Text

License Amendment Request Activation of the Trip Outputs of the Oscillation Power Range Monitor System
	ML041350313
Person / Time
Site:	LaSalle
Issue date:	04/30/2004
From:	Jury K; Exelon Generation Co, Exelon Nuclear
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	RS-04-069
	Download: ML041350313 (66)
	v • d • e

Exelknam Exelon Generation www.exeloncorp.com Nuclear 4300 Winfield Road Warrenville, IL 60555 10 CFR 50.90 RS-04-069 April 30, 2004 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:

License Amendment Request Activation of the Trip Outputs of the Oscillation Power Range Monitor System

Reference:

Letter from Keith R. Jury (Exelon Generation Company, LLC) to U. S. NRC,

'Schedule for Completing Actions to Implement Long-Term Stability Solution,"

dated December 19, 2003 In accordance with 10 CFR 50.90, 'Application for amendment of license or construction permit," Exelon Generation Company, LLC (EGC), requests a change to the Technical Specifications (TS), Appendix A, of Facility Operating License Nos. NPF-1 1 and NPF-18 for LaSalle County Station (LCS), Units 1 and 2.

The proposed changes incorporate into the TS the Oscillation Power Range Monitor (OPRM) instrumentation that will be declared operational in accordance with the schedule provided in the referenced letter. The proposed changes revise Sections 3.3.1.3, 'Oscillation Power Range Monitor (OPRM) Instrumentation," 3.4.1, 'Recirculation Loops Operating," and 5.6.5, 'Core Operating Limits Report (COLR)," to insert a new TS section for the OPRM instrumentation, delete the current thermal hydraulic instability administrative requirements, and add the appropriate references for the OPRM trip setpoints and methodology. Following NRC approval of the proposed TS changes, LCS will activate the reactor scram outputs of the OPRM instrumentation.

The referenced letter stated that EGC would provide the enclosed license amendment request by March 31, 2004. In a telephone conversation between Mr. A. R. Haeger of EGC and Mr. W.

A. Macon, Jr. of the NRC, it was agreed that EGC would submit the license amendment request by April 30, 2004.

The attached information supporting the proposed changes is subdivided as follows.

1 Attachment 1 gives a description and safety analysis of the proposed changes.

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

3. Attachment 3 provides re-typed versions of the TS pages with the proposed changes included.

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U. S. Nuclear Regulatory Commission April 30, 2004 Page 2

4. Attachment 4 includes the marked-up TS Bases pages. The TS Bases pages are provided for information only and do not require NRC approval.

EGC has concluded that the proposed changes present no significant hazards consideration under the standards set forth in 10 CFR 50.92(c), Issuance of amendment," paragraph (c).

EGC requests approval of the proposed changes by March 31, 2005, but no earlier than completion of the next refueling outage for LCS, Unit 2, which is currently scheduled to complete in late February 2005. Once approved, the changes shall be implemented within 60 days for both Units I and 2.

The proposed changes have been reviewed by the Plant Operations Review Committee and approved by the Nuclear Safety Review Board.

If you have any questions, please contact Mr. Allan Haeger at (630) 657-2807.

I declare under penalty of perjury that the foregoing is true and correct. Executed on the,30h day of April 2004.

Respectfully, Keith R. Jury Director, Licensing and Regulatory Affairs Exelon Generation Company, LLC Attachments:

1. Evaluation of the Proposed Changes

2. Marked-up Technical Specifications Pages for Proposed Changes

3. Revised Technical Specifications Pages for Proposed Changes

4. Marked-up Technical Specifications Bases Pages for Proposed Changes cc: NRC Regional Administrator - Region IlIl Senior Resident Inspector - LaSalle County Station Illinois Emergency Management Agency - Division of Nuclear Safety

Attachment I EVALUATION OF PROPOSED CHANGES

1.0 DESCRIPTION

2.0 PROPOSED CHANGE

S

3.0 BACKGROUND

4.0 TECHNICAL ANALYSIS

5.0 REGULATORY ANALYSIS

5.1 No Significant Hazards Consideration 5.2 Applicable Regulatory Requirements/Criteria

6.0 ENVIRONMENTAL CONSIDERATION

7.0 REFERENCES

Page 1 of 16

Attachment I 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 a change to the Technical Specifications (TS), Appendix A, of Facility Operating License Nos. NPF-1 1 and NPF-1 8 for LaSalle County Station (LCS), Units 1 and 2.

The proposed changes incorporate into the TS the Oscillation Power Range Monitor (OPRM) instrumentation that will be declared operational in accordance with the schedule provided in Reference 1. The proposed changes revise Sections 3.3.1.3, 'Oscillation Power Range Monitor (OPRM) Instrumentation," 3.4.1, " Recirculation Loops Operating," and 5.6.5, "Core Operating Limits Report (COLR)," to insert a new TS section for the OPRM instrumentation, delete current the thermal hydraulic instability administrative requirements, and add the appropriate references for the OPRM trip setpoints and methodology. Following NRC approval of the proposed TS changes, LCS will activate the reactor scram outputs of the OPRM instrumentation.

EGC requests approval of the proposed changes by March 31, 2005, but no earlier than completion of the next refueling outage for LCS, Unit 2, which is currently scheduled to complete in late February 2005. Once approved, the changes shall be implemented within 60 days for both Units 1 and 2.

2.0 PROPOSED CHANGE

S As described in Section 1.0, following NRC approval of the proposed TS changes, LCS will activate the reactor scram outputs of the OPRM instrumentation. The proposed changes incorporate the following TS changes.

A. Section 3.3.1.3, "Oscillation Power Range Monitor (OPRM) Instrumentation" This change adds a TS section that requires the OPRM instrumentation to be operable.

The required minimum number of operable OPRM channels will be four channels. The OPRM instrumentation will be required to be operable when Reactor Power is 2 25% Rated Thermal Power (RTP).

A note is placed in the Actions section that states, "Separate Condition entry is allowed for each channel."

An additional note is placed in the Actions section that states, "When OPRM channels are inoperable due to APRM indication not within limits in accordance with Specification 3.3.1.1, entry into associated Conditions and Required Actions may be delayed for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months if the APRM is indicating a lower power value than the calculated power, and for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months if the APRM is indicating a higher power value than the calculated power."

Limiting Condition for Operation (LCO) Condition A and associated Required Actions and Completion Times require that, with one or more channels inoperable, the inoperable channels Page 2 of 16

Attachment I EVALUATION OF PROPOSED CHANGES or the associated trip system be placed in trip or that alternate methods to detect and suppress thermal hydraulic instabilities be implemented within 30 days LCO Condition B and associated Required Actions and Completion Times require that, with OPRM trip capability not maintained, initiate alternate methods of detecting and suppressing thermal hydraulic instabilities within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and restore the OPRM trip capability within 120 days.

Condition C applies if the Completion Times for Required Actions are not met. The Required Action allows 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months to reduce reactor power to less than 25 percent.

The proposed SRs are as follows.

SR 3.3.1.3.1 Channel Functional Test. The OPRM instrumentation will have a Channel Functional Test requirement with a frequency of every 184 days (6 months).

SR 3.3.1.3.2 The OPRM instrumentation will have a Channel Calibration every 24 months. A clarifying statement is added to note that the setpoints for the trip function are specified in the COLR. Neutron detectors are excluded from the Channel Calibration via a note.

SR 3.3.1.3.3 The OPRM instrumentation will have a Logic System Functional Test every 24 months.

SR 3.3.1.3.4 This SR verifies that the OPRM system is not bypassed when thermal power > 28.6% rated thermal power and recirculation drive flow < 60% of rated recirculation drive flow. The required frequency is every 24 months.

SR 3.3.1.3.5 The reactor protection system response time will be verified within limits every 24 months on a staggered test basis. Neutron detectors are excluded from the response time testing via a note.

A note is placed before the SRs that states, 'When a channel is placed in a inoperable status solely for the performance of required Surveillances, entry into the associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months provided the OPRM maintains reactor protection system (RPS) trip capability.'

The proposed addition of Section 3.3.1.3 is consistent with the NRC-approved proposed changes for the Asea Brown Boveri (ABB) Combustion Engineering'OPRM system installation as described in Reference 2, with the following exceptions. The basis for these exceptions is discussed in Section 4.0 below.

The Actions note regarding Average Power Range Monitor (APRM) indication is not part of the Reference 2 TS changes.

The note placed before the SRs regarding delayed entry into the associated Conditions and Required Actions is not part of the Reference 2 TS changes.

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Attachment I EVALUATION OF PROPOSED CHANGES

The TS changes in Reference 2 include an SR that requires calibration of the Local Power Range Monitors (LPRMs) every 1000 megawatt days per metric ton uranium (MWD/MTU). The proposed changes in this amendment request do not include this requirement, since it is similar to another SR (i.e., SR 3.3.1.1.8) currently in LCS TS.

The surveillance frequency is updated to include plant-specific information.

A clarifying statement has been added to SR 3.3.1.3.2 to state that the setpoints for the trip function are specified in the Core Operating Limits Report (COLR).

B. Section 3.4.1, "Recirculation Loops Operating" Figure 3.4.1-1, "Power versus Flow," and associated references to the figure from the LCO, Actions, and SRs are deleted.

C. Section 6.6.5, "Core Operating Limits Report (COLR)"

Section 5.6.5.a will have a requirement added to include the setpoints for the OPRM trip function in the COLR.

Section 5.6.5.b will have a reference added to describe the NRC-approved methodology for determining the setpoints for the OPRM trip function. This reference is NEDO-32465-A, UBWR Owners' Group Reactor Stability Detect and Suppress Solutions Licensing Basis Methodology and Reload Applications," August 1996 (Reference 3).

3.0 BACKGROUND

The NRC issued Generic Letter (GL) 94-02, 'Long-Term Solutions and Upgrade of Interim Operating Recommendations for Thermal Hydraulic Instabilities in Boiling Water Reactors,"

which required licensees to develop and submit to the NRC a plan for long-term stability corrective actions. In response to GL 94-02, in Reference 4, EGC committed to implement the long-term solution designated as Option IlIl in NEDO-31960-A (including Supplement 1), "BWR Owner's Group Long-Term Stability Solutions Licensing Methodology," (Reference 5) by installing the ABB Combustion Engineering Option IlIl OPRM system. GL 94-02 also discussed the use of interim corrective actions (ICAs) to provide operator controlled actions to avoid regions of potential instability and insert a manual reactor scram if oscillations are detected.

The ABB system utilizes the OPRM detect-and-suppress function to implement Option Ill. The system monitors LPRM signals for indications of neutron flux oscillations. The OPRM also monitors indicated power and indicated recirculation flow to automatically enable the OPRM trip when in a predefined region of the power-to-flow map. The OPRM initiates a trip whenever it detects an instability condition when in the predefined region of the power-to-flow map.

The OPRM instrumentation modules, annunciators, and sequence of events recorder points were installed at LCS from 1999 to 2000. The OPRM trip functions were not activated at the time of installation in order to allow evaluation of the performance of the OPRM algorithms without the risk of spurious scrams. During this evaluation period, in 2001, General Electric (GE) Company initiated a report in accordance with 10 CFR 21, "Reporting of defects and Page 4 of 16

Attachment I EVALUATION OF PROPOSED CHANGES noncompliances," concerning stability reload licensing calculations that support the development of setpoints for the OPRM trip function. The OPRM trip functions were not armed pending resolution of this reported condition. The reported condition has now been resolved as described in Reference 6. In the interim, EGC has continued to implement the ICAs to detect and suppress power oscillations.

4.0 TECHNICAL ANALYSIS

The OPRM instrumentation installation at LCS follows the industry approach for implementation/activation of the OPRM trip function in accordance with NRC approved Licensing Topical Reports. In addition, EGC has incorporated relevant industry operating experience into the system settings, as appropriate.

A. Technical Basis for Proposed Addition of TS Section 3.3.1.3 The OPRM Instrumentation System consists of four OPRM instrumentation trip channels. Each trip channel consists of two OPRM instrumentation modules, either of which can initiate the trip signal for that channel. Each OPRM instrumentation module receives input from 21 or 22 LPRMs. Each OPRM instrumentation module also receives input from the other OPRM instrumentation module in the trip channel, as well as from RPS Average Power Range Monitor (APRM) power and flow signals to automatically enable the trip function of the OPRM instrumentation module.

The OPRM system uses three separate algorithms for detecting thermal hydraulic stability related oscillations: the period based detection algorithm (PBDA), the amplitude based algorithm, and the growth rate algorithm. The OPRM system hardware implements these algorithms in microprocessor-based modules. These modules execute the algorithms based on LPRM inputs and generate alarms and trips based on these calculations. These trips result in tripping the RPS when the appropriate trip logic (one out of two, taken twice) is satisfied. As discussed in Reference 3, only the PBDA is used in the safety analysis. The remaining algorithms provide defense in depth and additional protection against unanticipated oscillations.

The PBDA detects a stability related oscillation based on the occurrence of a fixed number of consecutive LPRM signal period confirmations concurrent with the LPRM signal amplitude exceeding a specified peak to average setpoint. Upon detection of a stability related oscillation, a trip is generated in the module associated with that OPRM instrumentation channel.

