Text

License Amendment Request (LAR) Pursuant to 10 CFR 50.90: Extended Power Uprate
	ML091610103
Person / Time
Site:	Nine Mile Point
Issue date:	05/27/2009
From:	Polson K; Constellation Energy Group
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	Download: ML091610103 (79)
	v • d • e

This letter forwards proprietary information in accordance with 10 CFR 2.390. The balance of this letter may be considered non-proprietary upon removal of Attachments 11, 13.1, 13.2, 13.3 & 13.4.

Keith J. Poison Vice President-Nine Mile Point P.O. Box 63 Lycoming, New York 13093 315.349.5200 315.349.1321 Fax Constellation Nine Energy Mile Point Nuclear Station May 27, 2009 U. S. Nuclear Regulatory Commission Washington, DC 20555-0001 ATTENTION: Document Control Desk

SUBJECT:

Nine Mile Point Nuclear Station Unit No. 2; Docket No. 50-410 License Amendment Request (LAR) Pursuant to 10 CFR 50.90: Extended Power T 1nr tA Pursuant to 10 CFR 50.90, Nine Mile Point Nuclear Station, LLC (NMPNS) hereby requests an amendment to Nine Mile Point Unit 2 (NMP2) Renewed Operating License (OL) NPF-69. The proposed amendment would increase the power level authorized by OL Section 2.C.(1), Maximum Power Level, from 3467 megawatts-thermal (MWt) to 3988 MWt. The new maximum power level represents an increase of 20 percent from the Original Licensed Thermal Power level of 3323 MWt and an increase of 15 percent from the Current Licensed Thermal Power level of 3467 MWt. NMP2 Amendment No. 66, dated April 28, 1995, approved a Stretch Power Uprate authorizing the increase from 3323 MWt to 3467 MWt.

The Enclosure and its associated Attachments to this application provide the evaluation of the proposed changes to NMP2 OL Section 2.C.(1) and other affected license conditions and Technical Specifications.

As indicated in the Enclosure, NMPNS has concluded that the activities associated with the proposed changes represent no significant hazards consideration under the standards set forth in 10 CFR 50.92.

NMPNS requests approval of this application in 18 months with implementation upon startup from the spring 2012 refueling outage. This submittal contains no regulatory commitments.

Pursuant to 10 CFR 50.91(b)(1), NMPNS has provided a copy of this license amendment request, with Enclosure, to the appropriate state representative.

'9 This letter forwards proprietary information in accordance with 10 CFR 2.390. The balance of this letter may be considered non-proprietary upon removal of Attachments 11, 13.1, 13.2, 13.3 & 13.4.

AOO (

Document Control Desk May 27, 2009 Page 2 Should you have any questions regarding the information in this submittal, please contact T. F. Syrell, Licensing Director, at (315) 349-5219.

Very truly yours, STATE OF NEW YORK TO WIT:

COUNTY OF OSWEGO I, Keith J. Polson, being duly sworn, state that I am Vice President-Nine Mile Point, and that I am duly authorized to execute and file this License Amendment Request on behalf of Nine Mile Point Nuclear Station, LLC. To the best of my knowledge and belief, the statements contained in this document are true and correct. To the extent that these statements are not based on my personal knowledge, they are based upon information provided by other Nine Mile Point employees and/or consultants. Such information has been reviewed in accordance with company practice and I believe it to be reliable.

Subscribed and sworn before me, a Notary Public in and for the State of New York and County of Oswego, this 0L day of aw , ,2009.

WITNESS my Hand and Notarial Seal: /---- "

Notary Public My Commission Expires:

Date LISAM.AK Date NOt PubklcIn the Stite of NewYork gI oCounty Reg. No. 01 CL60292 KJP/KHJ

Enclosure:

Evaluation of the Proposed Change

Document Control Desk May 27, 2009 Page 3 cc: NRC Regional Administrator, Region I NRC Resident Inspector NRC Project Manager NYSERDA (w/o Attachments 11, 13.1, 13.2, 13.3 and 13.4 of Enclosure)

ENCLOSURE EVALUATION OF THE PROPOSED CHANGE TA13LE OF CONTENTS 1.0

SUMMARY

DESCRIPTION 2.0 DETAILED DESCRIPTION 2.1 Operating License 2.C.(1), 2.C.(7) Changes 2.2 Technical Specification Changes 2.3 Technical Specifications not Requiring Change

3.0 TECHNICAL EVALUATION

3.1 Operating License and Technical Specification Changes 3.2 Technical Specification Instrument Setpoint Changes

4.0 REGULATORY EVALUATION

4.1 Applicable Regulatory Requirements/Criteria 4.2 Significant Hazards Consideration 4.3 Conclusions

5.0 ENVIRONMENTAL CONSIDERATION

6.0 REFERENCES

Nine Mile Point Nuclear Station, LLC May 27, 2009

ENCLOSURE TABLE OF CONTENTS ATTACHMENTS

1. Operating License / Technical Specifications Page Markups

2. Technical Specifications Bases Page Markups (Information Only)

3. NEDO-33351, Safety Analysis Report for Nine Mile Point Nuclear Station Unit 2 Constant Pressure Power Uprate (PUSAR) (non-proprietary version)

4. Affidavit Justifying Withholding Proprietary Information in NEDC-33351P

5. Regulatory Commitments

6. Modifications to Support EPU

7. EPU Test Plan

8. Grid Stability Evaluation

9. Supplemental Environmental Report

10. Flow Induced Vibration - Piping / Component Evaluation

11. NEDC-33351P, Safety Analysis Report for Nine Mile Point Nuclear Station Unit 2 Constant Pressure Power Uprate (PUSAR) (proprietary version)

12. Affidavit Justifying Withholding Proprietary Information in the Steam Dryer Evaluation

13. Steam Dryer Evaluation 13.1 CDI Report No.08-24P (Proprietary), Stress Assessments of Nine Mile Point Unit 2 Steam Dryer 13.2 CDI Report No.08-08P (Proprietary), Acoustic and Low Frequency Hydrodynamic Loads at CLTP Power Level on Nine Mile Point Unit 2 Steam Dryer to 250 Hz 13.3 CDI Report No.08-13P (Proprietary), Flow-Induced Vibration in the Main Steam Lines at Nine Mile Point Unit 2 and Resulting Steam Dryer Loads 13.4 SIA calculation NMP-26Q-302 (Proprietary), Nine Mile Point Unit 2 Main Steam Line Strain Gage Data Reduction 13.5 SIA Report No. 0801273.401, Flaw Evaluation and Vibration Assessment of the Nine Mile Point Unit 2 Steam Dryer for Extended Power Uprate Operating Conditions 13.6 SIA Report No. 0800528.402, Nine Mile Point Unit 2 Steam Dryer ASME Stress Analysis 13.7 CDI Report No. 08-24NP (Non-proprietary), Stress Assessments of Nine Mile Point Unit 2 Steam Dryer 13.8 CDI Report No. 08-08NP (Non-proprietary), Acoustic and Low Frequency Hydrodynamic Loads at CLTP Power Level on Nine Mile Point Unit 2 Steam Dryer to 250 Hz 13.9 SIA calculation NMP-26Q-302 (Non-proprietary version), Nine Mile Point Unit 2 Main Steam Line Strain Gage Data Reduction Nine Mile Point Nuclear Station, LLC May 27, 2009

EVALUATION OF THE PROPOSED CHANGE 1.0

SUMMARY

DESCRIPTION The Nine Mile Point Unit 2 (NMP2) Operating License (OL) specifies the maximum power level at which NMP2 may be operated. The proposed amendment would increase the maximum power level authorized from 3467 megawatts-thermal (MWt) to 3988 MWt. The new maximum power level represents an increase of 20 percent from the Original Licensed Thermal Power (OLTP) level of 3323 MWt and an increase of 15 percent from the Current Licensed Thermal Power (CLTP) level of 3467 MWt. Nine Mile Point Unit 2 Amendment No. 66 dated April 28, 1995, approved a Stretch Power Uprate authorizing the increase from 3323 MWt to 3467 MWt.

Approval of the proposed amendment will allow Nine Mile Point Nuclear Station (NMPNS) to implement the operational and plant configuration changes necessary to generate and supply a higher steam flow to the turbine-generator. The higher steam flow will enable NMP2 to increase its gross rated generator output from 1211 megawatts-electric (MWe) to 1369 MWe. The current Extended Power Uprate (EPU) implementation plan consists of a phased approach to power increase and installation of plant modifications. A limited number of EPU related modifications were completed during the NMP2 2008 Refueling Outage with the remainder of the modifications scheduled to be completed during the 2010 and 2012 refueling outages. Power will not be increased until all required modifications are completed. Reactor Recirculation System (RCS) modifications or additional system maintenance may be performed during the 2014 refueling outage to optimize plant performance at EPU conditions, but are not necessary prior to power increase.

Technical Specifications (TS) Amendment No. 123, dated February 27, 2008, expanded the NMP2 operating domain by implementing Average Power Range Monitor / Rod Block Monitor /

Technical Specifications / Maximum Extended Load Line Limit Analysis (ARTS/MELLLA).

The ARTS/MELLLA Amendment expanded the power-to-flow map's operating domain to allow for plant operation at an increased thermal power level. TS Amendment No. 125, dated May 29, 2008, permits full implementation of the Alternative Source Term (AST) as described in Regulatory Guide 1.183, Alternative Radiological Source Terms for Evaluating Design Basis Accidents at Nuclear Power Reactors. The AST Evaluation was performed at the proposed EPU power level so that the Design Basis Accident analyses could accommodate this EPU submittal.

Attachment 1 to this Enclosure provides the marked-up OL and TS pages showing the proposed changes. Associated TS Bases changes are shown in Attachment 2. The Bases changes are provided for information only and will be processed in accordance with the NMP2 TS Bases Control Program as described in TS 5.5.10.

NEDO-33351, "Safety Analysis Report for Nine Mile Point Nuclear Station Unit 2 Constant Pressure Power Uprate (PUSAR)" (non-proprietary version), is provided as. Attachment 3. This report provides an integrated summary of the results of the safety analyses and evaluations performed that support the proposed increase in the maximum power level at NMP2. The PUSAR safety evaluation follows the format and guidance delineated in RS-001 (Revision 0),

Office of Nuclear Reactor Regulation, "Review Standard for Extended Power Uprates," to the extent that the review standard is consistent with the design basis of NMP2. For differences between the plant-specific design bases and RS-001 regulatory evaluation sections, the corresponding PUSAR safety evaluation regulatory evaluation section was revised to reflect the NMP2 design basis. As appropriate, the PUSAR's technical evaluations are based on NRC approved topical report NEDC-33004P-A, "Licensing Topical Report Constant Pressure Power Uprate," Revision 4 (CLTR).

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EVALUATION OF THE PROPOSED CHANGE A proprietary version of the PUSAR is provided as Attachment 11. This attachment is considered by GE-Hitachi Nuclear Energy (GEH) to contain proprietary information exempt from disclosure pursuant to 10 CFR 2.390. Therefore, on behalf of GEH, NMPNS hereby makes application to withhold this document from public disclosure in accordance with 10 CFR 2.390(b)(1). An affidavit executed by GEH detailing the reasons for the request to withhold the proprietary information is provided in Attachment 4.

Attachment 5 is provided for the regulatory commitments associated with the proposed change.

Because no commitments associated with this submittal were identified, this attachment has been retained as a placeholder only.

Plant modifications associated with EPU and their implementation schedule are listed in Attachment 6, Modifications to Support EPU. The EPU Test Plan, Attachment 7, specifies the planned EPU testing activities including a comparison to the initial NMP2 start-up testing program. The Grid Stability Evaluation, provided as Attachment 8, evaluates the impact of EPU on the transmission system stability. NMPNS's assessment of the environmental impacts of the proposed EPU is contained in Attachment 9, Supplemental Environmental Report. This Report was prepared pursuant to 10 CFR 51.41, "Regulations to Submit Environmental Information."

Attachment 10, Flow Induced Vibration (FIV) Piping / Component Evaluation, provides a review of plant system piping and components potentially affected by FIV under EPU conditions.

Attachment 13, Steam Dryer Evaluation, provides an evaluation and validation of the structural adequacy of the NMP2 steam dryers at EPU conditions. This attachment is considered by Continuum Dynamics Incorporated (CDI) to contain proprietary information exempt from disclosure pursuant to 10 CFR 2.390. Therefore, on behalf of CDI, NMPNS hereby makes application to withhold this document from public disclosure in accordance with 10 CFR 2.390(b)(1). An affidavit executed by CDI detailing the reasons for the request to withhold the proprietary information is provided in Attachment 12.

2.0 DETAILED DESCRIPTION 2.1 Operating License 2.C.(1), 2.C.(7) Changes Nine Mile Point Unit 2 OL Section 2.C.(1), Maximum Power Level, specifies the maximum power level at which NMP2 may be operated. By letter dated July 22, 1993, NMP2 applied for a Stretch Power Uprate to increase the maximum power level specified in OL Section 2.C.(1) from the OLTP level of 3323 MWt to 3467 MWt (104.3% of OLTP). That request was approved by Amendment No. 66 dated April 28, 1995. The purpose of this license amendment request is to increase the maximum power level specified in OL 2.C.(1) from the CLTP level of 3467 MWt to 3988 MWt. The new maximum power level represents an increase of 20 percent (i.e., an Extended Power Uprate) from the OLTP level of 3323 MWt and an increase of 15 percent from the CLTP level of 3467 MWt.

Operating License Section 2.C.(7), Operation with Reduced Feedwater Temperature (Section 15.1, SSER 4), states NMP2 shall not be operated with a feedwater heating capacity less than that required to produce a feedwater temperature of 405' F at steady-state conditions unless analyses supporting such operations are submitted by NMPNS and approved by the staff. The 405' F value will be revised to 420.50 F.

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EVALUATION OF THE PROPOSED CHANGE 2.2 Technical Specification (TS) Changes TS changes are required to support the increase in the authorized maximum power level delineated in OL Section 2.C.(l). A description of each TS change is provided below. As indicated, the majority of the proposed changes involve TS values that are expressed as a percentage of Rated Thermal Power (RTP). However, multiple TSs were also identified that contain values expressed in terms of a percentage of RTP that do not require revision to support EPU. To avoid any misunderstanding, these TSs are discussed in Section 2.3 with an explanation as to why a revision is unnecessary.

TS Section 1.1, Definitions - Rated Thermal Power Rated thermal power is currently defined as the total reactor core heat transfer rate to the reactor coolant (i.e., 3467 MWt). The stated CLTP value of 3467 MWt will be changed to 3988 MWt.

TS Section 2.1.1, Reactor Core Safety Limits (SLs)

TS Section 2.1.1.1 currently states that with the reactor steam dome pressure < 785 psig or core flow < 10 % rated core flow, Thermal Power shall be < 25 % RTP. The stated RTP percentage will be changed from < 25 % RTP to <23 % RTP.

TS Section 3.1.7, Standby Liquid Control (SLC) System TS Section 3.1.7, SLC System, Surveillance Requirement (SR) 3.1.7.7, requires verification that each pump develop a flow rate > 41.2 gpm at a discharge pressure of > 1325 psig. The stated discharge pressure will be changed from > 1325 psig to > 1327 psig.

TS Section 3.2.1, Average Planar Linear Heat Generation Rate (APLHGR)

TS Section 3.2.1, APLHGR Applicability, Actions, and Surveillance Requirements are dependent on a percentage of RTP (i.e., 25 % RTP). The stated RTP percentage will be changed from 25 % RTP to 23 % RTP.

TS Section 3.2.2, Minimum Critical Power Ratio (MCPR)

TS Section 3.2.2, MCPR Applicability, Actions, and Surveillance Requirements are dependent on a percentage of RTP (i.e., 25 % RTP). The stated RTP percentage will be changed from 25 % RTP to 23 % RTP.

TS Section 3.2.3, Linear Heat Generation Rate (LHGR)

TS Section 3.2.3, LHGR Applicability, Actions, and Surveillance Requirements are dependent on a percentage of RTP (i.e., 25 % RTP). The stated RTP percentage will be changed from 25 % RTP to 23 % RTP.

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EVALUATION OF THE PROPOSED CHANGE TS Section 3.3.1.1, Reactor Protection System (RPS) Instrumentation The following RPS Instrumentation Actions and Surveillance Requirements contained in TS Section 3.3.1.1, including Table 3.3.1.1-1, are dependent on a percentage of RTP and will be revised as shown:

Required Action E.1, which requires that Thermal Power be reduced to < 30 % RTP, will be revised to require that Thermal Power be reduced to < 26 % RTP.

The threshold for performing SR 3.3.1.1.3 (and associated Note) will be revised from > 25 %

RTP to > 23 % RTP.

The threshold for performing SR 3.3.1.1.15, Turbine Stop Valve-Closure and Turbine Control Valve Fast Closure, Trip Oil Pressure-Low Functions, will be revised from > 30%

RTP to > 26 % RTP.

The threshold for performing SR 3.3.1.1.16, Average Power Rage Monitor (APRM)

Oscillation Power Range Monitor (OPRM)-Upscale Function, will be revised from > 30%

RTP to > 26 % RTP.

Table 3.3.1.1-1, Function 2.b, Flow Biased Simulated Thermal Power-Upscale, contains both a flow-biased Allowable Value (AV) (< 0.64W + 63.8 % RTP) and a fixed AV clamped at 115.5 % RTP. The flow-biased AV will be changed to (< 0.55W + 60.5 % RTP). Note (b) modifies the Function 2.b AV when reset for single loop operation per Limiting Condition for Operation (LCO) 3.4.1, Recirculation Loops Operating. Note (b) will be revised to a value of 0.50(W - 5%) + 53.5 % RTP. W = Recirculation Drive Flow in percent of Rated Flow.

