taken if the inoperable opposite unit AC electrical power distribution subsystem results in an inoperable required offsite circuit. This is an exception to LCO 3.0.6 and ensures the proper actions are taken for these components.

rE] . I and 7.2 If the inoperable electrical power distribution system cannot be restored to OPERABLE status within the associated Completion Times, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and to MODE 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

With the Division 3 electrical power distribution system inoperable (i.e., one or both Division 3 AC or DC electrical power distribution subsystems inoperable), the Division 3 powered systems are not capable of performing their intended functions. Immediately declaring the affected supported features, e.g., the High Pressure Core Spray System and its associated primary containment isolation valves, inoperable allows the ACTIONS of LCO 3.5.1, "ECCS-Operating," and LCO 3.6.1.3, "Primary Containment Isolation Valves (PCIVs),"

to apply appropriate limitations on continued reactor operation.

With the Division 1 250 V DC subsystem inoperable, the RCIC System and the RCIC DC powered PCIVs may be incapable of performing their intended functions and must be immediately declared inoperable. This declaration also requires entry (continued)

LaSalle 1 and 2 B 3.8.7-9 Revi si on 0

Distribution Systems-Operating B 3.8.7 BASES ACTIONS 1 (continued) into applicible Conditions and Required Actions of LCO 3.5.3, "Reactor Core Isolation Cooling (RCIC) System," and LCO 3.6.1.3, "Primary Containment Isolation Valves (PCIVs)."

Condition / corresponds to a level of degradation in the electrical power distribution system that causes a required safety function to be lost. When the inoperability of two or more inoperable electrical power distribution subsystems, in combination, result in the loss of a required function, the plant is in a condition outside the accident analysis.

Therefore, no additional time is justified for continued operation. LCO 3.0.3 must be entered immediately to commence a controlled shutdown. The term "in combination" means that the loss of function must result from the inoperability of two or more AC and DC electrical power distribution subsystems; a loss of function solely due to a single AC or DC electrical power distribution subsystem inoperability even with another AC or DC electrical power distribution subsystem concucrently inoperable, does not require entry into Conditionf. In addition, for this Action, Division 3 is considered redundant to Division 1 and 2 ECCS.

SURVEILLANCE SR 3.8.7.1 REQUIREMENTS Meeting this Surveillance verifies that the AC and DC electrical power distribution systems are functioning properly, with the correct circuit breaker alignment. The correct breaker alignment ensures the appropriate separation and independence of the electrical divisions is maintained, and the appropriate voltage is available to each required bus. The verification of proper voltage availability on the buses ensures that the required voltage is readily available for motive as well as control functions for critical system loads connected to these buses. The 7 day Frequency takes into account the redundant capability of the AC and DC electrical power distribution subsystems, and other indications available in the control room that alert the operator to subsystem malfunctions.

(continued)

LaSalle 1 and 2 B 3.8.7-10 Revi si on 0

Distribution Systems-Operating B 3.8.7 BASES (continued)

REFERENCES 1. UFSAR, Chapter 6.

2. UFSAR, Chapter 15.

3. Regulatory Guide 1.93, Revision 0, December 1974.

LaSalle 1 and 2 B 3.8.7-11 Revision 0

LaSalle County Station TSTF-423 LAR Technical Specification Bases Page Inserts LCO 3.3.8.2 Reactor Protection System (RPS) Electric Power Monitoring Insert 1 Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 2) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state.

Insert 2

2. NEDC-32988-A, Revision 2, "Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants", December 2002.

LCO 3.5.1 ECCS-Operatincq Insert 1 Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 13) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state.

Insert 2 H.1 and H.2 If two or more ADS valves are inoperable, there is a reduction in the depressurization capability. The plant must be brought to a condition in which the LCO does not apply.

To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and reactor steam dome pressure reduced to < 150 psig within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

Insert 3

13. NEDC-32988-A, Revision 2, "Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants", December 2002.

LCO 3.6.1.1 Primary Containment Insert 1 Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 5), because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state.

Insert 2

5. NEDC-32988-A, Revision 2, "Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants", December 2002.

LCO 3.6.1.6 Suppression Chamber-to-Drywell Vacuum Breakers Insert 1 B.1 If a required suppression chamber-to-drywell vacuum breaker is inoperable for opening and is not restored to OPERABLE status within the required Completion Time, the plant must be brought to a condition in which the overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 3) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short.