Each OPRM instrumentation module is continuously tested by a self-test function. On detection of an OPRM instrumentation module self-test failure, either a 'Trouble" or 'INOP" alarm is activated. The two alarms are displayed on a single control room annunciator and can be distinguished via the status lights on the OPRM modules or the OPRM relay panels. The

'Trouble" alarm indicates that a condition is present that reduces the robustness of the system but does not cause the OPRM channel to fail to meet its functional requirements. The OPRM instrumentation module provides an "INOP" alarm when the self-test feature indicates that the OPRM instrumentation module may not be capable of meeting its functional requirements.

When one OPRM instrumentation module is inoperable, the remaining redundant OPRM instrumentation module in the associated OPRM trip channel maintains the operability of the trip channel; thus, there is no loss of trip function redundancy and no TS actions are required. If both OPRM instrumentation modules in an OPRM channel are inoperable, the associated Page 5 of 16

Attachment I EVALUATION OF PROPOSED CHANGES OPRM instrumentation channel is inoperable, and the proposed TS actions are entered, consistent with the approved TS in Reference 2.

The detailed TS requirements for the OPRM system, including the LCO, Applicability, Conditions, Required Actions, and Completion Times, are consistent with the TS approved by the NRC in Reference 2, with the exceptions described in Section 2.0. The basis for these exceptions follows.

Note 2 has been added to the Actions section. This note allows delayed entry into the Conditions and Required Actions when OPRM channels are inoperable due to APRM indication not within limits in accordance with SR 3.3.1.1.2. Note 2 allows entry into associated Conditions and Required Actions to be delayed for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months if the APRM is indicating a lower power value (i.e., the gain adjustment factor (GAF) is high (nonconservative)), and for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months if the APRM is indicating a higher power value than the calculated power (i.e., the GAF is low (conservative)). The GAF for any APRM is defined as the power value determined by the heat balance divided by the APRM reading for that channel. Upon completion of the gain adjustment, or expiration of the allowed time, the OPRM channel must be returned to OPERABLE status or the applicable Condition entered and the Required Actions taken. This Note is consistent with the ACTIONS Note in Specification 3.3.1.1 and is based on the time required to perform gain adjustments on multiple APRM channels; additional time is allowed when the GAF is out of limits but conservative. This note is applicable to the OPRM instrumentation, since the APRM system provides input to enable the OPRM modules at the designated enable setpoint.

The TS changes in Reference 2 include an SR (SR 3.3.1.3.2) that requires calibration of the LPRMs every 1000 MWDIMTU. This value is bracketed in Reference 2, indicating that plant-specific information should be substituted. LCS TS, in SR 3.3.1.1.8, currently require this calibration and specify a frequency of 1000 effective full power hours (EFPH). The TS bases state that the 1000 EFPH frequency is based on operating experience with LPRM sensitivity changes. Since 1 EFPH equals approximately 0.9 MWD/MTU at LCS, the 1000 EFPH calibration frequency in the LCS SR is more frequent, and thus more conservative than the 1000 MWD/MTU calibration frequency specified in Reference 2. Thus, current SR 3.3.1.1.8 meets the intent of the SR for LPRM calibration in Reference 2, and is not required to be duplicated in proposed Section 3.3.1.3. The TS Bases for TS Sections 3.3.1.3 and 3.3.1.1 have been marked up to reflect that the LPRM calibration is required to demonstrate OPRM operability.

Proposed SR 3.3.1.3.2 states that the OPRM instrumentation will have a channel calibration every 24 months. A statement is added to note that the setpoints for the trip function are specified in the COLR. This statement clarifies that the setpoints for the trip function are to be stated in the COLR and provides consistency with the statement added to TS Section 5.6.5.a, which requires that the COLR contain the setpoints for SR 3.3.1.3.2.

SR 3.3.1.3.4 verifies that the OPRM system is not bypassed with reactor power > 28.6%

RTP and recirculation drive flow < 60% of rated recirculation drive flow. These values define the region in which the OPRM system is enabled, and are not protective limits.

Page 6 of 16

Attachment 1 EVALUATION OF PROPOSED CHANGES The 60% value is consistent with the value discussed in Reference 3, Section 2.2, "Licensing Compliance." The 28.6% RTP value is the plant-specific value for the 30%

RTP value, which is bracketed in Reference 2. In Reference 7, LCS requested changes to implement a 5% power uprate. Reference 7, Attachment E, Section 2.4, 'Stability,"

addressed the power uprate changes to both the reactor stability ICAs and OPRM Option Ill. In order to preserve the same level of protection against the occurrence of a thermal-hydraulic instability, the instability exclusion region boundaries were unchanged with respect absolute power level. Reactor core flow did not change with power uprate, so the flow portion of the enabled region remains 60% of rated core flow. In order to maintain the same level of protection, the 30% RTP value was reduced by the ratio of 100%/1 05%, which reduces the power portion of the enabled region to 28.6% RTP. The LCS power uprate amendments were approved and issued in Reference 8.

There are no allowable values in the proposed TS associated with the OPRM trip function. The OPRM PBDA upscale trip setpoints (i.e., the number of confirmation counts and the peak to average signal amplitude required to actuate a trip signal) are determined based on the Option Ill licensing methodology developed by the BWROG and described in Reference 3, which is approved by the NRC. These are treated as nominal setpoints and do not require additional allowances for uncertainty. A note has been added to SR 3.3.1.3.2 to state that the setpoints for the trip function are defined in the COLR.

There are also TS related setpoints for the auto-enable (not-bypassed) region, which are established as described in the TS Bases markup, and defined in SR 3.3.1.3.4. These are also treated as nominal setpoints, based on the conservatism in the establishment of the enable region, as discussed in Reference 9.

The PBDA algorithm includes several 'tuning" parameters. These were initially established as part of the modification process and have been adjusted based upon both plant and industry operating experience. Since these various parameters are considered to be 'tuning" parameters, they are not specifically listed within the TS.

Finally, there are also setpoints for the "defense-in-depth" algorithms discussed in the OPRM upscale function description in the TS Bases markup. These are also treated as nominal setpoints based on qualitative studies performed by the BWROG and documented in Appendix A of Reference 3. These algorithms are not credited in the safety analysis.

In Reference 2, the NRC accepted the use of the ABB OPRM system for licensees to the extent specified and under the limitations delineated in the associated NRC safety evaluation. The NRC requested licensees to address the following plant-specific questions when referencing the Reference 2 report in license applications.

Question 1 "Confirm the applicability of CENPD-400-P, including clarifications and reconciled differences between the specific plant design and the topical report design descriptions."

Response

The OPRM instrumentation design at LCS includes alarm, trip, inoperable/trouble annunciators and is consistent with the topical report design.

Page 7 of 16

Attachment I EVALUATION OF PROPOSED CHANGES Question 2 "Confirm the applicability of BWROG topical reports that address the OPRM and associated instability functions, setpoints and margin."

Response

Reports NEDO-32465-A and NEDO-31960-A were reviewed and determined to be applicable to LCS. In the safety evaluations for NEDO-31960-A and Supplement 1, the NRC found that Options IlIl and Ill-A were acceptable long-term solutions for implementation in any type of BWR, subject to the following five conditions:

2.1 "All three algorithms described in NEDO-31960 and Supplement 1 should be used in Option IlIl or III-A. These three algorithms are high LPRM oscillation amplitude, high-low detection algorithm, and period-based algorithm."

Response

All three algorithms are included in the ABB design. Automatic protection is actuated if any of the three algorithms meet their trip conditions. Only the PBDA, however, is used to demonstrate protection of the MCPR safety limit for anticipated reactor instabilities. The other two algorithms are included as defense-in-depth features.

2.2 "The validity of the scram setpoints selected should be demonstrated by analysis.

These analyses may be performed for a generic representative plant when applicable, but should include an uncertainty treatment that accounts for the number of failed sensors permitted by the Technical Specifications of the plant's applicant."

Response

The applicability of the scram setpoints will be demonstrated by cycle-specific analysis using the methodology described in Reference 3. The PBDA is based upon explicit analysis methodology (Reference 3) that is applied to demonstrate a basis for concluding that the algorithm can be credited in the licensing basis for meeting the requirements of 10 CFR 50, Appendix A, General Design Criterion (GDC) 10, "Reactor design," and GDC 12, 'Suppression of reactor power oscillations." The setpoints are selected to assure that a trip will occur for a reactor instability event.

Analysis of sensor failure in the OPRM system is addressed in Reference 3. The analysis of Reference 3 demonstrated that, for establishing the setpoint, it was more conservative to assume all LPRMs were operable because the sensitivity of the OPRM system increases as the number of LPRM failures increase. Due to the large number of LPRMs and OPRM cells, OPRM system operability is expected to be maintained under all conditions which satisfy operability of a sufficient number of LPRM channels to maintain APRM system operability.

2.3 "Implementation of Option IlIl or Ill-A will require that the selected bypass region outside of which the detect and suppress action is deactivated be defined in the Technical Specifications."

Response

This region is included in proposed SR 3.3.1.3.4. The bases for the values defining this region are provided above in the discussion related to SR 3.3.1.3.4.

Page 8 of 16

Attachment I EVALUATION OF PROPOSED CHANGES 2.4 If the algorithms detect oscillations, an automatic protective action should be initiated.

This action may be a full scram or an SRI. If an SRI is implemented with Option IlIl or lil-A, a backup full scram must take effect if the oscillations do not disappear in a reasonable period of time or if they reappear before control rod positions and operating conditions have been adjusted in accordance with appropriate procedural requirements to permit reset of the SRI protective action. u

Response

The automatic protective action of the OPRM systems at LCS will be a full reactor scram.

An automatic select rod insert (SRI) is not available at LCS.

2.5 "The LPRM groupings defined in NEDO-31960 to provide input to the Option IlIl or Ill-A algorithms are acceptable for the intended oscillation detection function. These LPRM groupings are the oscillation power range monitor for Option IlIl or the octant-based arrangements for Option Ill-A. The requirements for a minimum OPERABLE number of LPRM detectors set forth in NEDO-31960 are acceptable."

Response

As described in Reference 5 and Reference 3, the "Four LPRMs per OPRM Cell - 4BL" configuration is used at LCS. The 4BL arrangement is one of six approved configurations discussed in Reference 3, Appendix D. As described in Reference 5, current TS requirements for the operability of LPRMs (as amplified in the TS Bases) are sufficient to ensure an adequate number of operable LPRMs to provide input to the OPRM system.

Question 3 "Provide a plant-specific Technical Specification (TS) for the OPRM functions consistent with CENPD-400-P, Appendix A."

Response

The plant specific TS are provided in Attachment 2 and are consistent with Reference 2, Appendix A, except as described in this attachment.

Question 4 "Confirm that the plant-specific environmental (temperature, humidity, radiation, electromagnetic and seismic) conditions are enveloped by the OPRM equipment environmental qualification values."

Response

The OPRM system and components are mounted in main control room cabinets at LCS, which are located in a mild environmental zone. The OPRM components, including the replacement power supply are qualified to perform their Class 1E safety function. For ease of reference, the plant-specific environmental conditions at the OPRM installation location for temperature, humidity, and radiation are compared to the OPRM qualification values in the following table. As shown in the table, the generic OPRM qualification values envelope the LCS temperature and radiation environmental conditions. However, the LCS main control rooms may experience humidity values below the OPRM qualified range. This is discussed in Section 4.2.

Page 9 of 16

Attachment I EVALUATION OF PROPOSED CHANGES Environmental Condition LCS Environmental OPRM Generic Conditions Qualification (continuous operation)

Temperature 50*F to 1040F 400 F to 1200F Humidity 20% to 50% relative 30% to 95% RH humidity (RH) normal Radiation 1000 RAD total integrated <10,000 RAD TID dose (TID)

The following sections discuss the plant-specific temperature, humidity, radiation, electromagnetic and seismic environmental conditions pertaining to the OPRM at LCS.

4.1 Temperature/Heat Loading The temperature qualification of the OPRM module was performed by test. The OPRM module is designed to operate continuously in a normal ambient temperature range of 40 0F to 120 0F. The system is designed to operate continuously in an abnormal ambient temperature environment of 140 0F for 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months . The LCS control room temperature range is 50 0F to 104 0F, which is bounded by the design temperature range of the OPRM.

The normal temperature range for the LCS control rooms is between 65 0F and 85 0F.

The control room heat load has not increased significantly as a result of this modification.

4.2 Humidity The humidity qualification of the OPRM module was performed by test. The OPRM is designed to operate continuously in a humidity environment range of 30% to 95% RH, non-condensing.

The low end of the generic OPRM qualified humidity range is 30% RH. The normal relative humidity range for the LCS control rooms is between 20% and 50% RH.

However, the control room ventilation system is not equipped with humidification equipment, and thus, depending on outside air conditions, the relative humidity may be as low as 2.6% RH on a temporary basis during winter months.

The concern at low humidity conditions is the chance for damage from electrostatic discharge. The OPRM equipment has been tested for electrostatic discharge, as Page 10 of 16

Attachment I EVALUATION OF PROPOSED CHANGES described in Section 4.4 below. Further, the potential for electrostatic discharge is minimized, since the modules are located inside panels in metal enclosures, and are not subject to incidental contact by operations or maintenance personnel. Finally, the OPRM equipment has been installed and operating satisfactorily in the main control room environments at LCS for several years. Thus, the OPRM equipment should continue to operate properly if relative humidity is temporarily below 30% RH.

