RS-05-001, Request for a License Amendment to Extend the Completion Times Related to Technical Specifications Associated with Residual Heat Removal Service Water, Diesel Generator Cooling Water and the Opposite Unit Division 2 Diesel..

Request for a License Amendment to Extend the Completion Times Related to Technical Specifications Associated with Residual Heat Removal Service Water, Diesel Generator Cooling Water and the Opposite Unit Division 2 Diesel..

ML051040149
Person / Time
Site:	LaSalle
Issue date:	04/13/2005
From:	Bauer J Exelon Generation Co, Exelon Nuclear
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
RS-05-0011
Download: ML051040149 (128)

Text

4300 Winfield Road Warrenville, IL 60555 10 CFR 50.90 RS-050011 April 13,2005 U . S. Nuclear Regulatory Commission ATTN : Document Control Desk Washington, DC 20555-0001 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:

Request for a License Amendment to Extend the Completion Times Related to Technical Specifications associated with Residual Heat Removal Service Water, Diesel Generator Cooling Water and the Opposite Unit Division 2 Diesel Generator In accordance with 10 CFR 50.90, "Application for amendment of license or construction permit," Exelon Generation Company, LLC (EGC) requests an amendment to Facility Operating License Nos . NPF-1 1 and NPF-18 for LaSalle County Station (LSCS), Units 1 and 2 . The proposed changes modify Technical Specifications (TS) Sections 3.7.1, "Residual Heat Removal Service Water (RHRSW) System," 3.7.2, "Diesel Generator Cooling Water (DGCW) System," and 3.8.1, "AC Sources - Operating." The proposed changes address the following items.

1 . An extension of the Completion Time (CT) for Required Action A.1, "Restore RHRSW subsystem to OPERABLE status," associated with TS Section 3.7.1 from 7 days to 10 days . This proposed change will only be used during the upcoming Unit 1 Spring 2006 Refueling Outage.

2 . The establishment of a 6 day (for Division 2 Core Standby Cooling System (CSCS) maintenance) or 10 day (for Division 1 CSCS maintenance) CT for TS Section 3.7.2 when one or more required DGCW subsystem(s) are inoperable .

This proposed change will only be used during each of the upcoming Unit 1 Spring 2006 and Unit 2 Spring 2007 refueling outages, and during the subsequent Unit 1 Spring 2008 refueling outage .

3. An extension of the CT for Required Action CA, "Restore required Diesel Generator (DG) to OPERABLE status," associated with TS Section 3.8.1 from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to 6 days. This proposed change will only be used during the upcoming Unit 2 Spring 2007 refueling outage, and during the subsequent Unit 1 Spring 2008 refueling outage .

April 13,2005 U . S . Nuclear Regulatory Commission Page 2 4 . An extension of the CT for Required Action F1, "Restore one required Diesel Generator (DG) to OPERABLE status," associated with TS Section 3.8 .1 from 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> to 6 days. This proposed change will only be used during the upcoming Unit 2 Spring 2007 refueling outage, and during the subsequent Unit 1 Spring 2008 refueling outage.

The current TS Limiting Condition for Operation (LCO) 3 .7.1 requires that two RHRSW subsystems be operable in Modes 1, 2, and 3. Condition A allows one RHRSW subsystem inoperable with a CT of 7 days . An extension of the CT to 10 days for the requested refueling outage is needed to replace isolation valves in the Division 1 Core Standby Cooling System (CSCS).

The current TS LCO 3.7.2 requires that three DGCW subsystems ; and the opposite unit Division 2 DGCW subsystem be operable in Modes 1, 2, and 3. Condition A requires that with one or more DGCW subsystems inoperable, immediately declare supported component(s) inoperable . A CT of 10 days for the Division 1 DGCW subsystem during the upcoming Unit 1 Refueling Outage 11(L1 R11) or 6 days for Division 2 DGCW subsystems during the requested refueling outages is needed to replace isolation valves in the Division 1 and Division 2 CSCS.

The current TS LCO 3.8.1 requires that the Division 1, 2, and 3 DGs and the required opposite unit DG be operable in Modes 1, 2, and 3. Condition C currently allows both units' Division 2 DGs to be inoperable with a CT of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> . Additionally, Condition F currently allows both units' Division 2 DGs to be inoperable with a CT of 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. An extension of the (IT to 6 days for the requested refueling outages is needed to replace isolation valves in the Division 2 CSCS .

Currently, due to long term wear and corrosion, many valves within the CSCS are degrading such that isolation on a specific cooling line may not be adequate to perform maintenance on system components . As pat of the CSCS reliability improvement effort, CSCS isolation valves will be replaced with stainless steel valves less susceptible to the corrosion wear the current valves are experiencing .

In order to replace the isolation valves, the CSCS suction header will be blank-flanged at the intake structure. Non-code line stops will be required to isolate the Unit 1 portion of the common discharge header from the Unit 2 portion of the header. The non-code line stops are designed to the same pressure rating and seismic requirements as the CSCS piping and will maintain the availability of the online unit's Division 2 CSCS system .

The Unit 1 and Unit 2 Division 1 CSCS maintenance planned for the Unit 1 Refueling Outage 11 (L1 R11 ) will result in the inoperability of the Division 1 RHRSW subsystem and therefore will require Unit 2 entry into TS 3.7.1 Condition A for inoperability of one RHRSW subsystem, and will also require entry into TS 3 .7.2 Condition A for inoperability of the Division 1 DGCW subsystem.

The Unit 1 and Unit 2 Division 2 CSCS maintenance planned for the Unit 2 Refueling Outage 11 (L2R1 1) and the Unit 1 Refueling Outage 12 (L1 R12) will result in the inoperability of one RHRSW subsystem and will also require entry into TS 3.7.2 Condition A for inoperability of the Division 2 DGCW subsystems .

April 13,2005 U. S. Nuclear Regulatory Commission Page 3 The Unit 1 and Unit 2 [Division 2 CSCS maintenance planned for L2R11 and L1 R12 will also result in the inoperability of the 1A and 2A Diesel Generators (DGs) and will require entry into TS 3 .8 .1 Condition C and Condition F due to the inoperability of both units' Division 2 DGs .

These maintenance evolutions are time consuming and include draining portions of the systems. Based on historical data and best work planning estimates, completion of the entire evolution for each refueling outage specified cannot be assured with the existing 7-day CT for TS 3 .7 .1 .A.1, the 72-hour CT for TS 3.8 .1 .C .4, the 2-hour CT for TS 3 .8.1 .F.1 or the existing TS 3.7.2 Required Action A.1 . Therefore, an extension of the CT to 10 days for TS 3.7.1 .A .1, 6 days for TS 3.8.1 .C .4, 6 days for TS 3.8.1 . F.1, and a 6 day CT (for Division 2 CSCS maintenance) or 10 day CT (for Division 1 CSCS maintenance) for TS 3.7.2 for the specific refueling outages stated is requested .

Replacement of the CSCS isolation valves is a prudent and proactive action . Having the capability to isolate components within the CSCS system will enable necessary system maintenance to be performed in the future thus enhancing the reliability of the Unit 1 and Unit 2 CSCS system and overall plant safety .

The proposed changes have been evaluated using the risk informed processes described in Regulatory Guide (RG) 1 .174, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis," dated July 1998, and RG 1 .177, "An Approach for Plant-Specific, Risk-informed Decision making:

Technical Specifications," dated August 1998 . The risk associated with the proposed change was found to be acceptable .

The NRC has previously approved a similar change for the Braidwood Station in Amendment No. 130 and Byron Station in Amendment No. 136 respectively, issued on March 18, 2004.

This request is subdivided as follows.

0 Attachment 1 provides an evaluation supporting the proposed TS changes .

0 Attachment 2 contains the marked-up TS pages with the proposed changes indicated .

0 Attachment 3 provides revised TS pages with the proposed changes incorporated .

Attachment 4 provides the revised TS Bases pages with the proposed changes incorporated . The TS Bases pages are provided for information only, and do not require NRC approval.

Attachment 5 provides a summary of the internal events probabilistic risk assessment (PRA) for LaSalle County Station .

The proposed changes have 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 . EGC requests approval of these changes prior to January 31, 2006, in advance of the LSCS, Unit 1 Spring 2006 Refueling Outage 11 (L1 R11) . Once approved, the amendment shall be implemented within

April '13,2005 U. S . Nuclear Regulatory Commission Page 4 30 days of issuance . This implementation period will provide adequate time for station documents to be revised using the appropriate change control mechanisms .

In accordance with 10 CFR 50.91, "Notice for public comment ; State consultation,"

paragraph (b), EGC is notifying the State of Illinois of this application for changes to the TS by transmitting a copy of this letter and its attachments to the designated State Official .

K you have any questions or require additional information, please contact Ms. Alison M.

Mackellar at (630) 657-2817 .

I declare under penalty of perjury that the foregoing is true and correct. Executed on the 13th day of April 2005 .

Respectfully, Joseph A. Bauer Manager - Licensing Attachments:

Attachment 1: Evaluation of Proposed Changes Attachment 2: Markup of Technical Specification Pages Attachment 3: Retyped Technical Specification Pages Attachment 4: Retyped Technical Specification Bases Pages Attachment 5: Summary of LaSalle County Station PRA

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGES 1 .0 DESCRIPTION

2.0 PROPOSED CHANGE

S

4.0 TECHNICAL ANALYSIS

4.1 Defense in Depth Evaluation 4.2 Safety Margin Evaluation 4.3 Risk Evaluation 4.3.1 Tier 1 : PRA Capability and Insights 4.3.1 .1 Quantitative Acceptance Guidelines 4 .3 .1 .2 Risk from Internal Events 4.3.1 .3 Risk from Internal Fires 4.3.1 .4 Risk from Seismic Events 4.3.1 .5 Risk from Other External Events 4.3.1 .6 Averted Risk from a Plant Shutdown 4.3.1 .7 Summary of Risk Insights 4 .3 .2 Tier 2: Avoidance of Risk-Significant Plant Configurations 4 .3 .3 Tier 3: Risk-Informed Configuration Risk Management Program 5 .0 REGULATORY ANALYSIS 5.1 No Significant Hazards Consideration 5.2 Applicable Regulatory Requirements/Criteria 6 .0 ENVIRONMENTAL CONSIDERATION 7 .0 REFERENCES

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGES 1 .0 DESCRIPTION In accordance with 10 CFR 50.90, "Application for amendment of license or construction permit,"

Exelon Generation Company, LLC (EGC) requests an amendment to Facility Operating License Nos. NPF-1 1 and NPF-1 8 for LaSalle County Station (LSCS), Units 1 and 2. The proposed changes modify Technical Specifications (TS) Sections 17 .1, "Residual Heat Removal Service Water (RHRSW) System," 3.7 .2, "Diesel Generator Cooling Water (DGCW) System," and 3 .8 .1, "AC Sources - Operating." The proposed changes address the following items .

1 . An extension of the Completion Time (CT) for Required Action A.1, "Restore RHRSW subsystem to OPERABLE status," associated with TS Section 3.7.1 from 7 days to 10 days . This proposed change will only be used during the upcoming Unit 1 Spring 2006 Refueling Outage.

2. The establishment of a 6 day (for Division 2 CSCS maintenance) or 10 day (for Division 1 CSCS maintenance) CT for TS Section 3.7 .2 when one or more required DGCW subsystem(s) are inoperable . This proposed change will only be used during each of the upcoming Unit 1 Spring 2006 and Unit 2 Spring 2007 refueling outages, and during the subsequent Unit 1 Spring 2008 refueling outage.

3 . An extension of the CT for Required Action CA, "Restore required Diesel Generator (DG) to OPERABLE status," associated with TS Section 3.8.1 from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to 6 days .

This proposed change will only be used during the upcoming Unit 2 Spring 2007 refueling outage, and during the subsequent Unit 1 Spring 2008 refueling outage.

4 . An extension of the CT for Required Action F .1, "Restore one required Diesel Generator (DG) to OPERABLE status," associated with TS Section 3 .8 .1 from 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> to 6 days .

This proposed change will only be used during the upcoming Unit 2 Spring 2007 refueling outage, and during the subsequent Unit 1 Spring 2008 refueling outage.

2.0 PROPOSED CHANGE

S The current TS Limiting Condition for Operation (LCO) 3 .7.1 requires that two RHRSW subsystems be operable in Modes 1, 2, and 3 . Condition A allows one RHRSW subsystem inoperable with a CT of 7 days . The proposed amendment adds a note to Condition A stating that the Condition is not applicable to Unit 2 during the replacement of Division 1 Core Standby Cooling System (CSCS) isolation valves during the Unit 1 Refueling Outage 11 (1-1 R11) .

A new Condition is added to TS 3.7.1 to address the inoperability of one RHRSW subsystem with a CT of 10 days during the Division 1 CSCS isolation valve work specific to the Unit 1 Refueling Outage 11 (1-1 R11) .

The current TS LCO 3.7 .2 requires that three DGCW subsystems ; and the opposite unit Division 2 DGCW subsystem be operable in Modes 1, 2, and 3 . Condition A currently requires that with one or more DGCW subsystems inoperable, immediately declare the supported component(s) inoperable . The proposed amendment adds two notes to Condition A stating that the Condition is not applicable to that specific Division of the DGCW subsystem during the replacement of CSCS isolation valves during the next three specified refueling outages.

Two new Conditions are added to TS 3.7.2 to facilitate the requested CT . The first new Condition addresses the inoperability of one or more DGCW subsystems with a CT of 6 days (for Division 2 CSCS maintenance) or 10 days (for Division 1 CSCS maintenance) during each 2 of 51

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGES stated refueling outage. This proposed CT of 6 days will only be used for the maintenance on Division 2 CSCS during the Unit 2 Refueling Outage 11 (L2R1 1), and the Unit 1 Refueling Outage 12 (L1 R12). The proposed CT of 10 days will only be used for the maintenance on Division 1 CSCS during the Unit 1 Refueling Outage 11 (L1 R11) .

In accordance with TS LCO 3.0 .1 the components supported by inoperable DGCW subsystems) will be declared inoperable ; however, the CTs of the LCO Required Actions of the supported systems are not of sufficient duration to allow completion of the work evolution . TS LCO 3.0 .6 requires entry into the supported system Conditions and Required Actions pursuant to TS LCO 3.0.2 when the support system's Required Actions direct the supported system to be declared inoperable . By adding the proposed 6-day or 10 day CT for an inoperable DGCW subsystem, the allowances of TS LCO 3.0.6 can be utilized to defer entry into the supported system Conditions and Required Actions and the duration of the inoperability will be controlled by the support system LCO Actions . The second new Condition added to TS 3.7.2 supplements the CT by adding an end state for the proposed Required Action CTs.

The current TS LCO 3.8.1 requires that the Division 1, 2, and 3 DGs and the required opposite unit DG be operable in Modes 1, 2, and 3. Condition C currently allows both units' Division 2 DGs to be inoperable with a CT of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. Condition F currently allows both units' Division 2 DGs to be inoperable with a CT of 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. The proposed amendment adds two notes to Condition C and Condition F that the Conditions are not applicable to the non-refueling outage unit during the replacement of the Division 2 CSCS isolation valves during two specified refueling outages. A new Condition is added to TS 3.8 .1 to address the inoperability of both units' Division 2 DGs with a CT of 6 days during the CSCS isolation valve work specific to each stated refueling outage. This proposed extension of the CT will only be used during the Unit 2 Refueling Outage 11 (L2R1 1) and during the Unit 1 Refueling Outage 12 (L1 R12).

These maintenance evolutions are time consuming and include draining portions of the systems. Based on historical data and best work planning estimates, completion of the entire evolution for each refueling outage specified cannot be assured with the existing 7-day CT for TS 3.7.1 .A .1, the 72-hour CT for TS 3 .8 .1 .C .4, the 2-hour CT for TS 3 .8.1 .F .1 or the existing TS 3.7 .2 Required Action A.1 .

Replacement of the CSCS isolation valves is a prudent and proactive action . Having the capability to isolate components within the CSCS system will enable necessary system maintenance to be performed in the future thus enhancing the reliability of the Unit 1 and Unit 2 CSCS system and overall plant safety .

EGC requests approval of these changes prior to January 31, 2006, in advance of the LaSalle County Station, Unit 1 Spring 2006 Refueling Outage 11 (L1 R11). Once approved, the amendment shall be implemented within 30 days of issuance .

3.0 BACKGROUND

Report The CSCS system is discussed in the LaSalle Updated Final Safety Analyst (UFSAR),

Section 9.2.1, "CSCS Equipment Cooling," (Reference 1) .

The function of the Core Standby Cooling System-Equipment Cooling Water System (CSCS-ECWS) is to circulate lake water from the ultimate heat sink for cooling of the residual heat removal (RHR) heat exchange, diesel-generator coolers, CSCS cubicle area cooling coils, RHR pump seal coolers, and low-pressure core spray (LPCS) pump motor cooling coils.

3 of 51

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGES This system also provides a source of emergency makeup water for fuel pool cooling and also provides containment flooding water for post-accident recovery. This CSCS-ECWS system is equivalent in purpose to the essential service water cooling systems at other stations .

The CSCS-ECWS for each unit consists of three independent piping subsystems corresponding to the three essential electrical power supply divisions for each unit. All pumps and strainers are located in the basements of the buildings within watertight cubicles to provide separation between divisions and flood protection . The outdoor CSCS-ECWS piping is buried to provide tornado and missile protection . The CSCS-ECW subsystems take suction from the service water tunnel located in the basement of the Lake Screen House . The service water tunnel is kept full by six inlet lines which connect to the Circulating Water pump forebays .

Division 1 of each unit includes two RHR service water pumps which supply cooling water to the Division 1 RHR heat exchanger and RHR pump seal cooler . The fuel pool emergency makeup pump in Division 1 of each unit supplies a source of emergency makeup water to the spent fuel pool . Also included in Division 1 of Unit 1 is a diesel-generator cooling water pump which supplies cooling water to the Division 1 diesel generator, Unit 1 and 2 LPCS pump motor coolers, and Units 1 and 2 Division 1 CSCS area coolers. Electrical power for operation of these pumps is supplied from Division 1 essential power.

Two RHR service water pumps are also provided in Division 2 of each unit to supply cooling water to the Division 2 RHR heat exchanger and the two Division 2 RHR pump seal coolers.

The diesel-generator cooling water pump in Division 2 of each unit supplies cooling water to the Division 2 diesel generator and to the Division 2 CSCS area cooler . The Division 2 fuel pool emergency makeup pump provides a redundant source of emergency makeup water to the spent fuel pool and also provides a source of containment flooding water to the RHR system for post-accident recovery. Electrical power for these pumps is supplied from essential Division 2 power.

Both the High Pressure Core Spray (HPCS) diesel generator and the Division 3 CSCS area cooler are supplied with cooling water by the Division 3 HPCS diesel-generator cooling water pump . Electrical power for this pump is fed from Division 3 essential power.

Each of the six CSCS divisions across the two units is configured with a separate suction pipe from the service water tunnel . The CSCS discharge pipes are combined into a common discharge for identical divisions of both Units 1 and 2. The discharge pipe outlets at the CSCS cooling pond are located above the normal cooling lake level .

Redundancy is provided by designing the CSCS system as multiple independent subsystems .

between subsystems assures that no single failure can affect more than one Separation subsystem. Therefore, assuming a single failure in any subsystem including the subsystem shared between units, two subsystems in each unit will remain unaffected . These two subsystems can supply the minimum required cooling water for safe shutdown of a unit or mitigate the consequences of an accident .

Each Engineered Safety Features (ESF) Division has a Diesel Generator (DG) that serves as an independent onsite power source in the event of the simultaneous occurrence of a total loss of offsite power (LOOP) and a loss of the unit auxiliary power system . The DGs have ample 4 of 51

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGES capacity to supply all power required for the safe shutdown of both units in the event of a total loss of offsite power, a loss of coolant accident (LOCA) on one unit concurrent with the shutdown of a unit without a LOCA, or a concurrent shutdown of both units without LOCAs.

The RHR system has three functional modes, each of which contributes towards satisfying the design basis of be system .

The different modes of RHR operation include :

1) Shutdown Cooling Reactor Pressure Vessel Head Spray

2) Low Pressure Coolant Injection (LPCI) Mode

3) Containment Cooling Mode (Suppression Pool Cooling and Containment Spray)

The LPCS system's primary function is to provide low pressure core spray to mitigate the effects of an intermediate and large break LOCAs .

The risk-informed technical evaluation described in Section 4 .0 considered the risk impacts on each of these functions .

Need for Amendment Currently, due to long term wear and corrosion, many valves within the CSCS, which includes the RHRSW System, the DGCW system and the Fuel Pool Emergency Make-up (FC) system, are degrading such that isolation on a specific cooling line may not be adequate to perform maintenance on system components such as the Diesel Generator Coolers, Room Coolers, and other piping components. Isolation valves need to be replaced in the Unit 1 and Unit 2 Division 1 DGCW system, the Unit 1 Division 1 FC system, the Unit 1 Division 2 FC system, the Unit 2 Division 1 FC system, the Unit 2 Division 2 FC system, the Unit 1 Division 2 DGCW system and the Unit 2 Division 2 DGCW system as part of the CSCS reliability improvement effort.

The Division 1 CSCS isolation valves scheduled for replacement include ODG007, ODG001, 1 El 2-F330A, 1 El 2-F330B, 1 DG032, 2DG032, 1 FC046A, 1 FC040A, and 2FC046A . The valves will be replaced with stainless steel valves less susceptible to the corrosion wear the current valves are experiencing . This portion of the valve replacement will occur during the Unit 1 Refueling Outage 11 (L1 R11) scheduled for Spring 2006. In order to replace the isolation valves on Division 1 CSCS, the Unit 1 Division 1 Core Standby Cooling System suction header will be blank-flanged at the intake structure .

The Unit 1 and Unit 2 Division 1 CSCS maintenance planned for Ll R11 will result in the inoperability of both of the Division 1 RHRSW and DGCW subsystems and will require Unit 2 entry into TS 3.7.1 Condition A and TS 3.7.2 Condition A for inoperability of the RHRSW and DGCW subsystems .

The Unit 1 Division 2 CSCS and Unit 2 Division 2 CSCS isolation valves scheduled for replacement include 1 DG007, 2DG007, 1 FC046B and 2FC046B . These valves will also be replaced with stainless steel valves less susceptible to corrosion . This portion of the valve replacement will be completed during the Unit 2 Refueling Outage 11 (L2R1 1) scheduled for Spring 2007 and the following Unit 1 Refueling Outage 12 (L1 R12) scheduled for Spring 2008 .

In order to replace the isolation valves on Unit 1 Division 2 CSCS and on Unit 2 Division 2 5 of 51

ATTACHMENT I EVALUATION OF PROPOSED CHANGES CSCS non-code line stops will be utilized to isolate the Unit 1 portion of the common discharge from header the Unit 2 portion of the header.

result The Unit 1 and Unit 2 Division 2 CSCS maintenance planned for L2R1 1 and L1 R12 will in the inoperability of the Division 2 DGCW subsystems on both Units and will require entry into TS 3.7.2 Condition A for inoperability of the DGCW subsystems . Although inoperable, the use of non-code line stops is intended to maintain the availability of the Division 2 CSCS system, including the ECCS and DG systems it supports, for the online unit.