Table 3.3.1.1-1, Function 8, Turbine Stop Valve-Closure and Function 9, Turbine Control Valve Fast Closure, Trip Oil Pressure-Low, both specify an Applicable Mode or other Specified Conditions of > 30 % RTP. The > 30 % RTP value will be revised to > 26 % RTP.

The following notes will be added to the Table 3.3.1. 1-1 calibration surveillance requirements for the Flow Biased Simulated Thermal Power - Upscale function:

1. If the As-Found channel setpoint is outside its predefined as-found tolerances, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service.

2. The instrument channel setpoint shall be reset to a value that is within the As-Left tolerance around the nominal trip setpoint at the completion of the surveillance; otherwise, the channel shall be declared inoperable. Setpoints more conservative than the nominal trip setpoint are acceptable provided that the As-Found and As-Left tolerances apply to the actual setpoint implemented in the surveillance procedures to confirm channel performance. The nominal trip setpoint and the methodologies used to determine the As-Found and the As-Left tolerances are specified in the Bases associated with the specified function.

TS Section 3.3.2.2, Feedwater System and Main Turbine High Water Level Trip Instrumentation TS Section 3.3.2.2, Feedwater System and Main Turbine High Water Level Trip Instrumentation Applicability and Required Action C.2 are dependent on a percentage of RTP (i.e., 25 % RTP).

The stated RTP percentage will be changed from 25 % RTP to 23 % RTP.

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EVALUATION OF THE PROPOSED CHANGE TS Section 3.3.4.1, End of Cycle Recirculation Pump Trip (EGC - RPT) Instrumentation TS Section 3.3.4.1, End of Cycle Recirculation Pump Trip (EOC-RPT) Instrumentation Applicability, Actions, and Surveillance Requirements are dependent on a percentage of RTP (i.e,, 30 % RTP). The stated RTP percentages will be changed from 30 % RTP to 26 % RTP.

TS Table 3.3.6.1-1, Primary Containment Isolation Instrumentation TS Table 3.3.6.1-1, Primary Containment Isolation Instrumentation, Function I.c, Main Steam Line (MSL) Flow - High, specifies an AV of_< 122.8 psid. The stated AV of_< 122.8 psid will be changed to < 184.4 psid.

TS Section 3.4.3. Jet Pumos TS Section 3.4.3. Jet Pumps, SR 3.4.3.1, Note 2, indicates that the surveillance is not required to be performed until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after > 25 % RTP. The stated RTP percentage will be changed from

> 25 % RTP to > 23 % RTP.

TS Section 3.7.5, Main Turbine Bypass System TS Section 3.7.5, Main Turbine Bypass System, Applicability and Actions, are both dependent on a percentage of RTP (i.e., 25 % RTP). The stated RTP percentage will be changed from 25 %

RTP to 23 % RTP.

2.3 Technical Specifications Not Requiring Change The following table contains a listing of the NMP2 technical specifications that reference %RTP values that are not being changed as a result of EPU. A brief justification for leaving the %RTP value unchanged is provided.

Technical . 'Justification for .%RTP Remaining Unchanged Speci ication.. .-

TS 3.1.3 No changes required.

Control Rod OPERABILITY The Rod Worth Minimizer (RWM) Low Power Set Point (LPSP) is (10% RTP) unchanged in terms of percent power (%RTP) for EPU. The LPSP defines the power level below which the RWM is required.

Actions Maintaining this function in effect until 10% RTP will result in a larger RWM range in terms of absolute power; therefore, not revising the LPSP is conservative for EPU.

TS 3.1.4 No changes required.

Control Rod Scram Times As stated in the T.S. 3.1.4 Bases, the 40% RTP provides a reasonable (40% RTP) time to complete the scram time testing following a shutdown. As such, this is a timing consideration to allow for the testing to be Surveillance Requirement completed and does not affect the operation or operability of the control rods. Thus, it is acceptable to maintain the current 40% RTP.

TS 3.1.6 No changes required.

Rod Pattern Control The RWM LPSP is unchanged in terms of percent power for EPU.

(10% RTP) The LPSP defines the power level below which the RWM is required.

Maintaining this function in effect until 10% RTP will result in a Applicability larger RWM range in terms of absolute power; therefore, not revising this setpoint is conservative for EPU.

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EVALUATION OF THE PROPOSED CHANGE 2 T echnical -Justification, or %RTPRemainig Unchanged Sp fiwatio'ns S&' 7. .

TS 3.3.1.1 No changes required.

Reactor Protection System TS Bases states that the Scram Setdown function indirectly ensures that, Instrumentation before the reactor mode switch is placed in the run position, reactor (20% RTP) power does not exceed the Thermal Limit Monitoring value. The rescaled 23% RTP Thermal Limit Monitoring value continues to exceed Table 3.3.1.1-1 AV (Item 2a) the Scram Setdown Allowable Value (AV) of 20% RTP. Because the Scram Setdown is based on the AV, no change is required to the Scram Setdown.

TS 3.3.1.1 No changes required.

Reactor Protection System The Analytical Limit (AL) associated with the Allowable Value has Instrumentation not changed and the instrument has not changed. Therefore, the value (120% RTP) of_< 120% RTP does not change.

Table 3.3.1.1.-1 AV (Item 2c)

TS 3.3.1.1 No changes required.

Reactor Protection System There is sufficient margin between the actual and allowed Instrumentation sensitivity of the Local Power Range Monitor (LPRM) detectors to (1000 Effective Full Power absorb the sensitivity loss due to the increase in detector flux and Hours) burnup at EPU conditions. Therefore, LPRM calibration frequency is not affected by EPU and no changes are required.

SR 3.3.1.1.7 TS 3.3.2.1 No changes required.

Control Rod Block The RWM LPSP is unchanged in terms of percent power for EPU.

Instrumentation The LPSP defines the power level below which the RWM is required.

(10% RTP) Maintaining this function in effect until 10% RTP will result in a larger RWM range in terms of absolute power; therefore, not revising SR Table 3.3.2.1-1 (notes) this setpoint is conservative for EPU.

TS 3.3.2.1 No changes required.

Control Rod Block The AL associated with the AV power levels for the various ranges Instrumentation for RBM operability are unchanged in terms of percent power for (28%, 63%, 83%, & 90% RTP) EPU, thus no setpoint change is required (NEDC-33004P-A, CLUR Section 5.3.5). The power-dependant MCPR multipliers (Kp) at each SR Table 3.3.2.1-1 (notes) AL are verified on a cycle specific bases in order to determine if the Kp multiplier is bounding.

TS 3.3.4.2 No changes required.

ATWS Recirculation Pump SR 3.3.4.2.4 requires verification that for the reactor vessel steam Trip dome pressure - high function, the low frequency motor generator (5% RTP) (LFMG) trip is not bypassed for > 29 seconds when thermal power is

> 5% RTP. The combination of the reactor vessel steam dome Surveillance Requirement pressure - high function and the LFMG trip is intended to mitigate the effects of an Anticipated Transient Without Scram (ATWS) event.

For this surveillance, 5% RTP is a reasonable low power level at which the effects of an ATWS are not severe. The absolute thermal power level (MWt) in this range is approximately equal at CLIP and EPU. Therefore, the thermal power level of 5% RTP is not changed for EPU.

TS 3.4.11 No changes required.

RCS Pressure and Temperature Maintaining 30% RTP for implementation of surveillance (P/T) Limits requirements 3.4.11.5 and 3.4.11.6 is conservative because the (30% RTP in single loop surveillances will commence at a higher absolute power level (i.e.,

operation (SLO)) earlier) than would be required by scaling.

Surveillance Requirement TS 3.6.2.1 No changes required.

Suppression Pool Average The TS Bases on page B 3.6.2.1-1 states: "At 1% RTP, heat input is Temperature approximately equal to normal system heat losses." Because the TS (1% RTP) Bases define the criteria for 1% RTP (i.e., the point of adding heat),

the same power level will be utilized following EPU and a change to LCO and Actions this value is not required.

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EVALUATION OF THE PROPOSED CHANGE Technical.. Justification for %RTP RemainingUhnhanged Sipecification ,-,:

TS 3.6.3.2 No changes required.

Primary Containment Oxygen Reference is made in this section to "< 15% RTP" and "> 15% RTP."

Concentration This value is provided as an indication of plant startup and provides (15% RTP) for the start of containment inerting. Maintaining this value at 15% of the EPU RTP continues to comply with the Technical Specification Applicability, Actions Bases statement that for reactor power below this value, the potential for an event that generates significant hydrogen and oxygen is low.

3.0 TECHNICAL EVALUATION

3.1 Operating License and Technical Specifications Changes NEDC-33004P-A, Licensing Topical Report Constant Pressure Power Uprate, Revision 4, provides an NRC accepted approach for performing EPU. The approach is referred to as Constant Pressure Power Uprate (CPPU) and has been used as the basis of multiple power uprate license amendment requests submitted to and approved by the NRC. As the name suggests, the CPPU approach maintains a plant's current maximum operating reactor pressure. The constant pressure constraint, along with other required limitations and restrictions discussed in the CLTR, allows a simplified approach to power uprate analyses and evaluations.

Office of Nuclear Reactor Regulation, Review Standard for Extended Power Uprates, RS-001, Revision 0, December 2003, provides guidance to the NRC Staff when performing reviews of EPU applications. The review standard was developed to enhance the consistency, quality, and completeness of the Staff s reviews and to inform licensees of the guidance documents the Staff would use when reviewing EPU applications. These documents provide the acceptance criteria for the areas of review allowing licensees to prepare EPU applications that are complete with respect to the areas that are within the Staff's scope of review. Section 3.2 of RS-001, Template Safety Evaluation for Boiling-Water Reactor Extended Power Uprate, Inserts 1-13, provides the Staff an outline to follow when generating plant-specific safety evaluations. For each area of concern, a Regulatory Evaluation and Conclusion statement are provided. As noted in RS-001, the use of this review standard was not intended to undermine the NRC's topical report review and approval process. If a licensee references an NRC-approved topical report for an area covered by RS-001, the Staff will review the application only to ensure that the licensee is applying the topical report under conditions for which the topical report was approved, using appropriate plant-specific inputs.

NEDO-33351, Safety Analysis Report for Nine Mile Point Nuclear Station Unit 2 Constant Pressure Power Uprate, (non-proprietary version) is provided as Attachment 3 to this Enclosure.

This report provides an integrated summary of the results of the safety analyses and evaluations performed that support the proposed increase to the maximum power level at NMP2 as delineated in OL Section 2.C.(1), Maximum Power Level. The PUSAR, Section 2, Safety Evaluation, follows the format and guidance delineated in RS-001, Section 3.2, to the extent that the review standard is consistent with the design basis of NMP2. Differences between the plant-specific design basis and RS-001 Regulatory Evaluations are described and evaluations provided. As appropriate, the PUSAR's Technical Evaluations are based on NRC approved topical report NEDC-33004P-A, Licensing Topical Report Constant Pressure Power Uprate, Revision 4. A proprietary version of the Safety Analysis is provided as Attachment 11.

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EVALUATION OF THE PROPOSED CHANGE In developing the PUSAR, NMPNS identified certain evaluations that, due to size, level of detail, and/or subject matter, were more appropriately broken out as separate Attachments. These areas include the EPU Testing Plan, Attachment 7, the Grid Stability Evaluation, Attachment 8, the Flow Induced Vibration-Piping/ Component Evaluation, Attachment 10, and the Steam Dryer Evaluation, Attachment 13. These evaluations support the appropriate PUSAR Technical Evaluations.

The following table provides a list of the OL and TS changes along with a brief description of each and the PUSAR section which provides the technical basis for the change:

Technical -Description / Discussion of the Change" Supporting Speification -PUSA Section Operating License Revise the Rated Thermal Power in Section 2.C.(l) from 3467 MWt to 1.2.1 Maximum Power Level 3988 MWt.

Operating License The TS value of minimum feedwater temperature allowed during rated Table 1-2 Operation with Reduced steady-state conditions has been increased by the same amount as the Feedwater Temperature feedwater temperature used in the heat balance in order to maintain the same margin to the original basis. The feedwater temperature used in the heat balance was changed from 425.1 F to 440.5 F; therefore, the TS value in Section 2.C.(7) shall be changed from 405 F to 420.5 F.

TS 1.1 Revise Rated Thermal Power definition from 3467 MWt to 3988 MVWt to 1.2.1 Definitions reflect EPU conditions.

TS 2.1.1.1 The historical 25% of RTP value for the TS Safety Limit, some thermal 2.8.2.2 Reactor Core SLs limits monitoring LCO thresholds, and some SR thresholds are based on generic analyses (evaluated up to -50% of original RTP) applicable to the plant design with highest average bundle power for all of the BWR product lines. As originally licensed, the highest average bundle power (at 100%

RTP) for any BWR6 is 4.8 MWt/bundle. The 25% RTP value is a conservative basis, as described in the plant Technical Specifications, however, this % value should be reduced when any plant is uprated such that at 100% of uprated power the average bundle power is greater than the original generic basis of 4.8 MWt/bundle. Therefore, to maintain the same basis with respect to absolute thermal power, if the uprated average bundle power is > 4.8 MWt/bundle, then the % RTP value is revised to equal (25%

4.8 MWt/bundle * # of bundles / total uprated MWt). For the EPU, the average bundle power is > 4.8 MWt/bundle. Therefore, the Safety Limit %

RTP basis and the thermal limits monitoring LCO and SR % RTP thresholds are reduced to 23% RTP.

TS 3.1.7 Change > 1325 psig to > 1327 psig. The maximum pump discharge 2.8.4.5 Standby Liquid Control pressure for limiting ATWS event at EPU conditions is 1326.4 psig.

Surveillance Requirement TS 3.2.1 The 25% RTP value is reduced to 23% RTP. See discussion provided for 2.8.2.2 Average Planar Linear Heat TS 2.1.1.1.

Generation Rate (APLHGR)

Applicability, Actions, SR TS 3.2.2 The 25% RTP value is reduced to 23% RTP. See discussion provided for 2.8.2.2 Minimum Critical Power TS 2.1.1.1.

Ratio (MCPR)

Applicability, Actions, SR 8 of 16

EVALUATION OF THE PROPOSED CHANGE Technical 'Description /Discussion of the Change Suppoiting Specification *PUSAR

________________Section TS 3.2.3 The 25% RTP value is reduced to 23% RTP. See discussion provided for 2.8.2.2 Linear Heat Generation Rate TS 2.1.1.1.

(LHGR)

Applicability, Actions, SR TS 3.3.1.1 Based on the guidelines in Section F.4.2.3 of General Electric Licensing 2.4.1.3 Reactor Protection System Topical Report NEDC-32424P-A, the Turbine Stop Valve (TSV) Closure Instrumentation and Turbine Control Valve (TCV) Fast Closure Scram and RPT Bypass analytical limit in % RTP is reduced by the ratio of the power increase.

Actions, SR, Table 3.3.1.1-1 The new analytical limit does not change with respect to absolute thermal Functions 8 and 9 power. Because the trip does not change in terms of absolute power, there is no effect on the transient response. Therefore, the revised value in %

RTP is:

30% RTP x 3467 MWt/ 3988 MWt = 26% RTP TS 3.3.1.1 The 25% RTP value is reduced to 23% RTP. See discussion provided for 2.8.2.2 Reactor Protection System TS 2.1.1.1.

Instrumentation Surveillance Requirements TS 3.3.1.1 The AV of the APRM Flow Biased Simulated Thermal Power (STP) - 2.4.1.3 Reactor Protection System Upscale Scram is revised Instrumentation From: < 0.64 W + 63.8 % RTP AV Table 3.3.1.1-1 Item 2b To: < 0.55 W + 60.5 % RTP Additionally, footnote (b) revised From: "Allowable Value is .58(W-5%) + 62% RTP when reset for single loop operation per LCO 3.4.1, 'Recirculation Loops Operating"'

To: "Allowable Value is .50(W-5%) + 53.5% RTP when reset for single loop operation per LCO 3.4.1, 'Recirculation Loops Operating"'

This value is equivalent to the current set point and therefore is not a change in terms of absolute power.

TS 3.3.1.1 The following notes will be added to SR 3.3.1.1.13 for Item 2b: Section 3.2.3 of Reactor Protection System this Enclosure Instrumentation (c) If the As-Found channel setpoint is outside its predefined as-found tolerances, then the channel shall be evaluated to verify that it is Table 3.3.1.1-1 Item 2b functioning as required before returning the channel to service.

SR 3.3.1.1.13 Notes (d) The instrument channel setpoint shall be reset to a value that is within the As-Left tolerance around the nominal trip setpoint at the completion of the surveillance; otherwise, the channel shall be declared inoperable. Setpoints more conservative than the nominal trip setpoint are acceptable provided that the As-Found and As-Left tolerances apply to the actual setpoint implemented in the surveillance procedures to confirm channel performance. The nominal trip setpoint and the methodologies used to determine the As-Found and the As-Left tolerances are specified in the Bases associated with the specified function.

TS 3.3.2.2 The 25% RTP value is reduced to 23% RTP. See discussion provided for 2.8.2.2 Feedwater System and Main TS 2.1.1.1.

Turbine High Water Level Trip Instrumentation Applicability, Actions 9 of 16

EVALUATION OF THE PROPOSED CHANGE Technical Description-/ Discussion of the Change Supporting Specification PUSAR Section.

TS 3.3,4.1 The 30% RTP value is reduced to 26% RTP. See discussion provided for 2.4.1.3 End of Cycle Recirculation TS 3.3.1.1.

Pump Trip Instrumentation Applicability, Actions, SR TS 3.3,6.1 The AV of the Main Steam Line Isolation, Main Steam Line Flow - High is 2.4.1.3 Primary Containment revised.