4.3 Radiation The OPRM module is designed to operate and meet its performance requirements after a total integrated Co-60 gamma dose of less than 10,000 RAD. The plant specific total integrated dose condition at the OPRM installation location of less than 1000 RAD is less than the tested configuration. Therefore, the OPRM is acceptable for use at LCS.

4.4 Electromagnetic Interference (EMI)

EMI testing of the OPRM equipment was performed by ABB to ensure it would not be adversely affected by the plant EMI environment (susceptibility), and to ensure the OPRM modules would not be detrimental to the existing plant EMI environment (emissions). As noted in Reference 2, the testing was conducted to MILSTD-461C, "Guide for Instrumentation and Control Equipment Grounding in Generating Stations,"

and MIL-STD-462-1967, "Measurement of Electromagnetic Interference Characteristics," for the following tests.

CE01, 03 Conducted Emissions

. CE07 Conducted Switching Spikes RE02 Radiated Emissions (14 kHz to 1 GHz)

CS01, 02 Conducted Susceptibility AC Power Leads CS06 Conducted Susceptibility Spike

RS02, 03 Radiated Susceptibility Design features for EMI considerations include a metal enclosure around the OPRM equipment, filtered input wires, and the use of ground planes on circuit boards. Post-maintenance testing of the system at LCS has energized all portions of the OPRM circuits and has not resulted in any adverse affects on other systems.

In addition, ABB designed and tested the OPRM system to meet the electrostatic discharge requirements of IEC 801-2, "Electromagnetic Compatibility for Industrial Process Measurement and Control equipment," Level 4 (8 kilovolt) under laboratory reference conditions in accordance with IEC 801-2 Section 8.0.

Also, ABB demonstrated fast transient withstand (burst) capability for all power input and output and all process input and output circuits, signal common and protective earth connections based on IEC 801-4 Level 4 (4 kV on power and grounds, 2 kV on process signals) as described in IEC 801-4 Sections 7.3.1 and 7.3.2.

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Attachment 1 EVALUATION OF PROPOSED CHANGES 4.5 Seismic As noted in Reference 2, the OPRM system is seismically qualified by type testing in accordance with IEEE-344-1975, "Recommended Practice for Seismic Qualification of Class 1E Equipment for Nuclear Power Generating Stations." The OPRM system is subjected to a minimum of five operating basis earthquakes in each axis followed by at least one safe shutdown earthquake in each axis. Verification has been completed to document that the LCS control room response spectra are bounded by the test seismic response spectra in Reference 2.

Question 5 "Confirm that administrative controls are provided for manually bypassing OPRM channels or protective functions, and for controlling access to the OPRM functions.

Response

The OPRM has two modes of operation - operate and test. In the operate mode, the system performs normal trip and alarm functions. The test mode is used for test, calibration, setpoint adjustment, and downloading of event data. In the test mode, the OPRM's reactor trip output is bypassed and the OPRM module is considered inoperable. If both OPRM modules in a channel are in test, then the trip channel is inoperable. Entry into the test mode is controlled by a keylock switch and is annunciated in the control room. The OPRM module trip circuits may be bypassed by keylock switches for each module located on a panel in the main control room.

The bypass condition of the selected OPRM module is indicated by the sequence of events monitor and by indicating lights.

Administrative procedures will be provided for manually bypassing OPRM instrumentation channels or protective functions, and for controlling access to the OPRM functions.

Question 6 "Confirm that any changes to the plant operator's main control room panel have received human factor reviews per plant specific procedures."

Response

The changes made to the main control room panels for the OPRM system at LCS were evaluated by a human factors engineer in accordance with human factors engineering procedures for acceptability and conformance to human engineering design principles. The OPRM system instrumentation and associated components, controls, and annunciators were found acceptable from a human factors engineering perspective.

In the NRC safety evaluation contained in Reference 5, the NRC stated that, u...the recirculation drive flow channel should comply with the requirements of Electrical and Electronics Engineers, Standard 279...." As part of the OPRM installation, the existing recirculation drive flow units (i.e., a flow converter unit and a flow arithmetic unit per channel) were replaced with new Class 1E qualified flow units capable of providing total flow signals to the OPRM modules.

Further, in the NRC safety evaluation contained in Reference 5, the NRC requested that the plant-specific submittal discuss the isolation devices between the OPRM system and the associated protection system. Input signal isolators are installed on the shared APRM channels, while relay contact output provides output isolation.

Page 12 of 16

Attachment 1 EVALUATION OF PROPOSED CHANGES B. Technical Basis for Proposed Changes to TS Section 3.4.1 The incorporation of the OPRM instrumentation into the TS will allow the deletion of the Power versus Flow TS Figure and associated references. The OPRM Instrumentation will provide at least the same level of assurance that the MCPR safety limit will not be violated for anticipated oscillations as that provided by the current stability requirements in the LCS TS.

C. Technical Basis for Proposed Changes to TS Section 5.6.5 The addition of the requirement to include the setpoints for the OPRM trip function in the COLR follows the approach outlined in Reference 2 and is consistent with the industry standard technical specifications, which provide for placement of similar cycle-specific reactor core thermal limits in the COLR.

The addition of the reference to the approved methodology for determining the trip function setpoints also follows the approach outlined in Reference 2 and is also consistent with the industry standard technical specifications, which provide for placement of the NRC-approved methodologies for calculating core thermal limits in TS Section 5.6.5.

5.0 REGULATORY ANALYSIS

5.1 No Significant Hazards Consideration Exelon Generation Company, LLC (EGC), proposes changes to the Technical Specifications (TS) for LaSalle County Station (LCS), Units 1 and 2. The proposed changes incorporate into the TS the Oscillation Power Range Monitor (OPRM) instrumentation and delete the currently required manual methods for avoiding instabilities and for detecting and suppressing potential instabilities. The OPRM system monitors neutron flux signals for signs of neutron flux oscillations and initiates a reactor scram whenever it detects an instability condition when in the predefined region of the power-to-flow map. Following NRC approval of the proposed TS changes, LCS will activate the reactor scram outputs of the OPRM instrumentation.

EGC has evaluated whether or not a significant hazards consideration is involved with the proposed amendments by focusing on the three standards set forth in 10 CFR 50.92, "Issuance of amendment," as discussed below.

1. Does the proposed change involve a significant increase in the probability or consequences of an accident previously evaluated?

Response: No. This proposed change has no impact on any of the existing neutron monitoring functions.

Activation of the OPRM scram function will replace the current methods that require operators to insert an immediate manual reactor scram in certain reactor operating regions where thermal hydraulic instabilities could potentially occur. While these regions will continue to be avoided during normal operation, certain transients, such as a reduction in reactor recirculation flow, could place the reactor in these regions. During these transient conditions, with the OPRM instrumentation scram function activated, an Page 13 of 16

Attachment I EVALUATION OF PROPOSED CHANGES immediate manual scram will no longer be required. This may potentially cause a marginal increase in the probability of occurrence of an instability event. This potential increase in probability is acceptable because the OPRM function will automatically detect the instability condition and initiate a reactor scram before the Minimum Critical Power Ratio (MCPR) Safety Limit is reached. Consequences of the potential instability event are reduced because of the more reliable automatic detection and suppression of an instability event, and the elimination of dependence on the manual operator actions.

Operators will continue to monitor for indications of thermal hydraulic instability when the reactor is operating in regions of potential instability as a backup to the OPRM instrumentation.

Therefore, the proposed changes do not involve a significant increase in the probability or consequences of an accident previously evaluated.

2. Does the proposed change create the possibility of a new or different kind of accident from any accident previously evaluated?

Response: No. The proposed changes replace procedural actions that were established to avoid operating conditions where reactor instabilities might occur with an NRC approved automatic detect and suppress function (i.e., OPRM).

Potential failures in the OPRM trip function could result in either failure to take the required mitigating action or an unintended reactor scram. These are the same potential effects of failure of the operator to take the correct appropriate action under the current procedural actions. The effects of failure of the OPRM equipment are limited to reduced or failed mitigation, but such failure cannot cause an instability event or other type of accident.

Therefore, the proposed changes do not create the possibility of a new or different kind of accident from any accident previously evaluated.

3. Does the proposed change involve a significant reduction in a margin of safety?

Response: No. The OPRM trip function is being implemented to automate the detection and subsequent suppression of an instability event prior to exceeding the MCPR Safety Limit. The OPRM trip provides a trip output of the same type as currently used for the APRM. Its failure modes and types are identical to those for the present APRM output.

Since the MCPR Safety Limit will not be exceeded as a result of an instability event following implementation of the OPRM trip function, it is concluded that the proposed change does not reduce the margin of safety.

Therefore, the proposed changes do not involve a significant reduction in a margin of safety.

Based on the above, EGC concludes that the proposed amendment presents no significant hazards consideration under the standards set forth in 10 CFR 50.92, paragraph (c), and accordingly, a finding of no significant hazards consideration is justified.

Page 14 of 16

Attachment I EVALUATION OF PROPOSED CHANGES 5.2 Applicable Regulatory Requirements/Criteria 10 CFR 50, Appendix A, General Design Criterion (GDC) 10, "Reactor design," requires the reactor core and associated coolant, control, and protection systems to be designed with appropriate margin to assure that acceptable fuel design limits are not exceeded during any condition of normal operation, including the affects of anticipated operational occurrences.

Additionally, GDC 12, "Suppression of reactor power oscillations," requires the reactor core and associated coolant, control, and protection systems to be designed to assure that power oscillations which can result in conditions exceeding acceptable fuel design limits are either not possible or can be reliably and readily detected and suppressed. The OPRM Instrumentation System provides compliance with GDC 10 and GDC 12, thereby providing protection from exceeding the fuel MCPR safety limit.

The NRC issued GL 94-02, which requested licensees to develop and submit to the NRC a plan for long-term stability corrective actions. The OPRM provides the long-term stability corrective actions requested in GL 94-02.

Additionally, the proposed changes are similar to those approved by the NRC for the Columbia Generating Station and the Perry Nuclear Power Plant, Unit 1, in References 10 and 11, respectively.

5.3 Conclusion In conclusion, based on the considerations discussed above, (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) such activities will be conducted in compliance with the Commission's regulations, and (3) the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public.

6.0 ENVIRONMENTAL CONSIDERATION

A review has determined that the proposed amendment would change 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 would change an inspection or surveillance requirement. However, the proposed amendment does not involve (i) a significant hazards consideration, (ii) a significant change in the types or significant increase in the amounts of any effluents that may be released offsite, and (iii) a significant increase in individual or cumulative occupational radiation exposure. Accordingly, the proposed amendment meets the eligibility criterion for categorical exclusion set forth in 10 CFR 51.22, "Criterion for categorical exclusion; identification of licensing and regulatory actions eligible for categorical exclusion or otherwise not requiring environmental review," paragraph (c)(9). Therefore, in accordance with 10 CFR 51.22(b), no environmental impact statement, or environmental assessment need be prepared in connection with the proposed amendment.

7.0 REFERENCES

1. Letter from Keith R. Jury (Exelon Generation Company, LLC) to U. S. NRC, "Schedule for Completing Actions to Implement Long-Term Stability Solution," dated December 19, 2003 Page 15 of 16

Attachment 1 EVALUATION OF PROPOSED CHANGES

2. Letter from U. S. NRC to R. A. Pinelli (BWR Owners' Group), "Acceptance of Licensing Topical Report CENPID-400-P, 'Generic Topical Report for the ABB Option III Oscillation Power Range Monitor,'" dated August 16,1995

3. NEDO-32465-A, "BWR Owners' Group Reactor Stability Detect and Suppress Solutions Licensing Basis Methodology and Reload Applications," August 1996

4. Letter from J. C. Brons (Commonwealth Edison Company) to U. S. NRC, "Response to Generic Letter.94-02 (BWR Stability)," dated September 9,1994

5. Letter from U. S. NRC to L. A. England (BWR Owners' Group), "Acceptance for Referencing NEDO-31960 and NEDO-31960 Supplement 1, 'BWR Owner's Group Long-Term Stability Solutions Licensing Methodology,'" dated July 12,1993

6. Letter from K. S. Putnam (Boiling Water Reactor Owners' Group) to U. S. NRC, "Resolution of Reportable Condition for Stability Reload Licensing Calculations Using Generic Regional Mode DIVOM Curve," dated September 30, 2003

7. Letter from R. M. Krich, (Commonwealth Edison Company), to U. S. NRC, "Request for License Amendment for Power Uprate Operation," dated July 14, 1999

8. Letter from U. S. NRC to 0. D. Kingsley (Commonwealth Edison Company), "LaSalle -

Issuance of Amendments Regarding Power Uprate," dated May 9, 2000

9. Letter from K. P. Donovan (BWR Owners' Group) to U. S. NRC, "Guidelines for Stability Option IlIl 'Enabled Region,'" dated September 17,1996

10. Letter from U. S. NRC to J. V. Parrish (Energy Northwest), "Columbia Generating Station -

Issuance of Amendment RE: Oscillation Power Range Monitoring Technical Specifications,"

dated April 5, 2001

11. Letter from U. S. NRC to J. K. Wood (FirstEnergy Nuclear Operating Company), "Perry Nuclear Power Plant, Unit 1 - Issuance of Amendment RE: Activation of Thermal-Hydraulic Stability Monitoring Instrumentation," dated April 5, 2001 Page 16 of 16

Attachment 2 Marked-up Technical Specifications Pages for Proposed Changes Paaes i

3.3.1.3-1 (new page) 3.3.1.3-2 (new page) 3.3.1.3-3 (new page) 3.4.1-1 3.4.1-2 3.4.1-3 3.4.1-4 3.4.1-5 3.4.1-6 3.4.1-7 5.6-3 5.6-4

TABLE OF CONTENTS 1.0 USE AND APPLICATION 1.1 Definitions...................................... ... ... 1.1-1 1.2 Logical Connectors.................................. ..... 1.2-1 1.3 Completion Times.................................... ..... 1.3-1 1.4 Frequency....................................... ..... 1.4-1 2.0 SAFETY LIMITS (SLs) 2.1 SLs................................................. ..... 2.0-1 2.2 SL Violations...................................... ..... 2.0-1 3.0 LIMITING CONDITION FOR OPERATION (LCO) APPLICABILITY .. 3.0-1 3.0 SURVEILLANCE REQUIREMENT (SR) APPLICABILITY .. 3.0-4 3.1 REACTIVITY CONTROL SYSTEMS 3.1.1 SHUTDOWN MARGIN (SDM)............................... 3.1.1-1 .

