ML091610105

NEDO-33351, Rev. 0, Safety Analysis Report for Nine Mile Point Nuclear Station, Unit 2 Constant Pressure Power Uprate (Pusar), Attachment 3, Part 2 of 2 and Attachments 4 - 10 and 12 & 13

ML091610105
Person / Time
Site:	Nine Mile Point
Issue date:	05/31/2009
From:	GE-Hitachi Nuclear Energy Americas
To:	Office of Nuclear Reactor Regulation
References
DRF 0000-0069-9016 NEDO-33351, Rev 0
Download: ML091610105 (190)

Text

NEDO-33351 - REVISION.0 NON-PROPRIETARY INFORMATION 3, REFERENCES

1. GE Nuclear Energy, "Constant. Pressure Power Uprate," NEDC-33004P-A, Revision 4, Class III (Proprietary), July 2003; and NEDO-33004, Class I (Non-proprietary), July 2003.

2.

GE Nuclear Energy, "Generic Guidelines for General Electric Boiling Water Reactor Extended Power Uprate," NEDC-32424P-A, Class III (Proprietary), February 1999; and NEDO-32424, Class I (Non-proprietary), April 1995.

3. GE Nuclear Energy, "Generic Evaluations of General Electric Boiling Water Reactor Extended Power Uprate," NEDC-32523P-A, Class III (Proprietary), February 2000; NEDC-32523P-A, Supplement 1 Volume I, February 1999; and Supplement 1 Volume II, April 1999.

4.

GE Nuclear Energy, "General Electric Standard Application for Reactor Fuel," NEDE-24011-P-A and.NEDE-24011-P-A-US, Class III (Proprietary), (latest approved revision).

5. Regulatory Guide 1.49, "Power Levels of Nuclear Power Plants," Revision 1, December 1973. (Withdrawn, 72 FR 36737, 07/05/2007).

6. MFN 08-089, Ho K. Nieh, Deputy Director, Division of Policy and kulkmaking, Office of Nuclear Reactor Regulation to Robert E. Brown (GEH), "Final Safety Evaluation For General Electric (GE)-Hitachi Nuclear Energy Americas, LLC (GHNE) Licensing Topical Report.(LTR) NEDC-33173P, "Applicability Of GE Methods To Expanded Operating Domains" (TAC NO. MD0277)," January 17, 2008.

7.

Letter to Gary L. Sozzi (GE) from Ashok Thadani (NRC); "Use of the SHEX Computer Program and ANSI/ANS 5.1-1979 Decay Heat Source Term for Containment Long-Term Pressure and Temperature Analysis," July'13, 1993.

8. GE Nuclear Energy, "General Electric Methodology for Reactor Pressure Vessel Fast Neutron Flux Evaluations (TAC No..MC3788)i'" NEDC-32983P-A, November 17, 2005.

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12. BWRVIP-75, "BWR Vessel and Internals Project Technical Basis for Revisions to Generic Letter 88-01 Inspection," October 1999.

13. BWRVIP-75-A, "BWR Vessel and Internals Project Technical Basis for Revisions to Generic Letter 88-01 Inspection," October 2005.

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NEDO-33351 - REVISION 0 NON-PROPRIETARY INFORMATION

14. BWRVIP-62, "Technical Basis for Inspection Relief for BWR Internal Components with Hydrogen Injection," December 1998.

15. Regulatory Guide 1.54, "Service Level I, II, and III Protective Coatings Applied to Nuclear Power Plants (ML003714475)," Revision 1, July 2000.

16. NRC Generic Letter 98-04, "Potential for Degradation of the Emergency Core Cooling System and the Containment Spray System After a Loss-of-Coolant Accident Because of Construction and Protective Coating Deficiencies and Foreign Material in Containment," July 14, 1998.

17. NUREG-1801 (GALL), "Generic Aging Lessons Learned (GALL) Report - Tabulation of Results," Volume 2, Revision 1, September 2005.