Isolation Instrumentation From: 122.8 psid AV Table 3.3.6.1-1, Item ic To: 184.4 psid TS 3.4.3 The 25% RTP value is reduced to 23% RTP. See discussion provided for 2.8.2.2 Jet Pumps TS 2.1.1.1.

Surveillance Requirement TS 3.7.5 The 25% RTP value is reduced to 23% RTP. See discussion provided for 2.8.2.2 Main Turbine Bypass System TS 2.1.1.1.

Applicability, Actions 3.2 Technical Specification Instrument Setpoint Changes Technical Specification Allowable Values for the functions addressed below will be revised for operation at EPU conditions.

3.2.1 Setpoint Calculation Methodology APRM Flow-Biased Simulated Thermal Power - Upscale Scram The setpoints for this function were changed for the implementation of the ARTS/MELLLA amendment (Reference 4) in accordance with NRC approved GEH methodology in NEDC-31336P-A, General Electric Instrument Setpoint Methodology. For EPU, the changes in the instrument uncertainties were sufficiently small that using a simplified process to change the instrument Allowable Value and nominal trip setpoint by the same difference as the change in the Analytical Limit was justified by NRC approved GEH methodology in NEDC-33004P-A, Constant Pressure Power Uprate. The EPU Allowable Value for this function is provided in Section 2.2 of this Enclosure. The nominal trip setpoint (NTSP) is 0.55 W + 57.5 % RTP for two loop operation and 0.50 (W-5%) + 50.5% RTP for single loop operation, where W =

Recirculation Drive Flow in percent of Rated Flow. The Analytical Limit for this function is 0.55 W + 63.5 % RTP for two loop operation and 0.50 (W-5%) + 56.5% RTP for single loop operation.

Main Steam Line High Steam Flow Main Steam Isolation Valve (MSIV) Isolation The Analytical Limit for EPU conditions is maintained at 140% of the rated steam flow. The Allowable Value and nominal trip setpoint both increase in units of psid due to the higher absolute mass flowrate Analytical Limit for EPU. The Allowable Value and nominal trip setpoint were re-calculated using NRC approved GEH methodology in NEDC-31336P-A, General Electric Instrument Setpoint Methodology and NEDC-32889P, General Electric Methodology for Instrumentation Technical Specification and Setpoint Analysis. A sample calculation demonstrating the application of this methodology is provided in Section 2.4.2 of the PUSAR (Attachment 11). The EPU Allowable Value for this function is provided in Section 2.2 of this 10 of 16

EVALUATION OF THE PROPOSED CHANGE Enclosure. The nominal trip setpoint is 183 psid. The Analytical Limit for this function corresponding to 140% rated steam flow is 194.4 psid. There is a plant specific program which verifies that this instrument channel functions as required by verifying the as-left and as-found settings are consistent with those established by the setpoint methodology.

3.2.2 Safety Limit-Related Limiting Safety System Settings (LSSS) Determination In accordance with 10 CFR 50.36(c)(1)(ii)(A), the following guidance is provided for identifying a list of functions to be included in the subset of LSSSs specified for variables on which Safety Limits (SLs) have been placed as defined in Standard Technical Specifications Sections 2.1.1, "Reactor Core SLs," and 2.1.2, "Reactor Coolant System Pressure SLs." This subset includes automatic protective devices in Technical Specifications for specified variables on which SLs have been placed that: (1) initiate a reactor trip; or (2) actuate safety systems. In accordance with General Design Criteria 10, SLs ensure that specified acceptable fuel design limits are not exceeded during steady state operation, normal operational transients, and anticipated operational occurrences (AOOs). As explained below, there are no SL-Related LSSS functions being revised by this License Amendment Request.

APRM Flow-Biased Simulated Thermal Power - Upscale Scram As described in the TS Bases for Specification 3.3.1.1, no specific safety analyses take direct credit for the APRM Flow Biased Simulated Thermal Power - Upscale Function. Originally, the clamped Allowable Value was based on analyses that took credit for the APRM Flow Biased Simulated Thermal Power - Upscale Function for the mitigation of the loss of feedwater heater event. However, the current methodology for this event is based on a steady state analysis that allows power to increase beyond the clamped Allowable Value. Therefore, applying the current clamped Allowable Value is conservative. The TS Bases for this specification also state that functions not specifically credited in the accident analysis are retained for overall redundancy and diversity of the RPS as required by the NRC approved licensing basis. This function does not provide an automatic trip sepoint that protects against violating the Reactor Core Safety Limit or Reactor Coolant System Pressure Safety Limit during AOOs. As noted in NMP2 Amendment No. 123 dated February 27, 2008, Safety Evaluation Section 3.13.2, Non-SL-Related LSSS, the Flow Biased Simulated Thermal Power-Upscale Function is not a SL-Related LSSS.

Main Steam Line High Steam Flow MSIV Isolation The Main Steam Line Flow-High Function is directly assumed in the analysis of the main steam line break accident. NMP2 Updated Safety Analysis Report (USAR) Section 15.6.4.1.2, Frequency Classification, categorizes the main steam line break as a limiting fault. USAR Section 15.0.3.1 defines limiting faults as occurrences that are not expected to occur but are postulated because their consequences may result in the release of significant amount of radioactive material. This event is referred to as a design basis (postulated) accident. The isolation action, along with the scram function of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46 and the offsite doses do not exceed the 10 CFR 50.67 limits. Because the MSL Flow-High Function is credited only in a DBA and does not provide an automatic trip sepoint that protects against violating the Reactor Core Safety Limit or Reactor Coolant System Pressure Safety Limit during AOOs, it is therefore not considered an SL-Related LSSS function.

11 of 16

EVALUATION OF THE PROPOSED CHANGE 3.2.3' Instrument Setpoint Controls A Surveillance Test Program is in place to ensure the APRM Flow-Biased Scram STP Upscale Scram and Main Steam Line High Flow MSIV Isolation functions will perform in accordance with applicable design requirements. Nominal trip setpoints are specified in controlled setpoint calculations and incorporated into applicable Surveillance Test Procedures. The nominal trip setpoints and As-Left tolerances are selected to ensure that the actual setpoints do not exceed the Allowable Value between successive channel calibrations. Instrument reference accuracy is used for the As-Found and As-Left tolerances. An As-Left setting is procedurally required to be within the As-Left tolerance prior to returning the channel to service. If the As-Found setting is outside the required As-Found tolerance, the device is reset to within the As-Left tolerance.

Operability determinations are integral to the NMPNS 10CFR50, Appendix B, Criterion XVI, Corrective Action Program. When a problem described in a condition report represents an operability concern, an Operability Determination is completed. Return of a degraded or non-conforming component to service is addressed under the corrective action program.

For the APRM Flow-Biased Scram STP Upscale Scram function, setpoints found outside As-Found tolerances are evaluated for functionality through the corrective action program. A channel is inoperable if its actual trip setpoint is not within its required Allowable Value, or if it cannot be reset to within its As-Left tolerance. For Main Steam Line High Flow MSIV Isolation, a channel is inoperable if its actual trip setpoint is not within its required Allowable Value, or if it cannot be reset to within its As-Left tolerance. Applicable surveillance test procedures will be revised to ensure setpoints found outside As-Found tolerances are evaluated for functionality through the corrective action program.

Notes will be added to the applicable TS Surveillance Requirements that are consistent with the NRC staff's position on complying with 10 CFR 50.36 as provided in RIS 2006-17 and further clarified by Technical Specification Task Force (TSTF)-493, Revision 3. Specifically, the following notes are added to the TS Surveillance Requirements for the APRM Flow-Biased simulated Thermal Power Upscale Scram function:

1. If the As-Found channel setpoint is outside its predefined As-Found tolerances, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service.

2. The instrument channel setpoint shall be reset to a value that is within the As-Left tolerance around the nominal trip setpoint at the completion of the surveillance; otherwise, the channel shall be declared inoperable. Setpoints more conservative than the nominal trip setpoint are acceptable provided that the As-Found and As-Left tolerances apply to the actual setpoint implemented in the surveillance procedures to confirm channel performance. The nominal trip setpoint and the methodologies used to determine the As-Found and the As-Left tolerances are specified in the Bases associated with the specified function.

12 of 16

EVALUATION OF THE PROPOSED CHANGE Information will be added to the applicable TS Bases that are consistent with the NRC staff's position on complying with 10 CFR 50.36 as provided in RIS 2006-17 and further clarified by TSTF-493, Revision 3, and TSTF-09-07 letter to NRC dated February 23, 2009, for non-SL-Related LSSS functions. Specifically, the following information will be added to the TS Bases for the Main Steam Line High Flow MSIV Isolation function:

There is a plant specific program which verifies that this instrument channel functions as required by verifying the As-Left and As-Found settings are consistent with those established by the setpoint methodology.

4.0 REGULATORY EVALUATION

4.1 Applicable Regulatory Requirements/Criteria NEDO-33351, Safety Analysis Report for Nine Mile Point Nuclear Station Unit 2 Constant Pressure Power Uprate is provided as Attachment 3 (non-proprietary version) and Attachment 11 (proprietary version). For each PUSAR Safety Evaluation Section, a Regulatory Evaluation is provided which describes the pertinent regulatory requirements and criteria. Also provided is a Technical Evaluation which explains the EPU changes and how the applicable regulatory requirements are met. The PUSAR safety evaluation follows the format and guidance delineated in RS-001 (Revision 0), Office of Nuclear Reactor Regulation, Review Standard for Extended Power Uprates, to the extent that thereview standard is consistent with the design basis of NMP2.

For differences between the plant-specific design bases and RS-001 regulatory evaluation sections, the corresponding PUSAR safety evaluation regulatory evaluation section was revised to reflect the NMP2 design basis. As appropriate, the PUSAR's technical evaluations are based on NRC approved topical report NEDC-33004P-A, Licensing Topical Report Constant Pressure Power Uprate, Revision 4.

4.2 Significant Hazards Consideration In accordance with 10 CFR 50.91(a), "At the time a licensee requests an amendment, it must provide to the Commission.... its analysis about the issue of no significant hazards consideration using the standards in § 50.92." The following provides this analysis for the Nine Mile Point Nuclear Station Unit 2 (NMP2) Extended Power Uprate (EPU). The, conclusions are based on the evaluations provided in NEDC-33351P, Safety Analysis Report for Nine Mile Point Nuclear Station Unit 2 Constant Pressure Power Uprate, and are summarized as appropriate to the following safety considerations in accordance with 10 CFR 50.92.

1) Will the change involve a significant increase in the probability or consequences of an accident previously evaluated?

No, the increase in power level discussed herein will not significantly increase the probability or consequences of an accident previously evaluated.

The proposed change will increase NMP2's authorized maximum power level from the current licensed thermal power (CLTP) level of 3467 megawatts thermal (MWt) to 3988 MWt. In support of this Constant Pressure Extended Power Uprate (CPPU), a comprehensive evaluation was performed for nuclear steam supply system (NSSS) and balance of plant (BOP) systems, structures, components, and analyses that could be affected by this change. The effect of increasing the maximum power level from the CLTP of 3467 MWt to 3988 MWt on the NMP2 licensing and design bases was evaluated. The result of this evaluation is that all plant components, as modified, will continue to be capable of performing their design function at an 13 of 16

EVALUATION OF THE PROPOSED CHANGE uprated core power of 3988 MWt. In addition, an evaluation of the accident analyses concludes that applicable analysis acceptance criteria continue to be met. Power level is an input assumption to the equipment design and accident analyses, but it is not an initiator for any transient or accident. Therefore, no accident initiators are affected by this uprate and no challenges to any plant safety barriers are created by this change.

Therefore, operation of the facility in accordance with the proposed change does not involve a significant increase in the probability of an accident previously evaluated.

This change does not affect the release paths, the frequency of release, or the source term for release for any accidents previously evaluated in the Updated Safety Analysis Report (USAR).

Structures, systems, and components (SSC) required to mitigate transients remain capable of performing their design functions, and thus were found acceptable. The source terms used to assess radiological consequences have been reviewed and determined to bound operation at the uprated condition. The results of EPU accident evaluations do not exceed the U. S. Nuclear Regulatory Commission (NRC) approved acceptance limits.

The spectrum of postulated accidents and transients has been investigated and are shown to meet the regulatory criteria to which NMP2 is currently licensed. In the area of fuel and core design, the Safety Limit Minimum Critical Power ratio (SLMCPR) and other applicable Specified Acceptable Fuel Design Limits (SAFDLS) are still met. Continued compliance with the SLMCPR and other SAFDLs is confirmed on a cycle specific basis consistent with criteria accepted by the NRC.

Challenges to the reactor coolant pressure boundary were evaluated at EPU conditions (pressure, temperature, flow, and radiation) and found to meet the acceptance criteria for allowable stresses.

Adequate overpressure margin is maintained.

Challenges to the containment have been evaluated and the containment and its associated cooling system continue to meet applicable regulatory requirements. The increase in the calculated post Loss of Coolant Accident (LOCA) suppression pool temperature above the current peak temperature was evaluated and determined to be acceptable.

Radiological release events (accidents) have been evaluated and shown to meet the requirements of 10 CFR 50.67.

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

2) Will the change create the possibility of a new or different kind of accident from any accident previously evaluated?

No, the increase in power level discussed herein will not create the possibility of a new or different kind of accident from any accident previously evaluated.

The proposed change will increase NMP2's authorized maximum power level from the CLTP level of 3467 MWt to 3988 MWt. Equipment that could be affected by EPU has been evaluated.

No new operating mode, safety-related equipment lineup, accident scenario, or equipment failure mode was identified. The full spectrum of accident considerations has been evaluated and no new or different kind of accident has been identified. This Constant Pressure Extended Power Uprate utilizes a standard evaluation methodology applied to known technology employed within the range of current or modified plant capabilities. As such, the plant safety-related equipment continues to operate in accordance with regulatory criteria. Evaluations were performed using NRC approved codes, standards and methods. No new accidents or event precursors have been identified.

14 of 16

EVALUATION OF THE PROPOSED CHANGE All structures, systems and components previously required for the mitigation of a transient remain capable of fulfilling their intended design functions. The proposed changes do not adversely affect safety-related systems or components and do not challenge the performance or integrity .of any safety-related system. This change does not adversely affect any current system interfaces or create any new interfaces that could result in an accident or malfunction of a different kind than was previously evaluated. Operating at a core power level of 3988 MWt does not create any new accident initiators or precursors.

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

3) Will the change involve a significant reduction in a margin of safety?

No, the increase in power level discussed herein will not involve a significant reduction in a margin of safety.

Comprehensive analyses of the proposed changes have concluded that relevant design and safety acceptance criteria will be met without a significant reduction in margins of safety. The analyses supporting EPU have demonstrated that the NMP2 SSCs are capable of safely performing at EPU conditions. The analyses identified and defined the major input parameters to the NSSS, analyzed NSSS design transients, and evaluated the capabilities of the NSSS fluid systems, NSSS/BOP interfaces, NSSS control systems, and NSSS and BOP components, as appropriate.

Radiological consequences of design basis events remain within regulatory limits and are not increased significantly. The analyses confirmed that NSSS and BOP SSCs are capable, some with modifications, of achieving EPU conditions without significant reduction in margins of safety.

Analyses have shown that the integrity of primary fission product barriers will not be significantly affected as a result of the power increase. Calculated loads on SSCs important to safety have been shown to remain within design allowables under EPU conditions for all design basis event categories. Plant response to transients and accidents do not result in exceeding acceptance criteria. As appropriate, the evaluations that demonstrate acceptability of EPU have been performed using methods that have either been reviewed and approved by the NRC staff, or that are in compliance with regulatory review guidance and standards established for maintaining adequate margins of safety. These evaluations demonstrate that there are no significant reductions in the margins of safety.

Maximum power level is one of the inherent inputs that determine the safe operating range defined by the accident analyses. The Technical Specifications ensure that NMP2 is operated within the bounds of the inputs and assumptions used in the accident analyses. The acceptance criteria for the accident analyses are conservative with respect to the operating conditions defined by the Technical Specifications. The engineering reviews performed for the constant pressure extended power uprate confirm that the accident analyses criteria are met at the revised maximum allowable thermal power level of 3988 MWt, as well as at the rated thermal power (RTP) levels specified in the Facility Operating License and Technical Specifications. Therefore, the adequacy of the revised Facility Operating Licenses and Technical Specifications to maintain the plant in a safe operating range is also confirmed, and the increase in maximum allowable power level does not involve a significant decrease in a margin of safety.

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

15 of 16

EVALUATION OF THE PROPOSED CHANGE 4.3 Conclusions A CPPU to 120% of original licensed thermal power has been investigated. The NMP2 licensing requirements have been evaluated and the analyses demonstrate how this uprate can be accommodated without a significant increase in the probability or consequences of an accident previously evaluated, without creating the possibility of a new or different kind of accident from any accident previously evaluated, and without creating a significant reduction in the margin of safety.

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. Therefore, Nine Mile Point Nuclear Station, LLC concludes that the proposed amendment presents no significant hazards considerations under the standards set forth in 10 CFR 50.92, and, accordingly, a finding of "no significant hazards consideration" is justified.

5.0 ENVIRONMENTAL CONSIDERATION

The proposed OL and TS changes required for implementation of EPU meet the requirements for performing an environmental review as set forth in 10 CFR 51.20, Criteria for and Identification of Licensing and Regulatory Actions Requiring Environmental Impact Statements.

Attachment 9, Supplemental Environmental Report, concludes that that the environmental impacts of operation at 3988 MWt are either bounded by the impacts described in earlier National Environmental Policy Act assessments or constrained by applicable regulatory criteria. As a result, NMPNS believes that the EPU would not significantly affect human health or the environment.