3.1.2 Reactivity Anomalies................................ 3.1.2-1 .

3.1.3 Control Rod OPERABILITY............................. 3.1.3-1 .

3.1.4 Control Rod Scram Times............................ 3.1.4-1 .

3.1.5 Control Rod Scram Accumulators...................... 3.1.5-1 .

3.1.6 Rod Pattern Control................................. 3.1.6-1 .

3.1.7 Standby Liquid Control (SLC) System................. 3.1.7-1 .

3.1.8 Scram Discharge Volume (SDV) Vent and Drain Valves.. 3.1.8-1 .

3.2 POWER DISTRIBUTION LIMITS 3.2.1 AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR). 3.2.1-1 .

3.2.2 MINIMUM CRITICAL POWER RATIO (MCPR)................. 3.2.2-1 .

3.2.3 LINEAR HEAT GENERATION RATE (LHGR) ................. 3.2.3-1 .

3.3 INSTRUMENTATION 3.3.1.1 Reactor Protection System (RPS) Instrumentation...... ....3.3.1.1-1

-L . 3 3 J .

l. ?

X --s Rnnno qnilrpoP U IUlx Mnnitnr IVII I.U-(ISPM)

\ I Tncstrilmont;t~inn l .J . .. .l. .U . . .l.. .. .. . . .

3. 3. 1

.v . .

9?-1 3.3.2.1 Control Rod Block Instrumentation .. 3.3.2.1-1 3.3.2.2 Feedwater System and Main Turbine High Water Level Trip Instrumentation .................................... 3.3.2.2-1 3.3.3.1 Post Accident Monitoring (PAM) Instrumentation ........... 3.3.3.1-1 3.3.3.2 Remote Shutdown Monitoring System ........................ 3.3.3.2-1 3.3.4.1 End of Cycle Recirculation Pump Trip (EOC-RPT)

Instrumentation .3.3.4.1-1 3.3.4.2 Anticipated Transient Without Scram Recirculation Pump Trip (ATWS-RPT) Instrumentation ................... 3.3.4.2-1 3.3.5.1 Emergency Core Cooling System (ECCS) Instrumentation ..... 3.3.5.1-1 3.3.5.2 Reactor Core Isolation Cooling (RCIC) System Instrumentation ...... 3.3.5.2-1 3.3.6.1 Primary Containment Isolation Instrumentation ...... 3.3.6.1-1 3.3.6.2 Secondary Containment Isolation Instrumentation ...... 3.3.6.2-1 3.3.7.1 Control Room Area Filtration (CRAF) System Instrumentation .3.3.7.1-1

'3 ,,3 &s 0gId J4 1, *E.E>)-

e2i 1 and Amendment No.3

OPRM Instrumentation 3.3.1.3 3.3 INSTRUMENTATION 3.3.1.3 Oscillation Power Range Monitor (OPRM) Instrumentation LCO 3.3.1.3 Four channels of the OPRM instrumentation shall be OPERABLE.

APPLICABILITY: THERMAL POWER > 25% RTP.

ACTIONS

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

1. Separate Condition entry is allowed for each channel.

2. When OPRM channels are inoperable due to APRM indication not within limits in accordance with Specification 3.3.1.1, entry into associated Conditions and Required Actions may be delayed for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months if the APRM is indicating a lower power value than the calculated power, and for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months if the APRM.is indicating a higher power value than the calculated power.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more channels A.1 Place channel in 30 days inoperable. trip.

OR A.2 Place associated RPS 30 days trip system in trip.

A.3 Initiate alternate 30 days method to detect and suppress thermal hydraulic instability oscillations.

(continued)

LaSalle 1 and 2 3.3.1.3-1 Amendment No.

OPRM Instrumentation 3.3.1.3 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. OPRM trip capability B.1 Initiate alternate 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months not maintained. method to detect and suppress thermal hydraulic instability oscillations.

AU~

B.2 .Restore OPRM trip 120 days capability.

C. Required Action and C.1 Reduce THERMAL POWER 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months associated Completion < 25% RTP.

Time not met.

LaSalle 1 and 2 3.3. 1.3- 2 Amendment No.

OPRM Instrumentation 3.3.1.3 SURVEILLANCE REQUIREMENTS

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

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

SURVEILLANCE FREQUENCY SR 3.3.1.3.1 Perform CHANNEL FUNCTIONAL TEST. 184 days SR 3.3.1.3.2 ------------------- NOTE--------------------

Neutron detectors are excluded.

Perform CHANNEL CALIBRATION. The setpoints 24 months for the trip function shall be as specified in the COLR.

SR 3.3.1.3.3 Perform LOGIC SYSTEM FUNCTIONAL TEST. 24 months SR 3.3.1.3.4 Verify OPRM is not bypassed when THERMAL 24 months POWER is 2 28.6% RTP and recirculation drive flow is < 60% of rated recirculation drive flow.

SR 3.3.1.3.5 ------------------- NOTE--------------------

Neutron detectors are excluded.

Verify the RPS RESPONSE TIME is within 24 months on a limits. STAGGERED TEST BASIS LaSalle 1 and 2 3.3.1.3-3 Amendment No.

Recirculation Loops Operating 3.4.1 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.1 Recirculation Loops Operating LCO 3.4.1 Two recirculation loons with matched flows shall be in operation 4an III of OR One recirculation loop shall be in operation

-'tI~o. w with the following limits appied when itre34.

the associated LCO is applicable:

a. LCO 3.2.1, "AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)," single loop operation limits specified in the COLR;

b. LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)," single loop operation limits specified in the COLR;

c. LCO 3.3.1.1, "Reactor Protection System (RPS)

Instrumentation," Function 2.b (Average Power Range Monitors Flow Biased Simulated Thermal Power - Upscale),

Allowable Value of Table 3.3.1.1-1 is reset for single loop operation; and

d. LCO 3.3.2.1, "Control Rod Block Instrumentation,"

Function 1.a (Rod Block Monitor - Upscale), Allowable Value of Table 3.3.2.1-1, specified in the COLR, is reset for single loop operation.

APPLICABILITY: MODES 1 and 2.

LaSalle 1 and 2 3.4.1-1 Amendment (E No.

Recirculation Loops Operating 3.4.1 ACTIONS.

CONDITION I REQUIRED ACTION I COMPLETION TIME (A.1 -- F-lN T.F--

,111Ir-cuira l oil e5 Onvy 4tj pp-liaB

, * , ., -hl -en

-pe,-at-il~ wtin 3 tim es bas- inp Regien IIofe iur vnluc is> 102-p.k-nJ--p6aR V1U

-VelI;; AKPCM and-HIR4 fu X 7M re 1 St-, S

. e e.

t r 45 minutes fr~rn f

Cenditicn Conem d A ent with Fn ll[RMA-~Ll L QYA

- Eeen tinrue14_

LaSalle 1 and 2 3.4. 1-2 Amendment No.. ~

Recirculation Loops Operating 3.4.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME J

A. ( continued) A.2 ------ OTE-------

1M% H k - it u ea 1valuc is Ž 3 timcs

,bascline-gsit V rify ARRM1 UJ tLPRIM rf mfnUtvs fiUA nIuise lelhi

-4nrupezr

-ter etefo S' jiiinutes firom iiseaovry A co,

,,,,1 Yi th_

-any THCRMA-l POWER inere~e o f i~ 5%4GP

. - fy rer.r

.Vcri lati on -are pe-r_

4--rs e

,fFigAj~ue-v-r .

I B. Action A-1 -gcd

- -Satisfy the-

zt1on mm C+C (continued)

LaSalle 1 and 2 3.4. 1-3 Amendment No. E

Recirculation Loops Operating 3.4.1 ACTIONS CONDITION E REQUIRED ACTION I COMPLETION TIME l l C.1 - Exit 3.R4g.1 -1

_ Figure 3..1. ,

< Reyon I of- FigTjTWc f_ _ _

t No recirculation f loops in operation. flux aThie levelO Reduce IHLkRMAL POWEP Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months i

i 7,

'E. P.cuired Action B- i th LA ieshutdo t

-or 0.1 and aZsociatcC in thro ghtr1#4 I Cdirfplel~i l Time- not lp-Recirculation loop

,.cQV

(,.1 Declare the 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months flow mismatch not recirculation loop within limits. with lower flow to be "not in operation."

(continued)

LaSalle 1 and 2 3.4.1-4 Amendment No..

Recirculation Loops Operating 3.4.1 ACTIONS CONDITION R REQUIRED ACTION ICOMPLETION TIME Requirements of the Satisfy the 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months

(-I(gE) LCO not met for reasons othertSzL_

C-1 requirements of the LCO.

gonditionA(

0-E, Required Action and associated Completed Time of Condition(a

.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months not met. V

/

LaSalle 1 and 2 3.4. 1-5 Amendment No.e

Recirculation Loops Operating 3.4.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.1.1 ------------------- NOTE--------------------

Not required to be performed until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after both recirculation loops are in operation.

Verify recirculation loop jet pump flow 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months mismatch with both recirculation loops in operation is:

a. s 10% of rated core flow when operating at < 70% of rated core-flow; and

b. < 5% of rated core flow when operating at Ž 70% of rated core flow.

____ 1 F1 3u.4.1i-1

. P/

LaSalle I and 2 3.4.1-6 Amendment No. 9

Recirculation Loops Operating 3.4.1 80 Region I II Region III 70 (Restricted) \_ (Allowable 60 50 St bility Monitoring 40 39

,I Res ricted Region 30 II Stabi ty Monitoring 20

^ /_ Allowa le Region III Allowable egion 10 0

20 30 40 50 60 70 80 90 100 T al Core Flow (% of Rated)

Figure 3.4.1-1 (Page 1 of 1)

Power versus Flow LaSalle I and 2 3.4. 1-7 Amendment No. e

Requi rements Reporting Reporting Requirements 5.6 5.6 Reporting Requirements 5.6.5 CORE OPERATING LIMITS REPORT (COLR) (continued)

4. The Rod Block Monitor Upscale Instrumentation Setpoint for the Rod Block Monit. Enction Allowable yr~'~ {v 4Fe 3 .3.2 .1.

The analytical met s use to determine e core operating limits shall be those previously reviewed and approved by the NRC, specifically those described in the following documents:

1. ANF-1125(P)(A), "ANFB Critical Power Correlation."

2. Letter, Ashok C. Thadani (NRC) to R.A. Copeland (SPC),

"Acceptance for Referencing of ULTRAFLOWTH Spacer on 9x9-IX/X BWR Design," July 28, 1993.

3. XN-NF-524(P)(A), "ANF Critical Power Methodology for Boiling Water Reactors."

4. ANF-913(P)(A), "COTRANSA 2: A Computer Program for Boiling Water Reactor Transient Analysis."

5. ANF-CC-33(P)(A), "HUXY: A Generalized Multirod Heatup Code with 10 CFR 50, Appendix K Heatup Option."

6. XN-NF-80-19(P)(A), "Advanced Nuclear Fuel Methodology for Boiling Water Reactors."

7. XN-NF-85-67(P)(A), "Generic Mechanical Design for Exxon Nuclear Jet Pump BWR Reload Fuel."

8. ANF-89-014(P)(A), "ANF Corporation Generic Mechanical Design for ANF Corporation 9x9-IX and 9x9-9X BWR Reload Fuel."

9. EMF-CC-074(P)(A), Volume 4 - "BWR Stability Analysis:

Assessment of STAIF with input from MICROBURN-B2."

10. XN-NF-81-58(P)(A), "RODEX2 Fuel Rod Thermal-Mechanical Response Evaluation Model."

11. XN-NF-84-105(P)(A), "XCOBRA-T: A Computer Code for BWR Transient Thermal-Hydraulic Core Analysis."

(continued)

LaSalle 1 and 2 5.6-3 Amendment No.