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20. GE Nuclear Energy, "Nine. Mile Point 2 Reactor Internals Vibration Measurements,"

NEDE-31604P, Revision 1, March 1989.

21. BWRVIP-182, "Guidance for Demonstration. of Steam Dryer Integrity for Power Uprate," issued January, 2008.

22. Regulatory Guide 1.20, "Comprehensive Vibration Assessment Program for Reactor Internals During Preoperational and Initial Startup Testing," Revision 3, March 2007.

23. NRC Generic Letter 89-10, "Safety-Related Motor Operated Valve Testing and Surveillance," 6/28/1989.

24. NRC Generic Letter 96-05, "Verification of Design-Basis Capability of Safety-Related Motor Operated Valves," 9/18/1996.

25. NRC Generic Letter 95-07 addresses "Pressure Locking and Thermal Binding of Safety-Related Power-Operated Gate Valves," 8/17/1995.

26. GE Nuclear Energy, "Control Rod Guide Tube Stress Report," 22A4678, Revision 4, June 1986.

27. GE Nuclear Energy, "Feedwater Sparger Stress Report,". 385HA736, Revision 0, December 1976.

28. "Guidelines and Technical Bases for NUMARC Initiatives Addressing Station Blackout at Light Water Reactors," NUMARC 87-00, Rev. 1, August 199 1.

29. Regulatory Guide 1.155, "'Station Blackout," August 1988.

30. GE Nuclear Energy, "General Electric Instrument Setpoint Methodology," NEDC-31336P-A, Class III (Proprietary), September 1996.

31. GE Nuclear Energy Safety Communication, SC04-14, "Narrow Range Water Level Instrument Level 3 Trip Final Report," October 11, 2004.

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NEDO-33351 - REVISION 0 NON-PROPRIETARY INFORMATION

32. NUREG-1048, "Safety Evaluation Report Related.to the Operation. of Hope Creek Generating'Station," July 1986.

33: Regulatory Guide 1.115, "Protection Against Low-Trajectorly Turbine Missiles,"

Revision 1, July 1977.

34. Nine Mile Point, Unit 2 Issuance of License Amendment, "Implementation of Alternative Radiological Source Term," May 29, 2008. [ML081230439]

35. Nine Mile Point, Unit. 2 - License Amendment Request Pursuant to 10 CFR 50.90, "Application of Alternative Source Term," May 31, 2007. [ML071580314]

36. Regulatory Guide 1.52, Design, Inspection, and Testing Criteria for Air Filtration and Adsorption Units of Post-Accident Engineered-Safety-Feature Atmosphere Cleanup Systems in Light-Water-Cooled Nuclear Power Plants (MLO1 1710176)," Revision 3, June 2001.

37. Regulatory Guide 1.183, "Alternative Radiological Source Terms for Evaluating Design Basis Accidents at Nuclear Power Reactors (ML0037'16792)," July 2000.

38. Regulatory Guide 1.3, "Assumptions Used for Evaluating the Potential Radiological Consequences of a Loss of Coolant Accident for Boiling Water Reactors (ML003739601)," Revision 2, June 1974.

39. NUREG-0800, U.S. Nuclear Regulatory' Commission, Standard Review 'Plan, Section 6.2.1.1.C, "Pressure -Suppression Type BWR Containments," Revision 7, March 2007.

40. GE Nuclear Energy, "The General Electric Pressure Suppression Containment Analytical Model," NEDM-10320, Proprietary, March 1971.,

41. GE Nuclear Energy, "The General Electric Mark III Pressure Suppression' Containment System Analytical Model," NEDO-20533,: Class I (Non-proptietary), June.1974.

42. GE Nuclear Energy, "General Electric Model for LOCA Analysis In Accordance With 10 CFR 50 Appendix K," NEDE-20566-P-A, September 1986.