The non-code line stops being used to isolate the system during the specified refueling outages are being designed to the same pressure rating and seismic requirements as the CSCS piping .

Both the Unit 1 and Unit 2 Division 2 CSCS maintenance planned for L2R1 1 and Ll R12 result in the inoperability of the 1 A and 2A Diesel Generators (DGs) and pursuant to TS LCO 3.0 .6 and TS LCO 10.2 will require entry into TS 3.8.1 Condition C and Condition F for the online unit due to the inoperability of both units' Division 2 DGs.

These maintenance evolutions are time consuming and include draining portions of the system.

Based on historical data and best work planning estimates, completion of the entire evolution for each refueling outage specified cannot be assured with the existing 7-day CT for TS 3.7.1 .A.1, the 72-hour CT for TS 3 .8 .1 .C .4, the 2-hour CT for TS 3.8.1 .F.1 or the existing TS 3.7 .2 Required Action A.1 . Therefore, an extension of the CT to 10 days for TS 3.7.1 .A.1, 6 days for TS 3.8.1 .C.4, 6 days for TS 3 .8.1 .F.1, and a 6 day or 10 day CT for TS 3.7.2 for the specific refueling outages stated is needed to complete the planned CSCS isolation valve replacement.

Replacement of the CSCS isolation valves is a prudent and proactive action . Having the capability to isolate components within the CSCS system will enable necessary system maintenance to be performed in the future thus enhancing the reliability of the Unit 1 and Unit 2 CSCS system and overall plant safety .

The NRC has previously approved a similar change for the Braidwood Station in Amendment No . 130 and Byron Station in Amendment No. 136, both issued on March 18, 2004.

4.0 TECHNICAL ANALYSIS

The proposed changes have been evaluated using the risk informed processes described in Regulatory Guide (RG) 1 .174, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis," (Reference 3) and RG 1 .177, "An Approach for Plant-Specific, Risk-Informed Decision-making: Technical Specifications," (Reference 4) .

In implementing risk-informed decision-making under RGs 1 .174 and 1 .177, TS changes are expected to meet a set of five key principles . These principles include consideration of both traditional engineering factors (e.g ., defense in depth and safety margins) and risk information.

This section provides a summary of the technical analysis of the proposed CT change that considers each one of these principles :

1 . The proposed change meets the current regulations unless it is explicitly related to a requested exemption or rule change.

This change is being requested as a one-time change to the operating license for LSCS for each of the respective refueling outages stated .

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ATTACHMENT I EVALUATION OF PROPOSED CHANGES

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

Defense in depth considerations are considered and summarized in Section 4 .1 .

3. The proposed change maintains sufficient safety margins.

not Safety margin is impacted by the proposed change as summarized in Section 4.2.

4. When proposed changes result in an increase in core damage frequency or risk, the increases should be small and consistent with the intent of the Commission's Safety Goal Policy Statement.

A risk evaluation is presented in Section 4.3 that considers the impact of the proposed change with respect to the risks due to:

internal events, internal flooding, internal fires, seismic events, and other external hazards.

The requested CT extension has a temporary minor impact on the LSCS risk profile that is within regulatory guidelines. The quantitative acceptance guidelines are discussed in Section 4.3.1 .1 .

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

The three-tiered implementation approach consistent with RG 1 .177 is used, as described in Section 4 .3.

4.1 Defense in Depth Evaluation During the individual CSCS work windows, the at-power unit is considered to have adequate defense-in-depth . Division 1 CSCS defense in depth is evaluated below. Although Division 2 will be considered inoperable due to the use of non-code line stops, it will remain available for the operating unit and therefore a defense in depth evaluation is not necessary.

For Division 1 CSCS, defense-in-depth can be illustrated by a review of the remaining available systems to fulfill the critical safety functions (refer to Table 1). As can be seen from this review of the critical safety functions, some critical safety functions are not affected at all (e.g .,

Reactivity Control and Reactor Pressure Vessel (RPV) Pressure Control) . Some critical safety functions can be maintained by a number of options and the CSCS Division 1 work window has a minimal impact (e.g., inventory control, containment pressure control) . The other critical safety functions have a noteworthy change in the defense-in-depth ; however the remaining equipment provides adequate defense-in-depth.

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGES Table 1 DEFENSE IN DEPTH ASSESSMENT OF PLANNED DIVISION 1 CSCS CONFIGURATION System/Equipment Remaining for Critical Safety Function Impacted Systems Defense-In-Depth Reactivity Control No Impact " RPS

" ARI

" RPT

" SLC RPV Pressure Control No Impact SRVs Inventory Control RCIC HPCS LPCS CRD LPCI A LPCI B with RPV depressurization

" LPCI C with RPV de pressurization Containment Heat Removal RHR A Main Condenser

" RHR B

" Emergency Containment Venting Vapor Suppression Drywell Spray A Vacuum breakers

" Dr ell Spray B Containment Pressure Control Drywell Spray A Vapor Suppression

" Drywell Spray B

" RPV depressurization Support Systems Emergency AC Power Emergency AC power Div . 2 Div . 1 " Emergency AC power Div . 3 In addition to this review of the plant capability, LSCS has a disciplined configuration risk management program (CRMP) that plans the work windows and manages emerging conditions such that defense-in-depth is maintained . This CRMP dictates the urgency for resolution of plant conditions resulting in reduced defense-in-depth and identifies the systems to be protected and prioritized for return to service . RG 1 .174 (Reference 3) provides additional guidance on how defense-in-depth should be evaluated . These are evaluated in Table 2 for the planned CSCS maintenance configuration .

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGES Table 2 CONSIDERATION OF RG 1 .174 DEFENSE-IN-DEPTH GUIDELINES Guideline Evaluation A reasonable balance is preserved No new challenges to core damage, containment failure, or among prevention of core damage, consequence mitigation is introduced by this one-time prevention of containment failure, and change . The requested CT extension has a temporary consequence mitigation . minor impact on the LSCS risk profile. The risk assessment summarized in Section 4 .3 shows that the assessed temporary impact on the LSCS risk profile is within RG 1 .174 guidelines .

Over-reliance on programmatic activities Some compensatory measures have been identified to to compensate for weaknesses in plant minimize risk, but these measures are consistent with design is avoided . normal plant practices.

System redundancy, independence, and Adequate defense in depth is maintained during both diversity are preserved commensurate Division 1 and Division 2 CSCS maintenance. To augment with the expected frequency, the existing plant redundancy and diversity, compensatory of consequences challenges to the measures will be put into place during the requested system, and uncertainties (e.g., no risk configurations. The risk analysis documented in Section outliers). 4.3 shows that the existing plant redundancy and diversity, and the identified compensatory actions, are such that the risk impact of the requested CT extension is small and within RG 1 .174 guidelines .

Defenses against potential common No new common cause mechanisms are introduced by this cause failures are preserved, and the change. Where defenses against potential common cause potential for the introduction of new failures were impacted (i .e., fire and flood scenarios),

common cause failure mechanisms is additional compensatory measures have been identified to assessed . mitigate the impact .

Independence of barriers is not degraded . This change has no impact on the independence of barriers.

Defenses against human errors are This change has no impact on the defense against human preserved. errors . The compensatory measures put in place should improve defenses against human errors . The requested CT extensions do not impact the human error probabilities (HEPQ of any operator action significant to the LSCS PRA (refer to Section 4.3).

(continued)

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGES Table 2 CONSIDERATION OF RG 1 .174 DEFENSE-IN-DEPTH GUIDELINES Guideline Evaluation The intent of the General Design Criteria RHRSW - the current RHRSW LCO allows one RHRSW in Appendix A to 10 CFR Part 50 is subsystem to be inoperable for 7 days which is a temporary maintained . deviation from the GDC provision to provide protection from a single failure in the remaining OPERABLE subsystems .

DGCW - the current DGCW LCO directs immediate entry into the Conditions and Required Actions of the supported system LCOs . The completion time allowances of the supported system LCOs are a temporary deviation from the GDC provision to provide protection from a single failure in the remaining OPERABLE subsystems .

Division 2 DGs - the current TS, AC Sources - Operating, allows a Division 2 DG and the required opposite unit Division 2 DG be inoperable for 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> which is a temporary deviation from the GDC provision to have (2) redundant onsite AC power supplies .

The changes proposed establish a completion time of 6 days or 10 days for the DGCW, and extend the completion time to 10 days for RHRSW and 6 days for the Division 2 DGs during each of the respective refueling outages and therefore do not take further exceptions to the GDC .

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGES 4.2 Safety Margin Evaluation The proposed TS changes are consistent with the principle that sufficient safety margins are maintained based on the following:

Codes and standards (i .e., American Society of Mechanical Engineers (ASME), Institute of Electrical and Electronic Engineers (IEEE) or alternatives approved for use by the NRC) are met . The proposed changes are not in conflict with approved codes and standards relevant to the Division 1 or Division 2 CSCS systems or the Division 2 DGs .

While in certain configurations to replace the isolation valves, the Core Standby Cooling System suction header will be blank-flanged at the intake structure . Non-code line stops will be required to isolate the Unit 1 portion of the common discharge header from the Unit 2 portion of the header. The non-code line stops will maintain the availability of the online unit Division 2 CSCS system .

While in the proposed configurations, the safety analysis acceptance criteria for the CSCS subsystems described in the UFSAR are met, assuming that there are no additional failures . This is consistent with the guidelines provided in RG 1 .177, "An Approach for Plant-Specific, Risk-Informed Decisionmaking : Technical Specifications,"

(Reference 4).

While in the proposed configurations for the Division 2 CSCS maintenance, the safety analysis for the Division 2 DGs will not meet the acceptable restrictions described in RG 1 .93, "Availability of Electric Power Sources," (Reference 19). However, the risk impact of the proposed extension for L2R1 1 and Ll R12 of the Division 2 DGs is small and within industry risk acceptance guidelines provided in RG 1 .177, "An Approach for Plant-Specific, Risk-Informed Decisionmaking : Technical Specifications," (Reference 4).

0 In addition, the restrictions described in RG 1 .93 for the availability of onsite AC electric power supplies are associated with mitigating the effects of an accident in one unit and to safely shut down the other unit. The Division 2 CSCS maintenance will be performed only during the respective refueling outages therefore the risk associated with the immediate shutdown is eliminated .

4.3 Risk Evaluation RISK EVALUATION DIVISION I CSCS The risk impact of the proposed changes for the Division 1 CSCS work has been evaluated and found to be acceptable . The effect on risk of the proposed increase in CT has been evaluated using the NRC three-tier approach suggested in RG 1 .177, (i.e., Reference 4) . Although RG 1 .177 is intended for permanent changes to plant TS (refer to Section 4.3 .1 .1 below), the following general framework of the RG is considered applicable :

Tier 1 - PRA Capability and Insights Tier 2 - Avoidance of Risk-Significant Plant Configurations Tier 3 - Risk-informed Configuration Risk Management This evaluation assesses the risk impact of the proposed 10-day CT to perform valve replacements in the LSCS Units 1 and 2 Division 1 CSCS . The planned valve replacement work will be performed during the Unit 1 Refueling Outage 11 (1_1 R11) and when Unit 2 is at 11 of 51

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGES power. The focus of this risk impact is on the unit at power (i .e., Unit 2) because this is the unit that requires the one-time CT extension; however, the following risk evaluation does discuss qualitatively the risk impacts for the shutdown unit during the proposed CT extensions .

The following boundary valves are to be replaced during the proposed Division 1 CSCS work window:

Valve Designator Description OD0007 DG OA Room Cooler discharge valve ODG001 DG OA Cooling Water Pump suction valve 1 E12-F330A U-1 RHRSW Pump 1A suction valve 1 E12-F330B U-1 RHRSW Pump 1 B suction valve 1 DG032 U-1 RCIC/LPCS and RHR Room Cooler outlet valve 2DG032 U-2 RCIC/LPCS and RHR Room Cooler outlet valve 1 FC046A U-1 Fuel Pool Emergency Makeup valve 1 FC040A U-1 Fuel Pool Emergency Makeup pump suction valve 2FC046A U-2 Fuel Pool Emergency Makeup valve Other valves within the drained and isolated pipe sections may also be replaced during the work window. Whether or not additional valves in the isolated piping sections are replaced would not impact this risk assessment . A blank flange will be installed on the Unit 1 Division 1 CSCS suction line from the service water tunnel, and mechanical line stops will be installed at appropriate points in the system to isolate the piping sections containing the valves to be replaced. This work is shown in Figure 1 .

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGES Figure 1 GRAPHICAL VIEW OF DIVISION 1 CSCS WORK (PAGE 1 OF 2)

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGES Figure I GRAPHICAL VIEW OF DIVISION 1 CSCS WORK (PAGE 2 OF 2)

RHR TV 2 A MR.

MMM",

Page 14 of 52

ATTACHMENT I EVALUATION OF PROPOSED CHANGES RISK EVALUATION DIVISION 2 CSCS The risk impact of the proposed changes for the Division 2 CSCS work has been evaluated and found to be acceptable . The effect on risk of the proposed increase in CT has been evaluated using the NRC three-tier approach suggested in RG 1 .177 (i .e., Reference 4) . Although RG 1 .177 is intended for permanent changes to plant TS (refer to Section 4.3 .1 .1), the following general framework of the RG is considered applicable :

Tier 1 - PRA Capability and Insights Tier 2 - Avoidance of Risk-Significant Plant Configurations Tier 3 - Risk-Informed Configuration Risk Management The Division 2 CSCS work involves valve replacements for both units; as such, the Division 2 CSCS valve replacement work will be performed during two separate refueling outages (currently planned for Ll R12 and L2R1 1). Division 2 CSCS boundary valves to be replaced during the two separate Division 2 CSCS work windows include:

U-1 Division 2 CSCS Work (L1 R12)

Valve Designator Description 1 DG007 Unit 1 RHR B/C Room Cooler Discharge Valve 1FC046B Unit 1 Fuel Pool Cooling Discharge Valve U-2 Division 2 CSCS Work (L2R1 1)

Valve Designator Description 2DG007 Unit 2 RHR B/C Room Cooler Discharge Valve 2FC046B Unit 2 Fuel Pool Cooling Discharge Valve Other valves within the drained and isolated pipe sections may also be replaced during the same work windows. Whether or not additional valves in the isolated piping sections are replaced would not impact this risk assessment . Mechanical line stops will be installed at appropriate points in the system to isolate the piping sections containing the valves to be replaced. This work is shown in Figure 2 .

The Unit 1 Division 2 CSCS work will be performed during the Unit 1 Refueling Outage 12 (1_1 R12) when Unit 2 is at power. The Unit 2 Division 2 CSCS work will be performed during the Unit 2 Refueling Outage 11 (L2R1 1) when Unit 1 is at power. Separate 6-day CT extensions are proposed for each Division 2 work window. This evaluation assesses the risk impact for one of the proposed 6-day CT extensions . Given that the proposed configurations are the same, the risk assessment is also the same for each of the two Division 2 CSCS work windows.

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGES Figure 2 GRAPHICAL VIEW OF DIVISION 2 CSCS WORK (PAGE 1 OF 2) i F PHF;l 1EQW) :

`t" : pHF lP2-CA021-,

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGES Figure 2 GRAPHICAL VIEW OF DIVISION 2 CSCS WORK (PAGE 2 OF 2)

ATTACHMENT I EVALUATION OF PROPOSED CHANGES 4.3.1 Tier 1 : PRA Capability And Insights Risk-informed support for the proposed change is based on Probability Risk Assessment (PRA) calculations performed to quantify the Incremental Conditional Core Damage Probability (ICCDP) and the Incremental Conditional Large Early Release Probability (ICLERP) resulting from the increased Completion Time for the Division 1 and Division 2 CSCS Trains . These ICCDP and ICLERP values are also equivalent to the increase in Core Damage Frequency (CDF) and Large Early Release Frequency (LEAF) as these will be specific individual one-time changes.

The LSCS PRA was recently updated (i .e., June 2003) in accordance with the EGC PRA Maintenance Program (i.e., Periodic Update) . The PRA addresses internal events at full power, including internal flooding and seismic-induced LOOP events .

The scope, level of detail, and quality of the LSCS PRA is sufficient to support a technically defensible and realistic evaluation of the risk change from this proposed CT extension .

Updating and maintenance of the LSCS PRA is controlled under the EGC nuclear engineering procedure for risk management .

During the course of development and application of the LSCS PRA, a number of independent and self-assessment reviews have been conducted. For example, an independent assessment of the LSCS PRA, using the BWR Owners' Group (BWROG) PRA Peer Review Certification Program, was conducted by a team of industry experts. This independent review was performed in 2000 to evaluate the quality of the PRA and completeness of the PRA documentation . In addition to the BWROG peer review, a self-assessment of the LSCS PRA against the American Society of Mechanical Engineers (ASME) PRA Standard was performed by EGC in 2003.

As a result of the LSCS PRA maintenance and updates, self-assessment, and certification peer review, the LSCS PRA is considered to be consistent with the expectations for PRA quality set forth in RG 1 .174 (Reference 3) and RG 1 .177 (Reference 4). In addition, the LSCS PRA has been used in support of various regulatory programs and relief requests that have received NRC approval, further indication of the quality of the LSCS PRA and suitability for regulatory applications .

Further details on the quality and attributes of the LSCS PRA, including information on PRA updates and peer reviews, are presented in Attachment 5.

Risks of external hazards were evaluated as pat of the LSCS Individual Plant Examination of External Events (IPEEE) submitted in April 1994 . These evaluations included qualitative and conservative quantitative estimates of the plant capability to mitigate a range of potential external hazards.

4.3.1 .1 Quantitative Acceptance Guidelines No specific quantitative guidelines are provided in RGs 1 .174 and 1 .177 for one-time risk-informed changes. The quantitative acceptance guidelines in Section 2.2 .4 of RG 1 .174 are expressed in terms of changes to the annual average impact on CDF and LEAF . Because this is a one-time change, the risk impact mould not result in an on-going change in CDF and LEAF .

Nevertheless, as a point of reference, the quantitative acceptance guidelines in RG 1 .174 state that a long-term increase in CDF of less than 1 E-6/yr and LEAF of less than 1 E-7/yr would be considered to be "very small" .

18 of 51

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGES RG 1 .177 was developed specifically for TS changes. However, the acceptance guidelines provided in Section 2 .4 (i .e., lCCDP < 5E-7, ICLERP < 5E-8) are clearly stated to be "applicable only to permanent (as opposed to temporary, or "one time") changes to TS requirements ."

NUMARC 93-01, "Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," (Reference 6) addresses monitoring risk during maintenance activities and provides quantitative guidelines that indicate that routine activities should generally not involve an increase in lCCDP of greater than 1 E-6 or an ICLERP of greater than 1 E-7 . This planned one-time configuration would not be considered routine maintenance. NUMARC 93-01 also recommends that an upper limit configuration-specific CDF of 1 E-3/yr be used .

Based on the available quantitative guidelines for other applications, EGC has determined that the quantitative guidelines shown in Table 3 represent a reasonable set of acceptance guidelines . Less restrictive guidelines could also be justified; however, for the purposes of this evaluation, these guidelines demonstrate that the risk impacts are acceptably low.

Table 3 PROPOSED RISK ACCEPTANCE GUIDELINES Risk Acceptance Guideline Basis lCCDP < 1 E-6

• lCCDP appropriate metric for assessing risk impacts of out of service equipment per RG 1 .177 and NUMARC 93-01 0 1 E-6 consistent with NUMARC 93-01 guidance for routine maintenance and RG 1 .174 increases assessed as "very small" 0 Greater than RG 1 .177 guideline (5E-7) for permanent TS changes which may be entered repeatedly over the life of the plant.

ICLERP < 1 E-7

• ICLERP appropriate metric for assessing risk impacts of out of service equipment per RG 1 .177 and NUMARC 93-01

• 1 E-7 consistent with NUMARC 93-01 guidance for routine maintenance and RG 1 .174 increases assessed as "very small"

• Greater than RG 1 .177 guideline (5E-8) for permanent TS changes which may be entered repeatedly over the life of the plant.

Configuration-specific CDF < o NUMARC 93-01 recommends configurations exceeding II 1 E-3/yr this guideline be avoided, regardless of duration of the evolution .

(1) RG 1 .174 acceptance guidelines are in terms of deltaCDF . For the proposed configuration and this risk and ICCDP are equivalent calculations . The same is true of deltaLERF and ICLERP .

assessment, deRaCDF

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGES 4.3.1 .2 Risk from Internal Events Division 1 CSCS The LSCS internal events PRA is used as a tool to evaluate the quantitative risk impacts due to internal events during the planned Division 1 CSCS configuration . To determine the risk impact of the proposed 10-day CT, the guidance suggested in RG 1 .177 is used. Using the guidance in RG 1 .177, the following risk metrics were developed :

ICCDP = incremental conditional core damage probability with CSCS Division 1 out-of-service for an interval of time equal to the proposed new CT (i .e., 10 days) .

ICLERP = incremental conditional large early release probability with CSCS Division 1 out-of-service for an interval of time equal to the proposed new CT (i .e., 10 days) .

The ICCDP and ICLERIP are computed using definitions in RG 1 .177 . Risk acceptance guidelines used in this assessment are from RG 1 .174 (as discussed above in Section 4 .3.1 .1).

In terms of the above-defined parameters, the definition of ICCDP is as follows :

ICCDP = [(CDF with subject equipment OOS) - (Baseline CDF with nominal expected equipment unavaiIabHTes)] x (duration of CT under consideration)

= (CDFNEW - CDFBASE)

• TCT

= (CDFNEW - CDFBASE) * ( 10 days) * (365 days/year)-'

= (CDFNEW - CDFBASE)

• 2.74E-2 Note that in the above formula the term (365 days/year)-' is merely a conversion factor to convert the CT into units consistent with the CDF frequency units . The ICCDP values are dimensionless probabilities to evaluate the incremental probability of a core damage event over a period of time equal to the extended CT. Because this is a one-time CT change, the delta CDF risk metric of RG 1 .174 and the RG 1 .177 ICCDP risk metric reduce to the same calculation, as shown below :

deltaCDF = [ (TBASE/(TBASE + TNEW))CDFBASE + (TNEW/(TBASE +TNEW))CDFNEW I - CDFBASE (TBASE/(TBASE +TNEW))CDFBASE + (TNEW/(TBASE+TNEW))CDFNEW

- ((TBASE+TNEW)/(TBASE+TNEW))CDFBASE

(- TNEW/(TBAS NEW CDFBASE + (TNEW/(TBASE + TNEW)) CDFNEW (CDFNEW - CDFBASE) (TNEw/(TBASE + TNEW))

= (CDFNEW - CDFBASE) (10 days/(365 days))

= (CDFNEW - CDFBASE) 2.74E-2 As can be seen, the deltaCDF metric becomes numerically the same as the ICCDP when considered as an annual event .