6.0 REFERENCES

1. NEDC-33004P-A, Licensing Topical Report Constant Pressure Power Uprate, Revision 4, July 2003.

2. RS-001, Office of Nuclear Reactor Regulation, Review Standard for Extended Power Uprates, Revision 0, December 2003

3. Nine Mile Point Nuclear Station, Unit 2, Technical Specification Amendment No. 66, TAC No. M87088, dated April 28, 1995

4. Nine Mile Point Nuclear Station, Unit 2, Technical Specification Amendment No. 123, TAC No. MD5233, dated February 27, 2008

5. Nine Mile Point Nuclear Station, Unit 2, Technical Specification Amendment No. 125, TAC No. MD5758, dated May 29, 2008 16 of 16

ENCLOSURE ATTACHMENT 1 Operating License / Technical Specifications Page Markups Operating License Pages Included in this Markup 4

5 Technical Specifications Pages Included in this Markup 1.1-5 2.0-1 3.1.7-3 3.2.1-1 3.2.2-1 3.2.3-1 3.3.1.1-2 3.3.1.1-4 3.3.1.1-6 3.3.1.1-8 3.3.1.1-9 3.3.1.1-10 3.3.2.2-1 3.3.2.2-2 3.3.4.1-1 3.3.4.1-2 3.3.4.1-3 3.3.6.1-6 3.4.3-2 3.7.5-1 Nine Mile Point Nuclear Station, LLC May 27, 2009

.3988 (1) Maximum Power Level Nine Mile Point Nuclear Station, LLC is authorized to perate the facility at reactor core power levels not in excess o egawatts thermal (100 percent rated power) in accordance with the conditions specified herein.

(2) Technical Specifications and Environmental Protection Plan The Technical Specifications contained in Appendix A and the Environmental Protection Plan contained inAppendix B, both of which are attached hereto, as revised through Amendment No. 130 are hereby incorporated into this license. Nine Mile Point Nuclear Station, LLC shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

(3) Fuel Storage and Handling (Section 9.1, SSER 4)*

a. Fuel assemblies, when stored in their shipping containers, shall be stacked no more than three containers high.

b. When not inthe reactor vessel, no more than three fuel assemblies shall be allowed outside of their shipping containers or storage racks in the New Fuel Vault or Spent Fuel Storage Facility.

c. The above three fuel assemblies shall maintain a minimum edge-to-edge spacing of twelve (12) inches from the shipping container array and approved storage rack locations.

d. The New Fuel Storage Vault shall have no more than ten fresh fuel assemblies uncovered at any one time.

(4) Turbine System Maintenance Program (Section 3.5.1.3.10, SER)

The operating licensee shall submit for NRC approval by October 31, 1989, a turbine system maintenance program based on the manufacturers calculations of missile generation probabilities.

(Submitted by NMPC letter dated October 30, 1989 from C.D. Terry and approved by NRC letter dated March 15, 1990 from Robert Martin to Mr. Lawrence Burkhardt, Ill).

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

Renewed Li~enEsc No. NPF 6 Amendment 1- throug.h 129, 489--

(5) Inservice Inspection (Sections 5.2.4.3 and 6.6.3, SSER 5)

The operating licensee shall submit an inservice inspection program in accordance with 10 CFR 50,55a(g)(4) for staff review by July 31, 1987.

(6) Initial Startup Test Program (Section 14, SER, SSERs 4 and 5)

Any changes to the Initial Test Program described inSection 14 of the Final Safety Analysis Report made in accordance with the provisions of 10 CFR 50.59 shall be reported inaccordance with 50.59(b) within one month of such change.

(7) Operation with Reduoed Feedwater Temperature.(Section 15.1, SSER 4)

Nine Mile Point Nuclear Station, LLC shall not operate the facility with reduced feedwater temperature for the purpose of extending the normal fuel cycle. The facility shall not be operated with a feedwater heating ity less than that required to produce a feedwater temperature of

~M t rated steady-state conditions unless analyses supporting such operations are submitted by Nine Mile Point Nuclear Station, LLC and approved by the staff.

(8) Safety Parameter Display System (SPDS) (Section 18.2, SSERs 3 and 5)

Prior to startup following the first refueling outage, the operating licensee shall have operational an SPDS that includes the revisions described in their letter of November 19, 1985, Before declaring the SPDS operational, the operating licensee shall complete testing adequate to ensure that no safety concerns exist regarding the operation of the Nine Mile Point Nuclear Station, Unit No. 2 SPDS.

(9) Detailed Control Room Design Review (Section 18,1, SSERs 5 and 6)

(a) Deleted per Amendment No. 24 (12-18-90)

(b) Prior to startup following the first refueling outage, the operating licensee shall provide the results of the reevaluation of normally lit and nuisance alarms for NRC review inaccordance with its August 21, 1986 letter.

(c) Prior to startup following the first refueling outage, the operating licensee shall complete permanent zone banding of meters in accordance with its August 4, 1986 letter.

RAmenwd Heemse Nt. urr co Amendment

Definitions 1.1 1.1 Definitions (continued)

MODE A MODE shall correspond to any one inclusive combination of mode switch position, average reactor coolant temperature, and reactor vessel head closure bolt tensioning specified in Table 1.1-1 with fuel in the reactor vessel.

OPERABLE-OPERABILITY A system, subsystem, division, component, or device shall be OPERABLE or have OPERABILITY when it is capable of performing its specified safety function(s) and when all necessary attendant instrumentation, controls, normal or emergency electrical power, cooling and seal water, lubrication, and other auxiliary equipment that are required for the system, subsystem, division, component, or device to perform its specified safety function(s) are also capable of performing their related support function(s).

PHYSICS TESTS PHYSICS TESTS shall be those tests performed to measure the fundamental nuclear characteristics of the reactor core and related instrumentation.

These tests are:

a. Described in Chapter 14, Initial Test Program of the FSAR;

b. Authorized under the provisions of 10 CFR 50.59; or

c. Otherwise approved by the Nuclear Regulatory Commission.

RATED THERMAL POWER RTP shall be a total reactor core heat-transfer (RTP) rate to the reactor coolant of, 3987 M-1t REACTOR PROTECTION The RPS RESPONSE TIME shall be that time interval SYSTEM (RPS) RESPONSE from when the monitored parameter exceeds its RPS TIME trip setpoint at the channel sensor until de-energization of the scram pilot valve solenoids. The response time may be measured by means of any series of sequential, overlapping, or total steps so that the entire response time is measured.

(continued)

NMP2 1.1-5 Amendment -,

SLs 2.0 2.0 SAFETY LIMITS (SLs) 2.1 SLs 2.1.1 ReactorCqreSLs 2.1.1.1 With the reactor steam dome pressure < 785 psig or-core flow < 10% rated core flow:.

THERMAL POWER shall be . 23%

2.1.1.2 Wi the reactor steam dome pressure > 785 psig and core flow > 10% rated core flow.

MCPR shall be a 1.07 for two recirculation loop operation or a 1.09 for single recirculation loop operation.

2.1.1.3 Reactor vessel water level shall be greater than the top of active irradiated fuel, 2.1.2 Reactor Coolant System Pressure SL Reactor steam dome pressure shall be < 1325 psig.

2.2 SL Violations With any SL violation, the following actions shall be completed within 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months s:

2.2.1 Restore compliance with all SLs; and 2.2.2 Insert all insertable control rods.

NMP2 2.0-1 Amendment 94, 40, 41442-

SL.C System 3.1.7 SURVEILLANCE REQUIREMENTS (continued) ,

SURVEILLANCE FREQUENCY SR 3.1.7.7 Verify each pump develops aflow rate In accordance

> 41.2 gpm at a discharge pressure with the

, *Inservice Testing Program SR 3.1,7.8 Verify flow through one SLC subsystem 24 months on a from pump Into reactor pressure vessel. STAGGERED TEST BASIS SR 3.1.7.9 Verify all heat traced piping between 24 months storage tank and pump suction valve is unblocked. -AND Once within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after piping temperature is restored to

_>70°F SR 3.1.7.10 Verify sodium pentaborate enrichment Prior to is > 25 atom percent B-10. addition to SLO tank NMP2 3.1.7-3 Amendment 91, 1!!4,47, +Z-3.

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

LCO 3.2.1 All APLHGRs shall be less than or equal to the limits specified in the COLR.

APPLICABILITY: THERMAL POWER (1Ž RP Y23%-Q ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.. Any APLHGR not within A.1 Restore APLHGR(s) to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months limits, within limits.

B. Required Action and B.1 Reduce THERMAL POWER 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months associated Completion to <<9)RTP.

,Time not met. 23%

SURVYEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.2.1.1 Verify all APLHGRs are less than or equal Once within to the limits specified in the COLR. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months

Ž _I*RTP_after 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months thereafter NMP2 3.2.1-1 .Amendment MCPR 3.2.2 3.2 POWER DISTRIBUTION LIMITS 3.2.2 MINIMUM CRITICAL POWER RATIO (MCPR)

LCO 3.2.2 All MCPRs shall be greater than or equal to the MCPR operating limits specified in the COLR.

APPLICABILITY: THERMAL POWER M25 23%

RTP.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Any MCPR not within A.1 Restore MCPR(s) to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months limits, within limits.

B. Required Action and B.1 Reduce THERMAL POWER 4-hours associated Completion to <C- RTP.

Time not met.

SURVEILLANCE REQUIREMENTS-SURVEILLANCE FREQUENCY SR 3.2.2.1 Verify all MCPRs are greater than or equal Once within to the limits specified in the COLR. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after RTP 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months thereafter (continued)

NMP2 3.2.2-1 Amendment -9I-1

LHGR 3.2.3 3.2 POWER DISTRIBUTION LIMITS 3.2.3 LINEAR HEAT GENERATION RATE (LHGR)

LCO 3.2.3 All LHGRs shall be less than or equal to the limits specified in the COLR.

APPLICABILITY! THERMAL POWER ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Any LHGR not within A.1 Restore LHGR(s) to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months limits. within limits.

B. Required Action and B. Reduce] tERMAL POWER 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months associated Completion- tRTP.

Time not met. 23%

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.2.3.1 Verify all LHGRs are less than or equal to Once within the limits specified in the COLR. 12 urs after RTPI AND 23%

24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months thereafter WKP2 3.2.3-1 Amendment-%-,

RPS Instrumentation 3.3.I.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. One or more Functions C.1 Restore RPS trip 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months with RPS trip capability.

capability not maintained.

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

E. As-required by . 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months RequiredAction D.1 and referenced in Table 3.3.1.-1.

F. As required by F.1 Initiate alternate 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Required Action D.1 method to. detect and and referenced in suppress thermal-Table 3.3.1.1-1. hydraulic Ingtability oscillations.-

F.2 Restore required channel 120 days to OPERABLE status.

Y 1/

G. Required Action and G.I. Be in MODE 2. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months /

associated Completion Time of Condition F not met.

As required by Required Action D.1 and referenced in Table 3.3.1.1-1; (continued)

NMP2 . 3.3.1.1-2 Amendment 9e--

RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS .continued)

SURVEILLANCE FREQUENCY SR 3.3.1,1,3 ---- -. NOTE - ---

Not required to be performed until 12 123%oJ hours after THERMAL POWER Verify the absolute difference between 7 days the average power range monitor (APRM) channels and the calculated power

< 2% RTP while operating at>423/ o SR 3.3.1.1.4 --NOTE For Functions 1t .and 1.b, not required to be performed when entedng MODE 2 from MODE 1 until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after entering MODE 2.

Perform CHANNEL FUNCTIONAL TEST. 7 days SR 3.3.1.1.5 Vedfy the source range monitor-(SRM) and Prior to fully intermediate range monitor (IRM) channels withdrawing overlap. ,SRMs SR 3.3.1.1.6 - NOTE Only required to be met during entry into MODE 2 from MODE 1.

Verify the IRM and APRM channels overlap. 7days (continued)

NMP2 Amendment 94-2,W 42

RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.3.1.1.13 ------------------- NOTES-------------

1. Neutron detectors are excluded.

2. For Functions ].a and 2.a, not required to be performed when entering MODE 2 from MODE I until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after entering MODE 2.

3. For Function 2.e, the CHANNEL CALIBRATION only requires a verification of OPRM-Upscale setpotnts in the APRM by the review of the "Show Parameters' display.

Perform CHANNEL CALIBRATION. 24 months SR 3.3.1.1.14 Perform LOGIC SYSTEM FUNCTIONAL TEST. 24 months SR 3.3.1.1.15 Verify Turbine Stop Valve-Closure, and 24 months Turbine Control Valve Fast Closure, Trip Oil Pressure-Low Functions are not bypassed when THERMAL POWER is _>.LV ,

SR 3.3.1.1.16 Verify APRM OPRM-Upscale Fun'c-6on is not 24 months bypassed when THERMAL POWER is R RTPs and recirculation drive flow is < 60% of rated recirculation drive flow.

(continued)

NMP2 3.3.1.1-6 ,:=" * " q Amendment borrected by tctter .. 11:1W ?ý _ .

RPS Instrumentation 3.3.1.1 Table 3.3,1.1-1 (page 1 of 3)

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

1. Intermediate Range Monitors

a. Neutron Flux- Upscale 2. 3 H SR 3.3.1.1.1 < 122/125 SR 3.3.1.1.4 divisions SR 3.3.1.1.5 of full SR 3.3.1.1.6 scale SR 3.3.1.1,13 SR 3.3.1.1.14 3 SR 3.3.1.1.1 s 1221125 SR 3.3.1,1.4 divisions SR 3.3.1.1.13 of full SR 3.3.1.1.14 scale

b. Inop 2 3 H SR 3.3.1.1.4 NA SR 3.3.1.1.14 5(a) 3 SR 3,3.1.1.4 NA SR 3.3.1.1.14

2. Average Pqwer Range Monitors

a. Neutron Flux- Upscale, 2 3 per logic H SR 3.3.1.1.2 , 20% RTP Setdown channel SR 3.3.1.1.8 SR 3.3.1,1.7 SR 3.3,11,10 .55W + 60.5% RTP SR 3.3.1,1.13

b. Flow Biased Simulated 3 per loglc 0 SR 31.31.1.2 Thermal Power- Upscale channel SR 3,311.3 SR 3.3.1.1.7 n 1 3.R.1 1 1.(c),(d) 3 SR 3.3.1.1.10 RTp(b)

c. Fixed Neutron 1 3 per logic 0 SR 3.3.1.1.27 120%RTP Flux - Upscale channel RS 3.3.1.1.13 SR 3.3.1.1.3 SR 3,3,1,1.7 SIR 3.3.1.1.10 SR 3.3.1.1,13

d. Inop 1,2 .3 per logic H SR 3.3.1.1.7 NA channel SR 3.3.1.1.10

e. OPRM..Upscale 3 per logic. F SR 3.3.1.1.2 As channel SR 3.3.1,117 specified SR 3.3.1.1.10 In the COLR SR 3.3.1.1.13' SR 3.3.1.1.16

f. 2-Out-Of-4 Voter 1,2 2 H SR 3.3.1.1.2 NA SR 3.3.1.1.10

.5(-% + 53.5 .... .. (continued)

(a). With any conrlr thrw rm a corem call containing one or more fuel assemblies.

(b) Allowable value is* -1 .2IT~e

-- . _f -*h

.1 .....

reset*'

'orf"=)single loop operation per LCO 3.4-1, "Recirculation Loops. perating.

(c) if the As-Found channel setpoint is outside its predefined As-Found tolerances, then the channell sshall bbe Iner evaluated to verify that it is functioning as require beore returning the channel to s~ervice. -

NMP23.3.1.1-8 Amendment 9-4, $-%--

"Insert A" (d) The instrument channel setpoint shall be reset to a value that is within the As-Left tolerance around the nominal trip setpoint at the completion of the surveillance; otherwise, the channel shall be declared inoperable. Setpoints more conservative than the nominal trip setpoint are acceptable provided that the As-Found and As-Left tolerances apply to the actual setpoint implemented in the surveillance procedures to confirm channel performance. The nominal trip setpoint and the methodologies used to determine the As-Found and the As-Left tolerances are specified in the Bases associated with the specified function.

RPS Instrumentation 3.3-,1.1 Table 3.3.1.1-1 (page 2 of 3)

Reactor Protection System Instrumentation APPLICABLE CONDITIONS NOES OR REQUIfRED REFERENCED OTHER CMNANNELS FROM SPECIFIED PER TRIP REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS SYSTEM ACTION D.1 REQUIREMENTS VALUE

3. Reactor Vessel Steam Dome 1,2 2 SR 3.3.1.1.1 S 1072 psIg Pr*ssure - Nigh SR 3.3.1.1.8 SR 3.3.1.1.9 SR 3.3.1.1.13 St 3.3.1.1.14 SR 3.3.1.1.17 4.' Reactor Vessel Water Level - Low, Level 3 2 SR SR SR 3.3.1.1.1 3.3.1.1.8 3.3.1.1.9 t 157.8 inches 1$

SR 3.3.1.1.13 SR 3.3.1.1.14 SR 3.3.1.1.17

5. Main Stem Isolation a SR 3.3.1.1.8 s 121 closed Valve - Ctosure SR 3.3.1.1.13 SR 3.3.1.1.14 SR 3.3.1.1.17

6. Drywett Pressure-Nigh 1,2 H OR 3.3.1.1.1 5 1.85 pItg Al, SR 3.3.1.1..8 St 3.3.1.1.9 SR 3.3.1.1.13 SR 3.3.1.1.14 2

7. Scram Discýhrge Volume water Level - High

a. Trarnmitter/Trip Unit .1,2 SR 3.3.1.1.1 S 49.S Inches 3,.3.1. 1.8 SR 2 SR 3.3.1.1.9 SR 3.3.1.1.11 SR 3.3.1.1.14 St 3.3.1.1.1 5 49.5 inches 3.3.1.1.8 SR 49.5 lnchec 2 3.3.1.1.9 SR 3.3.1.1.1 3.3.1.1.14 SR Sn 3.3.1.1.8

b. Float Switch 1,2 :S49.5 inches -I-.