However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

Insert 2 If the open suppression chamber-to-drywell vacuum breaker cannot be closed within the required Completion Time Insert 3

3. NEDC-32988-A, Revision 2, "Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants", December 2002.

LCO 3.6.2.3 Residual Heat Removal (RHR) Suppression Pool Cooling Insert I B.1 If one RHR suppression pool cooling subsystem is inoperable and is not restored to OPERABLE status within the required Completion Time, the plant must be brought to a condition in which the overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 2) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state.

The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

Insert 2

2. NEDC-32988-A, Revision 2, "Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants", December 2002.

LCO 3.6.2.4 Residual Heat Removal (RHR) Suppression Pool Spray Insert I Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 2) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state.

Insert 2

2. NEDC-32998-A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants, December 2002.

LCO 3.6.4.1 Secondary Containment Insert I Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to, or lower than the risk in MODE 4 (Ref. 3), because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state.

Insert 2

3. NEDC-32988-A, Revision 2, "Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants", December 2002.

LCO 3.6.4.3 Standby Gas Treatment (SGT) System Insert 1 Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 5) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state.

Insert 2 Therefore, the plant must be brought to a MODE in which the overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 5) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

Insert 3

5. NEDC-32988-A, Revision 2, "Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants", December 2002.

LCO 3.7.1 Residual Heat Removal Service Water (RHRSW) System Insert I C.1 If one RHRSW subsystem is inoperable and not restored within the provided Completion Time, the plant must be brought to a condition in which the overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 6) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

Insert 2

6. NEDC-32988-A, Revision 2, "Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants", December 2002.

LCO 3.7.4 Control Room Area Filtration (CRAF) System Insert 1 Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 6) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state.

Insert 2 Therefore, the plant must be brought to a MODE in which the overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 6) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions is an orderly manner and without challenging plant systems.

Insert 3

6. NEDC-32988-A, Revision 2, "Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants", December 2002.

LCO 3.7.5 Control Room Area Ventilation AC System Insert 1 Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 4) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state.

Insert 2 Therefore, the plant must be brought to a MODE in which the overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 4) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE

status will be short. However, voluntary entry into MODE 4 maybe be made as it is also an acceptable low-risk state. The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

Insert 3

4. NEDC-32988-A, Revision 2, "Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants", December 2002.

LCO 3.7.6 Main Condenser OffQas Insert 1 Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 3) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state.

Insert 2

3. NEDC-32988-A, Revision 2, "Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants", December 2002.

LCO 3.8.1 AC Sources - Ooeratina Insert I Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 8) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state.

Insert 2

8. NEDC-32988-A, Revision 2, "Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants", December 2002.

LCO 3.8.4 DC Sources - ODeratina Insert 1 B.1 If a Division 1 or 2 DC electrical power subsystem is inoperable and not restored within the provided Completion Time, the plant must be brought to a condition in which the

overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 8) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

Insert 2

8. NEDC-32988-A, Revision 2, "Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants", December 2002.

LCO 3.8.7 Distribution Systems - Operatinq Insert 1 C.1 If one or both Division 1 and 2 AC or DC electrical power distribution subsystems are inoperable and not restored within the provided Completion Time, the plant must be brought to a condition in which the overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 4) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short.

However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

Insert 2

4. NEDC-32988-A, Revision 2, "Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants", December 2002.

ATTACHMENT 4 List of Regulatory Commitments The following table identifies those actions committed to by Exelon Generation Company, LLC (EGC) in this document. Any other statements in the submittal are provided for information purposes and are not considered to be regulatory commitments.

COMMITMENT TYPE COMMITMENT COMMITTED ONE-TIME PROGRAMMATIC DATE ACTION (Yes/No)

(Yes/No)

EGC will follow the guidance established in Section 11 of NUMARC 93-01, "Industry Guidance Ongoing No Yes for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants,"

Nuclear Management and Resource Council, Revision 3, July 2000.

EGC will follow the guidance established in TSTF-IG-05-02, Implement Implementation Guidance for with No Yes TSTF-423, Revision 0, "Technical amendment Specifications End States, NEDC-32988-A," September 2005.

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RS-06-141, Application for Technical Specification Change TSTF-423, Risk Informed Modification to Selected Required Action End States for BWR Plants, Using the Consolidated Line Item Improvement Process

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