ATTACHMENT I EVALUATION OF PROPOSED CHANGES Also note that the duration used in the risk calculations is equal to the entire time frame of the proposed 10-day CT. Reference 2, the technical bases document for RG 1 .177, identifies the following three approaches to defining the downtime for use in the risk evaluation (listed in order of increasing conservatism):

1 Average downtime based on assessment of plant experience with past similar maintenance activities .

2. Average downtime (as defined above in 1) increased according to the proportional increase in the proposed CT extension.

3. Equal to the proposed CT.

This analyst uses the third approach, and represents the bounding case.

Similarly, ICLERP is defined as follows :

ICLERP = (LERFNEW - LERFBASE) 2.74E-2 The internal events risk impact was performed by modifying and quantifying the LSCS Unit 2 2003A PRA Model of Record (i.e., the LSCS Unit 2 "average maintenance" model). The base CDF for the LSCS Unit 2 PRA is 6.64E-6/yr and the base LERF is 3 .59E-7/yr. Consistent with guidance in RG 1 .177 and the specifics of the proposed configuration, the following was performed:

Division 1 CSCS maintenance basic event set to a logical "TRUE" value to reflect the assumption that the entire Division 1 CSCS is unavailable.

Unit 1 unit auxiliary transformer (UAT) failure basic event set to a logical "TRUE" value, and the Unit 1 UAT to Unit 1 SAT fast transfer failure events deleted (to reflect that Unit 1 is in REFUEL and is powered from the Unit 1 SAT, such that, fast transfer failures to the Unit 1 SAT are not applicable) . This modeling change is conservative in that the Unit 1 SAT is assumed to be the only source of offsite power to Unit 1, when in fact Unit 1 may receive offsite power during REFUEL through backfeed from the main power transformer (MPT) . This conservative modeling for of change is made ease model manipulation but does not significantly impact the results (i .e., explicitly crediting MPT backfeed in the PRA logic would change the calculated CT configuration-specific CDF by <<1%) .

Common cause failure (CCF) basic events revised to reflect the proposed configuration . CCF events were revised for the emergency diesel generators (EDGs), diesel generator cooling water pumps (DGCWPs) and CSCS strainers.

CCF bast events for LPCS/HPCS pumps were removed as they do not apply to the proposed configuration because LPCS is a Division 1 system (i .e., LPCS will be unavailable during the proposed CT configuration) . The other CCF basic events were modified to re-define the common cause component group size consistent with the proposed configuration and re-calculate the individual CCF probabilities.

No changes are made to the PRA regarding the two out-of-service (OOS) Fuel Pool Emergency Makeup pumps (i .e., one for each unit), nor are any changes necessary because the FP Emergency Makeup option has a negligible impact on the LSCS 21 of 51

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGES plant risk profile . The Fuel Pool Emergency Makeup pumps are the last emergency option to provide coolant makeup to the fuel pool, as defined by the Fuel Pool Cooling system abnormal operating procedure.

The following are the Normal, Alternate and Emergency methods of providing coolant makeup to the fuel pool .

Normal: Via Fuel Pool Cooling pumps and surge tank (which is supplied by cycled condensate)

Alternate : Any of the following (may be concurrent):

From main condenser hotwell into RPV via Feedwater/Condensate ECCS systems from suppression pool into RPV Clean condensate hoses on the refueling floor RHR in Fuel Pool Cooling Assist Mode Fire Protection hoses on the refueling floor Via Fuel Pool Emergency Make-up pumps (requires spool piece installation)

Given the numerous other makeup methods available (and which would receive higher priority), whether or not the Fuel Pool Emergency Makeup pumps are available has a negligible impact on the plant risk profile . As such, this aspect is not explicitly quantified in this risk assessment .

Without consideration for any compensatory actions, the above model modifications result in an lCCDP for the proposed 10-day CT that does not meet the 1 E-6 risk guideline. Consistent with the guidance in RG 1 .177, the results of this initial bounding calculation were reviewed to identify the risk contributions of equipment OOS events for the purposes of defining compensatory actions for protecting such equipment during the proposed CT configuration. The equipment identified for protection during the proposed CT to assure the risk impacts are acceptably low is summarized in Table 4 . Measures taken to protect equipment are:

• Restrict concurrent maintenance on Unit 2 Division 2 4kv Bus 242Y ;

• Restrict concurrent maintenance on Unit 2 Division 2 EDG ;

0 Restrict concurrent maintenance on Unit 2 Division 2 Main Battery Charger; 0 Restrict concurrent maintenance on Unit 2 Division 2 CSCS ;

0 Restrict concurrent maintenance on Unit 2 Division 2 RHR; 0 Restrict concurrent maintenance on Unit 2 Division 3 HPCS ; and 0 Restrict concurrent maintenance on Unit 2 Motor-Driven Feedwater Pump.

Additional administrative actions to protect the listed equipment will be taken in accordance with station risk management procedures . These actions may include physical barricades to protected segregate equipment, poked signs and plant personnel awareness through pre-job briefings and outage communication bulletins .

22 of 51

ATTACHMENT I EVALUATION OF PROPOSED CHANGES Protecting the equipment identified in Table 4 (i.e., set the probabilities of the identified maintenance terms to 00) and re-quantifying the PRA results in a significantly reduced impact on internal events risk over the 10-day CT. The resulting configuration-specific CDF for the Division 1 CSCS outage is 4.19E-5/yr, and the configuration-specific LERF is 7 .40E-7/yr.

These result in the following ICCDP and ICLERP values .

ICCDP = (4 .19E 6 .64E-6) * (10/365) = 9.7E-7 ICLERP = (7.40E 3.59E-7) * (10/365) = 1 .OE-8 The dominant cutsets for the Division 1 CSCS 10-day work window are different than those of the LSCS base 2003A PRA Model of Record. Given that the proposed CT configuration involves Division 1 CSCS OOS and Division 1 CSCS is shared between two units, scenarios with initiators failing one or multiple divisions of equipment propagate to the top and become the dominant scenarios for the CT risk profile . Of the top 10 CDF cutsets for the Division 1 CSCS CT configuration (i.e., including the identified compensatory actions), four are unisolated internal flooding scenarios and five are initiated by loss of a divisional AC or DC bus. The top two CDF cutsets are unisolated turbine building flooding scenarios that disable the balance-of-plant (BOP), Division 2 and Division 3 equipment. No reasonable compensatory actions can be identified to address these internal flooding scenarios. However, the previously described compensatory actions are sufficient to reduce the impact on plant risk to small levels and within risk guidelines .

The dominant cutsets for LERF are less impacted by the Division 1 CSCS 10-day work window than are the CDF cutsbs. The lesser impact is due to the nature of large early release sequences at LSCS, which are dominated by containment bypass scenarios (e .g ., Intersystem LOCA (ISLOCAs)) and large LOCAs with vapor suppression system failure. Seven of the top 10 LERF cutsets for the Division 1 CSCS CT configuration are unchanged from the LSCS base PRA. Again, the previously described compensatory actions are sufficient to maintain the LERF impact to small levels and within risk guidelines .

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGES Table 4 LIST OF MAINTENANCE TERMS IN PRA IDENTIFIED AS COMPENSATORY ACTIONS EQUIPMENT PRA BASIC EVENT NAME DESCRIPTION U-2 Div . 2 4kv Bus 242Y 2ACBS-242Y---M-- 4.16 kVAC SWGR 242Y (2AP06E) MUA U-2 Div . 2 EDG 2DGDG-DG2A---M-- DG2A DIESEL GENERATOR 2DG01K MUA 2VD--CONTROL-M-- VD DG2A ROOM VENT DAMPERS CONTROL SYSTEM MUA 2VDDMDG2V09YBM-- VD DG2A ROOM VENT BAL DAMPER 2VD09YA MUA 2VDDMDG2V10YBM-- VD DG2A ROOM VENT BAL DAMPER 2VD10YA MUA 2VDDMDG2V11YBM-- VD DG2A ROOM VENT BAL DAMPER 2VD11YA MUA 2VDFNCS2V03CBM-- VD DG2A ROOM COOLNG FAN 2VD03C MUA U-2 Div . 2 Main Batt. Charger 2DCBC2DC17E--M-- 125 VDC UNIT 2 DIV 2 MAIN BATTERY CHARGER 2DC17E MUA U-2 Div . 2 CSCS 2DGPMCSDG2A--M-- DG2A COOLING WATER PUMP 2DG01 P TRAIN MUA 2RSFLCS2D300BM-- RHR SW TRAIN B STRAINER 2E12-D300B MUA 2RSMVCSCF068BM-- RHR SW MOV 2E12-FO68B MUA 2RSPMCS2C300CM-- RHR SW TRAIN B PUMP 2E12-C3000 MUA 2RSPMCS2C300DM-- RHR SW TRAIN B PUMP 2E12-C300D MUA U-2 Div . 2 RHR 2RHHETRAINB--M-- RH TRAIN B HX 2E12-B001B MUA 2RHMVF048B---M-- RH HX 2E12-B001 B BYPASS MOV 2E12-F048B MUA 2RHPME120002BM-- RH TRAIN 2B (2E12-0002B) MUA 2RHPME12C002CM-- RH TRAIN 2C (2E12-0002C) MUA 2VYFNSECORNERM-- VY SE CORNER ROOM (RHR B & C) COOLING / VENTILATION MUA U-2 HPCS (Div. 3) 2ACBS-243C---M-- 4 .16 kVAC SWGR 243C (2AP07E) MUA 2DGDG-DG2B---M-- DG2B DIESEL GENERATOR 2E22-S001 MUA 2DGPMCS220002M-- DG2B COOLING WATER PUMP 2E22-0002 MUA 2HCPM-HPCS---M-- HC SYSTEM (2E22-C001) MUA 2VDFNCS2V01CBM-- VD DG2B ROOM COOLNG FAN 2VD01C MUA 2VYFNSWCORNERM-- VY SW CORNER ROOM (HPCS) COOLING MUA U-2 MDFW 2FWAV2FW005--M-- FW MDRFP 2FW01PC FEED REG AOV 2FW005 MUA 2FWPMMDRFP---M-- FW MDRFP TRAIN MUA

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGES Internal Floodinq Risk The LSCS 2003A PRA Model of Record used in this analysis incorporates detailed assessment of internal flooding scenarios . Impacts to the internal flooding scenarios are accounted for in the internal events results previously discussed .

Although one may postulate gross rupture of the installed mechanical line stops, such an event is of extremely low likelihood . Mechanical line stops are temporary manual valves that are tapped into the piping system using specialized drilling machines . This is a standard technique for isolating wet piping systems and is used in various industries . The mechanical line stops will be designed to the same pressure rating and seismic design as the CSCS piping .

Effect of Recent LaSalle General Abnormal_(LGA) Changes For Security Scenario At the time of the development of this risk assessment, LSCS Station revised the emergency operating procedures (LGAs) and the Loss of AC Power abnormal operating procedure to direct new compensatory actions. These procedural changes went into effect at the end of October 2004. These new procedurally directed compensatory actions are designed specifically for a postulated security threat scenario defined as a loss of offsite power, with offsite AC unrecoverable for a day or more, and all CSCS unavailable . These new procedural changes have not yet been incorporated into the LSCS 2003A PRA Model of Record and as such they are not incorporated into the Division 1 CSCS risk results discussed previously .

The compensatory actions designed for the postulated security threat would be beneficial in reducing the risk associated with long-term station blackout scenarios and certain internal flooding scenarios that result in failure of multiple divisions of CSCS . The new compensatory actions include :

Alignment of fire protection for RPV injection early upon recognition of Station Blackout (SBO) ;

0 Obtaining and aligning long-term DC power (via gas-powered generator to supply existing battery chargers) ; and 0 Air bottle line-ups to the containment vent valves .

The above actions will ensure long-term ability to keep the RPV depressurized, which allows continued fire protection injection into the RPV, and to effect containment heat removal without the need for AC power. If these new LGA directives were to be included in the LSCS base PRA and this assessment, the internal events based ICCDP results discussed previously would be reduced by approximately 10%.

Comparison of Internal Events Base Results To Risk Acceptance Guidelines The results of the at-power internal events risk evaluation are compared in Table 5 with risk acceptance guidelines from Table 3 . The values for the ICCDP and the ICLERP demonstrate that the proposed CT change has a very small quantitative impact on plant risk .

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGES Table 5 RESULTS OF INTERNAL EVENTS RISK EVALUATION Risk Metric Risk L At-Power Internal Events( l)

Acceptance [------

Guideline LSCS Unit 2 Acceptable ICCDP <1 E-6 9.7 E-7 Yes ICTLERP <1 &7 1 .0 E-8 Yes

<1 E-3/yr 4.2 E-5 Yes CDFConfiguration I

Mote:

LSCS at-power internal events results include seismic risk contributors (refer to Section 4.3.1 .4).

Conclusions Related to Internal Event Risks The quantitative impacts on the at-power internal events risk profile due to the planned CT configuration, and accounting for the compensatory actions identified in Table 4, are within the core damage and large early release risk acceptance guidelines .

Division 2 CSCS The LSCS internal events PRA is used as a tool to evaluate the quantitative risk impacts due to internal events during the planned Division 2 CSCS configuration . To determine the risk impact of the proposed Way CT, the guidance suggested in RG 1 .177 is used . Using the guidance in RG 1 .177, the following risk metrics were developed:

ICCDP = incremental conditional core damage probability with CSCS Division 2 out-of-service for an interval of time equal to the proposed new CT (i .e., 6 days).

ICLERP = incremental conditional large early release probability with CSCS Division 2 out-of-service for an interval of time equal to the proposed new CT (i.e., 6 days) .

The ICCDP and ICLERP are computed using definitions in RG 1 .177 . Risk acceptance guidelines used in this assessment are from RG 1 .174 (as discussed above in Section 4 .3.1 .1).

In terms of the above-defined parameters, the definition of ICCDP is as follows :

1CCDP = [(CDF with subject equipment OOS) - (Baseline CDF with nominal expected equipment unavailabilities)] x (duration of CT under consideration)

= (CDFNEW - CDFBASE)

• TCT

= (CDFNEW - CDFBASE) * (6 days) * (365 days/year)"'

= (CDFNEW - CDFBASE)

• 1 .64 E-2 26 of 51

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGES Note that in the above equation, the term (365 days/year)"' is merely a conversion factor to convert the CT into units consistent with the CDF frequency units . The ICCDP values are dimensionless probabilities to evaluate the incremental probability of a core damage event over a period of time equal to the extended CT. Because this is a one-time CT change, the deltaCDF risk metric of RG 1 .174 and the RG 1 .177 ICCDP risk metric reduce to the same calculation, as shown below:

deltaCDF = [ (TBASE/(TBASE + TNEW))CDFBnE + (TNEW/(TBASE + TNEW))CDFNEW I - CDFBASE

= (TBASE/(TBAS NEW))CDFBASE + (TNEW/(TBASE+TNEW))CDFNEW

- ((TBASE+TNEW)/(TBASE+TNEW))CDFBASE

= (-TNEW/(TBASE + TNEW))CDFBASE + (TNEW/(TBASE + TNEW)) CDFNEW

= (CDFNEW - CDFBASE) (TNEW/(TBASE +TNEW))

= (CDFNEW - CDFBASE) (6 days/(365 days))

= (CDFNEW - CDFBASE) 1 .64 E-2 As can be seen, the deltaCDF metric becomes numerically the same as the ICCDP when considered as an annual event .

Also note that the duration used in the risk calculations is equal to the entire time frame of the proposed 6-day CT. Reference 2, the technical bases document for RG 1 .177, identifies the following three approaches to defining the downtime for use in the risk evaluation, listed in order of increasing conservatism .

1. Average downtime based on assessment of plant experience with past similar maintenance activities .

2. Average downtime (as defined above in 1) increased according to the proportional increase in the proposed CT extension .

3. Equal to the proposed CT .

This analyst uses the third approach, and represents the bounding case.

Similarly, ICLERP is defined as follows :

ICLERP = (LERFNEW - LERFBASE)

• 1 .64 E-2 The internal events risk impact for the proposed CT configuration is non-significant and within the risk guidelines. The reason that a CT extension request is necessary for the at-power unit is that a non-code line stop is to be used to isolate the shutdown unit's Division 2 CSCS discharge from the at-power unit's Division 2 CSCS discharge . Although TS require declaring Division 2 CSCS on the at-power unit to be inoperable due to the use of the non-code line stop, Division 2 CSCS on the at-power unit will remain available . As such, the risk impact on the at-power unit is negligible .

ATTACHMENT I EVALUATION OF PROPOSED CHANGES entire Assuming that the Division 21 CSCS on the shutdown unit is taken out of service, the internal events risk impact is calculated by modifying and quantifying the LSCS Unit 2 2003A PRA Model of Record (i .e., the LSCS Unit 2 "average maintenance" model). The base CDF for the LSCS Unit 2 PRA is 6.64E-6/yr and the base LERF is 3.59E-7/yr. Consistent with guidance in RG 1 .177 and the specifics of the proposed configuration, the following was performed .

Unit 1 Division 2 CSCS maintenance basic event set to a logical "TRUE" value to reflect the assumption that the entire Division 2 CSCS on the shutdown unit is disabled .

Unit 1 UAT failure basic event set to a logical "TRUE" value, and the Unit 1 UAT to Unit 1 SAT fast transfer failure events deleted (to reflect that Unit 1 is in REFUEL and is not powered from the UAT, such that, fast transfer failures to the SAT are not applicable). This modeling change is conservative in that the Unit 1 SAT is thus assumed to be the only source of offske power to Unit 1, when in fact, Unit 1 may receive offsite power during REFUEL through backfeed from the main power transformer (MPT) . This conservative modeling change is made for ease of model manipulation, but does not significantly impact the results (i .e., explicitly crediting MPT backfeed in the PRA logic would change the calculated CT configuration-specific CDF by <<1 %).

Common cause failure (CCF) basic events revised to reflect the proposed configuration. CCF events were revised for the EDGs, DGCWPs and CSCS strainers were modified to re-define the common cause component group size consistent with the proposed configuration and re-calculate the individual CCF probabilities .

No changes are made to the PRA regarding the OOS Fuel Pool Emergency Makeup pump (nor are any necessary) because the FP Emergency Makeup option has a negligible impact on the LSCS plant risk profile. The Fuel Pool Emergency Makeup pumps are the last emergency option to provide coolant makeup to the fuel pool, as defined by the Fuel Pool Cooling abnormal operating procedure.

The following are the Normal, Alternate and Emergency methods of providing coolant makeup to the fuel pool .

Normal : Via Fuel Pool Coding pumps and surge tank (which is supplied by cycled condensate)

Alternate : Any of the following (may be concurrent):

From main condenser hotwell into RPV via Feedwater/Condensate ECCS systems from suppression pool into RPV Clean condensate hoses on the refueling floor RHR in Fuel Pool Cooling Assist Mode Fire Protection hoses on the refueling Floor Emergenc rL: Via Fuel Pool Emergency Make-up pumps (requires spool piece installation)

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGES Given the numerous other makeup methods available (and which would receive higher priority), whether or not the Fuel Pool Emergency Makeup pumps are available has a negligible impact on the plant risk profile. As such, this aspect is not explicitly quantified in this risk assessment .

The above model modifications result in a Division 2 CSCS configuration-specific CDF for the at-power unit of 9 .53E-6/yr, and the configuration-specific LERF is 19007tyr. These result in the following IC;CDP and ICLERP values for the 6-day CT :

ICCDP = (9.53E 6.64E-6) * ( 6/365) = 4 .8E-8 ICLERP = (3 .90E 3.59E-7) * ( 6/365) = 5.1 E-10 The LSCS base PRA dominant cutsets are minimally impacted by the Division 2 CSCS specific 6-day work windows . Seven of the top 10 CDF cutsets for the Unit 2 Division 2 CSCS CT configuration are unchanged from the LSCS base PRA_ All ofthetoplOLERFcutsetsforthe Unit 2 Division 2 CSCS CT configuration are unchanged from the LSCS base PRA.

These results apply equally to the Unit 1 Division 2 CSCS 6-day work window (currently planned for L1 R12) and the Unit 2 Division 2 CSCS 6-day work window (currently planned for L2R1 1).

Internal Flooding Risk The LSCS 2003A PRA Model of Record used in this analysis incorporates detailed assessment of internal flooding scenarios . Impacts to the internal flooding scenarios are accounted for in the internal events results previously discussed.

Although one may postulate gross rupture of the installed mechanical line stops, such an event is of extremely low likelihood . Mechanical line stops are temporary manual valves that are tapped into the piping system using specialized drilling machines . This is a standard technique for isolating wet piping systems and is used in various industries . The mechanical line stops will be designed to the same pressure rating and seismic design as the CSCS piping .

Effect of Recent LGA Changes For Security Scenario At the time of the development of this risk assessment, LSCS Station revised the LSCS General Abnormal (LGA) operating procedures and the Loss of AC Power abnormal operating procedure to direct new compensatory actions. These procedural changes went into effect at the end of October 2004. These new procedurally directed compensatory actions are designed specifically for a postulated security threat scenario defined as a loss of offsite power, with offsite AC unrecoverable for a day or more, and all CSCS unavailable . These new procedural changes have not yet been incorporated into the LSCS 2003A PRA Model of Record and as such they are not incorporated into the Division 2 CSCS risk results discussed previously .

The compensatory actions designed for the postulated security threat would be beneficial in reducing the risk associated with long-term station blackout scenarios and certain internal flooding scenarios that result in failure of multiple divisions of CSCS . The new compensatory actions include:

a Alignment of fire protection for RPV injection early upon recognition of SBO

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGES 0 Obtaining and aligning long-term DC power (via a gas-powered generator to supply existing battery chargers)

Air bottle line-ups to the containment vent valves The above actions will ensure long-term ability to keep the RPV depressurized (which allows continued fire protection injection into the RPV) and to effect containment heat removal without the need for AC power. If these new LGA directives were to be included in the LSCS base PRA and this assessment, the Division 2 CSCS internal events based ICCDP results discussed previously would be reduced by approximately 10% (estimated based on similar calculation performed for the Division 1 CSCS CT risk assessment discussed previously).

Comparison of Internal Events Base Results To Risk Acceptance Guidelines The results of the at-power internal events risk evaluation are compared in Table 6 with risk acceptance guidelines from Table 3 . The values for the ICCDP and the ICLERP demonstrate that the proposed CT change has a very small quantitative impact on plant risk.

Table 6 RESULTS OF INTERNAL EVENTS RISK EVALUATION Risk Risk At-Power Internal Events( l)

Metric Acceptance Guideline LSCS U-2(z) Acceptable ICCDP <1E-6 ?8 &8 Yes ICLERkP <1E-7 5 .1 E-10 Yes CDFConfiguration < 1 E-3/yr 9.5 E-6 Yes Note:

1 . LSCS at-power internal events results include seismic risk contributors (refer to Section 4.3.1 .4).

2. Results apply equally to the Unit 1 Division 2 CSCS 6-day CT and the Unit 2 Division 2 CSCS 6-day CT .

Conclusions Related to Internal Event Risks The quantitative impacts on the at-power internal events risk profile due to the planned Division 2 CSCS CT configurations are within the core damage and large early release risk acceptance guidelines .