SR 3.3.1.1.13 SR 3.3.1.1.14 SIR 3.3.1.1.8 s 49.5 inches X SR 3,3.1.1.13 SR 3.3.1.1.14 3.3.1.1.8 S. Turbine Stop 4 SR S 7% closed

< RTP 3.3.1.1.13 Valve -Closure SR SR 3.3.1 *1.14 SR 3.3.1.1.15 SR 3.3.1 *1 *17 (cont fnueWc

}a) With an conttol rodf withdrawn, from a core cell containing one or more fuel essetlbles.

NMP2 NMPZ~~3.3.1.1-9Amnet Amendment .. , ,2

RPS Instrumentation 3.3.1.1 TabLe 3.3.1.1-1 (pmp 3 of 3)

Reactor Protectfon System instrumentation APPLICABLE CONDITIO* S INDES OR REQUIRED REFERENCEO OTHER CHANNELS FRPO SPECIFIED PER TRIP REQUIRED SURVEILLANCE ALLOWABL.E FUNCTION CONDITIONS SYSTEM ACTION 0.1 REQUIREMENTS VALUE

9. Turbine Controt Vaeve 2 E SR 3.3.1.1.8 465 psig Fast Ctosure, Trip OIL SR 3.3.1.1.13 Pressure - Low SR. 3.3.1.1.14 R 6

,2 rSt 3.3.1.1.15 SR 3.3.1.1.17

10. Reactor Node 2 N SR 3.3.1.1.14 NA Switch -Shutdown Position SR 3.3.1.1.14 5(a) 2 I SR 3.3.1.1.12 NA SR 3.3.11.1,4 Manual Sceam 1,2 1i. 8 SR 3.3.1.1.4 NA SR 3.3.1.1.14 5(a) 4 I SR 3.3.1.1 , NA SR 3.3.1.1.14 (a) With any control rod withdrawn from a core ceLL containing one or more fuet asseablies.

NMP2 3,3.1.1-10 Amendment-" *; 9 O-

Feedwater System and Main TtPbihe High Water Level Trip Instrumentation 3.3.2.2 3.3 INSTRUMENTATION 3.3.2.2 Feedwater System and Main Turbine High Water Level Trip Instrumentation LCO 3.3.2.2 Three channels of feedwater system and main turbine high water level trip instrumentation shall be OPERABLE.

APPLICABILITY: THERMAL POWER ~:RTP.

ACTIONS

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

Separate Condition entry is allowed for each channel.

CONDITION REQUIREDACTION COMPLETION TIME A. One feedwater system A.I Place channel in 7 days and main turbine high trip.

water level trip channel inoperable.

B. Two or more feedwater B.1 Restore feedwater 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months system and main system and main turbine high water turbine high water level trip channels level trip inoperable, capability.

(continued)

NMP2 3.3.2.2-1 Amendment --

Feedwater System and Main Turbine. High Water Level Trip Instrumentation 3.3.2.2 ACTIONS (ontinued) I_....___"____ ll CONDITION REQUIRED ACTION COMPLETION TIME C., Required Action and C.1 -------- NOTE---------

associated Completion Only applicable if Time not met. inoperable channel is the result of an inoperable feedwater pump breaker.

Remove affected 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months feedwater pump(s) from service.

OR C.2 Reduce THERMAL POWER 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months to <(9'RTP.

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 feedwater system and main turbine high-water level trip capability is maintained.

SURVEILLANCE FREQUENCY SR 3.3.2.2.1 Perform CHANNEL CHECK. 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months SR 3.3.2.2.2 Perform CHANNEL FUNCTIONAL TEST. .92 days (continued),

NMlP2 3.3.2.2-2 Amendment-9+-.5

EOC-RPT Instrumentation 3.3.4.1 3.3 INSTRUMENTATION 3.3.4.1 End of Cycle Recirculation Pump Trip (EOC-RPT) Instrumentation LCO 3.3.4.1 a. Two channels per trip system for each EOC-RPT instrumentation Function listed below shall be OPERABLE:

1. Turbine Stop Valve (TSV)-Closure; and

2. Turbine Control Valve (TCV) Fast Closure, Trip Oil Pressure-Low.

OR

b. LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR),"

limits for inoperable EOC-RPT as specified in the COLR are made applicable.

APPLICABILITY: THERMAL POWER > with any recirculation pump in fast speed.

ACTIONS

NOTE ---------

Separate Condition entry is allowed for each channel.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more required A.1 Restore channel to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months channels inoperable. OPERABLE status.

OR (continued)

NMP2 3.3.4.1-1 33Amendment -94

" EOC-RPT Instrumentation 3.3.4.1 ACTIONS _

CONDITION REQUIRED ACTION COMPLETION TIME A. (continued) A.2 ---------NOTE-------

Not applicable if inoperable channel is the result of an inoperable breaker.

Place channel in 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months trip.

B. One or more Functions B.1 Restore EOC-RPT trip 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months with EOC-RPT trip capability.

capability not maintained.

AND B.2 Apply the MCPR limit 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months for inoperable MCPR limit for EOC-RPT as specified inoperable EOC-RPT not in the COLR.

made applicable, C. Required Action and C.1 Remove the associated 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

associated Completion recirculation pump Time not met. fast speed breaker from service.

OR C.2 Reduce THERMAL POWER 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months to <6 NMP2 3.3.4.1-2 Amendment --

EOC-RPT Instrumentation 3.3.4.1 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 associated Function maintains EOC-RPT trip capability.

SURVEILLANCE FREQUENCY SR 3.3.4.1.1 Perform CHANNEL FUNCTIONAL-TEST. 92 days SR 3.3,4.1.2 Perform CHANNEL CALIBRATION. The 24' months Allowable Values shall be:

a. TSV-Closure:

7% closed; and

b. TCV Fast Closure, Trip Oil Pressure-Low: k 465 psig.

SR 3.3.4.1.3 Perform LOGIC SYSTEM FUNCTIONAL TEST, 24 months including breaker actuation.

SR 3.3.4.1.4 Verify TSV-Closure and TCV Fast Closure, 24 months' Trip Oil Pressure-Low Functions are not bypassed when THERMAL POWER is *(*RTP.

SR 3.3.4.1.5 ----------------- NOTE---------------

Breaker arc suppression time may be assumed from the most recent performance of SR 3.3.4.1.6.

Verify the EOC-RPT SYSTEM RESPONSE TIME 24 months on a is within limits. STAGGERED TEST BASIS (continued)

NMP2 3.3.4.1-3 Amendment Primary Containment Isolation Instrumentation 3.3.6.1 TabLe 3.3.6.1-1 (page 1 of 5)

Primary Contairfait isolation instrauentatl w' APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED OTHER CHANNELS FROM SPECIFIED PER TRIP REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS SYSTEM ACTION CA REQUIREMEN$TS VALUE

1. Main Steen Line Isolation

a. Reactor Vessel Water 12,3 2 D SR 3.3.6.1.1 10,8 inces lt Level - Low Low Low, SR 3.3.6.1.3 Level 1 SR 3.3.6.1.4 SR 3.3.6.1.5 SR 3.3.6.1.6 SR 3.3.6.1.7

b. Hain Steam Line 1 2 E SR 3.3.6.1.1 k 746 plsi Pressure - Low SR 3.3.6.1.3 SR 3.3.6.1.4 SR 3.3,6.1,5 SR 3.3,6.1.6 SR 3.3.6.1.7 184.4 4

C. Main Steam Line 1,2,3 2 per 14SL 0 SR 3.3.6.1.1 -psid Flow- High SR 3.3.6.1.3 SR 3.3.6.1.4 SR 3.3.6.1.5 SR 3.3,61.6 SR 3.3.6.1.7

d. Cordenser Vacuum - Low 1,2(8)s 2 D SR 3.3,6.1,1 t_7.6 inches It,) SR 3.3.6.1.3 Ng vacuum SR 3.3.6.1.4 SR 3.3.6.1.5 SR 3.3.6.1.6

e. Main Stewm Line 1,2,3 . SR 3.3.6.1.1 S 170.66F

,Tunnel SR 3.3.6.1.3 Temperature - High SR 3.3.6.1.1 SR 3.3.6.1.6 1,2,3 2 D SR 3.3.6.1.1 s 71.70F

f. Main Steam Line Tunnel Differential SR 3.3.6.1.3 Teuqwrature - High 3.3.6.1.5 SR 3.3.6.1.6 SR

9. Rain Steam Line 1,2,3 2 per area 3.3.6.1.1 s 151.69F(b)

Tunnel Lead Enclosure SR 3.3.6.1.2 Terperature - Ni gh SR 3.3.6.1.3 SR 3.3.6.1.5 SR 3.3,6.1.6

h. Manual Initiation 1,2,3 4 a SR 3.3.6.1.6 NA (continued)

(a) With any turbine stop valve not closed.

(b) 151.6"F + (0.6)(Tamb -909F) and S 175.69F provided the absence of steam leaks in the main steam line tunnel lead enclosure area Is verified by visual inspection prior to estabtishing the ALLowable Value.

NMP2 3.3.6.1-6 Amendment -093--11

Jet Pumps 3.4.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.3.1 ---------------- NOTES-----------------

1. Not required to be performed until 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months after associated recirculation loop is in operation.

2. Not required to be Rerfoiined until 23%

24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after>(M5RP.

Verify at least two of the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months criteria (a, b, and c) are satisfied for each operating recirculation loop:

a. Jet pump loop flow versus flow control valve position differs by 5 10% from established patterns.

b. Jet pump loop flow versus recirculation loop drive flow differs by S 10% from established patterns.

c. Each jet pump diffuser to lower plenum differential pressure differs by : 20%

from established patterns.

NMP2 3.4.3-2 NMP2 34.3-2Amendnient4-

Main Turbine Bypass System 3.7.5 3.7. PLANT SYSTEMS 3.7.5 Main Turbine Bypass System LCO 3.7.5 The Main Turbine Bypass System shall be OPERABLE.

LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)," limits for an inoperable Main Turbine Bypass System, as specified in the COLR, are made applicable.

APPLICABILITY: THERMAL POWER TP ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME

-A. Requirements of the A.I Satisfy the 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months LCO not met. requirements of the LCO.

B. Required Action and B. Reduce THERMAL POWER 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months associated Completion to <(gjRTP.

Time not met, SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.5.1 Perform a system functional test. 24 months SR 3.7.5.2 Verify the TURBINE BYPASS SYSTEM RESPONSE 24 months TIME is within limits.

NMP2 3.7.5-1 Amendment

ENCLOSURE ATTACHMENT 2 Technical Specifications Bases Page Markups (Information Only)

Pages Included in this Markup B 2.0-3 B 3.3.1.1-34 B 2.0-5 B 3.3.1.1-36 B 3.1.7-5 B 3.3.2.2-1 B 3.2.1-2 B 3.3.2.2-3 B 3.2.1-3 B 3.3.2.2-5 B 3.2.2-2 B 3.3.4.1-2 B 3.2.2-3 B 3.3.4.1-4 B 3.2.3-2 B 3.3.4.1-5 B 3.2.3-3 B 3.3.4.1-7 B 3.3.1.1-7 B 3.3.4.1-9 B 3.3.1.1-9 B 3.3.6.1-9 B 3.3.1.1-13 B 3.4.3-4 B 3.3.1.1-20 B 3.4.11-1 B 3.3.1.1-21 B 3.7.5-1 B 3.3.1.1-28 B 3.7.5-2 B 3.3.1.1-29 B 3.7.5-3 B 3.3.1.1-33 Nine Mile Point Nuclear Station, LLC May 27, 2009

Reactor Core SLs B 2.1.1

@4 BASES APPLICABLE 2,1.].1 FUel Cladding Integrity (continued)

SAFETY ANALYSES data taken at pressures from 14.7 psia to 800 psia indicate that the fuel assembly critical power at this flow is approximately 3.35 MWt. With the design peaking factors, this corresponds to a THERMAL POWER

> 50% RTP. Thus, a THERMAL POWER limit of (MRTP for reactor pressure < 785 psig is conservative.

2.1.1.2 MC 23%

The fuel cladding integrity SL is set such that no significant fuel damage is calculated to occur if the limit is not violated. Since the parameters that result in fuel damage are not directly observable during reactor operation, the thermal and hydraulic conditions that result in the onset of transition boiling have been used to mark the beginning of the region in which fuel damage could occur.

Although it is recognized that the onset of transition boiling would not result in damage to BWR fuel rods, the critical power at which boiling transition is calculated to occur has been adopted as a convenient limit. However, the uncertainties in monitoring the core operating state and in the procedures used to calculate the critical power result in an uncertainty in the value of the critical power.

Therefore, the fuel cladding integrity SL is defined as the critical power ratio in the limiting fuel assembly for which more than 99.9% of the fuel rods in the core are expected to avoid boiling transition, considering the power distribution within the core and all uncertainties.

The MCPR SL is determined using a statistical model that combines all the uncertainties in operating parameters and the procedures used to calculate critical power. The probability of the occurrence of boiling transition is determined using the approved General Electric Critical Power correlations. Details of the fuel cladding integrity SL calculation are given in References-QýReference 3 also includes a tabulation of the uncertainties sed in the determination of the MCPR SL and Reference 4Kai so provides the nominal values of the parameters used n the MCPR SL statistical analysis.

4n*(continued)

NMP2 B Z.0-3 Revision -t--

Reactor Core SLs B 2.1.1 BASES (continued)

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

2. GE Service Information Letter No. 516, Supplement 2, "Core Flow Indication in the Low-Flow Region,"

January 19, 1996.

3. NEDE-2401 1-P-A, "GE Standard Application for Reactor Fuel," (revision specified in the COLR).

4. Supplemental Reload Licensing Report for Nine Mile Point Nuclear Station Unit 2 (revision specified in the COLR).

5. 10 CFR 50.67, "Accident Source Term."

6. NEDC-331I73-P-A, "Applicability of GE Methods to Expanded Operating Domains" 49 NMP2 B 2.0-5 Revision Q ,-2 (A!-25) 1

SLC System B 3.1.7 BASES SURVEILLANCE SR 3.1.7.4 and SR 3.1.7.6 (continued)

REQUIREMENTS manual, power operated, and automatic valves in the SLC System flow path ensures that the proper flow paths will exist for system operation. A valve is also allowed to be in the nonaccident position, provided it can be aligned to the accident position from the control room, or locally by a dedicated operator at the valve control. This is acceptable since the SLC System is a manually initiated system. This Surveillance does not apply to valves that are locked, sealed, or otherwise secured in position, since they were verified to be in the correct position prior to locking, sealing, or securing. This verification of valve alignment does not apply to valves that cannot be inadvertently misaligned, such as check valves. This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of being mispositioned are in the correct positions. The 31 day Frequency is based on engineering judgment and is consistent with the procedural controls governing valve operation that ensure correct valve positions.

SR 3.1.7.5 This Surveillance requires an examination of the sodium pentaborate solution by using chemical analysis to ensure the proper concentration of boron (measured in weight %

sodium pentaborate decahydrate) exists in the storage tank.

SR 3.1.7.5 must be performed anytime boron or water is added to the storage tank solution to establish that the boron solution concentration is within the specified limits. This Surveillance must be performed anytime the temperature Is restored to within the limit (i.e., Ž 70 0F), to ensure no significant boron precipitation occurred. The 31 day Frequency of this Surveillance Is appropriate because of the relatively slow variation of boron concentration between surveillances.

SR 3.1.7.7 132 Demonstrating each SLC System pump evelops a flow rate

> 41.2 gpm at a discharge pressure >I- ___psig ensures that pump performance has not degraded during the fuel cycle.

This minimum pump flow rate requirement ensures that, when (continued)

NMP2 B 3.1.7-5 Revision 01 7 (A,47), 24 (A1^23), 26 (A4125)

APLHGR B 3.2.1 BASES APPLICABLE The APLHGR satisfies Criterion 2 of Reference 4.

SAFETY ANALYSES (continued)

LCO The APLHGR limits specified in the COLR are the result of fuel design and DBA analyses. For two recirculation loops operating, the limit is dependent on bundle exposure. With only one recirculation loop in operation, in cqnformance with the requirements of LCO 3.4.1, "Recirculatlon Loops Operating," the limit is determined by multiplying the exposure dependent APLHGR limit by a conservative multiplier determined by a specific single recirculation loop analysis (Ref. 2).

APPLICABILITY The APLHGR limits are primarily derived from fuel design evaluations and LOCA analyses that are assumed to occur at high power levels. Studies and operating experience have shown that as power is reduced, the margin to the required APLHGR limits increases. This trend continues down to the power range of 5% to 15% RTP when entry into MODE 2 occurs.

When in MODE 2, the intermediate range monitor (IRM) scram function provides prompt scram initiation during any significant transient, thereby effectively removing any APLHGR limit compliance ncern in MODE 2. Therefore, at THERMAL POWER levels c RTP, the reactor operates with substantial margin to the'APLHGR limits; thus, this LCO is not required. I>

ZJý10 ACTIONS If any APLHGR exceeds the required limits, an assumption regarding an initial condition of the DBA analyses may not be met. Therefore, prompt action is taken to restore the APLHGR(s) to within the required limits such that the plant will be operating within analyzed conditions and within the design limits of the fuel rods. The 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Completion Time is sufficient to restore the APLHGR(s) to within its limits and is acceptable based on the low probability of a DBA occurring simultaneously with the APLHGR out of specification.