Requirements Reporting Reporting Requirements 5.6 5.6 Reporting Requirements 5.6.5 CORE OPERATING LIMITS REPORT (COLR) (continued)

12. ANF-91-048(P)(A), "ANF Corporation Methodology for Boiling Water Reactors EXEM BWR Evaluation Model."

13. EMF-2209(P)(A), "SPCB Critical Power Correlation."

14. ANF-89-98(P)(A), "Generic Mechanical Design Criteria for BWR Fuel Designs."

15. NEDE-24011-P-A, "General Electric Standard Application for Reactor Fuel."

16. NFSR-0091, "Benchmark of CASMO/MICROBURN BWR Nuclear Design Methods."

17. EMF-1125(P)(A), "ANFB Critical Power Correlation Application for Co-Resident Fuel."

18. ANF-1125(P)(A), "ANFB Critical Power Correlation Determination of ATRIUM-9B Additive Constant Uncertainties."

19. EMF-85-74(P)(A), "RODEX2A (BWR) Fuel Rod Thermal-Mechanical Evaluation Model."

20. EMF-2158(P)(A), "Siemens Power Corporation Methodology for Boiling Water Reactors: Evaluation and Validation of CASMO-4/MICROBURN-B2."

21. NEDC-32981P(A), "GEXL96 Corelation for Atrium-9B Fuel."

22. NEDC-33106P, "GEXL97 Correlation for Atrium-10 Fuel."

The COLR will contain the complete identification for each of the TS referenced topical reports used to prepare the COLR (i.e., report number, title, revision, date, and any supplements).

LaSalle 1 and 2 5.6-4 Amendment No.

Attachment 3 Revised Technical Specifications Pages for Proposed Changes Pages i

3.3.1.3-1 (new page) 3.3.1.3-2 (new page) 3.3.1.3-3(new page) 3.4.1-1 3.4.1-2 3.4.1-3 5.6-3 5.6-4

TABLE OF CONTENTS 1.0 USE AND APPLICATION 1.1 Definitions...................................... ... ... 1.1 - 1 1.2 Logical Connectors ................- ..... 1.2-1 1.3 Completion Times.................................... ..... 1.3-1 1.4 Frequency........................................... ..... 1.4-1 2.0 SAFETY LIMITS (SLs) 2.1 SLs................................................ ..... 2.0-1 2.2 SL Violations....................................... ..... 2.0-1 3.0 LIMITING CONDITION FOR OPERATION (LCO) APPLICABILITY ........ 3.0-1 3.0 SURVEILLANCE REQUIREMENT (SR) APPLICABILITY ................. 3.0-4 3.1 REACTIVITY CONTROL SYSTEMS 3.1.1 SHUTDOWN MARGIN (SDM)............................... 3.1.1 -1 .

3.1.2 Reactivity Anomalies................................ 3.1.2 -1 .

3.1.3 Control Rod OPERABILITY............................. 3.1.3 -1 .

3.1.4 Control Rod Scram Times............................. .3.1.4-1 .

3.1.5 Control Rod Scram Accumulators...................... 3.1.5-1 .

3.1.6 Rod Pattern Control................................. 3.1.6-1 .

3.1.7 Standby Liquid Control (SLC) System................. 3.1.7-1 .

3.1.8 Scram Discharge Volume (SDV) Vent and Drain Valves.. 3.1.8-1 .

3.2 POWER DISTRIBUTION LIMITS 3.2.1 AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR). 3.2.1-1 .

3.2.2 MINIMUM CRITICAL POWER RATIO (MCPR)................. 3.2.2-1 .

3.2.3 LINEAR HEAT GENERATION RATE (LHGR) ................. 3.2.3-1 .

3.3 INSTRUMENTATION 3.3.1.1 Reactor Protection System (RPS) Instrumentation..... 3.3.1.1-1 .

3.3.1.2 Source Range Monitor (SRM) Instrumentation.......... 3.3.1.2-1 .

3.3.1.3 Oscillation Power Range Monitor (OPRM) Instrumentati on.. .3.3.1.3-1 3.3.2.1 Control Rod Block Instrumentation................... 3.3.2.1-1 .

3.3.2.2 Feedwater System and Main Turbine High Water Level Trip Instrumentation.............................. 3.3.2.2-1 .

3.3.3.1 Post Accident Monitoring (PAM) Instrumentation...... 3.3.3.1-1 .

3.3.3.2 Remote Shutdown Monitoring System................... 3.3.3.2-1 .

3.3.4.1 End of Cycle Recirculation Pump Trip (EOC-RPT)

Instrumentation............................. 3.3.4.1-1 .

3.3.4.2 Anticipated Transient Without Scram Recirculation Pump Trip (ATWS-RPT) Instrumentation.............. 3.3.4.2-1 .

3.3.5.1 Emergency Core Cooling System (ECCS) Instrumentation 3.3.5.1-1 .

3.3.5.2 Reactor Core Isolation Cooling (RCIC) System Instrumentation................................... 3.3.5.2-1 .

3.3.6.1 Primary Containment Isolation Instrumentation....... 3.3.6.1-1 .

3.3.6.2 Secondary Containment Isolation Instrumentation..... 3.3.6.2-1 .

3.3.7.1 Control Room Area Filtration (CRAF) System Instrumentation................................... 3.3.7.1-1 .

(continued)

LaSalle 1 and 2 i Amendment No. /

OPRM Instrumentation 3.3.1.3 3.3 INSTRUMENTATION 3.3.1.3 Oscillation Power Range Monitor (OPRM) Instrumentation LCO 3.3.1.3 Four channels of the OPRM instrumentation shall be OPERABLE.

APPLICABILITY: THERMAL POWER > 25% RTP.

ACTIONS

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

1. Separate Condition entry is allowed for each channel.

2. When OPRM channels are inoperable due to APRM indication not within limits in accordance with Specification 3.3.1.1, entry into associated Conditions and Required Actions may be delayed for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months if the APRM is indicating a lower power value than the calculated power, and for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months if the APRM is indicating a higher power value than the calculated power.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more channels A.1 Place channel in 30 days inoperable. trip.

OR A.2 Place associated RPS 30 days trip system in trip.

OR A.3 Initiate alternate 30 days method to detect and suppress thermal hydraulic instability oscillations.

(continued)

LaSalle 1 and 2 3.3. 1.3-1 Amendment No.

OPRM Instrumentation 3.3.1.3 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. OPRM trip capability B.1 Initiate alternate 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months not maintained. method to detect and suppress thermal hydraulic instability oscillations.

B.2 Restore OPRM trip 120 days capability.

C. Required Action and C.1 Reduce THERMAL POWER 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months associated Completion < 25% RTP.

Time not met.

LaSalle 1 and 2 3.3. 1.3-2 Amendment No.

OPRM Instrumentation 3.3.1.3 SURVEILLANCE REQUIREMENTS

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

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

SURVEILLANCE FREQUENCY SR 3.3.1.3.1 Perform CHANNEL FUNCTIONAL TEST. 184 days SR 3.3.1.3.2 ------------------- NOTE--------------------

Neutron detectors are excluded.

Perform CHANNEL CALIBRATION. The setpoints 24 months for the trip function shall be as specified in the COLR.

SR 3.3.1.3.3 Perform LOGIC SYSTEM FUNCTIONAL TEST. 24 months SR 3.3.1.3.4 Verify OPRM is not bypassed when THERMAL 24 months POWER is > 28.6% RTP and recirculation drive flow is < 60% of rated recirculation drive flow.

SR 3.3.1.3.5 ------------------- NOTE--------------------

Neutron detectors are excluded.

Verify the RPS RESPONSE TIME is within 24 months on a limits. STAGGERED TEST BASIS LaSalle 1 and 2 3.3.1.3-3 Amendment No.

Recirculation Loops Operating 3.4.1 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.1 Recirculation Loops Operating LCO 3.4.1 Two recirculation loops with matched flows shall be in operation.

One recirculation loop shall be in operation with the following limits applied when the -associated LCO is applicable:

a. LCO 3.2.1, "AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)," single loop operation limits specified in the COLR;

b. LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)," single loop operation limits specified in the COLR;

c. LCO 3.3.1.1, "Reactor Protection System (RPS)

Instrumentation," Function 2.b (Average Power Range Monitors Flow Biased Simulated Thermal Power - Upscale),

Allowable Value of Table 3.3.1.1-1 is reset for single loop operation; and

d. LCO 3.3.2.1, "Control Rod Block Instrumentation,"

Function l.a (Rod Block Monitor - Upscale), Allowable Value of Table 3.3.2.1-1, specified in the COLR, is reset for single loop operation.

APPLICABILITY: MODES 1 and 2.

LaSalle 1 and 2 3.4.1-1 Amendment No. /

Recirculation Loops Operating 3.4.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. No recirculation A.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months loops in operation.

B. Recirculation loop B.1 Declare the 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months flow mismatch not recirculation loop within limits. with lower flow to be "not in operation."

C. Requirements of the C.1 Satisfy the 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months LCO not met for requirements of the reasons other than LCO.

Condition A or B.

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

LaSalle I and 2 3.4.1-2 Amendment No. /

Recirculation Loops Operating 3.4.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.1.1 ------------------- NOTE------------------

Not required to be performed until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after both recirculation loops are in operation.

Verify recirculation loop jet pump flow 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months mismatch with both recirculation loops in operation is:

a.

10% of rated core flow when operating at < 70% of rated core flow; and

b. < 5% of rated core flow when operating at 2 70% of rated core flow.

I LaSalle 1 and 2 3.4.1-3 Amendment No. /

Reporting Requirements 5.6 5.6 Reporting Requirements 5.6.5 CORE OPERATING LIMITS REPORT (COLR) (continued)

4. The Rod Block Monitor Upscale Instrumentation Setpoint for the Rod Block Monitor-Upscale Function Allowable Value for Specification 3.3.2.1.

5. The OPRM setpoints for the trip function for SR 3.3.1.3.2.

b. The analytical methods used to determine the core operating limits shall be those previously reviewed and approved by the NRC, specifically those described in the following documents:

1. ANF-1125(P)(A), "ANFB Critical Power Correlation."

2. Letter, Ashok C. Thadani (NRC) to R.A. Copeland (SPC),

"Acceptance for Referencing of ULTRAFLOWTM Spacer on 9x9-IX/X BWR Design," July 28, 1993.

3. XN-NF-524(P)(A), "ANF Critical Power Methodology for Boiling Water Reactors."

4. ANF-913(P)(A), "COTRANSA 2: A Computer Program for Boiling Water Reactor Transient Analysis."

5. ANF-CC-33(P)(A), "HUXY: A Generalized Multirod Heatup Code with 10 CFR 50, Appendix K Heatup Option."

6. XN-NF-80-19(P)CA), "Advanced Nuclear Fuel Methodology for Boiling Water Reactors."

7. XN-NF-85-67(P)(A), "Generic Mechanical Design for Exxon Nuclear Jet Pump BWR Reload Fuel."

8. ANF-89-014(P)(A), "ANF Corporation Generic Mechanical Design for ANF Corporation 9x9-IX and 9x9-9X BWR Reload Fuel."

9. EMF-CC-074(P)(A), Volume 4 - "BWR Stability Analysis:

Assessment of STAIF with input from MICROBURN-B2."

10. XN-NF-81-58(P)(A), "RODEX2 Fuel Rod Thermal-Mechanical Response Evaluation Model."

11. XN-NF-84-105(P)(A), "XCOBRA-T: A Computer Code for BWR Transient Thermal-Hydraulic Core Analysis."

(continued)

LaSalle 1 and 2 5.6-3 Amendment No. /

Reporting Requirements 5.6 5.6 Reporting Requirements 5.6.5 CORE OPERATING LIMITS REPORT (COLR) (continued)

12. ANF-91-048(P)(A), "ANF Corporation Methodology for Boiling Water Reactors EXEM BWR Evaluation Model."

13. EMF-2209(P)(A), "SPCB Critical Power Correlation."

14. ANF-89-98(P)(A), "Generic Mechanical Design Criteria for BWR Fuel Designs."

15. NEDE-24011-P-A, "General Electric Standard Application for Reactor Fuel."

16. NFSR-0091, "Benchmark of CASMO/MICROBURN BWR Nuclear Design Methods."

17. EMF-1125(P)(A), "ANFB Critical Power Correlation Application for Co-Resident Fuel."

18. ANF-1125(P)(A), "ANFB Critical Power Correlation Determination of ATRIUM-9B Additive Constant Uncertainties."

19. EMF-85-74(P)(A), "RODEX2A (BWR) Fuel Rod Thermal-Mechanical Evaluation Model."

20. EMF-2158(P)(A), "Siemens Power Corporation Methodology for Boiling Water Reactors: Evaluation and Validation of CASMO-4/MICROBURN-B2."

21. NEDC-32981P(A), "GEXL96 Corelation for Atrium-9B Fuel."

22. NEDC-33106P, "GEXL97 Correlation for Atrium-10 Fuel."

23. NEDO-32465-A, "BWR Owners' Group Reactor Stability Detect and Suppress Solutions Licensing Basis Methodology and Reload Applications," August 1996.

The COLR will contain the complete identification for each of the TS referenced topical reports used to prepare the COLR (i.e., report number, title, revision, date, and any supplements).