ATTACHMENT I EVALUATION OF PROPOSED CHANGES 4.3.1 .3 Risk from Internal Fires The quantitative analysis of internal fire risk for the LSCS plant was submitted as part of the LSCS Individual Plant Examination of External Events (IPEEE). The LSCS IPEEE was submitted to the NRC in April 1994 (Reference 5). The foundation of the LSCS IPEEE are the risk analyses performed under the NRCYs Risk Methods Interpretation and Evaluations Programs (RMIEP) and the NRC's Phenomenology and Risk Uncertainty Evaluation Program (PRUEP), as documented in NUREG/CR-4832 (Reference 9) and NUREG/CR-5305 (Reference 10), respectively .

Internal fire cue damage sequence frequency quantification is not integrated with the internal events risk assessment results . Although the LSCS internal fire analysis performed for the RMIEP study is a rigorous LSCS specific analysis and is generally consistent with current techniques, it is conservative in the following key areas and is considered not to calculate best-estimate fire induced core damage frequencies :

The selection of fire types to represent postulated fire scenarios tends to overestimate the frequency of severe fires The translation of indicated fire-induced equipment damage into system models assumes wholesale failure of all equipment in the fire area The general qualitative conclusions regarding the RMIEP internal fires assessment of LSCS are considered still applicable, though specific dominant sequences and cutsets may differ due to plant procedural and PRA model changes .

Like many plants, LSCS does not maintain a fire PRA and the RMIEP fire analysis has not been updated . However, to provide some quantitative context in which to assess the proposed CT impact on LSCS fire risk, the LSCS RMIEP internal fire accident sequences were integrated with the LSCS 2003A PRA Model of Record system fault trees and component failure database :

A fire core damage event tree structure was developed based on the LSCS 2003A General Transient event tree.

RMIEP fire damage scenarios representing approximately 97% of the RMIEP fire CDF were modeled in CAFTA (the LSCS PRA software code) and linked with the fire event tree structure.

RMIEP-defined fire equipment damage per fire scenario were input into CAFTA via flag files.

Post-initiator operator action human error probabilities were reviewed and increased where appropriate to account for the additional effects of fire scenarios on operator stress and ex-control room access .

The base fire CDF resulting from quantification of this model is 7.78E-6/yr. This base fire model was then used to assess (in the same manner as previously discussed for the at-power internal events) the impact of the proposed CT configuration on LSCS fire risk .

ATTACHMENT I EVALUATION OF PROPOSED CHANGES Division I CSCS Including the same compensatory actions for protecting specific equipment as defined earlier for the internal events analysis, the initial fire assessment results in an increased fire CDF that produces an ICCDP of approximately 3.5E-7. Although this fire analysis is considered to have conservative elements and is not integrated with the internal events assessment results, it was determined that compensatory actions should be considered for fire to further minimize the risk impact .

Like the internal events analysis, the results of this initial fire risk quantification were reviewed to identify the major risk contributors and potential compensatory actions for reducing risk. Not surprisingly, given that the proposed CT configuration involves Division 1 CSCS, the dominant fire scenarios for the initial quantification involve fire damage scenarios occurring in the Unit 2 Division 2 Essential Switchgear Room (representing approximately 60% of the CDF of this initial fire quantification) .

Fires in the Division 2 Essential Switchgear Room are comprised of two main types:

0 Fires originating in individual switchgear cubicles 0 Large floor fire The Division 2 Essential Switchgear Room is not equipped with automatic fire suppression systems. In addition, negligible credit (0.98 failure probability) for manual suppression is included in the RMIEP fire assessment for this fire area.

Accordingly, a compensatory action identified for this proposed CT configuration to address the impact on fire risk is the posting of a qualified fire watch in the Unit 2 Division 2 Essential Switchgear Room during the Division 1 CSCS work . This compensatory action is modeled in this analysis by reducing the Unit 2 Division 2 Essential Switchgear Room fire damage scenario frequency by an order of magnitude (reflective of a 1 E-1 manual suppression failure rate for the fire watch) . An assumed 1 E-1 failure rate for manual suppression for the fire watch is but considered to be a conservative assumption reasonable for use in this assessment .

Protecting the equipment identified in Table 4 and posting a fire watch in the Unit 2 Division 2 Essential Switchgear Room results in an instantaneous fire CDF for the at-power unit of 8.82E-6/yr and a significantly reduced impact on fire risk over the 10-day CT:

ICCDPFIRE = (8.82E 7.78E-6) * (10/365) = 2.8E-8 As can be seen from the above result, the estimated impact on fire risk due to the proposed 10-day CT configuration is over an order of magnitude less in terms of ICCDP compared to that of the internal events .

Following incorporation of the above compensatory actions, the dominant fire scenario during the 10-day proposed CT configuration is an unsuppressed Control Room fire that requires evacuation and plant shutdown using the Remote Shutdown Panel (ASP). This scenario represents 6300 of the fire risk during the proposed CT. The significance of this fire scenario during the proposed C7 is due to the fact that the RSP requires both Division 1 (specifically Reactor Core Injection Cooling (RCIC)), which is inoperable due to loss of room cooling during the proposed CT) and Division 2 equipment. Given that modifying the RSP to add additional 32 of 51

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGES mitigative options is not feasible for this CT request, and that the Control Room is continuously manned (such that the reliability of manual fire suppression in the Control Room likely cannot be significantly increased), useful compensatory actions to reduce the Control Room fire risk have not been identified and are not proposed. However, such additional compensatory actions are considered to be unnecessary as the posting of the fire watch in the Unit 2 Division 2 Switchgear Room already results in a non-significant fire risk impact for the proposed CT configuration.

Level 2 Assessment for Fires As discussed previously, LSCS does not currently maintain a fire PRA. Although a quantitative core damage model for fire risk was developed for this CT risk assessment, a Level 2 (containment performance) quantitative fire model was not developed . However, the results of the Level 1 fire impacts discussed previously allow a reasonable approximation of the proposed CT impact on fire ICLERP.

Using a breakdown by cue damage accident class of be Level 1 fire CT configuration-specific CDF and applying conditional LERF probabilities (as a function of core damage accident types) obtained from the LSCS Unit 2 2003A PRA Model of Record, the impact on fire LERF was determined to be non-significant.

Conclusions Related to Fire Risk for Division 1 CSCS The quantitative impacts on the internal fires risk profit due to the planned CT configuration, and accounting for the compensatory actions identified in Table 4 and the posting of a fire watch in the Unit 2 Division 2 Essential Switchgear Room, are not significant (more than an order of magnitude less than for the internal event) and are well within the risk acceptance guidelines.

Division 2 CSCS Including the previously described model modifications into the fire model, the Division 2 CSCS configuration-specific instantaneous fire CDF for the at-power unit is 7.82E-6/yr, resulting in the following ICCDP for the 6-day CT:

ICCDPFIRE = (7.82E 7.78E-6) * (6/365) = 6 .6E-10 As can be seen from the above result, the estimated impact on fire risk due to the proposed 6-day CT configuration is over a magnitude less in terms of ICCDP compared to that of the internal events, and is non-significant This result applies equally to the Unit 1 Division 2 CSCS 6-day work window (currently planned for L1 R12) and the Unit 2 Division 2 CSCS 6-day work window (currently planned for L2R1 1).

Level 2 Assessment for Fires As discussed previously, LSCS does not currently maintain a fire PRA. Although a quantitative core damage model for fire risk was developed for this CT risk assessment, a Level 2 (containment performance) quantitative fire model was not developed. Given the very small Level 1 risk impact (as evidenced by the very small ICCDPFIRE), the ICLERP for fire is also very small - well over an order of magnitude below the risk acceptance guidelines.

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGES Conclusions Related to Fire Risk for Division 2 CSCS The quantitative impacts on the internal fires risk profile due to the Division 2 CSCS planned CT configuration is non-significant and well within the risk acceptance guidelines.

4.3.1 .4 Risk from Seismic Events The quantitative analyst of seismic risk for the LSCS plant was submitted as part of the LSCS Individual Plant Examination of External Events OPEEEY The LSCS IPEEE was submitted to the NRC in April 1994 (Reference 5). The foundation of the LSCS IPEEE are the risk analyses performed under the NRC's Risk Methods Interpretation and Evaluations Programs (RMIEP) and the NRC's Phenomenology and Risk Uncertainty Evaluation Program (PRUEP), as documented in NUREG/CR-4832 (Reference 9) and NUREG/CR-5305 (Reference 10),

respectively .

The ILSCS seismic analysis performed for the RMIEP study is a rigorous LSCS specific analysis . The methodology used is consistent with the requirements of the NRC IPEEE Program and with current seismic risk assessment technology . Although LSCS does not maintain a current seismic risk assessment, the general conclusions of the RMIEP study regarding the seismic response of the LSCS plant are considered to be still applicable .

However, the current specific dominant sequences and cutsets may differ due to plant procedural and PRA model changes.

Similar to the internal fires assessment previously discussed, seismic sequences from the RMIEP study have been reproduced and integrated with the LSCS 2003A system models and database, as follows :

The division of the LSCS seismic hazard curve into seven discrete seismic magnitude ranges is maintained in this assessment (the same ranges used in the RMIEP study are maintained).

0 Instead of the 1980's vintage seismic initiator frequencies used in the RMIEP study, this assessment uses the more current NUREG-1488 NRC/LLNL frequencies .

The quantification of the seismic sequences was incorporated into the internal events risk quantifications discussed previously in Section 4.3.1 .2 . Seismi c risk is a minor contributor to the ICCDP for the proposed CT, representing approximately 2% of the 9.7E-7 ICCDP estimated for Division 1 CSCS and approximately 5% of the 4 .8E-8 ICCDP for Division 2 CSCS .

4.3 .1 .5 Risk from Other External Events Volume 7 of NUREG/CR-4832 (Reference 9) provides the LSCS RMIEP external event screening analysis . The screening assessment appropriately begins with the comprehensive list of potential external event hazards provided in the PRA Procedures Guide, NUREG/CR-2300. Consistent with NUREG/CR-2300, the screening assessment employed the following criteria to eliminate external event challenges from further consideration :

1 The event is of equal or lesser damage potential than the events for which the plant is designed, or

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGES

2. The event has a significantly lower mean frequency of occurrence than other events with similar uncertainties and could not result in worse consequences than those events, or

3. The event cannot occur close enough to the plant to affect it, or The event is included in the definition of another event, or The event is slow in developing and there is sufficient time to eliminate the source of the threat or to provide an adequate response.

In addition to seismic and internal fires (which are discussed previously), the following external events were identified in the RMIEP screening assessment for further analysis (all others were screened, using the above criteria, from further analysis as non-significant contributors to plant risk):

Aircraft Impact Extreme Winds and Tornadoes Transportation/Toxic Chemicals/Explosions Turbine Generated Missiles External Flooding Aircraft Impact The RMIEP study of aircraft impact risk was reviewed . The CDF risk from such accidents is not significant. Explicit quantification of such accidents would not provide any significant quantitative or qualitative information to this CT risk assessment .

Extreme Winds and Tornadoes The RMIEP study of extreme winds and tornadoes risk was reviewed . The CDF risk from such accidents is not significant. Explicit quantification of such accidents would not provide any significant quantitative or qualitative information to this CT risk assessment .

Transportation/Toxic Chemicals/Explosions The RMIEP study of transportation/toxic chemicals/explosions risk was reviewed . The CDF risk from such accidents is not significant. Explicit quantification of such accidents would not provide any significant quantitative or qualitative information to this CT risk assessment .

Turbine Missiles The RMIEP study of turbine missiles risk was reviewed . The CDF risk from such accidents is not significant. Explicit quantification of such accidents mould not provide any significant quantitative or qualitative information to this CT risk assessment .

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGES External Flonoddinn iA The RMIEP study of external flooding risk was reviewed . The CDF risk from such accidents is not significant. Explicit quantification of such accidents would not provide any significant quantitative or qualitative information to this CT risk assessment .

Conclusions Regarding Other External Hazards Given the preceding discussions, the other external hazards are assessed to be negligible contributors to LSCS plant risk and have a non-significant impact on the risk assessment for the proposed CT.

4.3.1 .6 Averted Risk from a Plant Shutdown Instead of the Division 1 and Division 2 CSCS proposed individual one-time CTs to allow the work to proceed with one unit at power, the alternative is to concurrently shutdown the at-power unit. RG 1 .177 appropriately recognizes that the alternative of performing a unit shutdown to perform maintenance is in itself not a zero-risk alternative :

"In some cases, in support of a TS change, available alternatives are compared to justify the TS change. For changes in TS AOTs, such cases primarily involve comparing the risk of shutting down with the risk of continuing power operation, given that the plant is not meeting one or more TS LCOs. Such comparisons can be used to justify that the increase in at-power risk associated with the TS change is offset by the averting of some transition or shutdown risk."

Consistent with RG 1 .177, this evaluation assesses the averted risk contribution associated with performing a shutdown of the at-power unit .

Although a controlled shutdown is a routine and benign event, every transition from power has an associated risk, albeit very small. As such, if the at-power reactor is shutdown to support the CSCS work, there is a possibility that a plant upset may occur. Past industry studies have shown that the probability of experiencing a plant transient significantly increases during major plant perturbations such as a power descension . Reference 12 shows that a significant number of industry transient events occur during low power transitions (approximately 23% of transient events occur during low power transitions) .

The conditional probability of experiencing a core damage event is lower for a controlled shutdown than it is for a plant trip; as such, the higher the likelihood of a experiencing a plant trip during the shutdown process, the greater is the calculated averted risk of not performing a shutdown . For the purpose of this analysis, it is conservatively assumed here that the probability of experiencing a plant trip during a controlled shutdown at LSCS is 0 .00, this results in the minimal calculated averted risk .

The calculation of the averted risk of shutdown of the at-power unit is shown in Figure 3. The conditional core damage probabilities (CCDP) are based on the LSCS W03A Wit 2 PRA. The CCDP for a Manual Shutdown initiator is approximately 1AE-7. The CCDP for the scenario in which an unintended plant trip occurs during the controlled shutdown is based on the CCDP for the Main Steam Isolation Valve (MSIV) Closure initiator, this value is 3.OE-6.

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGES Figure 3 AVERTED RISK ASSOCIATED WITH ALTERNATIVE TO SHUTDOWN UNIT 2 Decision to ( Controlled SID CCDP I CDP Shutdown Unit 2 Without Trip OK 1 .4E-07 1 .4E-07 0K 000 3.0 E-06 O.OE+00 Total Averted Core Damage Probability: 1AE-07 Based on this assessment, the averted core damage risk of the alternative of a shutdown of the at-power unit, in addition to the unit in REFUEL, is estimated at 1AE-7 .

The averted large early release risk of the alternative of a Unit 2 shutdown is estimated at 1AE-9. The averted large early release contribution is estimated by applying a 1 E-2 conditional probability of a large early release. The 1 E-2 probability is the approximate conditional LERF probability for the Manual Shutdown initiator based on the LSCS 2003A PRA.

4.3.1 .7 Summary of Risk Insights The above evaluation assesses the risk from the following sources:

" Internal Events

" Internal Fire

" Seismic Events

" Other External Hazards Table 7 provides a summary of the approach and results of the evaluation of each of these potential risk contributors for Division 1 CSCS . For Division 1 CSCS this risk-informed evaluation identified a number of compensatory measures that will be implemented during the planned CT configuration . These are discussed in more detail in Section 4.3.2 .

Table 8 provides a summary of the approach and results of the evaluation for potential risk contributors for Division 2 CSCS .

These analyses demonstrate that the risk impact of the proposed extension of the CT to 10 days for TS 3.7.1 .A .1, 6 days for TS 3.8.1 .C .4 and TS 3.8.1 .F.1, and a 6 day or 10 day CT for TS 3 .7.2 for the specific refueling outages stated is small and within industry risk acceptance guidelines.

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGES Table if

SUMMARY

OF RISK INSIGHTS FOR DIVISION 1 CSCS CT EXTENSION RISK CONTRIBUTOR APPROACH/RESULTS INSIGHTS Internal Events Quantify ICCDP & ICLERP for planned Compensatory Measures keep risk within acceptance configuration, including Compensatory Measures : guidelines ICCDP < I E-6 ICLERP < 1 E-7 Internal Fire LSCS IPEEE (RMIEP) internal fire sequences Fire risk impact is much lower (by an order of integrated with LSCS 2003A PRA Model of Record, magnitude) than that for internal events . Risk is low and ICCDP and ICLERP estimated for fire for the because of the compensatory measures credited proposed CT configuration above and by posting a fire watch in the Unit 2 Division 2 Essential Switchgear room during the Division 1 CSCS work window.

Seismic LSCS IPEEE (RMIEP) seismic sequences Seismic risk impact is much lower than that for internal integrated with LSCS 2003A PRA Model of Record, events (representing approximately 2% of the internal and ICCDP and ICLERP estimated for seismic for events ICCDP) .

the proposed CT configuration . Quantification of seismic and internal events performed together is a single model quantification .

Other External Hazards LSCS IPEEE (RMIEP) other external events hazard Non-significant contributor to risk analysis reviewed and shown to be non-significant contributors to risk Transition Risk Quantitatively evaluate risk associated with the Shutdown and transition risk offsets some of the alternative option of manually shutting down Unit 2 calculated risk increase due to the proposed CT to perform the maintenance . extension .

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGES Table 8

SUMMARY

OF RISK INSIGHTS FOR DIVISION 2 CSCS CT EXTENSION RISK CONTRIBUTOR APPROACH/RESULTS INSIGHTS Internal Events Quantify ICCDP & ICLERP for planned Internal events ICCDP and ICLERP for the Division 2 configuration, including Compensatory Measures : CSCS CT configuration is non-significant and well

" ICCDP < 1 E-6 within the risk guidelines .

" ICLERP < 1E-7 Internal Fire LSCS IPEEE (RMIEP) internal fire sequences Fire risk impact is much lower (by an order of integrated with LSCS 2003A PRA Model of Record, magnitude) than that for internal events . Fire ICCDP and ICCDP and ICLERP estimated for fire for the and ICLERP for the Division 2 CSCS CT configuration proposed CT configuration is non-significant and well within the risk guidelines.

Seismic I-SCS IPEEE (RMIEP) seismic sequences Seismic risk impact is much lower than that for internal integrated with LSCS 2003A PRA Model of Record, events (representing approximately 5% of the internal and ICCDP and ICLERP estimated for seismic for events ICCDP).

the proposed CT configuration . Quantification of seismic and internal events performed together is a single model quantification .

Other External Hazards LSCS IPEEE (RMIEP) other external events hazard Non-significant contributor to risk analysis reviewed and shown to be non-significant contributors to risk Transition Risk Quantitatively evaluate risk associated with the Shutdown and transition risk offsets some of the alternative option of manually shutting down Unit 2 calculated risk increase due to the proposed CT to perform the maintenance . extension .

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGES 4.3.2 Tier 2: Avoidance of Risk-Significant Plant Configurations Division 1 CSCS In order to avoid risk-significant plant equipment outage configurations during the extended completion time, the impact of having other equipment unavailable was evaluated. This resulted in a list of protected equipment that will not be scheduled to be unavailable due to maintenance during the extended completion time . In addition, to minimize the impact on fire risk, a fire watch 0 to be posted at the Unit 2 Division 2 Essential Switchgear Room . These compensatory actions are summarized in Table 9.

In addition to the compensatory actions listed in Table 9, the Division 1 CSCS work will be performed with a number of controls in place (consistent with LSCS procedures and practices) to reduce errors and minimize risk.

Division 2 CSCS Due to the non-significant risk impacts of the Division 2 CSCS CT configuration, no compensatory actions are needed during the proposed work . However, the proposed Division 2 CSCS work will also be performed with a number of controls in place (consistent with LSCS procedures and practices) to reduce errors and minimize risk .

The controls for the Division 1 and the Division 2 CSCS maintenance will address potential errors prior to the actual work, during the work, and following the work during restoration of the system . These controls are summarized as follows:

Prior to Maintenance Work The following controls will ensure that the maintenance is performed on the proper piping segments and valves, and that the work does not proceed until the system is properly isolated and prepared :

The work is identified as a Hightened Level of Awareness (HLA) job and the draining activity for the piping will require a HLA pre-job brief be conducted. Special procedures governing these activities will be prepared .

0 A walkdown and visual inspection will be performed of the valves that need to be closed and those that will be replaced, in accordance with the EGC procedure for clearance and tagging of equipment.the This walkdown will be performed by Operations personnel knowledgeable of systems and by supervisory personnel in charge of the personnel performing the maintenance work.

0 An EGC procedurally controlled checklist will be used during the pre-job walkdown that specifically lists each of the valves that need to be closed . Additionally, each valve verification will require initialing and verification by a second individual .

9 Existing EGC maintenance procedures and special procedures prepared for this specific maintenance, do not allow work to commence until draining has been properly completed and verified .

ATTACHMENT I EVALUATION OF PROPOSED CHANGES During the Maintenance Work The following controls will ensure that inadvertent area flooding does not occur during the maintenance work :

0 The special procedures for this work require that the pressure integrity of the piping isolation points be verified prior to making any cuts into the system.

9 The mechanical line stops will be administratively controlled in accordance with the EGC equipment clearance process to prevent inadvertent opening or removal of the stops .

The special procedures for this work require damage control plugs be available should a failure of a line stop occur. The pressure head will be very low and these devices are very effective at stopping or minimizing leaks . The suction sides of the systems affected are in water tight rooms that offer further protection against flood propagation .

Following the Maintenance Work (System Restoration)

The following control will be taken after the maintenance is performed and the piping unisolated to ensure that drain valves that may have been opened during the work have been closed :

EGC maintenance procedures require similar line-up verifications for post-job system restoration as for the pre-job line-up.

4.3.3 Tier 3 : Risk-Informed Configuration Risk Management Program LSCS has developed a Configuration Risk Management Program (CRMP) governed by station procedures, and described by LSCS Technical Requirements Manual (TRM) Section 5 .0.e (Reference 15), that ensures the risk impact of equipment out of service is appropriately evaluated prior to performing any maintenance activity. This program requires an integrated review to uncover risk-significant plant equipment outage configurations in a timely manner both during the work management process and for emergent conditions during normal plant operation . Appropriate consideration is given to equipment unavailability, operational activities such as testing or load dispatching, and weather conditions. LSCS has the capability to perform a configuration dependent assessment of the overall impact on risk of proposed plant configurations prior to, and during, the performance of maintenance activities that remove equipment from service. Risk is re-assessed if an equipment failure/malfunction or emergent condition produces a plant configuration that has not been previously assessed .

For planned maintenance activities, an assessment of the overall risk of the activity on plant safety is performed prior to scheduled work . The assessment includes the following considerations .

Maintenance activities that affect redundant and diverse structures, systems, and components (SSCs) that provide backup for the same function are minimized.

The potential for planned activities to cause a plant transient are reviewed and work on SSCs that would be required to mitigate the transient are avoided .