(continued)

NMP2 B 3.2.1-2 Revision-0-1

APLHGR B 3.2.1 BASES ACT IONS (continued) If the APLHGR cannot b* restored to within its required limits within the asoI ated Completion Time, the plant must be brought to a MODE or ther specified condition in which the LCO does not apply. achieve this status, THERMAL POWER must be reduced to < RTP within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . The allowed Completion Time is reasonable, based on operating experience, to reduce THERMAL POWER to <JR RTP in an orderly manner and without challenging plan ,stems.

SURVEILLANCE SR 3.2.1.1 (

REQUIREMENTS APLHGRs are required to be initialiylcalculated within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after THERMAL POWER is Ž )RTP and then every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months thereafter. They are compared to the specified limits in the COLR to ensure that the reactor is operating within the assumptions of the safety analysis. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is based on both engineering judgment and recognition of the slowness of changes in power distribution under normal conditions. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowance after THERMAL POWER RTP is achieved is acceptable given the large inherent margi to operating limits at low power levels. (23%

I REFERENCES 1. NEDE-24011-P-A, "GE Standard Application for Reactor Fuel," (revision specified in the COLR).

2. USAR, Chapter 15B.

3. USAR, Chapter 15G.

4. 10 CFR 50.36(c)(2)(ii).

NMP2 B 3.2.1-3 NMP2B 3..1-3Revision-O

MCPR B 3.2,2 BASES APPLICABLE The MCPR operating limits derived from the transient SAFETY ANALYSES analysis are dependent on the operating core flow and power state (continued) (MCPRf and MCPRp, respectively) to ensure adherence to fuel design limits during the worst transient that occurs with moderate frequency as identified in USAR, Chapter 15B. The determination of MCPR limits is discussed in Reference 6.

The MCPR operating limit is the greater of either the flow dependent f

MCPR limit (MCPR1 ) or the power dependent MCPR limit (MCPRp).

The power dependent multiplier increases at lower powers due to the feedwater controller failure transient because, for lower powers, the K

mismatch between runout and Initial feedwater flow increases, This -4 results in an increase in reactor subcooling and more severe changes in thermal limits during the event at offrated power. The flow /

dependent limit increases at lower flows due to recirculation flow

/

increase events because, for lower flows, the difference between initial flow and maximum possible core flow increases. This results in /

/

an increase in reactor power and more severe changes in thermal 4-limits during the event at offrated flow. /

The MCPR satisfies Criterion 2 of Reference 4, LCO The MCPR operating limits specified in the COLR are the result of the Design Basis Accident (DBA) and transient analysis. The MCPR operating limits./( limit is determined by the larger of the MCPRf and -MCPR,

~~1 APPLICABILITY The MCPR operating limits are primarily derived from ansient analyses that are assumed to occur at high power levels. Belo* RTP the reactor is operating at a slow recirculation pump speed and the moderator void ratio is small. Surveillance of thermal limits below4"0(

RTP is unnecessary due to the large inherent margin that ensures that(

the MCPR SL is not exceeded even if a limiting transient occurs.

Statistical analyses documented in Reference 5 indicate that the nominal value of the initial MCPR expected at -ETP is > 3.5, Studies of the variation of limiting transient behavior have een performed over the range of power and flow conditions. These 23%

studies encompass the range of key actual plant parameter values important to typically limiting transients. The results of these studies demonstrate that a margin is expected between performance and the MCPR requirements, and that margins increase as power is reduced to(gRTP. This trend is expected to continue to the 5% to 15% powe range when entry into MODE 2 (conntin usd*

"1 NMP2 B 3.2.2-2 23% Revision G 24 (A4a3)-*,

vj cmmr\f

, A,v

MCPR B 3.2,2 BASES APPLICABILITY occurs. When in MODE 2, the intermediate range monitor (continued) (IRM) provides rapid scram initiation for any significant power increase transient, which effectively eliminates any M MCPR compliance concern. Therefore, at THERMAL POWER levels C23%o ) RTP, the reactor is operating with substantial margin t MCPR limits and this LCO is not required.

tthe ACTIONS A.1I If any MCPR is outside the required limits, an assumption regarding an initial condition of the design basis transient analyses may not be met. Therefore, prompt action should be taken to restore the MCPR(s) to within the required limits such that the plant remains operating within analyzed conditions. The 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Completion Time is normally sufficient to restore the MCPR(s) to within its limits and is acceptable based on the low probability of a transient or DBA occurring simultaneously with the MCPR out of specification.

.1_23%

If the MCPR cannot be estored to within the required limits within the associated Completion Time, the plant must be brought to a MODE or other specified condition in which the LCO does not apply. o achieve this status, THERMAL POWER must be reduced to <cgRTP within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . The allowed Completion Time is reasonable, based on operating experience, to reduce THERMAL POWER to < RTP in an orderly manner and without challenging plant systems.

SURVEILLANCE Ha .2.2 1 3

.2323%

REQUIREMENTS The MCPR is required to be initiall alculated within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after THERMAL POWER is ŽC)RTP and then every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months thereafter. It is compared to the specified limits in the COLR to ensure that the reactor is operating within the assumptions of the safety analysis. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is based on both engineering judgment and recognition of the slowness of changes in power distribution during normal operation. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowance after THERMAL POWER reaches ; 1RTP is acceptable given the large inherent margin to operating limits at low power levels. )r!

C2 3ý%/ýo(continued)

NMP2 8 3.2.2-3 Revision-O--

.4

LHGR B~3.2,3 BASES APPLICABLE The LHGR limit is the applicable rated-power, rated-flow LHGR limit SAFETY ANALYSES multiplied by the smaller of either the flow dependent multiplier or the (continued) power dependent multiplier as specified in the COLR. The power dependent multiplier increases at lower powers due to the feedwater controller failure transient because, for lower powers, the mismatch between runout and initial feedwater flow increases. This results in an increase in reactor subcooling and more severe changes in thermal limits during the event at offrated power. The flow dependent multiplier increases at lower flows due to recirculation flow increase events because, for tower flows, the difference between initial flow and maximum possible core flow Increases. This results in an increase in reactor power and more severe changes in thermal limits during the event at offrated flow.

The LHGR satisfies Criterion 2 of Reference 4, LCO The LHGR is a basic assumption in the fuel design analysis.

The fuel has been designed to operate at rated core power with sufficient design margin to the LHGR calculated to cause a 1% fuel cladding plastic strain. The operating limit to accomplish his objective Is specified in the COLR.

The LHGR limits are dendved from fuel design analysis that APPLICABILITY is limiting at high ower level conditions. At core thermal power levels <(5RTP, the reactor is operating with a substantial margin to the LHGR limits and, therefore, the Specification is only required when the reactor is operating at

RTP.

Ai4 ACTIONS *.....L If any LHGR exceeds its required limit, an assumption regarding an initial condition of the fuel design analysis is not met. Therefore, prompt action should be taken to restore the LHGR(s) to within its required limits such that the plant is operating within analyzed conditions. The 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Completion Time is normally sufficient to restore the LHGR(s) to within its limits and is acceptable based on the low probability of a transient or Design Basis Accident occurring simultaneously with the LHGR out of specification.

(continued)

NMP2 B 3.2.3-2 Revision 9.24-'A`2')-5

LHGR B 3.2.3 BASES ACTIONS B.1 23%

(continued) If the LHGR cannot be estored to within its required limits within the associated ompletion Time, the plant must be brought to a MODE r other specified condition In which the LCO does not apply To achieve this status, THERMAL POWER must be reduced to RTP within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , The allowed Completion Time is reasonable, based on operatin experience, to reduce THERMAL POWER to RTP in an orderly manner and without challenging plant system 23%

OU M!r¶ IL.L.MI'Ifl orwF REQUIREMENTS The LHGRs are required to be initially alculated within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after THERMAL POWER is > 0 RTP and then every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months thereafter. They are compared with the specified limits in the COLR to ensure that the reactor is operating within the assumptions of the safety analysis. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is based on both engineering judgment and recognition of the slowness of changes in power distribution under normal conditions. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowance after THERMAL POWER >: gRTP is achieved is acceptable given the large levels.inherent margin to operating limits at lower power

_* "r -

REFERENCES 1. NEDE-2401 1-P-A, "GE Standard Application for Reactor Fuel," (revision specified in the COLR).

2. Supplemental Reload Licensing Report for Nine Mile Point Nuclear Station Unit 2, (revision specified in the COLR).

3. NUREG-0800, Section IIA.2(g), Revision 2, July 1981.

4. 10 CFR 50.36(c)(2)(ii).

5. NEDC-33286P, "Nine Mile Point Nuclear Station Unit 2 -

APRM/RBM/Technical Specifications/Maximum Extended Load Line Limit Analysis (ARTS/MELLLA)," March 2007.

NMP2 B 3.2.3-4 Revision 0, N2 4 ý-

RPS Instrumentation B 3.3.1.1 BASES APPLICABLE 2.a. Average Power Rance Monitor Neutron Flux-Upscale, SAFETY ANALYSES, Setdown (continued)

LCO, and APPLICABILITY With the IRMs at Range 9 or 10, it is possible that the Average Power Range Monitor Neutron Flux-Upscale, Setdown Function will provide the primary trip signal for a core-wide increase In power.

No specific safety analyses take direct credit for the Average Power Range Monitor Neutron Flux-Upscale, Setdown Function. However, this Function indirectly ensures that, 23o% /

before the reactor mode switch is placed in he runC position, reactor power does not exceed t*RTP (SL 2.1.1.1) when operating at 1ow reactor pressure and low core flow.

Therefore, it indirectly prevents fuel damage during significant tivity increases with THERMAL POWER The APR9 System is divided into four APRMs, each providing an input into both trip systems via the 2-Out-Of-4 Voter 1/1 channels, Function 2.f. Each APRM inputs to all four 2-Out-Of-4 Voter channels, with each APRM input into a 2-Out-Of-4 Voter channel considered a channel. Thus, there are a total of 16 Average Power Range Monitor Neutron Flux-Upscale, Setdown channels, with eight channels per trip system and four channels per logic channel. The system is designed to allow one APRM to be bypassed (and since the APRM provides an input to all four 2-Out-Of-4 Voter channels, one channel in each logic channel is effectively bypassed). Any two APRM channels in a logic channel can cause the associated trip system to trip. Since each APRM inputs into both trip systems, this effectively means that when two APRMs provide a Neutron Flux-Upscale, Setdown signal, two channels, in both logic channels in each trip system will trip, producing a scram. Twelve channels of Average Power Range Monitor Neutron Flux-Upscale, Setdown, with three channels per logic channel in each trip system are required to be OPERABLE to ensure that no single failure will preclude a scram from this Function on a valid signal.

In addition, to provide adequate coverage of the entire core, at least 20 LPRM inputs are required for each APR4, with at least three LPRM inputs from each of the four axial levels at which the LPRMs are located.

The Allowable Value is based on preventing sJ ificant increases in power when THERMAL POWER is <L RTP.

NM~P( B 3conti-nud NMP2 ýB 3.3.1.1-7 Rev is ion +-1--

RPS Instrumentation B 3.3.1.1

.. BASES APPLICABLE 2.b. Average Power Rapqg Monitor Flow Biased Simulated SAFETY ANALYSES, Thermal Power-Upscale (continued)

LCO, and APPLICABILITY 2-Out-Of-4 Voter channels, with each APRM input into a 2-Out-Of-4 Voter channel considered a channel. Thus, there are a total of 16 Average Power Range Monitor Flow Biased Simulated Thermal Power-Upscale channels, with eight channels per trip system and four channels per logic channel. The system is designed to allow one APRM to be bypassed (and since the APRM provides an input to all four 2-Out-Of-4 Voter channels, one channel in each logic channel is effectively bypassed). Any two APRM channels in a logic channel can cause the associated trip system to trip. Since each APRM inputs into both trip systems, this effectively means that when two APRMs provide a Flow Biased Simulated Thermal Power-Upscale signal, two channels in both logic channels in each trip system will trip, producing a scram.

Twelve channels of Average Power Range Monitor Flow Biased Simulated Thermal Power-Upscale, with three channels per logic channel in each trip system are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function on a valid signal. In addition, to provide adequate coverage of the entire core, at least 20 LPRM inputs are required for each APRM, with at least three LPRM inputs from each of the four axial levels at which the LPRMs are located. Each APRM receives two flow signals from two flow transmitters, one from each reactor recirculation loop. The total. recirculation drive flow signal is generated by the flow processing logic part of the Thenominaltripsetpointforthis APRM, by summing the flow calculated from these two flow heunctiomn tripse+ t%fr S

RTP transmitter signal inputs. Each APRM receives flow signals functionisO.SSW+S7.S%RTP - from different flow transmitters (a total of eight flow (or O.SO (W-S %) + 50.5 % RTP when transmitters).

reset for single loop operation).

The nominaltripsetpoint, andthe No specific safety analyses take direct credit for the As-Found and As-Left tolerances Average Power Range Monitor Flow Biased Simulated Thermal Power-Upscale Function. Originally, the clamped Allowable weredeterminedinaccordance Value was based on analyses that took credit for the Average with the setpoint methodology Power Range Monitor Flow Biased Simulated Thermal of Reference 16. Power-Upscale Function for the mitigation of the loss of feedwater heater event'. However, the current methodology for this event is based on a steady state analysis that allows power to increase beyond the clamped Allowable Value.

Therefore, applying a clamp is conservative. The THERMAL POWER time constant of < 6.6 seconds is based on the fuel heat transfer dynamics and provides a signal that is proportional to the THERMAL POWER.

(continued)

NMP2 B 3.3.1.1-9 Revision-0-)

RPS Instrumentation B 3.3.1.1 BASES APPLICABLE 2.e. Average Power Range Monitor OPM,-U~scale (continued)

SAFETY ANALYSES, LCO, and An OPRM--Upscale trip can also be generated if either the APPLICABILITY growth rate or amplitude based algorithms detect growing oscillatory changes in the neutron flux for one or more cells. However, this portion of the trip is not required b this Specification; only the period based algorithm is required for OPERABILITY.

The APR1 System is divided into four APRMs, each providing an input into both trip systems via the 2-Out-Of-4 Voter channels, Function 2.f. Each APRM inputs to all four r'1 2-Out-Of-4 Voter channels, with each APRM input into a 2-Out-Of-4 Voter channel considered a channel. Thus, there are a total of 16 Average Power Range Monitor OPRM-Upscale channels, with eight channels per trip system and four channels per logic channel. The system is designed to allow I, one APRM to be bypassed (and since the APRM provides an input to all four 2-Out-Of-4 Voter channels, one channel in each logic channel is effectively bypassed). Any two APRM channels in a logic channel can cause the associated trip system to trip. Since each APRM inputs into both trip systems, this effectively means that when two APRMs provide "/

an OPRM--Upscale signal, two channels in both logic channels in acrh trin uvetm will trin nrndirinn a erram Twolvu channels of Average Power Range Monitor OPRil-Upscale with three channels per logic channel in each trip system are required to be OPERABLE to ensure that no single instrument /

failure will preclude a scram from this Function on a valid signal. In addition, to provide adequate coverage of the entire core, a minimum of 21 cells, each with a minimum of two LPRMs, are required for each OPRM-Upscale Function.

The Allowable Value, which is specified in the COLR, is based on ensuring the MCPR Safety Limit is not exceeded due '

to anticipated thermal-hydraulic power oscillations.

The Average Power Range Monitor OPRM-Upscale Function 26%

automatic trip is only enabled when THERMAL POWER, as determined by APRM Simulated Thermal Power, is Ža RTP and reactor core flow, as indicated by recirculation drive flow, is < 60% of rated recirculation drive flow. This is the operating region where actual thermal-hydraulic oscillations may occur. However, the Average Power Range Monitor OPRM--Upscale Function is required to be OPERABLE at all times while in MODE 1. When the automatic trip is bypassed,-

the Average Power Range Monitor OPRM-Upscale Function is (continued)

NMP2 B 3.3.1.1-13 Rev is ion ý-,4 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE 8. Turbine Stop Valve-Closure (continued)

SAFETY ANALYSES, LCO, and RPS trip system receives an input from four Turbine Stop APPLICABILITY Valve-Closure channels, each consisting of one valve stem position switch (which is common to a channel in the other RPS trip system) and a switch contact. The logic for the Turbine Stop Valve-Closure Function is such that three or more TSVs must be closed to produce a scram. In addition, certain combinations of two valves closed will result in a half scram. - 26%

This Function must be enabled at THERMAL POWER >_ RTP.

This is normally accomplished automatically by pressure transmitters sensing turbine first stage pressure; therefore, opening the turbine bypass valves may affect this Function.

The Turbine Stop Valve-Closure, Allowable Value is selected to detect imminent TSV closure thereby reducing the severity of the subsequent pressure transient.

Eight channels of Turbine Stop Valve-Closure, with four channels in each trip system, are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function if the TSVs should close. This Function is required, = sistent with analysis assumptions, whenever THERMAL POWER is 3_ ý RTP. This Function is not required when THERMAL POWER is < RTP since the Reactor Vessel Steam Dome Pressure-High and he Average Power Range Monitor Fixed Neutron Flux-Upscale Fu tions are adequate to maintain the necessary safety margins. 26%

9. Turbine Control Valye.Fast Closure. Trio Oil Pressure--Low Fast closure of the TCVs results in the loss of a heat sink that produces reactor pressure, neutron flux, and heat flux transients that must be limited. Therefore, a reactor scram is initiated on TCV fast closure in anticipation of the transients that would result from the closure of these valves. The Turbine Control Valve Fast Closure, Trip Oil Pressure-Low Function is the primary scram signal for the generator load rejection event analyzed in Reference 4. For this event, the reactor scram reduces the amount of energy required to be absorbed and, along with the actions of the EOC-RPT System, ensures that the MCPR SL is not exceeded.