(continued)

LaSalle 1 and 2 5.6-4 Amendment No. /

Attachment 4 Marked-up Technical Specifications Bases Pages for Proposed Changes Pages B 3.3.1.1-30 B 3.3.1.3-1 (new page)

B 3.3.1.3-2 (new page)

B 3.3.1.3-3 (new page)

B 3.3.1.3-4 (new page)

B 3.3.1.3-5 (new page)

B 3.3.1.3-6 (new page)

B 3.3.1.3-7 (new page)

B 3.3.1.3-8 (new page)

B 3.3.1.3-9 (new page)

B 3.3.1.3-10 (new page)

B 3.3.1.3-11 (new page)

B 3.4.1-2 B 3.4.1-3 B 3.4.1-4 B 3.4.1-5 B 3.4.1-6 B 3.4.1-7 B 3.4.1-8 B 3.4.1-9 B 3.4.1-10

TABLE OF CONTENTS B 2.0 SAFETY LIMITS (SLs)

B 2.1.1 Reactor Core SLs .................................... B 2.1.1-1 B 2.1.2 Reactor Coolant System (RCS) Pressure SL ........... B 2.1.2-1 B 3.0 LIMITING CONDITION FOR OPERATION (LCO) APPLICABILITY ...B 3.0-1 B 3.0 SURVEILLANCE REQUIREMENT (SR) APPLICABILITY ............B 3.0-11 B 3.1 REACTIVITY CONTROL SYSTEMS B 3.1.1 SHUTDOWN MARGIN (SUM) ............................... B 3.1.1-1 B 3.1.2 Reactivity Anomalies ................................ B 3.1.2-1 B 3.1.3 Control Rod OPERABILITY ..............................B 3.1.3-1 B 3.1.4 Control Rod Scram Times ............................. B 3.1.4-1 B 3.1.5 Control Rod Scram Accumulators .......................B 3.1.5-1 B 3.1.6 Rod Pattern Control ........ .e.................B 3.1.6-1 B 3.1.7 Standby Liquid Control (SLC) ................. B 3.1.7-1 B 3.1.8 Scram Discharge Volume (SDV) Vent and Drain Valves ..B 3.1.8-1 B 3.2 POWER DISTRIBUTION LIMITS B 3.2.1 AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR) .......................................... B 3.2.1-1 B 3.2.2 MINIMUM CRITICAL POWER RATIO (MCPR) .................B 3.2.2-1 B 3.2.3 LINEAR HEAT GENERATION RATE (LHGR) ................. B 3.2.3-1 B 3.3 INSTRUMENTATION B 3.3.1.1 Reactor Protection System (RPS) Instrumentation ..... B 3.3.1.1-1 B 3.3.1.2 Source Range Monitor (SRM) Instrumentation .......... B 3.3.1.2-1 B 3.3.2.1 Control Rod Block Instrumentation .......

. ...........B 3.3.2. 1-1 B 3.3.2.2 Feedwater System and Main Turbine High Water Level Trip Instrumentation .............................. B 3.3.2.2-1 B 3.3.3.1 Post Accident Monitoring (PAM) Instrumentation ...... B 3.3.3. 1-1 B 3.3.3.2 Remote Shutdown Monitoring System ...................B 3.3.3.2-1 B 3.3.4.1 End of Cycle Recirculation Pump Trip (EOC-RPT)

Instrumentation ............ B 3.3.4.1-1 B 3.3.4.2 Antici pated Transient Wi thout Scram Recirculation Pump Trip (ATWS-RPT) Instrumentation ..............B 3.3.4.2-1 B 3.3.5.1 Emergency Core Cooling System (ECCS)

Instrumentation ................................... B 3.3.5.1-1 B 3.3.5.2 Reactor Core Isolation Cooling (RCIC) System Instrumentation ....... ........................... B 3.3.5.2-1 B 3.3.6.1 Primary Containment Isolation Instrumentation ....... B 3.3.6.1-1 B 3.3.6.2 Secondary Containment Isolation Instrumentation ..... B 3.3.6.2-1 B 3.3.7.1 Control Room Area Filtration (CRAF)

System Instrumentation ............................ B 3.3.7.1-1 B 3.3.8.1 Loss of Power (LOP) Instrumentation .................B 3.3.8. 1-1 B 3.3.8.2 Reactor Protection System (RPS) Electric Power "nn; +. -o nn ULUlLet lily . D 0 I I a

.J.2R.LJso 9_1 LaSalle 1 and 2 i Revi sion X~

RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.6 and SR 3.3.1.1.7 (continued)

REQUIREMENTS channel(s) declared inoperable. Only those appropriate channel(s) that are required in the current MODE or condition should be declared inoperable.

A Frequency of 7 days is reasonable based on engineering judgment and the reliability of the IRMs and APRMs.

SR 3.3.1.1.8 LPRM gain settings are determined from the local flux profiles measured by the Traversing Incore Probe (TIP)

System. This establishes the relative local flux profile for appropriate representative input to the APRM System.

The 1000 effective full power hours (EFPH) Frequency is ased on operating experience with LPRM sensitivity changes.

f t4k 3.3.1.1.9 and SR 3.3.1.1.12

(

CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the channel will perform the intended function. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at lease once per refueling interval with applicable extensions. Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology.

The 92 day Frequency of SR 3.3.1.1.9 is based on the reliability analysis of Reference 10.

The 24 month Frequency of SR 3.3.1.1.12 is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned (continued)

LaSalle 1 and 2 B 3.3.1.1-30 Revision X

OPRM Instrumentation B 3.3.1.3 B 3.3 INSTRUMENTATION B 3.3.1.3 OSCILLATION POWER RANGE MONITOR (OPRM) INSTRUMENTATION BASES BACKGROUND General Design Criteria 10 (GDC 10) requires the reactor core and associated coolant, control, and protection systems to be designed with appropriate margin to assure that acceptable fuel design limits are not exceeded during any condition of normal operation, including the effects of anticipated operational occurrences. Additionally, GDC 12 requires the reactor core and associated coolant, control and protection systems to be designed to assure that power oscillations which can result in conditions exceeding acceptable fuel design limits are either not possible or can be reliably and readily detected and suppressed. The OPRM System provides compliance with GDC 10 and GDC 12, thereby providing protection from exceeding the fuel minimum critical power ratio (MCPR) safety limit.

References 1, 2, and 3 describe three separate algorithms for detecting stability related oscillations: the period based detection algorithm, the amplitude based algorithm, and the growth rate algorithm. The OPRM System hardware implements these algorithms in microprocessor based modules.

These modules execute the algorithms based on local power range monitor (LPRM) inputs and generate alarms and trips based on these calculations. These trips result in tripping the Reactor Protection System (RPS) when the appropriate RPS trip logic is satisfied, as described in the Bases for LCO 3.3.1.1, "Reactor Protection System (RPS) Instrumentation."

Only the period based detection algorithm is used for safety analysis. The remaining algorithms provide defense in depth and additional protection against unanticipated oscillations.

The period based-detection algorithm detects a stability related oscillation based on the occurrence of a fixed number of consecutive LPRM signal period confirmations coincident with the LPRM signal peak to average amplitude exceeding a specified setpoint. Upon detection of a stability related oscillation, a trip is generated for that OPRM channel.

(continued)

LaSalle 1 and 2 B 3.3.1.3-1 Revi sion

OPRM Instrumentation B 3.3.1.3 BASES BACKGROUND The OPRM System consists of 4 OPRM trip channels, each (continued) channel consisting of two OPRM modules. Each OPRM module receives input from LPRMs. Each OPRM module also receives input from the RPS average power range monitor (APRM) power and flow signals to automatically enable the trip function of the OPRM module. The outputs of the OPRM trip channels input to the associated RPS trip channels which are configured into a one-out-of-two taken twice trip logic as described in the Bases for Section 3.3.1.1.

Each OPRM module is continuously tested by a self-test function. On detection of any OPRM module failure, either a Trouble alarm or INOP alarm is activated. The OPRM module provides an INOP alarm when the self-test feature indicates that the OPRM module may not be capable of meeting its functional requirements.

APPLICABLE It has been shown that BWR cores may exhibit SAFETY ANALYSES thermal-hydraulic reactor instabilities in high power and low flow portions of the core power to flow operating domain (Reference 4). GDC 10 requires the reactor core and associated coolant, control, and protection systems to be designed with appropriate margin to assure that acceptable fuel design limits are not exceeded during any condition of normal operation, including the effects of anticipated operational occurrences. GDC 12 requires assurance that power oscillations which can result in conditions exceeding acceptable fuel design limits are either not possible or can be reliably and readily detected and suppressed. The OPRM System provides compliance with GDC 10 and GDC 12 by detecting the onset of oscillations and suppressing them by initiating a reactor scram. This assures that the MCPR safety limit will not be violated for anticipated oscillations.

The OPRM Instrumentation satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii).

The OPERABILITY of the OPRM System is dependent on the OPERABILITY of the four individual instrumentation channels with their setpoints within the specified nominal setpoint.

Each channel must also respond within its assumed response time.

(continued)

LaSalle 1 and 2 B 3.3.1.3-2 Revi sion

OPRM Instrumentation B 3.3.1.3 BASES APPLICABLE The nominal setpoints for the OPRM Period Based Trip SAFETY ANALYSES Function are specified in the Core Operating Limits Report.

(continued) The trip setpoints are treated as nominal setpoints and do not require additional allowances for uncertainty.

Trip setpoints are those predetermined values of output at which an action should take place. The setpoints are compared to the actual process parameter value and when the measured output value of the process parameter exceeds the setpoint, the associated device (e.g., trip unit) changes state.

The OPRM period based setpoint is determined by cycle specific analysis based on positive margin between the Safety Limit MCPR and the Operating Limit MCPR minus the change in CPR (ACPR). This methodology was approved for use by the NRC in Reference 5.

LCO Four channels of the OPRM System are required to be OPERABLE to ensure that stability related oscillations are detected and suppressed prior to exceeding the MCPR safety limit.

Only one of the two OPRM modules (with an active period based detection algorithm) is required for OPRM channel OPERABILITY. The minimum number of LPRMs required to.

maintain the APRM system OPERABLE per LCO 3.3.1.1 provides an adequate number of LPRMs to maintain an OPRM channel OPERABLE.

APPLICABILITY The OPRM instrumentation is required to be OPERABLE in order to detect and suppress neutron flux oscillations in the event of thermal-hydraulic instability. As described in References 1, 2, 3, and 9, the region of anticipated oscillation is defined by THERMAL POWER > 28.6% rated thermal power (RTP) and recirculation drive flow < 60% of (continued)

LaSalle 1 and 2 B 3.3.1.3-3 Revi sion

OPRM Instrumentation B 3.3.1.3 BASES APPLICABILITY rated recirculation drive flow. The OPRM trip is required (continued) to be enabled in this region, and the OPRM must be capable of enabling the trip function as a result of anticipated transients that place the core in that power/flow condition.

Therefore the OPRM instrumentation is required to be OPERABLE with THERMAL POWER > 2596 RTP. It is not necessary for the OPRM instrumentation to be OPERABLE with THERMAL POWER < 25% RTP because the MCPR safety limit is not applicable below 25% RTP.

ACTIONS Note 1 has been provided to modify the ACTIONS related to the OPRM instrumentation channels. Section 1.3 Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition discovered to be inoperable or not within limit will not result in separate entry into the Condition. Section 1.3 also specifies that Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for inoperable OPRM instrumentation channels provide appropriate compensatory measures for separate inoperable channels. As such, a Note has been provided that allows separate Condition entry for each inoperable OPRM instrumentation channel.

Note 2 allows delayed entry into the Conditions and Required Actions when OPRM channels are inoperable due to APRM indication not within limits in accordance with SR 3.3.1.1.2. This entry into associated Conditions and Required Actions may to be delayed for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months if the APRM is indicating a lower power value (i.e., the gain adjustment factor (GAF) is high (nonconservative)), and for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months if the APRM is indicating a higher power value than the calculated power (i.e., the GAF is low (conservative)). The GAF for any APRM is defined as the power value determined by the heat balance divided by the APRM reading for that channel. Upon completion of the gain adjustment, or expiration of the allowed time, the OPRM channel must be returned to OPERABLE status or the applicable Condition entered and the Required Actions taken.

This Note is consistent with the ACTIONS (continued)

LaSalle I and 2 B 3.3.1.3-4 Revision

OPRM Instrumentation B 3.3.1.3 BASES ACTIONS Note in Specification 3.3.1.1 and is based on the time (continued) required to perform gain adjustments on multiple APRM channels; additional time is allowed when the GAF is out of limits but conservative. This note is applicable to the OPRM instrumentation, since the APRM system provides input to enable the OPRM modules at the designated enable setpoint.

A.1. A.2. and A.3 Because of the reliability and on-line self-testing of the OPRM instrumentation and the redundancy of the RPS design, an allowable out of service time of 30 days has been shown to be acceptable (Ref. 6) to permit restoration of any inoperable channel to OPERABLE status. However, this out of service time is only acceptable provided the OPRM instrumentation still maintains OPRM trip capability (refer to Required Actions B.1 and B.2 Bases). The remaining OPERABLE OPRM channels continue to provide trip capability (see Condition B). The remaining OPRM modules have high reliability. With this high reliability, there is a low probability of a subsequent channel failure within the allowable out of service time. In addition, the OPRM modules continue to perform on-line self-testing and alert the operator if any further system degradation occurs.