Work is not normally scheduled that is highly likely to exceed a TS or Technical Requirements Manual (TRM) Completion Time requiring a plant shutdown . For activities that are expected to exceed 50% of a TS allowed outage time, compensatory measures 41 of 51

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGES and contingency plans are considered to minimize SSC unavailability and maximize SSC reliability.

For Maintenance Rule (MR) High Risk Significant SSCs, the impact of the planned activity on the unavailability performance criteria is evaluated.

As a final check, a blended qualitative-quantitative risk assessment is performed to ensure that the activity does not pose any unacceptable risk . This evaluation is performed using the impact on both CDF and LERF . The results of the risk assessment are classified by a color code based on the increased risk of the activity as shown below.

The qualitative assessment examines redundant systems used to support critical safety functions, such that a loss of redundancy is highlighted via risk colors as part of the CRMP .

Color Meaning Plant Impact and Required Action Green Non-risk significant Small impact on plant risk.

Requires no specific actions.

Yellow Non-risk significant with non- Impact on plant risk .

quantitative factors applied Limit unavailability time or take compensatory actions to reduce plant risk .

Orange Potentially risk-significant Significant impact on plant risk .

Requires senior management review and approval prior to entering this condition .

Requires compensatory measures to reduce risk including contingency plans.

All entries will be of short duration .

Red Risk-significant Not entered voluntarily .

If this condition occurs, immediate and significant actions taken to alleviate the problem .

Program Maintenance Rule The reliability and availability of the CSCS pumps are monitored under the MR Program . If the pre-established reliability or availability performance criteria are exceeded for the CSCS pumps, they are considered for 10 CFR 50 .65, "Requirements for monitoring the effectiveness of maintenance at nuclear power plants," paragraph (a)(1) actions, requiring increased management attention and goal setting in order to restore their performance (i .e., reliability and availability) to an acceptable level. The performance criteria are risk-informed and, therefore, are a means to manage the overall risk profile of the plant. An accumulation of large core damage probabilities over time is precluded by the performance criteria .

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGES Table 9

SUMMARY

OF COMPENSATORY MEASURES FOR DIVISION 1 CSCS CT COMPENSATORY ACTION DESCRIPTION U-2 Div . 2 4kv Bus 242Y 4.16 kVAC Bus 242Y (2AP06E)

U-2 DO. 2 EDG DG2A Diesel Generator (2DG01 K)

DG2A Room Ventilation Dampers (2VD09YA,2VD10YA,2VD11YA)

DG2A Room Cooling Fan (2VD03C)

U-2 DO. 2 Bat Charger 125 VDC U-2 Division 2 Battery Charger (2DC17E or 2DC16E)

U-2 DO. 2 CSCS DG2A Cooling Water Pump (2DG01 P)

RHRSW Train `B' Pump (2E12-C3000)

RHRSW Train `B' Pump (2E12-C300D)

RHRSW Train ` B' Strainer (2E12-D300B)

PROTECTED RHRSW Train 'B'HX Outlet MOV (2E12-F068B)

EQUIPMENT U-2 Div . 2 RHR RHR Train `B' Heat Exchanger (2E12-8001 B)

RHR Train 'B'HX Bypass MOV (2E12-F048B)

RHR Train `2B' Pump (2E12-0002B)

RHR Train '2C' Pump (2E12-0002C)

SE Corner Room Area Cooler and Fan (2VY03A, 2VY03C)

U-2 HPCS (Div. 3) HPCS Pump (2E22-CO01) 4 .16 kVAC Bus 243C (2AP07E)

DG213 Diesel Generator (2E22-SO01)

DG2B Cooling Water Pump (2E22-CO02)

DG2B Room Cooling Fan (2VD01C)

SW Corner Room Area Cooler and Fan (2VY02A, 2VY02C)

U-2 MDFW Motor-Driven FW Pump (2FW01 PC)

Motor-Driven FW Regulating AOV (2FW005)

FIRE WATCH Zone 4E4 Unit 2 Division 2 Essential Switchgear Room

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGES Chanqe Control The CRMP is referenced and maintained as an administrative program in accordance with the LSCS TRM Section 5.0.e and procedure WC-AA-101, "On-Line Work Control Process" (Reference 16). The goat of a CRMP are to ensure that risk-significant plant configurations will not be inadvertently entered for planned maintenance activities, and appropriate actions will be taken should unforeseen events place the plant in a risk-significant configuration during the proposed extended Division 1 and Division 2 CSCS CTs.

Overall Conclusion This request has been evaluated consistent with the key principles identified in RG 1 .174 and RG 1 .177 for risk informed changes to the licensing basis and demonstrates that the risk from the proposed change is acceptably small. The evaluation with respect to these principles is summarized below.

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

This proposed change will only be used during each of the upcoming Unit 1 and Unit 2 refueling outages, and during the subsequent Unit 1 refueling outage.

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

The configuration to be entered for the Division 1 CSCS maintenance decreases the redundancy of the CSCS system due to the removal from service of the Division 1 train of CSCS . Although, the reduced redundancy increases the potential for the plant to lose CSCS cooling to plant equipment, two additional trains of CSCS per unit remain operable .

Defense-in-depth is maintained during the configurations for both Division 1 and Division 2 CSCS maintenance. Compensatory measures are identified for Division 1 and additional controls will be in place for both Division 1 and Division 2 CSCS maintenance to strengthen the level of defense-in-depth and reduce overall risk.

• The proposed change maintains sufficient safety margins.

The proposed TS change is consistent with the principle that sufficient safety margins are maintained based on the following.

The proposed changes meet and are not in conflict with, approved codes and standards (mg., ASME, IEEE or NRC approved alternatives).

The non-code line stops will maintain the availability of the online unit Division 2 CSCS system.

While in the proposed configurations the safety analysis acceptance criteria for the CSCS subsystems in the UFSAR are met, assuming there are no additional failures .

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGES While in the proposed configurations for the Division 2 CSCS maintenance, the safety analysis for the Division 2 DGs will not meet acceptable restrictions described in RG 1 .93, however the risk impact is small and within industry guidelines.

The Division 2 CSCS maintenance will be performed only during the respective refueling outages and therefore the risk associated with the immediate shutdown of the non-accident unit restriction in RG 1 .93 is eliminated When proposed changes result in an increase in core damage frequency or risk, the increases should be small and consistent with the intent of the Commission's Safety Goal Policy Statement.

A risk evaluation was performed that considers the impact of the proposed change with respect to the risks due to internal events, internal fires, seismic events and other external hazards. The risk analysis documented in Section 4 .3 shows that the existing plant redundancy and diversity for Division 1 and Division 2 CSCS, and the identified compensatory actions for Division 1 CSCS, are such that the risk impact of the requested CT extension is small and within RG 1 .174 guidelines.

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

The EGC configuration risk management program will effectively monitor the risk of emergent conditions during the period of time that the proposed change is in effect . This will ensure that any additional risk increase due to emergent conditions is appropriately managed.

5.0 REGULATORY ANALYSIS

5.1 No Significant Hazards Consideration According to 10 CFR %92, "Issuance of amendment," paragraph (c), a proposed amendment to an operating license involves no significant hazards consideration if operation of the facility in accordance with the proposed amendment would not:

Involve a significant increase in the probability or consequences of an accident previously evaluated ; or (2) Create the possibility of a new or different kind of accident from any accident previously evaluated ; or Involve a significant reduction in a margin of safety .

In support of this determination, an evaluation of each of the three criteria set forth in 10 CFR 50 .92 is provided below regarding the proposed license amendment.

In accordance with 10 CFR 50.90, "Application for amendment of license or construction permit,"

Exelon Generation Company, LLC (EGC) requests an amendment to Facility Operating License Nos . NPF-1 1 and NPF-18 for LaSalle County Station (LSCS), Units 1 and 2. The proposed changes modify Technical Specifications (TS) Sections 3.7.1, "Residual Heat Removal Service 45 of 51

ATTACHMENT I EVALUATION OF PROPOSED CHANGES Water (RHRSW) System," 3.7.2, "Diesel Generator Cooling Water (DGCW) System," and 3 .8 .1, "AC Sources - Operating ." The proposed changes address the following items.

1 . An extension of the Completion Time (CT) for Required Action A.1, "Restore RHRSW subsystem to OPERABLE status," associated with TS Section 3 .7.1 from 7 days to 10 days . This proposed change will only be used during the upcoming Unit 1 Spring 2006 Refueling Outage .

2 . The establishment of a 6 day (for Division 2 Core Standby Cooling System (CSCS) tenance) or 10 day (for Division 1 CSCS maintenance) CT for TS Section 3.7.2 when one or more required DGCW subsystem(s) are inoperable . This proposed change will only be used during each of the upcoming Unit 1 Spring 2006 and Unit 2 Spring 2007 refueling outages, and during the subsequent Unit 1 Spring 2008 refueling outage.

3. An extension of the CT for Required Action CA, "Restore required Diesel Generator (DG) to OPERABLE status," associated with TS Section 3 .8 .1 from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to 6 days .

This proposed change will only be used during the upcoming Unit 2 Spring 2007 refueling outage, and during the subsequent Unit 1 Spring 2008 refueling outage .

4. An extension of the CT for Required Action F.1, "Restore one required Diesel Generator (DG) to OPERABLE status," associated with TS Section 3 .8.1 from 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> to 6 days .

This proposed change will only be used during the upcoming Unit 2 Spring 2007 refueling outage, and during the subsequent Unit 1 Spring 2008 refueling outage.

The current TS Limiting Condition for Operation (LCO) 3.7.1 requires that two RHRSW subsystems be operable in Modes 1, 2, and 3. Condition A allows one RHRSW subsystem inoperable with a CT of 7 days. An extension of the CT to 10 days for the requested refueling outage is needed to replace isolation valves in the Division 1 Core Standby Cooling System (CSCS).

The current TS LCO 3.7.2 requires that three DGCW subsystems ; and the opposite unit Division 2 DGCW subsystem be operable in Modes 1, V, and 3 . Condition A requires that with one or more DGCW subsystems inoperable, immediately declare supported component(s) inoperable .

A CT of 10 days for the Division 1 DGCW subsystem during the upcoming Unit 1 Refueling Outage 11(L1 R11) or 6 days for Division 2 DGCW subsystems during the requested refueling outages 4 needed to replace isolation valves in the Division 1 and Division 2 CSCS.

The current TS LCO 3.8.1 requires that the Division 1, 2, and 3 DGs and the required opposite unit DG be operable in Modes 1, 2, and 3 . Condition C currently allows both units' Division 2 DGs to be inoperable with a CT of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. Additionally, Condition F currently allows both units' Division 2 DGs to be inoperable with a CT of 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. An extension of the CT to 6 days for the requested refueling outages is needed to replace isolation valves in the Division 2 CSCS.

Currently, due to long term wear and corrosion, many valves within the CSCS are degrading such that isolation on a specific cooling line may not be adequate to perform maintenance on system components . As part of the CSCS reliability improvement effort, CSCS isolation valves will be replaced with stainless steel valves less susceptible to the corrosion wear the current valves are experiencing .

In order to replace the isolation valves the CSCS suction header will be blank-flanged at the intake structure. Non-code line stops will be required to isolate the Unit 1 portion of the 46 of 51

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGES common discharge header from the Unit 2 portion of the header. The non-code line stops are designed to the same pressure rating and seismic requirements as the CSCS piping and will maintain the availability of the online unit's Division 2 CSCS system .

The Unit 1 and Unit 2 Division 1 CSCS maintenance planned for the Unit 1 Refueling Outage 11 (L1 R11) will result in the inoperability of the Division 1 RHRSW subsystem and therefore will require Unit 2 entry into TS 3 .7 .1 Condition A for inoperability of one RHRSW subsystem, and will also require entry into TS 3.7.2 Condition A for inoperability of the Division 1 DGCW subsystem .

The Unit 1 and Unit 2 Division 2 CSCS maintenance planned for the Unit 2 Refueling Outage 11 (L2R1 1) and the Unit 1 Refueling Outage 12 (L1 R12) will result in the inoperability of one RHRSW subsystem and will also require entry into TS 3.7.2 Condition A for inoperability of the Division 2 DGCW subsystems .

The Unit 1 and Unit 2 Division 2 CSCS maintenance planned for L2R1 1 and Ll R12 will also result in the inoperability of the 1 A and 2A Diesel Generators (DGs) and will require entry into TS 3 .8 .1 Condition C and Condition F due to the inoperability of both units' Division 2 DGs.

These maintenance evolutions are time consuming and include draining portions of the systems . Based on historical data and best work planning estimates, completion of the entire evolution for each refueling outage specified cannot be assured with the existing 7-day CT for TS 3 .7.1 .A.1, the 72-hour CT for TS 3.8.1 .C .4, the 2-hour CT for TS 3.8.15.1 or the existing entry into TS 3.7.2 Required Action A.1 . Therefore, an extension of the CT to 10 days for TS 3 .7 .1 .A.1, 6 days for TS 3 .8.1 .C .4, 6 days for TS 3.8.1 .F.1, and a 6 day CT (for Division 2 CSCS maintenance) or 10 day CT (for Division 1 CSCS maintenance) for TS 3.7.2 for the specific refueling outages stated is requested .

Replacement of the CSCS isolation valves is a prudent and proactive action . Having the capability to isolate components within the CSCS system will enable necessary system maintenance to be performed in the future thus enhancing the reliability of the Unit 1 and Unit 2 CSCS system and overall plant safety .

The proposed changes have been evaluated using the risk informed processes described in Regulatory Guide (RG) 1 .174, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis," dated July 1998, and RG 1 .177, "An Approach for Plant-Specific, Risk-informed Decision making: Technical Specifications," dated August 1998 . The risk associated with the proposed change was found to be acceptable .

1 The proposed TS change does not involve a significant increase in the probability or consequences of an accident previously evaluated.

The proposed changes have been evaluated using the risk informed processes described in RG 1 .174, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis," dated July 1998 and RG 1 .177, "An Approach for Plant-Specific, Risk-Informed Decisionmaking :

Technical Specifications," dated August 1998 . The risk associated with the proposed change was found to be acceptable .

The previously analyzed accidents are initiated by the failure of plant structures, systems, or components . The proposed change does not have a detrimental impact on 47 of 51

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGES the integrity of any plant structure, system, or component that initiates an analyzed event. No active or passive failure mechanisms that could lead to an accident are affected . Non-code line stops required to isolate the Unit 1 portion of the common discharge header from the Unit 2 portion of the header during the specified CSCS maintenance will maintain the availability of the online unit's Division 2 CSCS system .

The non-code line stops being used to isolate the system during the specified refueling outages are being designed to the same pressure rating and seismic requirements as the CSCS piping .

Redundancy is provided by designing the CSCS system as multiple independent subsystems . Separation between subsystems assures that no single failure can affect more than one subsystem . Therefore, assuming a single failure in any subsystem including the subsystem shared between units, two subsystems in each unit will remain unaffected . These two subsystems can supply the minimum required cooling water for safe shutdown of a unit or mitigate the consequences of an accident .

The proposed limited use of increased CT's of the operating unit's CSCS system maintains the design basis assumptions; therefore, the proposed change does not involve a significant increase in the consequences of an accident previously evaluated.

2. The proposed TS change does not create the possibility of a new or different kind of accident from any accident previously evaluated.

The proposed change involves the temporary installation of new equipment (mechanical line stops) that will be designed and installed to the same pressure rating and seismic design as the CSCS piping . The currently installed equipment will not be operated in a new or different manner. No new or different system interactions are created and no new processes are introduced . The proposed changes will not introduce any new failure mechanisms, malfunctions, or accident initiators not already considered in the design and licensing bases. Based on this evaluation, the proposed change does not create the possibility of a new or different kind of accident from any accident previously evaluated.

3. The proposed TS change does not involve a significant reduction in a margin of safety .

The proposed change does not alter any existing setpoints at which protective actions are initiated and no new sApoints or protective actions are introduced . The design and operation of the CSCS system remains unchanged . The risk associated with the proposed increase in the CTs for TS 3 .7 .1, TS 3.7.2 and TS 3.8 .1 were evaluated using the risk informed processes described in RG 1 .174, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing July Basis," dated 1998 and RG 1 .177, "An Approach for Plant-Specific, Risk-Informed Decisionmaking : Technical Specifications, " dated August 1998 . The risk was shown to be acceptable . Based on this evaluation, the proposed change does not involve a significant reduction in a margin of safety .

Based on the above evaluation, EGC concludes that the proposed amendment presents no significant hazards consideration under the standards set forth in 10 CFR 50.92(c) .

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGES 5 .2 Applicable Regulatory Requirements/Criteria The design of the unit-specific CSCS must satisfy the requirements of 10 CFR 50 .36, "Technical Specifications," paragraph (c)(2)0i), Criterion 3. These requirements state the following :

(ii) A Technical Specification Limiting Condition for Operation ITS LCO) of a nuclear reactor must be established for each item meeting one or more of the following criteria :

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

The design bast of the CSCS is described in the UFSAR, Section 9 .2 .1, "CSCS Equipment Cooling ."

Impact on Previous Submittals/Precedent The NRC has previously approved a similar change for the Braidwood Station in Amendment No . 130 and Byron Station in Amendment No. 136, both issued on March 18, 2004.

6.0 ENVIRONMENTAL CONSIDERATION

EGC has evaluated this proposed operating license amendment consistent with the criteria for identification of licensing and regulatory actions requiring environmental assessment in accordance with 10 CFR 51 .21, "Criteria for and identification of licensing and regulatory actions requiring environmental assessments." EGC has determined that these proposed changes meet the criteria for a categorical exclusion set forth in paragraph (c)(9) of 10 CFR 51 .22, "Criterion for categorical exclusion; identification of licensing and regulatory actions eligible for categorical exclusion or otherwise not requiring environmental review," and as such, has determined that no irreversible consequences exist in accordance with paragraph (b) of 10 CFR 50 .92, "Issuance of amendment." This determination is based on the fact that this change is being proposed as an amendment to a license issued pursuant to 10 CFR 50, "Domestic Licensing of Production and Utilization Facilities," which changes a requirement with respect to installation or use of a facility component located within the restricted area, as defined in 10 CFR 20, "Standards for Protection Against Radiation," or which changes an inspection or a surveillance requirement, and the amendment meets the following specific criteria :

The amendment involves no significant hazards consideration.

As demonstrated in Section 5 .1, "No Significant Hazards Consideration," the proposed changes do not involve any significant hazards consideration .

(ii) There is no significant change in the types or significant increase in the amounts of any effluent that may be released offsite.

The proposed change to increase the time a unit-specific RHRSW subsystem train, Divisional specific DGCW or Division 2 DG may be inoperable does not result in an increase in power level, does not increase the production nor alter the flow path or method of disposal, of radioactive waste or byproducts ; thus, there will be no change in the amounts of radiological effluents released offsite.

49 of 51

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGES not Based on the above evaluation, the proposed change will result in a significant change in the types or significant increase in the amounts of any effluent released offske .

There is no significant increase in individual or cumulative occupational radiation exposure.

The proposed change to increase the time a unit-specific RHRSW subsystem train, Divisional specific DGCW or Division 2 DG may be inoperable will not result in any changes to the previously analyzed configuration of the facility. There will be no change in the level of controls or methodology used for the processing of radioactive effluents or handing of solid radioactive taste, nor will the proposal result in any change in the normal radiation levels in the plant. Therefore, there will be no increase in individual or cumulative occupational radiation exposure resulting from this change.

7.0 REFERENCES

1 . LSCS Updated Final Safety Analysis Report, Section 9.2.1, "CSCS Equipment Cooling Water Syste

2. NUREG/CR-6141, "Handbook of Methods for Risk-Based Analyses of Technical Specifications," December 1994

3. Regulatory Guide 1 .174, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Bask," July 1998

4. Regulatory Guide 1 .177, "An Approach for Plant-Specific, Risk-Informed Decisionmaking : Technical Specifications," August 1998

5. Letter from M.J . Vonk to NRC, "LaSalle County Nuclear Power Station Individual Plant Examination and Individual Plant Examination (External Events) Submittal," dated April 29,1994 6 . NUMARC 93-01, "Industry Guideline for Monitoring the Effectiveness Maintenance at Nuclear Power Plants"

7. NUREG-1488, "Revised Livermore Seismic Hazard Estimates for Sixty-Nine Nuclear Power Plant Sites East of the Rocky Mountains," April, 1994

8. NUREG/CR-4550, Vol. 3, Rev. 1 . Part 3, "Analysis of Core Damage Frequency: Surry Power Station, Unit 1 External Events," December 1990

9. NUREG/CR-483Z "Analysis of the LaSalle Unit 2 Nuclear Power Plant: Risk Methods Integration and Evaluation Program (RMIEP)," 10 volumes, 1992-1993

10. NUREG/CR-5305, "Integrated Risk Assessment of the LaSalle Unit 2 Nuclear Power Plant: Phenomenology and Risk Uncertainty Evaluation Program," 3 volumes, 1992-1993 11 . NURECK 407, Procedural and Submittal Guidance for the Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities

ATTACHMENT 1 EVALUATION OF PROPOSED CHANGES

12. NUREG/CR-3862, "Development of Transient Initiating Event Frequencies for Use in Probabilistic Risk Assessments," May 1985

13. Letter from 401 Jury to NRC, "Request for a License Amendment for a One-Time Extension of the Essential Service Water Train Completion Time," dated June 11, 2003

14. "LaSalle PRA Initiating Events Notebook," LS-PSA-001, Revision 3, June 2003

15. LSCS Technical Requirements Manual (TAM), Section 5.0e, "Configuration Risk Management Program (CAMP)"

16. EGC Procedure WC-AA-101, "On-Line Work Control Process"

17. NSAC-154, "ISLOCA Evaluation Guidelines," September 1991

18. EPRI 1002965, "Risk-Managed Technical Specification (AMTS) Guidelines,"

November 2003

19. Regulatory Guide 1 .93, "Availability of Electric Power Sources," December 1974

20. "LaSalle Division 1 and Division 2 CSCS Valve Replacement Project - Temporary Extension of Technical Specifications Completion Times," Exelon Risk Management Document SA-1 354, Revision 0, dated December 2, 2004

ATTACHMENT 2 Markup of Proposed Technical Specifications Page Changes LASALLE COUNTY STATION REVISED TS PAGES 3.7 .1-1 to 3.7 .1-2 3.7.2-1 to 3.7 .2-2 3.8.1-4 3.8.1-6 to 3 .8.1-19

RHRSW System 3 .7 .1 3 .7 PLANT SYSTEMS 3 .7 .1 Residual Heat Removal Service Water (RHRSW) System LCO 3 .7 .1 Two RHRSW subsystems shall be OPERABLE .

APPLICABILITY : MODES 1, 2, and 3 .

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME One RHRSW subsystem A .1 --------NOTE---------

inoperable . Enter applicable Conditions and Required Actions of LCO 3 .4 .9, "Residual Heat Removal (RHR)

Shutdown Cooling System-Hot Shutdown," for RHR shutdown cooling subsystem made inoperable by RHRSW System .

Restore RHRSW 7 days subsystem to OPERABLE status .