(continued)

NMP2 B 3.3.1.1-20 Revision ,4-

RPS Instrumentation B 3.3.1.1 BASES APPLICABLE 9. Turbine Control Valve Fast Closure, Trip Oil SAFETY ANALYSES, Pressure-Low (continued)

.LCO, and APPLICABILITY Turbine Control Valve Fast Closure, Trip Oil Pressure-Low signals are initiated by the EHC fluid pressure at each control valve. There is one pressure switch associated with each control valve, the signal from each switch being assigned to a separate RPS logic channel. This Function 26%

must be enabled at THERMAL POWER Ž VP. This is normally accomplished automatically by pressure transmitters sensing turbine first stage pressure; therefore, opening the turbine bypass valves may affect this Function.

The Turbine Control Valve Fast Closure, Trip Oil Pressure-Low Allowable Value is selected high enough to detect imminent TCV fast closure.

Four channels of Turbine Control Valve Fast Closure, Trip Oil Pressure-Low Function, with two channels in each trip system arranged in a one-out-of-two logic, are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function on a valid signal. TIh -

Function is required, consistent with the ar/a sis assumptions, whenever THERMAL POWER is >TRTP. This 26%

Function is not required when THERMAL POWER is < TP since the Reactor Vessel Steam Dome Pressure-High and the 260%

Average Power Range Monitor Fixed Neutron Flux-Upscale Functions are adequate to maintain the necessary safety margins.

10. Reactor Mode Switch-Shutdown Position The Reactor Mode Switch-Shutdown Position Function provides signals, via the manual scram logic channels, that are redundant to the automatic protective instrumentation channels and provide manual reactor trip capability. This Function was not specifically credited in the accident analysis, but it is retained for the overall redundancy and diversity of the RPS as required by the NRC approved licensing basis.

The reactor mode switch is a single switch with four channels (one from each of the four independent banks of contacts), each of which inputs into one of the RPS logic channels.

(continued)

NMP2 B 3.3.1.1-21 Revi si on ,+9

RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1,1 and SR 3.3.1.1.2 REQUIREMENTS (continued) Performance of the CHANNEL CHECK once every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months or every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , as applicable, ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value.

Significant deviations between the instrument channels could be an indication of excessive instrument drift on one of the channels or something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the. instrumentation continues to operate properly between each CHANNEL CALIBRATION.

Agreement criteria are determined by the plant staff based on a combination of the channel instrument uncertainties, including indication and readability. If a channel is outside the criteria, it may be an indication that the instrument-has drifted outside its limit.

The Frequency Is based upon operating experience that demonstrates channel failure is rare. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the channels required by the LCO.

SR 3.3.1.1.3 To ensure that the APRMs are accurately indicating the true core average power, the APRMs are calibrated to the reactor power calculated from a heat balance. The Frequency of once per 7 days is based on minor changes in LPRM sensitivity, which could affect the APRM, reading between performances of SR 0

3.3,1.1.7, An allowance is provided that requires the SR to be performed only at ;t ,'RTP because it is difficult to accurately maintal PRM indication of core THERMAL POWER 23% (continued)

NMP2 B 3.3.1.1-28 Revision 0,, 2-(4A42*

RPS Instrumentation 8 3.3.1.1 BASES 3.3,.1.3, (continued) 20 SURVEILLAN CEE REQUIREMENTS consistent with a heat balance when <f(RTP. At low power levels, a high degree of accuracy is unnecessary because of 2 the large inherent margin to thermal limits (MCPR, APLHGR, and LHGR). At - RTP, the Surveillance is required to have been satisfactorily accordance with SR 3.0.2. performed A Note iswithin the which last 7allows days in jrovided an increase in THERMAL POWER above- the 7 daay2 Frequency is not met per SR 3.0.2. In this event, the SR 23%_must be erformed within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after reaching or exceendi TRTP. Twelve hours is based on operating experience and in consideration of providing a reasonable time in which to complete the SR.

SR 3.3.1.1.4 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the channel will perform the intended function, Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology.

As noted, for Functions I.a and l.b, SR 3.3.1.1.4 is not required to be performed when entering MODE 2 from MODE I since testing of the MODE 2 required IRM Functions cannot be performed in MODE I without utilizing jumpers, lifted leads, or movable links. This allows entry into MODE 2 if the 7 day Frequency is'not met per SR 3.0.2. In this event, the SR must be performed within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after entering MODE 2 from MODE I. Twelve hours is based on operating experience and in consideration of providing a reasonable time in which to complete the SR.

A Frequency of 7 days provides an acceptable level of system average unavailability over the Frequency interval and is based on reliability analysis (Ref. 10). (The Manual Scram Function CHANNEL FUNCTIONAL TEST Frequency was credited in the analysis to extend many automatic scram Functions Frequencies.)

SR 3.3.1,1.5 and SR 3.3.1.1.6 These Surveillances are established to ensure that no gaps in neutron flux indication exist from subcritical to power (continued)

NMP2 B 3.3.1.1-29 Revision fi-ý-

.A

RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3,3.1.111 and SR 3.3.1.1.13 (continued)

REQUIREMENTS "Show Parameters" display. This is acceptable because, other than the flow and LPRM input processing, all OPRM functional processing is performed digitally involving equipment or components that cannot be calibrated. The Frequency of SR 3.3.1.1.11 is based upon the assumption of a 18 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis. The Frequency of SR 3.3.1.1.13 is based on the assumption of a 24 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.

SR 3.31.1.,14 The LOGIC SYSTEM FUNCTIONAL TEST (LSFT) 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 SDV vent and drain valves, in LCO 3.1.8, "Scram Discharge Volume (SDV) Vent and Drain Valves," overlaps this Surveillance to provide complete testing of the assumed safety function. In addition, for Function 2.f, the LSFT includes simulating APRM trip conditions at the APR?? channel inputs to the 2-Out-Of-4 Voter channel to check all combinations of two tripped APRM channel inputs to the 2-Out-Of-4 Voter logic in the 2-Out-Of-4 Voter channels.

The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power.

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

This SR ensures that scrams initiated from the Turbine Stop Valve-,Closure and Turbine Control Valve Fast Closure, Trip Oil Pressure-Low Functions will not be inadvertently 2b assed when THERMAL POWER is ;ý RTP. This involves calibra ion o e " h s. Adequate margins for the instrument setpoint methodology are incorporated into the Allowable Value and the actual setpoint. Because main

-(continued)

NMP2 B 3.3.1.1-33 Revision *--+/-

RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.15 (continued)

REQUIREMENTS 2?

turbine bypass flow can affect this setpoint nonconservatively (THERMAL POWER is derived from turbine first stage pressure), the main turbine bypass valves must remain closed during an in-service calibration at THERMAL POWER RTP to ensure that the calibration is valid. 26%

If any bypass channel setpoint is n nc rvative (i.e., the Functions are bypassed at > TP, either due to open main turbine bypass valve(s) or other reasons), then the affected Turbine Stop Valve - Closure and Turbine Control Valve Fast Closure, Trip Oil Pressure - Low Functions are considered inoperable. Alternatively, the bypass channel can be placed in the conservative condition (nonbypass). If placed in the nonbypass condition, this SR is met and the channel is considered OPERABLE.

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

SR 3.3.1.1.16 26%

This SR ensures that scram initiated from the APRM OPRM - Upscale Function not be inadvertently bypassed when THERMAL POWER is > RTP and recirculation drive flow is < 60% rated recirculation drive flow.

If any bypass channel setpoint is nonconservative (i.e., the Function is bypassed at RTP and < 60% rated recirculation drive flow), then the affected channel is considered inoperable. 2 The Frequency of 24 mont s is based on Ref. 15.

SR 3.3.1.1.17 This SR ensures that the individual channel response times are less than or equal to the maximum values assumed in the accident analysis. The RPS RESPONSE TIME acceptance criteria are included in Reference 12.

(continued)

NMP2 B 3.3.1.1-34 Revision G-,4,.-2 RPS Instrumentation B 3.3.1.1 BASES REFERENCES 8. USAR, Section 15.4.9.

(continued)

9. Letter, P. Check (NRC). to G. Lainas (NRC), "BWR Scram Discharge System Safety Evaluation," December 1, 1980.

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

March 1988.

11. NEDC-32410-P-A, "Nuclear Measurement Analysis and Control Power Range Neutron Monitor (NUMAC-PRNM)

Retrofit Plus Option III Stability Trip Function,"

October 1995.

12. Technical Requirements Manual.

13. NEDO-32291-A, "System Analyses for the Elimination of Selected Response Time Testing Requirements,"

October 1995.

14. USAR, Section 7.6.1.4.3.

15. NEDC-32410-P-A,, 'NUMAC-PRNM Retrofit Plus Option III Stability Trip Functions, Supplement 1,"

November 1997.

Setpoint Methodology", Class III (Proprietary), September 1996.

NMP2 B 3.3.1.1-36 Revision 0, 1 1

Feedwater System and Main Turbine High Water Level Trip Instrumentation B 3.3.2.2 B 3.3 INSTRUMENTATION B 3.3.2.2 Feedwater System and Main Turbine High Water Level Trip Instrumentation BASES BACKGROUND The Feedwater System and Main Turbine High Water Level Trip Instrumentation is designed to detect a potential failure of the Feedwater Level Control System that causes excessive feedwater flow.

With excessive feedwater flow, the water level in the reactor vessel rises toward the high water level, Level 8 reference point, causing the trip of the three feedwater pumps and the main turbine.

Reactor Vessel Water Level-High, Level 8 signals are provided by differential pressure transmitters that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level in the reactor vessel (variable leg). Three channels of Reactor Vessel Water Level-High, Level 8 instrumentation are provided as input to a two-out-of-three initiation logic that trips the three feedwater pumps and the main turbine. The channels include electronic equipment (e.g., trip units) that compares measured input signals with pre-established setpoints. When the setpoint is exceeded, the channel output relay actuates, which then outputs a feedwater pump and main turbine trip signal to the trip logic.

A trip of the feedwater pumps limits further increase in reactor vessel water level by limiting further addition of feedwater to the reactor vessel. A trip of the main turbine and closure of the stop valves protects the turbine from damage due to water entering the turbine.

APPLICABLE The Feedwater System and Main Turbine High Water Level Trip SAFETY ANALYSES Instrumentation is assumed to be capable of providing a feedwater pump and main turbine trip in the design basis transient analysis for a feedwater controller failure, maximum demand event (Ref. 1) and in other design basis events in Reference 2. The Level 8 trip indirectly

§jinitiates a reactor scram from the main turbine trip (above C26% ._RTP) and trips the feedwater pumps, thereby terminating the event. The reactor scram mitigates the reduction in MCPR.

_(continued)

NMP2 B 3.3.2.2-1 Revision-e- 5

Feedwater System and Main Turbine High Water Level Trip Instrumentation B 3.3.2.2 BASES LCO derived trip setpoints are used. In addition, both the (continued) Allowable Values and trip setpolnts may have additional conservatisms. .....

APPLICABILITY The Feedwater System and Main Turbine High Waterj ee Trip Instrumentation is required to be OPERABLE at Ž _ RTP to ensure that the fuel cladding integrity Safety Limit and the cladding 1% plastic strain limit are not violated during the feedwater controller failure, maximum demand event. As discussed in the Bases for LCO 3.2.1, "Average Planar Linear Heat Generation Rate (APLHGR)," and LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR), " sufficient margin to these limits exists below RTP; therefore, these requirements are only necessary when operating at or above this power level.!!n 3%! -- -

ACTIONS A Note has been provided to modify the ACTIONS related to Feedwater System and Main Turbine High Water Level Trip 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 limits, 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 Feedwater System and Main Turbine High Water Level Trip 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 Feedwater System and Main Turbine High Water Level Trip Instrumentation channel.

A.1 With one channel inoperable, the remaining two OPERABLE channels can provide the required trip signal. However, overall instrumentation reliability is reduced because a single failure in one of the remaining channels concurrent with feedwater controller failure,- maximum demand event, may result in the instrumentation not being able to perform its intended function. Therefore, continued operation is only allowed for a limited time with one channel inoperable. If the inoperable channel cannot be restored to OPERABLE status (continued)

NMP2 B 3.3.2.2-3 Revision4-O'

Feedwater System and Main Turbine High Water Level Trip Instrumentation B 3.3.2.2 BASES ACTIONS C.1 and C.2 23%

(continued)

With a channel not restored to OPERABLE st tus or placed in trip, THERMAL POWER must be reduced to <'2* RTP within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . As discussed in the Applicability section of the Bases, operation belot%4ýRTP results in sufficient margin to the required limits, and the Feedwater System and Main Turbine High Water Level Trip Instrumentation is not required to protect fuel integrity during the feedwater controller failure, maximum demand event. Alternately, if a channel is inoperable solely due to an inoperable feedwater pump breaker, the affected feedwater pump breaker may be removed from service since this performs the intended function of the instrumentation. The allowed Completion Time of 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months is based on operating experience to reduce THERMAL POWER to <C RTP from full power conditions in an orderly manner andfwithout challenging plant systems.

SURVEILLANCE The Surveillances a-re*oified by a Note to indicate that REQUIREMENTS 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 Function maintains feedwater system and main turbine high water level 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 reliability analysis (Ref. 4) assumption that 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months is the average time required to perform channel Surveillance. That analysis demonstrated that the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months testing allowance does not significantly reduce the probability that the feedwater pumps and main turbine will trip when necessary.

SR 3.3.2.2.1 Performance of the CHANNEL CHECK once every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between instrument channels could be an indication of excessive instrument drift in one of the channels, or something even more serious. A CHANNEL CHECK will detect (continued)

NMP2 B 3.3.2.2-5 Rev is ion-0--)

EOC-RPT Instrumentation B 3.3.4.1 BASES BACKGROUND trip system to actuate. If either trip system actuates, (continued) both recirculation pumps, if operating in fast speed, will trip. There are two EOC-RPT breakers in series per recirculation pump. One trip system trips one of the two EOC-RPT breakers for each recirculation pump and the second trip system trips the other EOC-RPT breaker for each recirculation pump.

APPLICABLE The TSV-Closure and the TCV Fast Closure, Trip Oil SAFETY ANALYSES, Pressure-Low Functions are designed to trip the LCO, and recirculation pumps, if operating in fast speed, in the APPLICABILITY event of a turbine trip or generator load rejection to mitigate the neutron flux, heat flux and pressurization transients, and to increase the margin to the MCPR SL. The analytical methods and assumptions used in evaluating the turbine trip and generator load rejection, as well as other safety analyses that assume EOC-RPT, are summarized in Reference 2.

To mitigate pressurization transient effects, the EOC-RPT must trip the recirculation pumps, if operating in fast speed, after initiation of initial closure movement of either the TSVs or the TCVs. The combined effects of this trip and a scram reduce fuel bundle power more rapidly than does a scram alone, resulting in an increased margin to the MCPR SL. Alternatively, MCPR limits for an inoperable EOC-RPT as specified in the COLR are sufficient to mitigate pressurization transient effects. The EOC-RPT function is automatically disabled when THERMAL PWER, as sead by turbine first stage pressure, is < P. 6%

EOC-RPT instrumentation satisfies Criterion 3 of Reference 3.

The OPERABILITY of the EOC-RPT is dependent on the OPERABILITY of the individual instrumentation channel Functions. Each Function must have a required number of OPERABLE channels in each trip system, with their setpoints within the specified Allowable Value of SR 3.3.4.1.2. The actual setpoint is calibrated consistent with applicable setpoint methodology assumptions. Channel OPERABILITY also includes the associated EOC-RPT breakers. Each channel (including the associated EOC-RPT breakers) must also respond within its assumed response time.

(continued)

NMP2 B 3.3.4.1-2 Revision-0--5

EOC-RPT Instrumentation B 3.3.4.1 BASES APPLICABLE Turbine- Stoo Valve-Closure SAFETY ANALYSES, LCO, and Closure of the TSVs and a main turbine trip result in the APPLICABILITY loss of a heat sink that produces reactor pressure, neutron (continued) flux, and heat flux transients that must be limited.

Therefore, an RPT is initiated on TSV-Closure, in anticipation of the transients that would result from closure of these valves. EOC-RPT decreases reactor power and aids the reactor scram in ensuring the MCPR SL is not exceeded during the worst case transient.

Closure of the TSVs is detprmined by measuring the position of each stop valve. There is one valve stem position switch associated with each stop valve, and the signal from each switch is assigned to a separate trip channel. The logic for the TSV-Closure Function is such that two or more TSVs must be closed to produce an EOC-RPT. This Function must be ena e at THERMAL POWER RTP. This is normally accomplished automatically by pressure transmitters sensing turbine first stage pressure; therefore, opening of the turbine bypass valves may affect this Function. Four channels of TSV-Closure, with two channels in each trip system, are available and required to be OPERABLE to ensure that no single instrument failure will preclude an EOC-RPT from this Function on a valid signal. The TSV-Closure Allowable Value is selected to detect imminent TSV closure.

This protection is required, consistent with the safet -21 analysis assumptions, whenever THERMAL POWER is Ž %TRTP with any recirculating pump in fast speed. Below P or with the recirculation in slow speed, the Reactor Vessel "'r Steam Dome Pressure-High and the Average Power Range 2 Monitor (APRM) Fixed Neutron Flux-Upscale Functions of the Reactor Protection System (RPS) are adequate to maintain the necessary safety margins.

TCV Fast Closure. Tri Oil Pressure-Low Fast closure of the TCVs during a generator load rejection results in the loss of a heat sink that produces reactor pressure, neutron flux, and heat flux transients that must be limited. Therefore, an RPT is initiated on TCV Fast Closure, Trip Oil Pressure-Low in anticipation of the transients that would result from the closure of these (continued)

NMP2 B 3.3.4.1-4 Rev is ion .