If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the OPRM channel or associated RPS trip system must be placed in the tripped condition per Required Actions A.1 and A.2. Placing the inoperable OPRM channel in trip (or the associated RPS trip system in trip) would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue. Alternately, if it is not desired to place the OPRM channel (or RPS trip system) in trip, the alternate method of detecting and suppressing thermal hydraulic instability oscillation is required (Required Action A.3). This alternate method is described in Reference 7. It consists of avoidance of the region where oscillations are possible, exiting this region if it is entered due to unforeseen circumstances, and increased operator awareness and monitoring for neutron flux oscillations while taking action to exit the region. If indications of oscillation, as described in Reference 7, are (continued)

LaSalle I and 2 B 3.3.1.3-5 Revi sion

OPRM Instrumentation B 3.3.1.3 BASES ACTIONS A.1. A.2. and A.3 (continued) observed by the operator, the operator will take the actions described by procedures, which include initiating a manual scram of the reactor. Continued operation with one OPRM channel inoperable, but not tripped, is permissible if the OPRM system maintains trip capability, since the combination of the alternate method and the OPRM trip capability provides adequate protection against oscillations.

B.1 and B.2 Required Action B.1 is intended to ensure that appropriate actions are taken if multiple, inoperable, untripped OPRM channels within the same RPS trip system result in not maintaining OPRM trip capability. The OPRM trip function is considered to be maintained when sufficient OPRM channels are OPERABLE or in trip (or the associated RPS trip system is in trip), such that both trip systems will generate a trip signal from the OPRM Period Based Trip Function on a valid signal.

Because of the low probability of the occurrence of an instability, 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is an acceptable time to initiate the alternate method of detecting and suppressing thermal hydraulic instability oscillations described in Required Action A.3 above. The alternate method of detecting and suppressing thermal hydraulic instability oscillations avoids the region where oscillations are possible and would adequately address detection and mitigation in the event of instability oscillations. Based on industry operating experience with actual instability oscillations, the operator would be able to recognize instabilities during this time and take action to suppress them through a manual scram. Since plant operation is minimized in areas where oscillations may occur, operation for 120 days without OPRM trip capability is considered acceptable with implementation of an alternate method of detecting and suppressing thermal hydraulic instability oscillations.

(continued)

LaSalle 1 and 2 B 3.3.1.3-6 Revi sion

OPRM Instrumentation B 3.3.1.3 BASES ACTIONS C. 1 (continued)

With any Required Action and associated Completion Time not met, the plant must be placed in a MODE or other specified condition in which the LCO does not apply. To achieve this status, THERMAL POWER must be reduced to < 25% RTP within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . Reducing THERMAL POWER to < 25% RTP places the plant in a region where instabilities cannot occur. The 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months is reasonable, based on operating experience, to reduce THERMAL POWER < 25% RTP from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE The Surveillances are modified by a Note to indicate that, REQUIREMENTS when a channel is placed in an inoperable status solely for the performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , provided the associated Function maintains trip capability. Upon completion of the Surveillance, or expiration of the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken.

This Note is based on the RPS reliability analysis (Ref. 8) assumption of the average time required to perform channel surveillance. That analysis demonstrated that the 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months testing allowance does not significantly reduce the probability that the RPS will trip when necessary.

SR 3.3.1.3.1 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the channel will perform the intended function. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions.

A Frequency of 184 days provides an acceptable level of system average unavailability over the Frequency interval and is based on the reliability analysis (Ref. 6).

(continued)

LaSalle 1 and 2 B 3.3.1.3-7 Revi sion

OPRM Instrumentation B 3.3.1.3 BASES SURVEILLANCE SR 3.3.1.3.2 REQUIREMENTS (continued) The CHANNEL CALIBRATION is a complete check of the instrument loop. This test verifies the channel responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations, consistent with the plant specific setpoint methodology.

Calibration of the channel provides a check of the internal reference voltage and the internal processor clock frequency. It also compares the desired trip setpoint with those in the processor memory. Since the OPRM is a digital system, the internal reference voltage and processor clock frequency are, in turn, used to automatically calibrate the internal analog to digital converters. The nominal setpoints for the period based detection algorithm are specified in the COLR. As noted, neutron detectors are excluded from CHANNEL CALIBRATION because of difficulty of simulating a meaningful signal. Changes in neutron detector sensitivity are compensated for by performing the 1000 effective full power hour (EFPH) calibration against the TIPs (SR 3.3.1.1.8). SR 3.3.1.1.8 thus also ensures the operability of the OPRM instrumentation.

The nominal setpoints for the OPRM trip function for the period based detection algorithm (PBDA) are specified in the Core Operating Limits Report. The PBDA trip setpoints are the number of confirmation counts required to permit a trip signal and the peak to average amplitude required to generate a trip signal.

The Frequency of 24 months is based upon the assumption of the magnitude of equipment drift provided by the equipment supplier (Ref. 6).

SR 3.3.1.3.3 -

The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required trip logic for a specific channel. The functional testing of control rods, in LCO 3.1.3, "Control Rod OPERABILITY," and scram discharge volume (SDV) vent and drain valves, in LCO 3.1.8, "Scram Discharge Volume (SDV) Vent and Drain Valves," overlaps this (continued)

LaSalle 1 and 2 B 3.3.1.3-8 Revi sion

___- ~----O-R--Instrumentation_

OPRM Instrumentation B 3.3.1.3 BASES SURVEILLANCE SR 3.3.1.3.3 (continued)

REQUIREMENTS Surveillance to provide complete testing of the assumed safety function. The OPRM self-test function may be utilized to perform this testing for those components that it is designed to monitor.

The 24 month Frequency is based on engineering judgment and reliability of the components. Operating experience has shown these components usually pass the surveillance when performed at the 24 month Frequency.

SR 3.3.1.3.4 This SR ensures that trips initiated from the OPRM System will not be bypassed (i.e., fail to enable) when THERMAL POWER is 2 28.6% RTP and recirculation drive flow is < 60%

of rated recirculation drive flow. This normally involves calibration of the bypass channels. The 28.6% RTP value is the plant specific value for the enable region, as described in Reference 9.

These values have been conservatively selected so that specific, additional uncertainty allowances need not be applied. Specifically, for THERMAL POWER, the Average Power Range Monitor (APRM) establishes the reference signal to enable the OPRM system at 28.6% RTP. Thus, the nominal setpoints corresponding to the values listed above (28.6% of RTP and 60% of rated recirculation drive flow) will be used to establish the enabled region of the OPRM System trips.

(References 1, 2, 5, 9, and 11)

If any bypass channel setpoint is nonconservative (i.e., the OPRM module is bypassed at 2 28.6% RTP and < 60% of rated recirculation drive flow), then the affected OPRM module is considered inoperable. Alternately, the bypass channel can be placed in the conservative condition (nonbypass). If placed in the nonbypass condition, this SR is met and the module is considered OPERABLE.

The Frequency of 24 months is based on engineering judgment and reliability of the components.

(continued)

LaSalle 1 and 2 B 3.3.1.3-9 Revi sion

OPRM Instrumentation B 3.3.1.3 BASES SURVEILLANCE SR 3.3.1.3.5 REQUIREMENTS (continued) This SR ensures that the individual channel response times are less than or equal to the maximum values assumed in the accident analysis. The OPRM self-test function may be utilized to perform this testing for those components it is designed to monitor. The RPS RESPONSE TIME acceptance criteria are included in Reference 10.

RPS RESPONSE TIME may be verified by actual response time measurements in any series of sequential, overlapping, or total channel measurements. As noted, neutron detectors are excluded from RPS RESPONSE TIME testing because the principles of detector operation virtually ensure an instantaneous response time. RPS RESPONSE TIME tests are conducted on a 24 month STAGGERED TEST BASIS. This Frequency is consistent with the refueling cycle and is based upon operating experience, which shows that random failures of instrumentation components causing serious time degradation, but not channel failure, are infrequent.

REFERENCES 1. NEDC-39160, "BWR Owners Group Long-Term Stability Solutions Licensing Methodology," June 1991.

2. NEDO-31960, "BWR Owners Group Long-Term Stability Solutions Licensing Methodology," Supplement 1, March 1992.

3. NRC Letter, A. Thadani to L. A. England, "Acceptance for Referencing of Topical Report NEDO-31960, Supplement 1, 'BWR Owners Group Long-Term Stability Solutions Licensing Methodology,'" July 12, 1994.

4. Generic Letter 94-02, "Long-Term Solutions and Upgrade of Interim Operating Recommendations for Thermal-Hydraulic Instabilities in Boiling Water Reactors,"

July 11, 1994.

5. NEDO-32465-A, "BWR Owners Group Reactor Stability Detect and Suppress Solution Licensing Basis Methodology and Reload Application," August 1996.

(continued)

LaSalle I and 2 B 3.3.1.3-10 Revision

OPRM Instrumentation B 3.3.1.3 BASES REFERENCES 6. CENPD-400-P, Rev. 01, "Generic Topical Report for the (continued) ABB Option III Oscillation Power Range Monitor (OPRM)," May 1995.

7. BWROG Letter BWROG-9479, "Guidelines for Stability Interim Correction Action," June 6, 1994.

8. NEDC-30851-P-A, "Technical Specification Improvement Analyses for BWR Reactor Protection System,"

March 1988.

9. NEDC-32701P, "Power Uprate Safety Analysis Report for LaSalle County Station Units 1 and 2," Revision 2.

10. Technical Requirements Manual.

11. Letter from K. P. Donovan (BWR Owners' Group) to U. S.

NRC, "Guidelines for Stability Option III 'Enabled Region,'" dated September 17, 1996.

.Aq LaSalle 1 and 2 B 3.3.1.3-11 Revision

Reci rcul ation Loops Operating B 3.4.1 BASES BACKGROUND The subcooled water enters the bottom of the fuel channels (continued) and contacts the fuel cladding, where heat is transferred to the coolant. As it rises, the coolant begins to boil, creating steam voids within the fuel channel that continue until the coolant exits the core. Because of reduced moderation, the steam voiding introduces negative reactivity that must be compensated for to maintain or to increase reactor power. The recirculation flow control allows operators to increase recirculation flow and sweep some of the voids from the fuel channel, overcoming the negative reactivity void effect. Thus, the reason for having variable recirculation flow is to compensate for reactivity effects of boiling over a wide range of power generation (i.e., approximately 65 to 100% RTP) without having to e rods and disturb desirable flux patter normally maintaied 5uch that core thcrm2 hydi lic l

-..ecirculation loop, and no recirculation loop 3peratii.

UtlIIU vetdcr and NRC IczuIeInded requiremcnts and a'ouii ulto

'iI"ill;ize lthe-pJuleL idl ur co the 1 wal -Ilyurdul Each recirculation loop is manually started from the control room. The recirculation flow control valves provide regulation of individual recirculation loop drive flows.

The flow in each loop can be manually or automatically controlled.

APPLICABLE The operation of the Reactor Recirculation System is SAFETY ANALYSES an initial condition assumed in the design basis loss of coolant accident (LOCA) (Ref. 1). During a LOCA caused by a recirculation loop pipe break, the intact loop is assumed to provide coolant flow during the first few seconds of the accident. The initial core flow decrease is rapid because the recirculation pump in the broken loop ceases to pump reactor coolant to the vessel almost immediately. The pump in the intact loop coasts down relatively slowly. This pump coastdown governs the core flow response for the next several seconds until the jet pump suction is uncovered (Ref. 2). The analyses assume that both loops are operating at the same flow prior to the accident. However, the LOCA (continued)

LaSalle 1 and 2 B 3.4.1-2 Revi s ion

Recirculation Loops Operating B 3.4.1 BASES APPLICABLE analysis was reviewed for the case with a flow mismatch SAFETY ANALYSES between the two loops, with the pipe break assumed to be in (continued) the loop with the higher flow. While the flow coastdown and core response are potentially more severe in this assumed case (since the intact loop starts at a lower flow rate and the core response is the same as if both loops were operating at a lower flow rate), a small mismatch has been determined to be acceptable based on engineering judgement.

The recirculation system is also assumed to have sufficient flow coastdown characteristics to maintain fuel thermal margins during abnormal operational transients (Ref. 2),

which are analyzed in Chapter 15 of the UFSAR.

A plant specific LOCA analysis has been performed assuming only one operating recirculation loop. This analysis has demonstrated that, in the event of a LOCA caused by a pipe break in the operating recirculation loop, the Emergency Core Cooling System response will provide adequate core cooling, provided the APLHGR requirements are modified accordingly (Ref. 3).

The transient analyses in Chapter 15 of the UFSAR have also been performed for single recirculation loop operation (Ref. 3) and demonstrate sufficient flow coastdown characteristics to maintain fuel thermal margins during the abnormal operational transients analyzed provided the MCPR requirements are modified. During single recirculation loop operation, modification to the Reactor Protection System average power range monitor (APRM) and the Rod Block Monitor (RBM) Allowable Values is also required to account for the different relationships between recirculation drive flow and reactor core flow. The APLHGR and MCPR limits for single loop operation are specified in the COLR. The APRM Flow Biased Simulated Thermal Power-Upscale Allowable Value is in LCO 3.3.1.1, "Reactor Protection System (RPS)

Instrumentation." The Rod Bloc, Monitor-Upscale Allowable Value is spcified inc n Laaareeian2 3.4.1-3 Revi power/low (continued)

LaSalle 1 and 2 B 3.4.1-3 -Revision

Recirculation Loops Operating B 3.4.1 BASES APPLICABLE neral Electric ervice Information Letter L .