(continued)

LaSalle 1 and 2 3 .7 .1-1 Amendment No .

RHRSW System 3 .7 .1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME

.Both RHRSW subsystems ________NOTE-________

inoperable . 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 <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> subsystem to OPERABLE status .

Required Action and Be in MODE 3 . 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> associated Completion Time not met . AND Be in MODE 4 . 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3 .7 .1 .1 Verify each RHRSW manual, power operated, 31 days and automatic valve in the flow path, that is not locked, sealed, or otherwise secured in position, is in the correct position or can be aligned to the correct position .

LaSalle 1 and 2 3 .7 .1-2 Amendment No . 44444-a'3-

INSERT I

________NOTE-_______ ________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 I 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 subsystem to OPERABLE status .

DGCW System 3 .7 .2 3 .7 PLANT SYSTEMS 3 .7 .2 Diesel Generator Cooling Water (DGCW) System LCO 3 .7 .2 The following DGCW subsystems shall be OPERABLE :

a. Three DGCW subsystems ; and

b. The opposite unit Division 2 DGCW subsystem .

APPLICABILITY : MODES 1, 2, and 3 .

ACTIONS

---

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

Separate Condition entry is allowed for each DGCW subsystem .

CONDITION REQUIRED ACTION COMPLETION TIME One or more DGCW A .1 Declare supported Immediately subsystems inoperable . component s) inoperable .

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3 .7 .2 .1 Verify each DGCW subsystem manual, power 31 days operated, and automatic valve in the flow path, that is not locked, sealed, or otherwise secured in position, is in the correct position .

(continued)

LaSalle 1 and 2 3 .7 .2-1 Amendment No .

INSERT 2 A- --------NOTES--------

l . Not applicable to Division 1 during replacement of the Division 1 CSCS isolation valves during Unit 1 Refueling 11 while Unit I is in MODE 4,5, or defueled .

2 . Not applicable to Division 2 during replacement of the Division 2 CSCS isolation valves during Unit 2 Refueling 11 while Unit 2 is in MODE 4,5, or defueled and during Unit 1 Refueling 12 while Unit I is in MODE 4,5, or defueled .

INSERT 3 CONDITION REQUIRED ACTION COMPLETION TIME

________NOTES-_______ B .1 Restore DGCW 6 days 1 . Only applicable to subsystem to OPERABLE Division 1 during status . OR replacement of the Division 1 CSCS 10 days if isolation valves Division 1 CSCS during Unit 1 inoperable Refueling 11 while Unit 1 is in Mode 4,5, or defueled .

2 . Only applicable to Division 2 during replacement of the Division 2 CSCS isolation valves during Unit 2 Refueling 11 while Unit 2 is in MODE 4,5, or defueled and during Unit 1 Refueling 12 while Unit I is in MODE 4,5, or defueled .

One or more DGCW subsystems inoperable .

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

C .2 Be in MODE 4 . 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />

DGCW System 3 .7 .2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3 .7 .2 .2 Verify each DGCW pump starts automatically 24 months on each required actual or simulated initiation signal .

LaSalle 1 and 2 3 .7 .2-2 Amendment No . 44-0-4~tf

AC Sources-Operating 3 .8 .1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C. Required Division 3 DG C .1 Perform SR 3 .8 .1 .1 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> inoperable . for OPERABLE required offsite circuit(s) . AND OR Once per One required Division 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> 1, 2, or 3 DG thereafter inoperable and the required opposite unit AND Division 2 DG inoperable . C .2 Declare required 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> from feature(s), supported discovery of by the inoperable Condition C DG(s), inoperable concurrent with when the redundant inoperability required feature s) of redundant are inoperable . required feature s)

AND C .3 .1 Determine OPERABLE 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> DG(s) are not inoperable due to common cause failure .

C .3 .2 Perform SR 3 .8 .1 .2 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for OPERABLE DG(s) .

AND C .4 Restore required 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> DG(s) to OPERABLE status . AND 17 days from discovery of failure to meet LCO 3 .8 .1 .a or b (continued)

LaSalle 1 and 2 3 .8 .1-4 Amendment No . ?W~Jkaf

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 <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> 1, 2, or 3 DGs DG to OPERABLE inoperable . status . OR

_OR 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> if Division 3 DG Division 2 DG and the is inoperable required opposite unit Division 2 DG inoperable .

1H A. Required Action and 'K.1 Be in MODE 3 . 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> associated Completion Time of Condition A, AND fH B, C, D, E, on-? not met . F 0e Co 2 Be in MODE 4 . 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> Three or more required Al Enter LCO 3 .0 .3 . Immediately AC sources inoperable .

& & 9 V1 LaSalle 1 and 2 3 .8 .1-6 Amendment No .

INSERT 4 ACTIONS G- ________NOTES-_______

1 . Only applicable to Unit 1 during replacement of the Unit 2 Division 2 CSCS isolation valves during Unit Refueling 11 while Unit 2 is in MODE 4,5, or defueled .

2 . Only applicable to Unit 2 during replacement of the Unit 1 Division 2 CSCS isolation valves during Unit Refueling 12 while Unit 1 is in MODE 4,5, or defueled .

Division 2 DG and the required opposite uni Division 2 DG inoperable .

AC Sources-Operating 3 .8 .1 SURVEILLANCE REQUIREMENTS

____________________________________NOTES ------------------------------------

1 SR 3 .8 .1 .1 through SR 3 .8 .1 .20 are applicable only to the given unit's AC electrical power sources .

2. SR 3 .8 .1 .21 is applicable to the required opposite unit's DG .

SURVEILLANCE I FREQUENCY SR 3 .8 .1 .1 Verify correct breaker alignment and 7 days indicated power availability for each required offsite circuit .

SR 3 .8 .1 .2 ___________________NOTES-__________________

1. All DG starts may be preceded by an engine prelube period and followed by a warmup period prior to loading .

2. A modified DG start involving idling and gradual acceleration to synchronous speed may be used for this SR as recommended by the manufacturer .

When modified start procedures are not used, the time, voltage, and frequency tolerances of SR 3 .8 .1 .7 must be met .

3. A single test of the common DG at the specified Frequency will satisfy the Surveillance for both units .

Verify each required DG starts from standby 31 days conditions and achieves steady state voltage 1 4010 V and n 4310 V and frequency i 58 .8 Hz and S 61 .2 Hz .

(continued)

LaSalle 1 and 2 3 .8 .14~5 Amendment No .

AC Sources-Operating 3 .8 .1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3 .8 .1 .3 ___________________NOTES-__________________

1. DG loadings may include gradual loading as recommended by the manufacturer .

2. Momentary transients outside the load range do not invalidate this test .

3. This Surveillance shall be conducted on only one DG at a time .

4. This SR shall be preceded by, and immediately follow, without shutdown, a successful performance of SR 3 .8 .1 .2 or SR 3 .8 .1 .7 .

5. A single test of the common DG at the specified Frequency will satisfy the Surveillance for both units .

Verify each required DG is synchronized and 31 days loaded and operates for n 60 minutes at a load ! 2400 W and i 2600 W SR 3 .8 .1 .4 Verify each required day tank contains 31 days n 250 gal of fuel oil for Divisions 1 and 2 and n 550 gal for Division 3 .

SR 3 .8 .1 .5 Check for and remove accumulated water from 31 days each required day tank .

SR 3 .8 .1 .6 Verify each required fuel oil transfer 92 days system operates to automatically transfer fuel oil from storage tanks to the day tank .

(continued)

LaSalle 1 and 2 3 .8 . Amendment No . 147/133

AC Sources-Operating 3 .8 .1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3 .8 .1 .7 ___________________NOTES-__________________

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

2. A single test of the common DG at the specified Frequency will satisfy the Surveillance for both units .

Verify each required DG starts from standby 184 days condition and achieves :

a . In n 13 seconds, voltage ! 4010 V and frequency ! 58 .8 Hz ; and Steady state voltage ! 4010 V and n 4310 V and frequency n 58 .8 Hz and n 61 .2 Hz .

SR 3 .8 .1 .8 ___________________NOTE-___________________

This Surveillance shall not normally be performed in MODE I or 2 . However, this Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced . Credit may be taken for unplanned events that satisfy this SR .

Verify manual transfer of unit power supply 24 months from the normal offsite circuit to the alternate offsite circuit .

(continued)

LaSalle 1 and 2 3 .8 . Amendment No . 147/133

AC Sources-Operating 3 .8 . 1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3 .8 .1 .9 __________________NOTES-___________________

I

. This Surveillance shall not normally be performed in MODE 1 or 2 . However, this Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced .

Credit may be taken for unplanned events that satisfy this SR .

2. A single test of the common DG at the specified Frequency will satisfy the Surveillance for both units .

Verify each required DG rejects a load 24 months greater than or equal to its associated single largest post-accident load and following load rejection, the frequency is n 66 .7 Hz .

SR 3 .8 .1 .10 _________________NOTES-____________________

This Surveillance shall not normally be performed in MODE I or 2 . However, this Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced .

Credit may be taken for unplanned events that satisfy this SR .

2. A single test of the common DG at the specified Frequency will satisfy the Surveillance for both units .

Verify each required DG does not trip and 24 months voltage is maintained i 5000 V during and following a load rejection of a load n 2600 W .

(continued)

LaSalle 1 and 2 3 .8 .1- Amendment No . 147/133

AC Sources-Operating 3 .8 .1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3 .8 .1 .11 ___________________NOTES-__________________

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

2. This Surveillance shall not normally be performed in MODE 1 or 2 . However, portions of the Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced . Credit may be taken for unplanned events that satisfy this SR .

Verify on an actual or simulated loss of 24 months offsite power signal :

a . De-energization of emergency buses ;

b. Load shedding from emergency buses for Divisions 1 and 2 only ; and C. DG auto-starts from standby condition and :

energizes permanently connected loads in i 13 seconds,

2. energizes auto-connected shutdown loads,

3. maintains steady state voltage n 4010 V and <_ 4310 V, maintains steady state frequency n 58 .8 Hz and a 61 .2 Hz, and supplies permanently connected and auto-connected shutdown loads for

! 5 minutes .

(continued)

LaSalle 1 and 2 3 .8 . Amendment No . 147/133

AC Sources-Operating 3 .8 .1 SURVEILLANCE REQUIREMENTS SURVEILLANCE I FREQUENCY SR 3 .8 .1 .12 ___________________NOTES-__________________

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

2. This Surveillance shall not normally be performed in MODE I or 2 . However, portions of the Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced . Credit may be taken for unplanned events that satisfy this SR .

Verify on an actual or simulated Emergency 24 months Core Cooling System (ECCS) initiation signal each required DG auto-starts from standby condition and :

In i 13 seconds after auto-start, achieves voltage n 4010 V and frequency ! 58 .8 Hz ;

b. Achieves steady state voltage ! 4010 V and i 4310 V and frequency n 58 .8 Hz and i 61 .2 Hz ; and C. Operates for ! 5 minutes .

(continued)

LaSalle 1 and 2 3 .8 . Amendment No .

AC Sources-Operating 3 .8 .1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3 .8 .1 .13 ___________________NOTE-___________________

This Surveillance shall not normally be performed in MODE 1 or 2 . However, this Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced . Credit may be taken for unplanned events that satisfy this SR .

Verify each required DG's automatic trips 24 months are bypassed on an actual or simulated ECCS initiation signal except :

Engine overspeed ; and Generator differential current .

(continued)

LaSalle 1 and 2 3 .8 .1- Amendment No .

AC Sources-Operating 3 .8 .1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3 .8 .1 .14 ___________________NOTES-__________________

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

2. This Surveillance shall not normally be performed in MODE 1 or 2 unless the other two DGs are OPERABLE . If either of the other two DGs becomes inoperable, this Surveillance shall be suspended . However, this Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced . Credit may be taken for unplanned events that satisfy this SR .

If grid conditions do not permit, the power factor limit is not required to be met . Under this condition, the power factor shall be maintained as close to the limit as practicable .

A single test of the common DG at the specified Frequency will satisfy the Surveillance for both units .

Verify each required DG operating within 24 months the power factor limit operates for n 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> :

a. For n 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> loaded ! 2860 kW ; and For the remaining hours of the test loaded 1 2400 W and i 2600 W .

(continued)

LaSalle 1 and 2 3 .8 .1- Amendment No .

AC Sources-Operating 3 .8 .1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY I

SR 3 .8 .1 .15 ___________________NOTES-__________________

1. This Surveillance shall be performed within 5 minutes of shutting down the DG after the DG has operated 1 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> loaded ! 2400 W and n 2600 W .

Momentary transients outside of load range do not invalidate this test .

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

3. A single test of the common DG at the specified Frequency will satisfy the Surveillance for both units .

Verify each required DG starts and 24 months achieves :

In i 13 seconds, voltage n 4010 V and frequency ! 58 .8 Hz ; and

b. Steady state voltage n 4010 V and

<_ 4310 V and frequency n 58 .8 Hz and a 61 .2 Hz .

(continued)

LaSalle 1 and 2 3 .8 .1-16 Amendment No .

AC Sources-Operating 3 .8 .1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3 .8 .1 .16 ___________________NOTE-___________________

This Surveillance shall not normally be performed in MODE 1 or 2 . However, this Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced . Credit may be taken for unplanned events that satisfy this SR .

Verify each required DG : 24 months Synchronizes with offsite power source while loaded with emergency loads upon a simulated restoration of offsite power ;

Transfers loads to offsite power source ; and C. Returns to ready-to-load operation .

(continued)

LaSalle 1 and 2 3 .8 .1-.1,6 i I Amendment No . t_K_t/=Ta

AC Sources-Operating 3 .8 . 1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3 .8 .1 .17 ___________________NOTE-___________________

This Surveillance shall not normally be performed in MODE 1 or 2 . However, portions of the Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced . Credit may be taken for unplanned events that satisfy this SR .

Verify, with a required DG operating in 24 months test mode and connected to its bus :

a. For Division 1 and 2 DGs, an actual or simulated ECCS initiation signal overrides the test mode by returning DG to ready-to-load operation ; and

b. For Division 3 DG, an actual or simulated DG overcurrent trip signal automatically disconnects the offsite power source while the DG continues to supply normal loads .

SR 3 .8 .1 .18 ___________________NOTE____________________

This Surveillance shall not normally be performed in MODE 1 or 2 . However, this Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced . Credit may be taken for unplanned events that satisfy this SR .

Verify interval between each sequenced load 24 months block, for Division 1 and 2 DGs only, is

! 90% of the design interval for each time delay relay .

(continued)

LaSalle 1 and 2 3 .8 .1- Amendment No .

AC Sources-Operating 3 .8 . 1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3 .8 .1 .19 ___________________NOTES-__________________

I

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

2. This Surveillance shall not normally be performed in MODE 1 or 2 . However, portions of the Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced . Credit may be taken for unplanned events that satisfy this SR .

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

a . De-energization of emergency buses ;

b. Load shedding from emergency buses for Divisions 1 and 2 only ; and C. DG auto-starts from standby condition and :

energizes permanently connected loads in ! 13 seconds,

2. energizes auto-connected emergency loads including through time delay relays, where applicable,

3. maintains steady state voltage n 4010 V and , 4310 A

4. maintains steady state frequency n 58 .8 Hz and i 61 .2 Hz, and

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

! 5 minutes .

(continued)

LaSalle 1 and 2 3 .8 .1- L& r4 Amendment No .

AC Sources-Operating 3 .8 . 1 SURVEILLANCE REQUIREMENTS SURVEILLANCE I FREQUENCY SR 3 .8 .1 .20 ___________________NOTE-___________________

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

Verify, when started simultaneously from 10 years standby condition, each required DG achieves, in ! 13 seconds, voltage n 4010 V and frequency n 58 .8 Hz .

SR 3 .8 .1 .21 ___________________NOTE-___________________

When the opposite unit is in MODE 4 or 5, or moving irradiated fuel assemblies in secondary containment, the following opposite unit SRs are not required to be performed : SR 3 .8 .1 .3, SR 3 .8 .1 .9 through SR 3 .8 .1 .11, SR 3 .8 .1 .14 through SR 3 .8 .1 .16 .

For required opposite unit DG, the SRs of In accordance the opposite unit's Specification 3 .8 ." with applicable except SR 3 .8 .1 .12, SR 3 .8 .1 .13, SRs SR 3 .8 .1 .17, SR 3 .8 .1 .18, SR 3 .8 .1 .19, and SR 3 .8 .1 .20, are applicable .

LaSalle 1 and 2 3 .8 .1-j Amendment No .

ATTACHMENT 3 Typed Pages for Technical Specifications Changes LASALLE COUNTY STATION REVISED TS PAGES 3.7 .1-1 to 3 .7.1-3 3.7 .2-1 to 3 .7.2-4 3 .8 .1-4 3 .8 .1-6 to 3.8.1-20

RHRSW System 3 .7 .1 3 .7 PLANT SYSTEMS 3 .7 .1 Residual Heat Removal Service Water (RHRSW) System LCO 3 .7 . Two RHRSW subsystems shall be OPERABLE .

APPLICABILITY : MODES 1, 2, and 3 .

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME

________NOTE-_______ ________NOTE-________

Not applicable to Enter applicable Unit 2 during Conditions and replacement of the Required Actions of Division I CSCS LCO 3 .4 .9, "Residual isolation valves Heat Removal (RHR) during Unit 1 Shutdown Cooling Refueling 11 while System-Hot Unit I is in Mode 4,5, Shutdown," for RHR or defueled . shutdown cooling subsystem made One RHRSW subsystem inoperable by RHRSW inoperable . System .

Restore RHRSW 7 days subsystem to OPERABLE status .

(continued)

LaSalle 1 and 2 Amendment No . xxx/xxx

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 .

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

inoperable . 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 <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> subsystem to OPERABLE status .

D. Required Action and D .1 Be in MODE 3 . 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> associated Completion Time not met . AND D .2 Be in MODE 4 . 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> LaSalle 1 and 2 3 .7 .1-2 Amendment No . xxx/xxx

RHRSW System 3 .7 .1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3 .7 .1 .1 Verify each RHRSW manual, power operated, 31 days and automatic valve in the flow path, that is not locked, sealed, or otherwise secured in position, is in the correct position or can be aligned to the correct position .

LaSalle 1 and 2 3 .7 .1-3 Amendment No . xxx/xxx

DGCW System 3 .7 .2 3 .7 PLANT SYSTEMS 3 .7 .2 Diesel Generator Cooling Water (DGCW) System LCO 3 .7 .2 The following DGCW subsystems shall be OPERABLE :

a. Three DGCW subsystems ; and

b. The opposite unit Division 2 DGCW subsystem .

APPLICABILITY : MODES 1, 2, and 3 .

ACTIONS

---

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

Separate Condition entry is allowed for each DGCW subsystem .

LaSalle 1 and 2 3 .7 .2-1 Amendment No . xxx/xxx

DGCW System 3 .7 . 2 ACTIONS A- --------NOTES--------

l . Not applicable to Division 1 during replacement of the Division I CSCS isolation valves during Unit 1 Refueling 11 while Unit 1 is in MODE 4,5, or defueled .

2 . Not applicable to Division 2 during replacement of the Division 2 CSCS isolation valves during Unit 2 Refueling 11 while Unit 2 is in MODE 4,5, or defueled and during Unit 1 Refueling 12 while Unit 1 is in MODE 4,6, or defueled .

One or more DGCW subsystems inoperable .

(continued)

LaSalle 1 and 2 3 .7 .2-2 Amendment No . xxx/xxx

DGCW System 3 .7 .2 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B- ________NOTES-_______ B .1 Restore DGCW 6 days 1 . Only applicable to subsystem to OPERABLE Division I during status . 0 replacement of the Division 1 CSCS 10 days if isolation valves Division 1 CSCS during Unit 1 inoperable Refueling 11 while Unit 1 is in Mode 4,5, or defueled .

2 . Only applicable to Division 2 during replacement of the Division 2 CSCS isolation valves during Unit 2 Refueling 11 while Unit 2 is in MODE 4,5, or defueled and during Unit 1 Refueling 12 while Unit I is in MODE 4,5, or defueled .

One or more DGCW subsystems inoperable .

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

C .2 Be in MODE 4 . 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> LaSalle 1 and 2 3 .7 .2-3 Amendment No . xxx/xxx

DGCW System 3 .7 .2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3 .7 .2 .1 Verify each DGCW subsystem manual, power 31 days operated, and automatic valve in the flow path, that is not locked, sealed, or otherwise secured in position, is in the correct position .

SR 3 .7 .2 .2 Verify each DGCW pump starts automatically 24 months on each required actual or simulated initiation signal .

LaSalle 1 and 2 3 .7 .2-4 Amendment No . xxx/xxx

AC Sources-Operating 3 .8 .1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C- --------NOTES-------- C .1 Perform SR 3 .8 .1 .1 I hour 1 . Not applicable to for OPERABLE required Unit 1 during offsite circuit(s) . AND replacement of the Unit 2 Division 2 Once per CSCS isolation 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> valves during Unit thereafter 2 Refueling 11 while Unit 2 is in AND MODE 4,5, or defueled . C .2 Declare required 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> from feature(s), supported discovery of 2 . Not applicable to by the inoperable Condition C Unit 2 during DG(s), inoperable concurrent with replacement of the when the redundant inoperability Unit 1 Division 2 required feature s) of redundant CSCS isolation are inoperable . required valves during Unit feature s)

I Refueling 12 while Unit 1 is in AND MODE 4,5, or defueled . C .3 .1 Determine OPERABLE 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> DG(s) are not inoperable due to Required Division 3 DG common cause failure .

inoperable .

C .3 .2 Perform SR 3 .8 .1 .2 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> One required Division for OPERABLE DG(s) .

1, 2, or 3 DG inoperable and the 8 required opposite unit Division 2 DG C .4 Restore required 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> inoperable . DG(s) to OPERABLE status .

17 days from discovery of failure to meet LCO 3 .8 .1 .a or b (continued)

LaSalle 1 and 2 3 .8 .1-4 Amendment No . xxx/xxx

AC Sources-Operating 3 .8 .1 ACTIONS F- --------NOTES--------

1 . Not applicable to Unit 1 during replacement of the Unit 2 Division 2 CSCS isolation valves during Unit Refueling 11 while Unit 2 is in MODE 4,5, or defueled .

2 . Not applicable to Unit 2 during replacement of the Unit 1 Division 2 CSCS isolation valves during Unit Refueling 12 while Unit 1 is in MODE 4,5, or defueled .

Two required Division 1, 2, or 3 DGs inoperable .

OR Division 2 DG and the required opposite uni Division 2 DG inoperable .

(continued)

LaSalle 1 and 2 3 .8 .1-6 Amendment No . xxx/xxx

AC Sources-Operating 3 .8 .1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME G- --------NOTES-------- G .1 Restore required 6 days 1 . Only applicable to Division 2 DG to Unit 1 during OPERABLE status .

replacement of the Unit 2 Division 2 CSCS isolation valves during Unit 2 Refueling 11 while Unit 2 is in MODE 4,5, or defueled .