EOC-RPT Instrumentation B 3.3.4.1 BASES APPLICABLE TCV Fast Closure. Trip Oi] Preksure-Low (continued)

SAFETY ANALYSES, LCO, and valves. The EOC-RPT decreases reactor power and aids the APPLICABILITY reactor scram in ensuring that the MCPR SL is not exceeded during the worst case transient.

Fast closure of the TCVs is determined by measuring the EHC fluid pressure at each control valve. There is one pressure switch associated with each control valve, and the signal from each switch is assigned to a separate trip channel. The logic for the TCV Fast Closure, Trip Oil Pressure-Low Function is such that two or more TCVs must be closed (pressure switch trips) to produce an EOC-RPT. This Function must be enabled at THERMAL POWER _j TP. This is normally accomplished automatically by pressure"-- 6*

transmitters sensing turbine first stage pressure; therefore, opening of the turbine bypass valves may affect this Function. Four channels of TCV Fast Closure, Trip Oil Pressure-Low, with two channels in each trip system, are available and required to be OPERABLE to ensure that no single instrument failure will preclude an EOC-RPT from this Function on a valid signal. The TCV Fast Closure, Trip Oil Pressure-Low Allowable Value is selected high enough to detect imminent TCV fast closure. J26:%

This protection is required consigent with the analysis, D2%

whenever the THERMAL POWER is Ž RTP with n recirculation pump in fast speed. Below P or with the recirculation pumps in slow speed, the Reactor Vessel Steam Dome Pressure-High and the APRM Fixed Neutron Flux-Upscale Functions of the RPS are adequate to maintain the necessary safety margins. The turbine first stage pressure/reactor power relationship for the setpoint of the automatic enable is identical to that described for TSV closure.

ACTIONS A Note has been provided to modify the ACTIONS related to EOC-RPT 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 limits, 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 (continued)

NMP2 B 3.3.4.1-5 Revi s ion-O1-9

EOC-RPT Instrumentation B 3.3.4.1 BASES ACTIONS B.1 and B_ (continued)

Function not maintaining EOC-RPT trip capability. A Function is considered to be maintaining EOC-RPT trip capability when sufficient channels are OPERABLE or in trip, such that the EOC-RPT System will generate a trip signal from the given Function on a valid signal and both recirculation pumps, if operating in fast speed, can be tripped. This requires two channels of the Function, in the same trip system, to each be OPERABLE or in trip, and the associated EOC-RPT breakers to be OPERABLE or in trip.

Alternatively, Required Action B.2 requires the MCPR limit for inoperable EOC-RPT, as specified in the COLR, to be applied. This also restores the margin to MCPR assumed in the safety analysis.

The 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Completion Time is sufficient for the operator to take corrective action, and takes into account the likelihood of an event requiring actuation of the EOC-RPT instrumentation during this period. It is also consistent with the 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Completion Time provided in LCO 3.2.2, Required Action A.1, since this instrumentation's purpose is to preclude a MCPR violation.

26%

With any Required Action and associated Completion Time not met, THERMAL POWER must be reduced to < RTP within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . Alternately, the associated recirculation pump fast speed breaker may be removed from service since this performs the intended function of the instrumentation. The allowed Completion Time of 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months is reasonable, based on 26%o operating experience, to reduce THERMAL POWER to < T from full power conditions in an orderly manner and wit out 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 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 EOC-RP7 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 (continued)

NMP2 B 3.3.4.1-7 Revision-9

.41

EOC-RPT Instrumentation B 3.3.4.1 BASES SURVEILLANCE SR 3.3.4.1.3 (continued)

REQUIREMENTS The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power.

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

SIR 3.3.4.1.4 26 This SR e ures that an EOC-RPT initiated from the TSV- Cl ure and TCV Fast Closure, Trip Oil Pressure - Low Functions ill not be inadvertently bypassed when THERMAL POWER is o RTP. This involves calibration of the bypass channels. Adequate margins for the instrument setpoint methodologies are incorporated into the actual setpoint.

Because main turbine bypass flow can affect this setpoint nonconservatively (THERMAL POWER is derived from first stage pressure), the main turbine bypass valves must 26%o remain closed during an in-service calibration at THERMAL OWER ý: o RTP to ensure that the calibration remains valid. If any bypass channel's setpoint is nonconservative (i.e., the Functions are bypassed at -- RTP either due to open main turbine bypass valves or other reasons), the affected TSV - Closure and TCV Fast Closure, Trip Oil 26%

Pressure - Low Functions are considered inoperable.

Alternatively, the bypass channel can be placed in the conservative condition (nonbypass). If placed in the nonbypass condition, this SR is met and the channel considered OPERABLE.

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

(continued)

NMP2 B 3.3.4.1-9 Revision 9,

Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE I.b. Main Steam Line Pressure - Low (continued)

SAFETY ANALYSES, LCO, and Function closes the MSIVs prior to pressure decreasing below APPLICABILITY 766 psig, which results Ina sr9,pm due to MSIV closure, thus reducing reactor power to 23%.)

The MSL low pressure signals are initiatedfromfour pressure transmitters that are connected to the MSL header.

The transmitters are arranged such that, even though physically separated from each other, each transmitter is able to detect low MSL pressure. Four channels of Main Steam Line Pressure - Low Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.

The Allowable Value was selected to be high enough to prevent excessive RPV depressurization.

The Main Steam Line Pressure - Low Function is only required to be OPERABLE in MODE 1 since this is when the assumed transient can occur (Ref. 4).

This Function isolates the Group 1 valves.

I .c. Main Steam Line Flow - Hiah Main Steam Line Flow- High is provided to detect a break of the MSL and to initiate closure of the MSIVs. Ifthe steam were allowed to continue flowing out of the break, the reactor would depressurize and the core could uncover. If the RPV water level decreases too far, fuel damage could occur. Therefore, the isolation is initiated on high flow to prevent or minimize core damage. The Main Steam Line There is a..la ..... p ...m Flow - High Function is directly assumed in the analysis of There-saplatspeciic program the main steam line break (MSLB) accident (Ref. 6). The that verifies that this instrument isolation action, along with the scram function of the RPS, channel functions as required by ensures that the fuel peak cladding temperature remains verifying the As-Found and As-Left below the limits of 10 CFR 50.46 and offsite doses do not settings are consistent with those exceed the 10 CFR 50.67 limits.

established by the setpoint b methodology. The MSL flow signals are initiated from 16 differential pressure transmitters that are connected to the four MSLs (the differential pressure transmitters sense differential pressure across a flow ventud). The transmitters are arranged such that, even though physically separated from (continued)

NMP2 B 3.3.6.1-9 Revision 0, 26 W25Y5

Jet Pumps B 3.4.3 BASES SURVEILLANCE SR 3.4.3.1 (continued)

REQUIREMENTS Individual jet pumps in a recirculation loop typically do not have the same flow, The unequal flow is due to the drive flow manifold, which does not distribute flow equally to all risers. The jet pump diffuser to lower plenum differential pressure pattern or relationship of one jet pump to the loop average is repeatable. An appreciable change in this relationship is an indication that increased (or reduced) resistance has occurred in one of the jet pumps.

The deviations from normal are considered indicative of a potential problem in the recirculatlon drive flow or jet pump system (Ref. 3). Normal flow ranges and established jet pump differential pressure patterns are established by plotting historical data as discussed in Reference 3.

The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency has been shown by operating experience to be adequate to verify jet pump OPERABILITY and is consistent with the Frequency for recirculation loop OPERABILITY verification.

This SR is modified by two Notes. Note I allows this Surveillance not to be performed until 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months after the associated recirculatlon loop is in operation, since these checks can only be performed during jet pump operation. The 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months is an acceptable time to establish conditions appropriate for data collection and evaluation. 23%

Note 2 allows this SR not toibe performed until W4 after THERMAL POWER exceeds RTP, During low flow conditions, jet pump noise approaches the threshold response of the associated flow instrumentation and precludes the collection of repeatable and meaningful data. The 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is an acceptable time to establish conditions appropriate to perform this SR.

REFERENCES 1. USAR, Section 6.3.

2, 10 CFR 50.36(c)(2)(ii).

3. GE Service Information Letter No. 330 including Supplement 1, "Jet Pump Beam Cracks," June 9, 1980.

(continued)

NMP2 B 3.4.3-4 Revision-0-)

RCS P/T Limits B 3.4.11

.) B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.11 RCS Pressure and Temperature (P/T) Limits BASES BACKGROUND All components of the RCS are designed to withstand effects of cyclic loads due to system pressure and temperature changes. These loads are introduced by startup (heatup) and shutdown (cooldown) operations, power transients, and reactor trips. This LCO limits the pressure and temperature changes during RCS heatup and cooldown, within the design assumptions and the stress limits for cyclic operation.

The Specification contains P/T limit curves for heatup, cooldown, system leakage and hydrostatic testing, and criticality, and also limits the maximum fluence used for the the maximum rate of change of reactor coolant temperature. The P/T limiting adjusted reference limit curves are applicable up tof'.,*

t e m p e ra tur e fo r t he 22 e ff ect ive f ull E III .. I0

! po power years asdfie finedd in in Tal Table 4.1....

4 1T Each P/T limit curve defines an acceptable region for normal operation.

ofR .. Sfe The use of the curves usual maneuvering, cooldown ct is operational guidance during heatup or when pressure and temperature indications are mmonitored I and compared to the applicable curve to determine that operation is within the allowable region.

The LCO establishes operating limits that provide a margin to brittle failure of the reactor vessel and piping of the reactor coolant pressure boundary (RCPB). The vessel is the component most subject to brittle failure. Therefore, the LCO limits apply mainly to the vessel.

10 CFR 50, Appendix G (Ref. 1), requires the establishment of P/T limits for material fracture toughness requirements of the RCPB materials. Reference 1 requires an adequate margin to brittle failure during normal operation, anticipated operational occurrences, and system hydrostatic tests. It mandates the use of the American Society of Mechanical Engineers (ASME) Code,Section III, Appendix G (Ref.

2).

The actual shift in the RTNDT of the vessel material will be established periodically by evaluating the irradiated reactor vessel material data provided as part of the Boiling Water Reactor Vessel and Internals Project (BWRVIP) Integrated Surveillance Program (Refs. 11 and 12),

in accordance with 10 CFR 50, Appendix H (Ref. 4). The operating PiT limit curves will be adjusted, (continued)

NMP2 B 3.4.11-1 Revision 0, 40, 44-C)

Main Turbine Bypass System B 3.7.5 B 3.7 PLANT SYSTEMS 8 3.7.5 'Main Turbine Bypass System L 5%o BASES BACKGROUND The Main Turbine Bypass System is design d to control steam pressure when reactor steam generation xceeds turbine requirements during unit startup, sudde load reduction, and cooldown. It allows excess steam flow rom the reactor to the condenser without going through the turbine. The bypass capacity of the system is approximately of the Nuclear Steam Supply System rated steam flow. Sudden load reductions within the capacity of the steam bypass can be accommodated without reactor scram. The Main Turbine Bypass System consists of a five valve manifold connected to the main steam lines between the main steam isolation valves and the main turbine stop valves. Each of these valves is sequentially operated by hydraulic cylinders. The bypass valves are controlled by the pressure regulation function of the Turbine Electro Hydraulic Control System, as discussed in the USAR, Section 7.7.1.5 (Ref. 1). The bypass valves are normally closed, and the pressure regulator controls the turbine control valves, directing all steam flow to the turbine. If the speed governor or the load limiter restricts steam flow to the turbine, the pressure regulator controls the system pressure by opening the bypass valves.

When the bypass valves open, the steam flows from the valve manifold, through connecting piping, to the pressure breakdown assemblies, where a series of orifices are used to further reduce the steam pressure before the steam enters the condenser.

APPLICABLE The Main Turbine Bypass System is assumed to function during SAFETY ANALYSES the design basis feedwater controller failure, maximum demand event, described in the USAR, Section 15.1.2 (Ref. 2). Opening the bypass valves during the pressurization event mitigates the increase in reactor vessel pressure, which affects the MCPR during the event.

An Inoperable Main Turbine Bypass System may result in an MCPR penalty.

The Main Turbine Bypass System satisfies Criterion 3 of Reference 3.

(continued)

NMP2 B 3.7.5-1 Revision-6-.)

Main Turbine Bypass System B 3.7.5 BASES (continued)

LCO The. Main Turbine Bypass System is required to be OPERABLE to limit peak pressure in the main steam lines and maintain reactor pressure within acceptable limits during events that cause rapid pressurization, such that the Safety Limit MCPR is not exceeded. With the Main Turbine Bypass System inoperable, modifications to the MCPR limits (LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)O) may be applied to allow continued operation.

An OPERABLE Main Turbine Bypass System requires the bypass valves to open in response to increasing main steam line pressure. This response is within the assumptions of the applicable analysis (Ref. 2). The MCPR limit for the inoperable Main Turbine Bypass System is specified in the COLR.*

APPLICAB:ILITY TheeMain Turbine Bypass System is required to be OPERABLE at

> *RTP to ensure that the fuel cladding integrity Safety Limit is not violated during the feedwater controller failure, maximum demand event. As discussed in the Bases for LCO 3.2.2, sufficient margin to this limit exists

'23% < RTP. Therefore, these requirements are only necessary when operating at or above this power level.

ACTIONS A._I If the Main Turbine Bypass System is inoperable (one or more bypass valves inoperable), and the MCPR limits for an inoperable Main Turbine Bypass System, as specified in the COLR, are not applied, the assumptions of the design basis transient analysis may not be met. Under such circumstances, prompt action should be taken to restore the Main Turbine Bypass System to OPERABLE status or adjust the MCPR limits accordingly. The 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Completion Time is reasonable, based on the time to complete the Required Action and the low probability of an event occurring during this period requiring the Main Turbine Bypass System.

(continued)

NMP2 8 3.7.5-2 Revision-C- 5

Main Turbine Bypass System B 3.7.5 BASES

Ž 23% 23%

ACTIONS D.

iJ._s -

(continued) If the Mail Turbine Byp ss System cannot be restored to OPERABLE status and th@ MCPR limits for an inoperable Main Turbine Byp sSystem *re not applied, THERMAL POWER must be reduced to < RTP. *As discussed in the Applicability section, operation at < RTP results in sufficient margin to the required limits, and the Main Turbine Bypass System is not required to protect fuel integrity during the feedwater controller failure, maximum demand event. The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time is reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.

SURVEILLANCE REQUIREMENTS SR 3.7Z..1 The Main Turbine Bypass System is required to actuate automatically to perform its design function. This SR demonstrates that, with the required system initiation signals, the valves will actuate to their required position.

While this Surveillance can be performed with the reactor at power, operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency, which is based on the refueling cycle.

Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

SR 3.7.5..Z This SR ensures that the TURBINE BYPASS SYSTEM RESPONSE TIME is in compliance with the assumptions of the appropriate safety analysis. The response time limits are specified in the Technical Requirements Manual (Ref. 4). While this Surveillance can be performed with the reactor at power, operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency, which is based on the refueling cycle. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

(continued)

NMP2 B 3.7.5-3 Rev is ion-0-,.

v t e Letter Sequence Request
TAC:ME1476, Clarify Application of Setpoint Methodology for LSSS Functions (Approved, Closed)
Initiation Request, Request, Request, Request Acceptance, Acceptance, Acceptance, Acceptance Supplement, Supplement, Supplement, Supplement Administration Withholding Request Acceptance, Withholding Request Acceptance, Withholding Request Acceptance, Withholding Request Acceptance, Withholding Request Acceptance, Withholding Request Acceptance, Withholding Request Acceptance, Withholding Request Acceptance, Withholding Request Acceptance, Withholding Request Acceptance, Withholding Request Acceptance, Withholding Request Acceptance, Withholding Request Acceptance, Withholding Request Acceptance, Withholding Request Acceptance Meeting Questions 29 March 2011 8 October 2009 13 November 2009 18 November 2009 23 December 2009 10 March 2010 10 March 2010 10 March 2010 11 May 2010 10 May 2010 8 June 2010 14 July 2010 15 June 2010 18 September 2009 12 January 2010 27 January 2010 1 February 2010 6 October 2010 12 November 2010 9 February 2011 8 April 2011 14 April 2011 12 May 2011 5 April 2011 Answers 23 December 2009 19 February 2010 16 April 2010 7 May 2010 3 June 2010 30 June 2010 9 July 2010 30 July 2010 5 November 2010 13 December 2010 10 December 2010 19 January 2011 23 March 2011 9 May 2011 13 June 2011 15 July 2011 5 August 2011 19 August 2011 8 October 2015 Results Approval, Approval, Approval, Approval Other: ML092460553, ML092460595, ML092460596, ML100190073, ML100190074, ML100190075, ML100190076, ML100190077, ML101300006, ML101900448, ML101900449, ML101900450, ML101950497, ML101950498, ML103050187, ML110460160, ML110880302, ML11171A060, ML111920326, ML111950133, ML112031112, ML112081701, ML112160736, ML11221A013, ML112450479, ML112460008, ML112460009, ML113340186, ML120050150, ML120250137, ML12313A203, ML12313A204, ML12313A206, NRC-2010-0117, Final Environmental Assessment and Finding of No Significant Impact - Federal Register Notice - Related to the Proposed License Amendment to Increase the Maximum Reactor Power Level
MONTHYEAR2010-02-01 [Table View]

ML091610103

Text

SUBJECT:

Enclosure:

SUMMARY

3.0 TECHNICAL EVALUATION

4.0 REGULATORY EVALUATION

5.0 ENVIRONMENTAL CONSIDERATION

6.0 REFERENCES

SUMMARY

3.0 TECHNICAL EVALUATION

4.0 REGULATORY EVALUATION

5.0 ENVIRONMENTAL CONSIDERATION

6.0 REFERENCES

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