SAFETY ANALYSES l380 (Re. 4) addre sed boiling instability and made several (continued) recomm ndations. In this SIL, the power! low operating map was dyvided in s'everal regions of vary ng concern. It also discusse the objectives and philo ophy of "detect and sup ress."

lNC Generi Letter 86-02 (Ref. 5) d cussed both the GE d iemens st bility methodology and tated that due to uncertain ies, 10 CFR 50, Appendi A, General Design Criteria (GDC) 10 and 12 could t be met using avai able analyti al procedures on a BWR The Generic Letter discus ed SIL 380 and stated hat GDC 10 and 12 c id be met by im osing SIL 380 recomme dations in operating regions of pot tial instability. T NRC concluded that egions of p ential instability co stituted decay ratio of 0.8 and greater by the GE metho ology and 0.75 by th Siemens methodology. Figure 3.4.1-1 was generated/s an interim solution to provide increased margin o safety until the investigation is completed (Ref. 6)

Recirculation loops operating satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).

LCO Two recirculation loops are normally required to be in operation with their flows matched within the limits specified in SR 3.4.1.1 to ensure that during a LOCA caused by a break of the piping of one recirculation loop the assumptions of the LOCA analysis are satisfied. With the limits specified in SR 3.4.1.1 not met, the recirculation loop with the lower flow must be considered not in operation. With only one recirculation loop in operation, modifications to the required APLHGR limits (LCO 3.2.1, "AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)"), MCPR limits (LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)"),

APRM Flow Biased Simulated Thermal Power-Upscale Allowable Value (LCO 3.3.1.1), and the Rod Block Monitor-Upscale Allowable Value (LCO 3.3.2.1) must be applied to allow continued operati of Reference 3.

(continued)

LaSalle 1 and 2 B 3.4.1-4 Revision

Recirculation Loops Operating B 3.4.1 BASES APPLICABILITY In MODES 1 and 2, requirements for operation of the Reactor Recirculation System are necessary since there is considerable energy in the reactor core and the limiting design basis transients and accidents are assumed to occur.

In MODES 3, 4, and 5, the consequences of an accident are reduced and the coastdown characteristics of the recirculation loops are not important.

ACTIONS . . and A/

With on ,or two recirculation loops in operation in Region II of F gure 3.4.1-1, t e plant is operating n a region where he potential fo thermal-hydraulic os illations exis s. To ensure os 1 ations are not occ rring, APRM and LPR neutron flux noi e evels must be ver fied to be less th or equal to th lar er of either 3 mines the baseline no se levels or 10 peak to-peak (Requir d Action A.1 and A 2) when Region I is e tered. For th/ LPRM neutron flux oise verificatio , dete tor levels A Xnd C of one LPRM tring per core ctant lus detector evels A and C of one LPRM string in he center region of he core should be monitored. Pr pt action to monito APRM and LPRM neutron flux noise lev ls should be taken o ensure oscillations re not occurring The 45 minu e Completion Time Required Actions A.1 and A.2 providd a reasonable tim to stabilize operatio in Region II nd verify the neu on flux noise levels re within li its. A verificat'n of the APRM and LP neutron flux noi e levels once per 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months following th initial verific tion provides fre uent periodic informa ion of neutro flux noise level to verify stable stady state oper ion. Also, a ver/fication of neutron lux noise lev s after any THER AL POWER increase of - 5Z RTP while in Re ion II provides Addication of operational stability following a potential for change of the thermal-hydraulic roperties of the system.

(continued)

LaSalle 1 and 2 B 3.4.1-5 Revisio 1

INSERT A A.1 With no recirculation loops in operation, 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 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . In this condition, the recirculation loops are not required to be operating because of the reduced severity of design basis accidents and minimal dependence on the recirculation loop coastdown characteristics. The allowed Completion Time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is reasonable, based on operating experience to reach MODE 3 from the full power condition in an orderly manner and without challenging plant systems.

Recirculation Loops Operating B 3.4.1 BASES ACTIONS A Caontinued)

In a dition, a ver'fication that one or oth recirculation loo are not op ating within Region of Figure 3.4.1-1 (R uired Actio A.3) is required to e performed once pear 1 hours1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . The/Completion Time of o e per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is /

easonable bred on operating exper ence and the operator's knowledge o reactor status, inc ding changes in reactor power and ore flow.

If idence of approaching eactor instability occ s (i.e.,

AP or LPRM neutron flux oise levels exceed th associated 1 mit of Required Action A.1 or A.2, as applic le) while perating in Region II f Figure 3.4.1-1, prom t action should be taken to res ore the APRM or LPRM utron flux noise levels to withi the associated limit/or exit Region I! of Figure 3.4.1-1 This may be accompl shed by either increasing core flo by recirculation 10 flow control valve manipulation or reduction of THER AL POWER by contr rod insertion. T e 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Completion ime is reasonabl to restore plant pa ameters in an orderl manner and with ut challenging pla t systems. /

With one r both recirculation loops in opera on in Region I of Fig re 3.4.1-1, the plan is operating n a region where t e potential for ther al-hydraulic scillations is increa ed and sufficient m gin may not available for oper or response to supp ess potential hermal-hydraulic osc0 lations. As a res t, prompt ac on should be taken to ex.r Region I of Figur 3.4.1-1. Th' may be accomplished y either increasing ore flow by r circulation loop flow control valve manip lation or red tion of THERMAL POWER y control rod inser on. The 2 ho Completion Time is reasonable to re tore plant par meters in an orderly anner and without cha lenging plan stem,;

(continued)

LaSalle 1 and 2 B 3.4.1-6 Revision

Recirculation Loops Operating B 3.4.1 BASES

-7/

ACTIONS D.1.D.2.and D.3 (continued)

With no re rculation loo in service Ahe probability of the rm al- ~raulic oscill kons is grea y increased.

Therefo~e prompt actio should be ta en to ensure/

oscill tions are not occurring by ye ifying APRM and LPR neutr n flux noise le els are < 10X peak-to-peak. If neu ron flux noise 1Ivels are disc vered to be > 10%

pe k-to-peak at an ime while in his Condition, Cond tion E st be immediate y entered.

Also, prompt ac on should be aken to reduce THE AL POWER low enough to void the regio of potential inst bility in natural circu ation (i.e., r duce THERMAL POWE below 36%

RTP). The 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Completio Time provides ar reasonable time to res ore operation o Region III of F gure 3.4.1-1.

In additi n, with no rec rculation loops n operation, plan operatio is not allowe to continue in ODE 1 or 2.

Therefo e, the unit is/required to be ought to a MODE which he LCO does no apply. The al owed Completion T me of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is reaso able, based on perating experie e, to rea MODE 3 in an rderly manner d without challe ging pl tsystems. ///

In the event/no recirculatio loops are in o eration and evidence is/indicated of ap roaching react instability (i.e., AP or LPRM neutro flux noise le els exceed the associat limit) or APR or LPRM neutr flux noise leve)s cannot e restored with' 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months whil in Region II of Figur 3.4.1-1, action ust be immedi tely initiated elimi ate the potenti for a therm -hydraulic ins bility ev t. As such, th reactor mode witch must be mediately wn position (continued)

LaSalle 1 and 2 B 3.4.1-7 nj Revi si on V)

Recirculation Loops Operating B 3.4.1 BASES ACTIONS i.1 andi.1 (continued)

With both recirculation loops operating but the flows not matched, the flows must be matched within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months . If matched flows are not restored, the recirculation loop with lower flow must b declared "not in operation," as required Dy Required Acti o

_ ).1. This Required Action does not require tripping the recirculation pump in the lowest flow loop when the mismatch between total jet pump flows of the two loops is greater than the required limits. However, in cases where large flow mismatches occur, low flow or reverse flow can occur in the low flow loop jet pumps, causing vibration of the jet pumps. If zero or reverse flow is detected, the condition should be alleviated by changing flow control valve position to re-establish forward flow or by tripping the pump-g With the requireme of he LCO not met for reasons other than Conditions A'c:-nf (e.g., one loop is "not in operation"), compliance with the LCO must be restored within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . A recirculation loop is considered not in operation when the pump in that loop is idle or when the mismatch between total jet pump flows of the two loops is greatpL than reqpiired limits for greater than 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months (i.e.,

-- ~----PRequired Actioi

.1 has been taken). Should a LOCA occur with one recirculation loop not in operation, the core flow coastdown and resultant core response may not be bounded by the LOCA analyses. Therefore, only a limited time is allowed to restore the inoperable loop to operating status.

Alternatively, if the single loop requirements of the LCO are applied to the APLHGR and MCPR operating limits and RPS and RBM Allowable Values, operation with only one recirculation loop would satisfy the requirements of the LCO and the initial conditions of the accident sequence.

The 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months and 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Times are based on the low probability of an accident occurring during this time period, on a reasonable time to complete the Required Action, and on frequent core monitoring by operators allowing abrupt changes in core flow conditions to be quickly detected.

(continued)

LaSalle II and 2 B 3.4.1-8 Revisione

Recirculation Loops Operating B 3.4.1 BASES ACTIONS (continued)

If the Re jred Action and associated Completion Time of Condition ( is not met, the unit is required to be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

In this condition, the recirculation loops are not required to be operating because of the reduced severity of DBAs and minimal dependence on the recirculation loop coastdown characteristics. The allowed Completion Time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.4.1.1 REQUIREMENTS This SR ensures the recirculation loop flows are within the allowable limits for mismatch. At low core flow (i.e.,

< 70% of rated core flow), the APLHGR and MCPR requirements provide larger margins to the fuel cladding .integrity Safety Limit such that the potential adverse effect of early boiling transition during a LOCA is reduced. A larger flow mismatch can therefore be allowed when core flow is < 70% of rated core flow. The recirculation loop jet pump flow, as used in this Surveillance, is the summation of the flows from all of the jet pumps associated with a single recirculation loop.

The mismatch is measured in terms of percent of rated core flow. If the flow mismatch exceeds the specified limits, the loop with the lower flow is considered not in operation.

This SR is'not required when both loops are not in operation since the mismatch limits are meaningless during single loop or natural circulation operation.. The Surveillance must be performed within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after both loops are in operation.

The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is consistent with the Frequency for jet pump OPERABILITY verification and has been shown by operating experience to be adequate to detect off normal jet pump loop flows in a timely manner.

(continued)

LaSalle 1 and 2 B 3.4.1-9 Revi si on V

Recirculation Loops Operating B 3.4.1 BASES SURVEILLANCE R 4 el./

REQUIREMENTS (continued) The R ensures the ombination of cor flow and THERMAL PO R are within he appropriate ii ts to prevent advertent entr into a region of/potential thermal-hydrau ic instability. low recirculation oop flow and high reactor power, th reactor exhibits i creased susceptibili y to thermal-hyd aulic instability. /I Figure 3.4 -1 is based on idance provided in eferences 4 and 5. T e 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Freq ncy is based on oper ing experiece and the oper tor's knowledge of t reactor status, including si ificant changes in T RMAL POWER and REFERENCES 1. UFSAR, Sections 6.3 and 15.6.5.

2. UFSAR, Appendix G.3.1.2.

3. UFSAR, Section 6.B.

GE Servige Information Letter (S No. 380, "BWR ore Thermal/ ydraulic Stability," R vision 1, February 10,

5. NRC Gen ic Letter 86-02, " echnical Resolution of Ge eric Issue B-19, Therm Hydraulic Stability,"

nuary 22, 1986. //

6. NRC Safety Evaluation supporting Amendment No. 60 to Facility Operating cense No. 11 and Amendm t No. 40 to Facility Opera ng License No. 18, Comm wealth Edison Company, aSalle County Station its 1 and 2, emb 1988.

LaSalle 1 and 2 B 3.4.1-10 Revisio

RS-04-069, License Amendment Request Activation of the Trip Outputs of the Oscillation Power Range Monitor System

Contents

Text

Subject:

Reference:

1.0 DESCRIPTION

2.0 PROPOSED CHANGE

3.0 BACKGROUND

4.0 TECHNICAL ANALYSIS

5.0 REGULATORY ANALYSIS

6.0 ENVIRONMENTAL CONSIDERATION

7.0 REFERENCES

1.0 DESCRIPTION

2.0 PROPOSED CHANGE

3.0 BACKGROUND

4.0 TECHNICAL ANALYSIS

Response

Response

Response

Response

Response

Response

Response

Response

Response

Response

Response

5.0 REGULATORY ANALYSIS

6.0 ENVIRONMENTAL CONSIDERATION

7.0 REFERENCES

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RS-04-069, License Amendment Request Activation of the Trip Outputs of the Oscillation Power Range Monitor System

Text

Subject:

Reference:

1.0 DESCRIPTION

2.0 PROPOSED CHANGE

3.0 BACKGROUND

4.0 TECHNICAL ANALYSIS

5.0 REGULATORY ANALYSIS

6.0 ENVIRONMENTAL CONSIDERATION

7.0 REFERENCES

1.0 DESCRIPTION

2.0 PROPOSED CHANGE

3.0 BACKGROUND

4.0 TECHNICAL ANALYSIS

Response

Response

Response

Response

Response

Response

Response

Response

Response

Response

Response

5.0 REGULATORY ANALYSIS

6.0 ENVIRONMENTAL CONSIDERATION

7.0 REFERENCES

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