2 . Only applicable to Unit 2 during replacement of the Unit 1 Division 2 CSCS isolation valves during Unit 1 Refueling 12 while Unit 1 is in MODE 4,5, or defueled .

Division 2 DG and the required opposite unit Division 2 DG inoperable .

H. Required Action and H .1 Be in MODE 3 . 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> associated Completion Time of Condition A, AND B, C, D, E, F or G not met . H .2 Be in MODE 4 . 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> I . Three or more required I .1 Enter LCO 3 .0 .3 . Immediately AC sources inoperable .

LaSalle 1 and 2 3 .8 .1-7 Amendment No . xxx/xxx

AC Sources-Operating 3 .8 .1 SURVEILLANCE REQUIREMENTS

____________________________________NOTES ------------------------------------

1. SR 3 .8 .1 .1 through SR 3 .8 .1 .20 are applicable only to the given unit's AC electrical power sources .

2. SR 3 .8 .1 .21 is applicable to the required opposite unit's DG .

SURVEILLANCE FREQUENCY SR 3 .8 .1 .1 Verify correct breaker alignment and 7 days indicated power availability for each required offsite circuit .

SR 3 .8 .1 .2 ___________________NOTES-__________________

1. All DG starts may be preceded by an engine prelube period and followed by a warmup period prior to loading .

2. A modified DG start involving idling and gradual acceleration to synchronous speed may be used for this SR as recommended by the manufacturer .

When modified start procedures are not used, the time, voltage, and frequency tolerances of SR 3 .8 .1 .7 must be met .

3. A single test of the common DG at the specified Frequency will satisfy the Surveillance for both units .

Verify each required DG starts from standby 31 days conditions and achieves steady state voltage 1 4010 V and z 4310 V and frequency

! 58 .8 Hz and ! 61 .2 Hz .

(continued)

LaSalle 1 and 2 3 .8 .1-8 Amendment No . xxx/xxx

AC Sources-Operating 3 .8 .1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3 .8 .1 .3 ___________________NOTES-__________________

1. DG loadings may include gradual loading as recommended by the manufacturer .

2. Momentary transients outside the load range do not invalidate this test .

3. This Surveillance shall be conducted on only one DG at a time .

4. This SR shall be preceded by, and immediately follow, without shutdown, a successful performance of SR 3 .8 .1 .2 or SR 3 .8 .1 .7 .

5. A single test of the common DG at the specified Frequency will satisfy the Surveillance for both units .

Verify each required DG is synchronized and 31 days loaded and operates for ! 60 minutes at a load ? 2400 kW and ! 2600 W SR 3 .8 .1 .4 Verify each required day tank contains 31 days

! 250 gal of fuel oil for Divisions 1 and 2 and ! 550 gal for Division 3 .

SR 3 .8 .1 .5 Check for and remove accumulated water from 31 days each required day tank .

SR 3 .8 .1 .6 Verify each required fuel oil transfer 92 days system operates to automatically transfer fuel oil from storage tanks to the day tank .

(continued)

LaSalle 1 and 2 3 .8 .1-9 Amendment No . xxx/xxx

AC Sources-Operating 3 .8 .1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3 .8 .1 .7 ___________________NOTES-__________________

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

A single test of the common DG at the specified Frequency will satisfy the Surveillance for both units .

Verify each required DG starts from standby 184 days condition and achieves :

a. In ! 13 seconds, voltage ? 4010 V and frequency ? 58 .8 Hz ; and

b. Steady state voltage ? 4010 V and ! 4310 V and frequency ! 58 .8 Hz and n 61 .2 Hz .

SR 3 .8 .1 .8 ___________________NOTE-___________________

This Surveillance shall not normally be performed in MODE I or 2 . However, this Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced . Credit may be taken for unplanned events that satisfy this SR .

Verify manual transfer of unit power supply 24 months from the normal offsite circuit to the alternate offsite circuit .

(continued)

LaSalle 1 and 2 3 .8 .1-10 Amendment No . xxx/xxx

AC Sources-Operating 3 .8 . 1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3 .8 .1 .9 __________________NOTES-___________________

1. This Surveillance shall not normally be performed in MODE 1 or 2 . However, this Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced .

Credit may be taken for unplanned events that satisfy this SR .

2. A single test of the common DG at the specified Frequency will satisfy the Surveillance for both units .

Verify each required DG rejects a load 24 months greater than or equal to its associated single largest post-accident load and following load rejection, the frequency is n 66 .7 Hz .

SR 3 .8 .1 .10 _________________NOTES-____________________

1. This Surveillance shall not normally be performed in MODE I or 2 . However, this Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced .

Credit may be taken for unplanned events that satisfy this SR .

2. A single test of the common DG at the specified Frequency will satisfy the Surveillance for both units .

Verify each required DG does not trip and 24 months voltage is maintained 1 5000 V during and following a load rejection of a load n 2600 kW .

(continued)

LaSalle 1 and 2 3 .8 .1-11 Amendment No . xxx/xxx

AC Sources-Operating 3 .8 . 1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3 .8 .1 .11 ___________________NOTES-__________________

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

2. This Surveillance shall not normally be performed in MODE 1 or 2 . However, portions of the Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced . Credit may be taken for unplanned events that satisfy this SR .

Verify on an actual or simulated loss of 24 months offsite power signal :

a. De-energization of emergency buses ;

Load shedding from emergency buses for Divisions 1 and 2 only ; and C. DG auto-starts from standby condition and :

energizes permanently connected loads in n 13 seconds,

2. energizes auto-connected shutdown loads,

3. maintains steady state voltage i 4010 V and i 4310 A

4. maintains steady state frequency

! 58 .8 Hz and Z 61 .2 Hz, and supplies permanently connected and auto-connected shutdown loads for

! 5 minutes .

(continued)

LaSalle 1 and 2 3 .8 .1-12 Amendment No . xxx/xxx

AC Sources-Operating 3 .8 . 1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3 .8 .1 .12 ___________________NOTES-__________________

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

2. This Surveillance shall not normally be performed in MODE 1 or 2 . However, portions of the Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced . Credit may be taken for unplanned events that satisfy this SR .

Verify on an actual or simulated Emergency 24 months Core Cooling System (ECCS) initiation signal each required DG auto-starts from standby condition and :

In 5 13 seconds after auto-start, achieves voltage ! 4010 V and frequency ! 58 .8 Hz ;

Achieves steady state voltage ? 4010 V and n 4310 V and frequency 0 58 .8 Hz and ! 61 .2 Hz ; and C. Operates for ? 5 minutes .

(continued)

LaSalle 1 and 2 3 .8 .1-13 Amendment No . xxx/xxx

AC Sources-Operating 3 .8 . 1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3 .8 .1 .13 ___________________NOTE-___________________

This Surveillance shall not normally be performed in MODE 1 or 2 . However, this Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced . Credit may be taken for unplanned events that satisfy this SR .

Verify each required DG's automatic trips 24 months are bypassed on an actual or simulated ECCS initiation signal except :

Engine overspeed ; and

b. Generator differential current .

(continued)

LaSalle 1 and 2 3 .8 .1-14 Amendment No . xxx/xxx

AC Sources-Operating 3 .8 . 1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3 .8 .1 .14 ___________________NOTES-__________________

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

2. This Surveillance shall not normally be performed in MODE 1 or 2 unless the other two DGs are OPERABLE . If either of the other two DGs becomes inoperable, this Surveillance shall be suspended . However, this Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced . Credit may be taken for unplanned events that satisfy this SR .

3. If grid conditions do not permit, the power factor limit is not required to be met . Under this condition, the power factor shall be maintained as close to the limit as practicable .

A single test of the common DG at the specified Frequency will satisfy the Surveillance for both units .

Verify each required DG operating within 24 months the power factor limit operates for i 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> :

a. For A 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> loaded ! 2860 W ; and

b. For the remaining hours of the test loaded ! 2400 W and i 2600 W.

(continued)

LaSalle 1 and 2 3 .8 .1-15 Amendment No . xxx/xxx

AC Sources-Operating 3 .8 .1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3 .8 .1 .15 ___________________NOTES-__________________

1. This Surveillance shall be performed within 5 minutes of shutting down the DG after the DG has operated ? 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> loaded ! 2400 W and ! 2600 W .

Momentary transients outside of load range do not invalidate this test .

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

3. A single test of the common DG at the specified Frequency will satisfy the Surveillance for both units .

Verify each required DG starts and 24 months achieves :

a. 5 13 seconds, voltage A 4010 V and equency ! 58 .8 Hz ; and Steady state voltage n 4010 V and

! 4310 V and frequency ! 58 .8 Hz and ! 61 .2 Hz .

(continued)

LaSalle 1 and 2 3 .8 .1-16 Amendment No . xxx/xxx

AC Sources-Operating 3 .8 .1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3 .8 .1 .16 ___________________NOTE____________________

This Surveillance shall not normally be performed in MODE I or 2 . However, this Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced . Credit may be taken for unplanned events that satisfy this SR .

Verify each required DG : 24 months a . Synchronizes with offsite power source while loaded with emergency loads upon a simulated restoration of offsite power ;

b. Transfers loads to offsite power source ; and C. Returns to ready-to-load operation .

(continued)

LaSalle 1 and 2 3 .8 .1-17 Amendment No . xxx/xxx

AC Sources-Operating 3 .8 . 1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3 .8 .1 .17 ___________________NOTE-___________________

This Surveillance shall not normally be performed in MODE 1 or 2 . However, portions of the Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced . Credit may be taken for unplanned events that satisfy this SR .

Verify, with a required DG operating in 24 months test mode and connected to its bus :

a. For Division 1 and 2 DGs, an actual or simulated ECCS initiation signal overrides the test mode by returning DG to ready-to-load operation ; and For Division 3 DG, an actual or simulated DG overcurrent trip signal automatically disconnects the offsite power source while the DG continues to supply normal loads .

SR 3 .8 .1 .18 ___________________NOTE-___________________

This Surveillance shall not normally be performed in MODE 1 or 2 . However, this Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced . Credit may be taken for unplanned events that satisfy this SR .

Verify interval between each sequenced load 24 months block, for Division 1 and 2 DGs only, is

? 90% of the design interval for each time delay relay .

(continued)

LaSalle 1 and 2 3 .8 .1-18 Amendment No . xxx/xxx

AC Sources-Operating 3 .8 . 1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3 .8 .1 .19 ___________________NOTES-__________________

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

2. This Surveillance shall not normally be performed in MODE 1 or 2 . However, portions of the Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced . Credit may be taken for unplanned events that satisfy this SR .

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

a. De-energization of emergency buses ;

b. Load shedding from emergency buses for Divisions 1 and 2 only ; and C. DG auto-starts from standby condition and :

energizes permanently connected loads in ! 13 seconds,

2. energizes auto-connected emergency loads including through time delay relays, where applicable,

3. maintains steady state voltage

? 4010 V and ! 4310 V, maintains steady state frequency

? 58 .8 Hz and a 61 .2 Hz, and

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

? 5 minutes .

(continued)

LaSalle 1 and 2 3 .8 .1-19 Amendment No . xxx/xxx

AC Sources-Operating 3 .8 . 1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3 .8 .1 .20 ___________________NOTE-___________________

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

Verify, when started simultaneously from 10 years standby condition, each required DG achieves, in 13 seconds, voltage ? 4010 V and frequency 58 .8 Hz .

SR 3 .8 .1 .21 ___________________NOTE-___________________

When the opposite unit is in MODE 4 or 5, or moving irradiated fuel assemblies in secondary containment, the following opposite unit SRs are not required to be performed : SR 3 .8 .1 .3, SR 3 .8 .1 .9 through SR 3 .8 .1 .11, SR 3 .8 .1 .14 through SR 3 .8 .1 .16 .

For required opposite unit DG, the SRs of In accordance the opposite unit's Specification 3 .8 . with applicable except SR 3 .8 .1 .12, SR 3 .8 .1 .13, SRs SR 3 .8 .1 .17, SR 3 .8 .1 .18, SR 3 .8 .1 .19, and SR 3 .8 .1 .20, are applicable .

LaSalle 1 and 2 3 .8 .1-20 Amendment No . xxx/xxx

ATTACHMENT 4 Typed Pages for Technical Specifications Bases Changes LASALLE COUNTY STATION REVISED TS BASES PAGES B 3.7 .1-4 to B 3.7.1-6 B 3 .7 .2-3 to B 3.7.2-6 B 3.8 .1-13 B3 .8 .1-19 to B 3.8 .1-21 B 3.8 .1-45

RHRSW System B 3 .7 .1 BASES (continued)

ACTIONS A .1 Condition A is modified by a Note indicating that this Condition is not applicable to Unit 2 during replacement of the Division 1 CSCS isolation valves during Unit 1 Refueling 11 while Unit 1 is in MODE 4, 5, or defueled .

When the Division 1 RHRSW subsystem is inoperable during the CSCS isolation valve maintenance, Condition B provides the appropriate Required Actions .

Required Action A .1 is intended to handle the inoperability of one RHRSW subsystem . The Completion Time of 7 days is allowed to restore the RHRSW subsystem to OPERABLE status .

With the unit in this condition, the remaining OPERABLE RHRSW subsystem is adequate to perform the RHRSW heat removal function . However, the overall reliability is reduced because a single failure in the OPERABLE RHRSW subsystem could result in loss of RHRSW function . The Completion Time is based on the redundant RHRSW capabilities afforded by the OPERABLE subsystem and the low probability of an event occurring requiring RHRSW during this period .

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 .

Condition B is modified by a Note indicating that this Condition is only applicable to Unit 2 during replacement of the Division 1 CSCS isolation valves during Unit 1 Refueling Outage 11 while the outage unit is in MODE 4, 5, or defueled .

Required Action B .1 is intended to handle the inoperability of one RHRSW subsystem . The Completion Time of 10 days is allowed to restore the RHRSW subsystem to OPERABLE status .

With the unit in this condition, the remaining OPERABLE RHRSW subsystem is adequate to perform the RHRSW heat removal function . However, the overall reliability is reduced because a single failure in the OPERABLE RHRSW subsystem could result in loss of RHRSW function . The (continued)

LaSalle 1 and 2 B 3 .7 .1-4 Revision x

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 <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> . The 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> Completion Time for restoring one RHRSW subsystem 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 .

D .1 and D .2 If any Required Action and associated Completion Time of Condition A, B, or C are not 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 <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in MODE 4 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> . The allowed Completion Times are 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 x

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 .

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 Completion Times", December 02, 2004 .

LaSalle 1 and 2 B 3 .7 .1-6 Revision x

DGCW System B 3 .7 .2 BASES LCO subsystem is based on having an OPERABLE pump and an (continued) OPERABLE flow path capable of taking suction from the CSCS water tunnel and transferring cooling water to the associated diesel generator, LPCS pump motor cooling coils, and ECCS cubicle area cooling coils, as required .

An adequate suction source is not addressed in this LCO since the minimum net positive suction head of the DGCW pump and the maximum suction source temperature are covered by the requirements specified in LCO 3 .7 .3, "Ultimate Heat Sink (UHS) ."

APPLICABILITY In MODES 1, 2, and 3, the DGCW subsystems are required to support the OPERABILITY of equipment serviced by the DGCW subsystems and required to be OPERABLE in these MODES .

In MODES 4 and 5, the OPERABILITY requirements of the DGCW subsystems are determined by the systems they support .

Therefore, the requirements are not the same for all facets of operation in MODES 4 and 5 . Thus, the LCOs of the systems supported by the DGCW subsystems will govern DGCW System OPERABILITY requirements in MODES 4 and 5 .

ACTIONS The ACTIONS Table is modified by a Note indicating that separate Condition entry is allowed for each DGCW subsystem .

This is acceptable, since the Required Actions for the Condition provide appropriate compensatory actions for each inoperable DGCW subsystem . Complying with the Required Actions for one inoperable DGCW subsystem may allow for continued operation, and subsequent inoperable DGCW subsystem(s) are governed by separate Condition entry and application of associated Required Actions .

Condition A is modified by two Notes indicating that this Condition is not applicable during replacement of CSCS isolation valves during the specified unit outages while the outage unit is in MODE 4, 5, or defueled . When the specified DGCW subsystem(s) are inoperable during the CSCS isolation valve maintenance, Condition B provides appropriate Required Actions .

(continued)

LaSalle 1 and 2 B 3 .7 .2-3 Revision x

DGCW System B 3 .7 .2 BASES ACTIONS A .1 (continued)

If one or more DGCW subsystems are inoperable, the associated DG(s) and ECCS components supported by the affected DGCW loop, including LPCS pump motor cooling coils or ECCS cubicle area cooling coils, as applicable, cannot perform their intended function and must be immediately declared inoperable . In accordance with LCO 3 .0 .6, this also requires entering into the Applicable Conditions and Required Actions for LCO 3 .4 .9, "RHR Shutdown Cooling System

-Hot Shutdown," LCO 3 .5 .1, "ECCS-Operating," LCO 3 .5 .3, "RCIC System," LCO 3 .6 .2 .3, "RHR Suppression Pool Cooling,"

LCO 3 .6 .2 .4, "RHR Suppression Pool Spray," LCO 3 .6 .3 .1, "Primary Containment Hydrogen Recombiners," and LCO 3 .8 .1, "AC Sources- Operating," as appropriate .

Condition B is modified by two Notes indicating that this Condition is only applicable during replacement of CSCS isolation valves during the specified unit outages while the outage unit is in MODE 4, 5, or defueled .

If one or more DGCW subsystems are inoperable, the associated DG(s) and ECCS components supported by the affected DGCW loop, including LPCS pump motor cooling coils or ECCS cubicle area cooling coils, as applicable, cannot perform their intended function and must be restored to OPERABLE status within 6 days during replacement of Division 2 CSCS isolation valves or within 10 days during replacement of the Division 1 CSCS isolation valves . Overall ESF system reliability is reduced in this Condition because a single failure in one of the remaining OPERABLE subsystems concurrent with a design basis LOCH may result in the DGCW system not being able to perform its intended safety function . These Completion Times are based upon a risk-informed assessment that concluded that the associated risk with the unit in the specified configuration is acceptable (Ref . 4) .

C .1 and C .2 If the Required Action and associated Completion Time of Condition B is not 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 <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and (continued)

LaSalle 1 and 2 B 3 .7 .2-4 Revision x

DGCW System B 3 .7 .2 BASES ACTIONS C .1 and C .2 (continued) in MODE 4 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> . The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems .

SURVEILLANCE SR 3 .7 .2 .1 REQUIREMENTS Verifying the correct alignment for manual, power operated, and automatic valves in each DGCW subsystem flow path provides assurance that the proper flow paths will exist for DGCW subsystem 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, and yet be considered in the correct position provided it can be automatically realigned to its accident position, within the required time . 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 .

SR 3 .7 .2 .2 This SR ensures that each DGCW subsystem pump will automatically start to provide required cooling to the associated DG, LPCS pump motor cooling coils, and ECCS cubicle area cooling coils, as applicable, when the associated DG starts and the respective bus is energized .

For the Division 1 DGCW subsystem, this SR also ensures the DGCW pump automatically starts on receipt of a start signal for the unit LPCS pump . These starts may be performed using actual or simulated initiation signals .

Operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency, which is based at the refueling cycle . Therefore, this Frequency is concluded to be acceptable from a reliability standpoint .

(continued)

LaSalle 1 and 2 B 3 .7 .2-5 Revision x

DGCW System B 3 .7 .2 BASES (continued)

REFERENCES 1 . UFSAR, Section 9 .2 .1 .

2. UFSAR, Chapter 6 .

3. UFSAR, Chapter 15 .

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

Temporary Extension of Technical Specification Completion Times", December 02, 2004 .

LaSalle 1 and 2 B 3 .7 .2-6 Revision x

AC Sources-Operating B 3 .8 .1 BASES ACTIONS B .4 (continued)

The "AND" connector between the 14 day and 17 day Completion Times means that both Completion Times apply simultaneously, and the more restrictive Completion Time must be met .

Similar to Required Action B .2, the Completion Time of Required Action B .4 allows for an exception to the normal "time zero" for beginning the allowed outage time "clock ."

This exception results in establishing the "time zero" at the time the LCO was initially not met, instead of the time Condition B was entered .

Condition C Condition C is modified by two Notes indicating that this Condition is not applicable during replacement of Division 2 CSCS isolation valves during the specified unit outages while the outage unit is in MODE 4, 5, or defueled . When the Division 2 DGs are inoperable during the CSCS isolation valve maintenance, Condition G provides appropriate Required Actions .

To ensure a highly reliable power source remains, it is necessary to verify the availability of the remaining required offsite circuit on a more frequent basis . Since the Required Action only specifies "perform," a failure of SR 3 .8 .1 .1 acceptance criteria does not result in a Required Action being not met . However, if a circuit fails to pass SR 3 .8 .1 .1, it is inoperable . Upon offsite circuit inoperability, additional Conditions must then be entered .

C .2 Required Action C .2 is intended to provide assurance that a loss of offsite power, during the period that the DG(s) is inoperable as described in Condition C, does not result in a complete loss of safety function of critical systems . These features are designed with redundant safety related divisions (i .e ., single division systems are not included, although, for this Required Action, Division 3 (HPCS System) is considered redundant to Division 1 and 2 ECCS) .

(continued)

LaSalle 1 and 2 B 3 .8 .1-13 Revision x

AC Sources-Operating B 3 .8 . 1 BASES ACTIONS Fol (continued) required offsite circuits) . This difference in reliability is offset by the susceptibility of this power system configuration to a single bus or switching failure . The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Completion Time takes into account the capacity and capability of the remaining AC sources, reasonable time for repairs, and low probability of a DBA occurring during this period .

Condition F is modified by two Notes indicating that this Condition is not applicable during replacement of Division 2 CSCS isolation valves during the specified unit outages while the outage unit is in MODE 4, 5, or defueled . When the Division 2 DGs are inoperable during the CSCS isolation valve maintenance, Condition G provides appropriate Required Actions .

With two required unit DGs inoperable or both required Division 2 DGs inoperable, there is no more than two remaining standby AC sources . Thus, with an assumed loss of offsite electrical power, sufficient standby AC sources may not be available to power the minimum required ESF functions . Since the offsite electrical power system is the only source of AC power for the majority of ESF equipment at this level of degradation, the risk associated with continued operation for a very short time could be less than that associated with an immediate controlled shutdown (the immediate shutdown could cause grid instability, which could result in a total loss of AC power) . Since any inadvertent generator trip could also result in a total loss of offsite AC power, however, the time allowed for continued operation is severely restricted . The intent here is to avoid the risk associated with an immediate controlled shutdown and to minimize the risk associated with this level of degradation .

According to Regulatory Guide 1 .93 (Ref . 6), with Division 1 and 2 unit DGs inoperable, operation may continue for a period that should not exceed 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> . This Completion Time assumes complete loss of onsite (DG) AC capability to power the minimum loads needed to respond to analyzed events .

In the event the unit Division 3 DG in conjunction with a unit Division 1 or 2 DG is inoperable, with a unit Division 1 or 2 DG remaining, a significant spectrum of breaks would be capable of being responded to with onsite power . Even (continued)

LaSalle 1 and 2 B 3 .8 .1-19 Revision x

AC Sources-Operating B 3 .8 . 1 BASES ACTIONS F .1 (continued) the worst case event would be mitigated to some extent-an extent greater than a typical two division design in which this condition represents a complete loss of function .

Given the remaining function, a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time is appropriate . At the end of this 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> period, the unit Division 3 system (HPCS System) could be declared inoperable (See Applicability Note 1) and this Condition could be exited with only one remaining required unit DG inoperable .

However, with a unit Division 1 or 2 DG remaining inoperable and the HPCS System declared inoperable, a redundant required feature failure exists, according to Required Action B .3 or C .2 .

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 <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> 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 .

Condition G Condition G is modified by two Notes indicating that this Condition is only applicable during replacement of Division 2 CSCS isolation valves during the specified unit outages while the outage unit is in MODE 4, 5, or defueled .

With both required Division 2 DGs inoperable, there is no more than two remaining OPERABLE standby AC sources . Thus, (continued)

LaSalle 1 and 2 B 3 .8 .1-20 Revision x

AC Sources-Operating B 3 .8 . 1 BASES ACTIONS G .1 (continued) with an assumed loss of offsite electrical power, sufficient standby AC sources may not be available to power the minimum required Division 2 ESF functions . Since the offsite electrical power system is the only source of AC power for the Division 2 ESF equipment at this level of degradation, the risk associated with continued operation during the Division 2 CSCS valve replacement maintenance must be mitigated by the use of mechanical line stops to maintain the availability of the Division 2 CSCS system for the online Unit . The line stops are designed to the same pressure rating and seismic design as the CSCS piping . At least one required Division 2 DG must be restored to OPERABLE status within 6 days of entry into Condition G .

This 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 . 13) .

If at least one Division 2 DG is not maintained available while in this Condition, the assumptions of the risk assessment of Reference 13 are no longer valid and Condition H should be entered immediately .

H .1 and H .2 If the inoperable AC electrical power sources 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 unit must be brought to MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and to MODE 4 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> . 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 .

Condition I 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 .

(continued)

LaSalle 1 and 2 B 3 .8 .1-21 Revision x

AC Sources-Operating B 3 .8 .1 BASES SURVEILLANCE SR 3 .8 .1 .21 (continued)

REQUIREMENTS 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 .

8. 10 CFR 50, Appendix A, GDC 18 .

9. Regulatory Guide 1 .137 .

10 . ANSI C84 .1, 1982 .

11 . ASME, Boiler and Pressure Vessel Code,Section XI .

12 . IEEE Standard 308 .

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

Temporary Extension of Technical Specification Completion Times", December 02, 2004 .

LaSalle 1 and 2 B 3 .8 .1-45 Revision x

ATTACHMENT 5

SUMMARY

OF LASALLE COUNTY STATION PRA 1 .0 LEVEL OF DETAIL 1 .1 Initiating Events 1 .2 System Models 1 .3 Operator Actions 1 .4 Data 1 .5 Common Cause Events 1 .6 Level 2 PRA 2 .0 MAINTENANCE OF PRA 3 .0 COMPREHENSIVE CRITICAL REVIEWS 3.1 LSCS PRA Self-Assessment 3 .2 NEI PRA Peer Review 4 .0 PRA QUALITY

SUMMARY

5 .0 REFERENCES

ATTACHMENT 5

SUMMARY

OF LASALLE COUNTY STATION PRA 1 .0 LEVEL OF DETAIL The quality of the LSCS internal events at-power PRA models (i .e., the LSCS 2003A PRA Model of Record, References 6 and 7) used in performing this risk assessment is manifested by the following :

" Level of detail in PRA

" Maintenance of the PRA

" Comprehensive critical reviews The LSCS PRA modeling is highly detailed, including a wide variety of initiating events, modeled systems, operator actions, and common cause events .

ting Events The LSCS at-power PRA explicitly models a large number of initiating events :

" General transients

" Support system failures

" LOCAs, including ISLOCA and Break Outside Containment

" Internal Flooding events

" Seismic initiators The initiating events explicitly modeled in the LSCS at-power PRA are summarized in Table 1 .

The number of internal initiating events modeled in the LSCS at-power PRA is similar to the majority of U .S. BWR PRAs currently in use. In addition, seismic-initiated accident scenarios (based on the information in References 8 and 9) are included in the LSCS 2003A Model of Record.

1 .2 System Models The LSCS at-power PRA explicitly models a large number of frontline and support systems that are credited in the accident sequence analyses . The LSCS systems explicitly modeled in the LSCS at-power PRA are summarized in Table 2 . The number and level of detail of plant systems modeled in the LSCS at-power PRA is equal to or greater than the majority of U .S.

BWR PRAs currently in use. Where other PRAs may not develop logic for such systems as instrument air, ECCS instrumentation, main steam and condenser or fire protection, the LSCS PRA specifically models these with fault tree logic.

ATTACHMENT 5

SUMMARY

OF LASALLE COUNTY STATION PRA Table I LSCS 2003A PRA INITIATING EVENTS Description Event ID Transients Manual Shutdown QGMS Turbine Try With Bypass %TT Inadvertent MSIV Closure 56TM Loss of Condenser Vacuum %TCC Loss of FeedwaWr 50F Single Unit Loss of Off-Site Power %LOOP Dual Unit Loss of Off-Site Power %DLOOP Inadvertently Open Relief Valve 501 Svecial Initiators Loss of 4 .16 kVAC Bus 241Y %TAC241 Y Lou of 4 .16 kVAC Bus 242Y %TAC242Y Loss of 6 .9 kVAC Bus 252 9&TAC252 Loss of 125 VDC Division 1 Bus %TDCA Loss of 125 VDC Division 2 Bus 5GTDCB Loss of Multiple 125 VDC Buses %TCDAB Loss of Service Water (LOSW) %TSW Loss of RBCCW %RBCCW Loss of TBCCT/ Q&TBCCVW Loss of Instrument Air (LOIA) 501A LOCAs Excessive LOCA 00 FR Large Break LOCA (LLOCA) 56A Medium Break LOCA (MLOCA) 101 Small Break LOCA (SLOCA) %S2 Interfacing Systems LOCH (ISLOCA) 941SLOCA Break Outside Containment %BOC Internal Floods SW Line Break in Location 3E (RB) %TS1 SW Line Break in Location 3G.1 (RB) 1%FS2 SW Pipe Rupture (TB) %TBFS1 SW Component Rupture (TB) %TBFS2 CA/ Pipe Rupture (TB)  !&TBFS3 CA/ Component Rupture (TB) 9?TBFS4 Unit 2 120-Inch Deicing Line Ruptures (TB)  !?TBFS5 Unit 1 120-Inch Deicing Line Ruptures (TB) 9?TBFS6 3 of 12

ATTACHMENT 5

SUMMARY

OF LASALLE COUNTY STATION PRA Table 1 LSCS 2003A PRA INITIATING EVENTS Description Event ID SW Return Line Ruptures (TB) %TBFS7 CW Manways and SW Attached Pipe Ruptures (36-Inch Dia) Q0BFS8 SW Attached Pipe Ruptures (24-Inch Diameter) %TBFS9 36-Inch Diameter SW Pipe Ruptures and Failure To Isolate VOTBFS10 24-Inch Diameter SW Pipe Ruptures and Failure To Isolate V%TBFS1 1 Seismic Events Low Level 1 Seismic-induced DLOOP %SEIS-LL1 Level 1 Seismic-Induced DLOOP %SEIS-L1 Level 2 Seismic-induced DLOOP %SEIS-L2 Level 3 Seismic-induced DLOOP %SEIS-L3 Level 4 Seismic-induced DLOOP %SEIS-L4 Level 5 Seismic-Induced DLOOP %SEIS-L5 Level 6 Seismic-induced DLOOP %SEIS-L6

ATTACHMENT 5

SUMMARY

OF LASALLE COUNTY STATION PRA Table 2 SYSTEMS MODELED IN LSCS 2003A PRA(')

AC Electric Power (including EDGs)

Alternate Rod Insertion Automatic Depressurization System and SRVs Circulating Water Condensate and Condensate Booster System Control Rod Drive Hydraulics Core Standby Cooling System Cycled Condensate and Condensate Storage and Transfer DC Electric Power ECCS Instrumentation Feedwater System Fire Protection Alternative RPV Injection Heater Drain System High Pressure Core Spray HVAC/Emergency Room Cooling Low Pressure Core Spray Main Steam and Main Condenser Pneumatics/instrument Air Primary Containment Isolation System Primary Containment Venting Reactor Building Closed Cooling Water Reactor Core Isolation Cooling Reactor Protection System Reactor Water Cleanup (isolation function for SLC)

Recirculation Pump Trip Residual Heat Removal Service Water Standby Liquid Control Turbine Building Closed Cooling Water Vapor Suppression Notes:

(1) This table is provided as general information as to the systems modeled in the LSCS PRA. This is not an exhaustive list of the systems modeled in the PRA with fault tree logic. Other systems that are modeled implicitly (e.g., main generator, which is addressed implicitly in the Turbine Trip initiating event frequency) are not summarized in this list.

ATTACHMENT 5

SUMMARY

OF LASALLE COUNTY STATION PRA 1 .3 Operator Actions The LSCS at-power PRA explicitly models a large number of operator actions :

Pre-initiator actions Post-Initiator actions Recovery Actions Over 100 individual operator actions (approximately 30 pre-initiator HEPs and approximately 90 post-initiator and recovery actions) are explicitly modeled . In addition, the LSCS PRA models approximately 50 dependent operator action combinations (e .g ., probability that operator fails to initiate SPC AND fails to initiate emergency containment venting) . Given the large number of actions modeled in the LSCS at-power internal events PRA, a summary table of the individual actions modeled is not provided here .

The human error probabilities for the actions are modeled with accepted industry HRA techniques and include input based on discussion with cognizant personnel (EOP coordinator, operators and trainers). The following HRA methods are employed in the LSCS 2003A PRA:

EPRI Cause-Based Post-Initiator HRA (Reference 10)

NRC ASEP Time Reliability Correlation Pre-Initiator and Post-Initiator HRA (Reference 11)

Technique for Human Error Rate Prediction (THERP) for manipulation/execution error contributions (Reference 12)

The number of operator actions modeled in the LSCS at-power PRA, and the level of detail of the HRA, is equal to or greater than many U .S. BWR PRAs currently in use .

1 .4 Data Initiating Event Frequencies The frequency of each initiating event category is assessed using both LSCS specific and generic a

data . LSCS plant experience is used in Bayesian update statistical analysis with generic data to produce the transient initiating event frequencies for use in the PRA. This is a standard and expected industry technique.

Component Failure Rates (Generic)

The LSCS 2003A PRA uses a defined priority for use of generic industry data for component failure rates. The primary preferred source of generic failure rates is the EPRI ALWR database .

(Reference 5) Secondary sources include NUREG-1 150 and IEEE-500 Std ., among others .

Component Failure Rates (Plant Specific)

The LSCS 2003A PRA plant specific component data analysis is a Bayesian update statistical analysis of selected important equipment with an extensive set of plant specific data (obtained from the LSCS Maintenance Program and other plant sources) .

ATTACHMENT 5

SUMMARY

OF LASALLE COUNTY STATION PRA Table 3 contains a list of the component types and failure modes modeled with plant-specific data in the LSCS 2003A PRA.

Maintenance and Testing Unavailability The unavailability of components due to on-line maintenance and testing activities is estimated using either LSCS specific or generic industry data . The components in the LSCS 2003A modeled with plant-specific unavailability estimates are summarized in Table 3 . Plant-specific unavailability data is primarily obtained from the LSCS Maintenance Rule Program.

1 .5 Common Cause Events Dependent failures (i.e., common cause failures not due to support system failures) are also treated in the LSCS PRA model . Common cause failures (CCF) are evaluated for like components within a system . This includes similar components within different trains of the same system . Similar components in different systems, in general, are not modeled with common mode failures . Notable exceptions to this are common mode failures of:

HPCS and LPCS pumps HPCS EDG and other EDGs Plant SW and CSCS strainers The LSCS at-power PRA explicitly models a large number of common cause component failures . The number and level of detail of common cause component failures modeled in the LSCS at-power PRA is equal to or greater than the majority of U.S . BWR PRAs currently in use.

The common cause failure probabilities in the LSCS 2003A PRA are calculated using the Multiple Greek Letter (MGL) model . The MGL parameters used in calculating the LSCS CCF probabilities are taken from the INEEL CCF database documented in NUREG/CR-5497.

(Reference 4) In addition, LSCS specific MGL parameters are calculated for the following dominant CCF events in the PRA:

EDGs Fail to Start EDGs Fail to Run CSCS Pumps Fail to Start CSCS Pumps Fail to Run CSCS Strainers Fail to Allow Flow RHR MOVs Fail to Close

ATTACHMENT 5

SUMMARY

OF LASALLE COUNTY STATION PRA Table 3 LSCS 2003A PLANT-SPECIFIC COMPONENT FAILURE MODES COMPONENT FAILURE MODES Diesel Generator FTS, FTR, OOS Unavailability HPCS Pumps FTS, FTR, OOS Unavailability LPCS Pumps FTS, FTR, OOS Unavailability RCIC Pumps FTS, FTR, OOS Unavailability RHR Pumps FTS, FTR, OOS Unavailability RHR Service Water Pumps FTS, FTR, OOS Unavailability Condensate Pumps FTS, FTR, OOS Unavailability SBLC Pumps FTS, FTR, OOS Unavailability TBCCW Pumps FTS, FTR, OOS Unavailability SW Pumps FTS, FTR, OOS Unavailability RBCCW Pumps FTS, FTR, OOS Unavailability CRD Pumps FTS, FTR, OOS Unavailability MDFVV Pump FTS, FTR, COS Unavailability TDFW Pumps FTR, OOS Unavailability DGCW Pumps FTS, FTR, OOS Unavailability Diesel Fire Pumps FTS, FTR, OOS Unavailability Heater Drain Pumps FTS, FTR, COS Unavailability Cycled Condensate Pumps FTS, FTR, OOS Unavailability Circulating Water Pumps FTR, OOS Unavailability Service Air Compressors FTS, FTR, OOS Unavailability Service Air Doers FTF EDG Output Circuit Breakers FTO, FTC 4/6 .9KV Circuit Breakers FTO, FTC, OOS Unavailability 480V Circuit Breakers FTO, FTC, OOS Unavailability Battery Chargers FTF, OOS Unavailability hAOVS FTO, FTC, OOS Unavailability Notes to Table 3:

FTS = Fails to Start FTR = Fails to Run FTO = Fails to Open FTC = Fails to Close FTF = Fails to Function OOS = Out of Service

ATTACHMENT 5

SUMMARY

OF LASALLE COUNTY STATION PRA 1 .6 Level 2 PRA The LSCS Level 2 PRA is a LERF (large, early release frequency) model . The LSCS Level 2/LERF PRA is a realistic, plant-specific model that incorporates the following features :

LERF Containment Event Trees (CETs) designed for three types of core damage scenarios :

Containment intact at time of core damage Containment failed at time of core damage Containment bypass scenarios

• LERF CETs address:

Containment isolation In-vessel and Ex-Vessel core damage progression Energetic phenomena Emergency procedures (e .g., containment flooding)

Containment failure location 0 Level 1 PRA accident sequence logic and system logic linked directly into the LERF CETs 0 Containment isolation failure fault tree based on plant-specific analysis 0 Containment ultimate capability based on plant-specific analyses 0 Accident progression timings and radionuclide release characteristics based on plant-specific thermal hydraulic analyses using the MAAP code 2.0 MAINTENANCE OF PRA The LSCS PRA model and documentation has been maintained as a living program, and the PRA is routinely updated approximately every 3 years to reflect the current plant configuration and to reflect the accumulation of additional plant operating history and component failure data.

The Level 1 and Level 2 LSCS PRA analyses were originally developed and submitted to the NRC in 1994 as the Individual Plant Examination (IPE) Submittal . (Reference 1) The LSCS PRA has been updated many times since the original IPE. A summary of the LSCS PRA history is as follows:

Original IPE (1994)

Updated IPE (1996) 1999 Upgrade 2000A Model 2000B Model 2000C Model 2001A Model 2003A Model (current Model of Record) 9 of 12

ATTACHMENT 5

SUMMARY

OF LASALLE COUNTY STATION PRA An administratively controlled process is used to maintain configuration control of the LSCS County Station PRA models, data, and software. In addition to model control, administrative mechanisms are in place to assure that plant modifications, procedure changes, calculations, operator training, and system operation changes are appropriately screened, dispositioned, and scheduled for incorporation into the model in a timely manner. These processes help assure that the LSCS County Station PRA reflects the as-built, as-operated plant within the limitations of the PRA methodology and as resources allow the level of modeling detail .

This process involves a periodic review and update cycle to model any changes in the plant design or operation. Plant hardware and procedure changes are reviewed on an approximate quarterly basis to determine if they impact the PRA and if a PRA modeling and/or documentation change is warranted . These reviews are documented . If any PRA changes are warranted they are added to the PRA Update Requirements Evaluation (URE) database for PRA implementation tracking .

The LSCS URE database was reviewed in support of this CT risk assessment to identify the impact on this analysis from any open (i .e ., not yet officially resolved and incorporated into the PRA) UREs . The open UREs contain identified PRA changes to address plant modifications (as discussed above) as well as changes to correct errors or to enhance the model . This review determined that the open LSCS PRA UREs have a non significant (i .e., from a slight decrease in the CT ICCDP to a 1% increase in ICCDP) impact on the results and conclusions.

3.0 COMPREHENSIVE CRITICAL REVIEWS The LSCS PRA model has benefited from the following comprehensive technical reviews:

" LSCS PRA Self-Assessment

" NEI PRA Peer Review 3.1 LSCS PRA Self-Assessment A self-assessment of the LSCS PRA against the ASME PRA Standard was performed by EGC in 2003 using guidance provided in NRC Draft Regulatory Guide DG-1122, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results from Risk-Informed Activities" . (Reference 2) This self-assessment was documented and used as a planning guide for the LSCS 2003A PRA update .

Many of the areas of potential improvement identified in the self-assessment (e.g., document dependent HEPs ; plant-specific MGL parameters for dominant CCF events ; perform updated/additional MAAP runs and update Success Criteria documentation, etc .) have been incorporated into the LSCS 2003A Model of Record. Those areas of potential enhancement from the self-assessment that have yet to be formerly addressed in the PRA were reviewed in support of this CT risk assessment . This review determined that none of these items has a significant impact on this risk assessment . The majority are documentation enhancements and process issues ; of the potential technical enhancements, the impact on the LSCS base PRA and this risk assessment was determined to be non-significant.

3.2 NEI PRA Peer Review The LSCS internal events PRA received a formal industry PRA Peer Review in 2000.

(Reference 3) The purpose of the PRA Peer Review process is to provide a method for establishing the technical quality of a PRA for the spectrum of potential risk-informed plant 1 0 of 12

ATTACHMENT 5

SUMMARY

OF LASALLE COUNTY STATION PRA licensing applications for which the PRA may be used . The PRA Peer Review process uses a team composed of industry PRA and system analysts, each with significant expertise in both PRA development and PRA applications . This team provides both an objective review of the PRA technical elements and a subjective assessment, based on their PRA experience, regarding the acceptability of the PRA elements . The team uses a set of checklists as a framework within which to evaluate the scope, comprehensiveness, completeness, and fidelity of the PRA products available .

The LSCS review team used the March 2000 NEI draft "Probabilistic Risk Assessment (PRA)

Peer Review Process Guidance" as the basis for the review .

The general scope of the implementation of the PRA Peer Review includes review of eleven main technical elements, using checklist tables (to cover the elements and sub-elements), for an at-power PRA including internal events, internal flooding, and containment performance, with focus on large early release frequency (LERF) .

The comments from the PRA Peer Review were prioritized into four categories (A through D) based upon importance to the completeness of the model . All comments in Categories A and B (recommended actions and items for consideration) were identified to LSCS as priority items to be resolved in the next model update . The comments in Categories C and D (good practices and editorial) are potential enhancements for consideration in future updates of the Level 1 and 2 PRA models.

All of the A and B priority comments from the 2000 Peer Review with a potential impact on this risk assessment have been reconciled and addressed in the PRA models and documentation as appropriate. All but two of the A and B priority F&Os have been resolved and addressed in the PRA as appropriate . The two open items involve documentation clean-up issues and do not impact the results or conclusions of this risk assessment .

4 .0 PRA QUALITY

SUMMARY

The quality of modeling and documentation of the LSCS PRA models has been demonstrated by the foregoing discussions on the following aspects:

Level of detail in PRA Maintenance of the PRA Comprehensive critical reviews The LSCS Level 1 and Level 2 PRAs provide the necessary and sufficient scope and level of detail to allow the calculation of CDF and LERF changes due to the proposed CT configuration.

In addition, the LSCS PRA has been used in support of various regulatory programs and relief requests that have received NRC SERs, further indication of the quality of the LSCS PRA and suitability for regulatory applications . This list includes :

LSCS IPE SER LSCS IPEEE SER EIDG AOT Extension SER RI-ISI (Risk Informed Inservice Inspection) SER ILRT Frequency Extension SER 1 1 of 12

ATTACHMENT 5

SUMMARY

OF LASALLE COUNTY STATION PRA

5.0 REFERENCES

1 . Letter from Nil Vonk to NRC, "LaSalle County Nuclear Power Station Individual Plant Examination and Individual Plant Examination (External Events) Submittal," dated April 29,1994

2. Draft Regulatory Guide DG-1122, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities" 3 . LSCS PRA Peer Review Certification Report, GE Document BWROG/PRA-2000-01, dated July 2000 4 . NUREG/CR-5497, "Common Cause Failure Parameter Estimations," October 1998 5 . EPRI TR-01 6780, "Advanced Light Water Reactor Requirements Document,"

Revision 6, 1997 6 . Exelon RM Documentation "2003A LaSalle County Generating Station Analyst No . 1189, Probabilistic Risk (PRA) Core Damage Frequency (CDF) Model," Revision 1, approved May 12, 2004

7. Exelon RM Documentation No . 1190, "2003A LaSalle County Generating Station Probabilistic Risk Analysis (PRA) Level 2/LERF Model," Revision 0, approved September 4, 2003

8. NUREG/CR-4832, 'Analysis of the LaSalle Unit 2 Nuclear Power Plant: Risk Methods Integration and Evaluation Program (RMIEP)," 10 volumes, 1992-1993

9. NUREG/CR-5305, "Integrated Risk Assessment of the LaSalle Unit 2 Nuclear Power Plant: Phenomenology and Risk Uncertainty Evaluation Program", 3 volumes, 1992-1993 10 . EPRI TR-1 00259, "An Approach to the Analysis of Operator Actions in Probabilistic Risk Assessment," June 1992 11 . NUREG/CR-4772, "Accident Sequence Evaluation Program Human Reliability Analysis Procedure," February 1987 12 . NUREG/CR-1278, "Handbook of Human Reliability Analysis with Emphasis on Nuclear Power Plant Applications," August 1983