43. GE Nuclear. Energy, "Mark II Containment Dynamic Forcing Functions Information Report," NEDO-21061, Revision 4, November 1981.

44. NUREG-0487, "Mark II Containment Lead Plant' Program Load Evaluation and Acceptance Criteria," Sujpplement'l, September 1980.

45. NUREG-0808, "Mark II Containment Program Load Evaluation and Acceptance Criteria," August 1981.

'46. Letter, B. Sheron'to RA Pinelli, "Safety Assessment of Report NEDC-32399-P, Basis for GE RTNDT Estimation Method, September 1994," NRC, December 16, 1994.

47. NRC Generic Letter 98-05, "Boiling Water Reactor Licensees.Use of the BWRVIP-05 Report to Request Relief from Augmented Examination Requirements on Reactor Pressure Vessel Circumferential Shell Welds," November 1998.

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NEDO-33351 - REVISION 0 NON-PROPRIETARY INFORMATION

48. C.I. Grimes (NRC) to Carl Terry (Niagara Mohawk Power Company), "Acceptance For Referencing Of EPRI Proprietary Report TR-113596, "BWR Vessel And Internals Project, BWR Reactor Pressure Vessel Inspection And Flaw Evaluation Guidelines (BWRVIP-74)," and Appendix A, "Demonstration Of Compliance With The Technical Information Requirements Of The License Renewal Rule (10 CFR 54.21),"

October 18, 2001.

49. BWRVIP-135, Revision 1, "BWR Vessel and Internals Project Integrated Surveillance Program (ISP) Data Source Book and Plant Evaluations," EPRI, Palo Alto, CA, June 2007 (TR-1013400).

50. Regulatory Guide 1.99,"Radiation Embrittlemeht of Reactor Vessel Materials,"

Revision 2, May 1988.

51. NUREG-0783, "Suppression Pool Temperature Limits for BWR Containment," July 1981.

52. GE Nuclear Energy Safety Communication, SC06-01, "Worst Single. Failure for Suppression Pool Temperature Analysis," January 19, 2006.

53. GE Hitachi Nuclear Energy, "NMP2 Increased UHS Temperature and SC06-01 Evaluation," GE-NE-0000-0070-0145-RO, October 2007.

54. GE Nuclear Energy Service Information Letter No. 636, "Additional Terms included in Reactor Decay Heat Calculations," Revision 1, June 2001.

55. NUREG-0802, "Safety/Relief Valve Quencher Loads: Evaluation for BWR Mark II and III Containments."

56. GE Nuclear Energy, "Annulus Pressurization Load Adequacy Evaluation," NEDO-24548, January 1979.

57. Regulatory Guide 1.61, "Damping Values for Seismic Design of Nuclear Power Plants,"

Revision 1, March 2007.

58. Niagara Mohawk Letter NMP2L 1741, "90 Day Response to Generic Letter 97-04, "Assurance of Sufficient Net Positive Suction Head for Emergency Core Cooling and Containment Heat Removal Pumps," December 30, 1997.

59. Boiling Water Reactor Owner's Group, "Utility Resolution Guide for ECCS Suction Strainer Blockage," NEDO-32686-A, Class I (Non-proprietary), October 1998.

60. GE Nuclear Energy, "Power Uprate Licensing Evaluation for Nine Mile Point Unit 2,"

NEDC-31994P, Revision 1, May 1993.

61. Letter from Marshall J. David (NRC) to Keith J., Polson (Nine Mile Point Nuclear Station, Unit No. 2), Issuance of Amendment Re: Implementation of ARTS/MELLLA (TAC No. MVD5233),

dated February 27, 2008 (ADAMS Accession Number ML080230230).

62. GEH Letter (MFN 08-693), "Implementation of Methods Limitations - NEDC-33173P (TAC No. MD0277)," September 18, 2008.

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NEDO-33351 - REVISION 0 NON-PROPRIETARY INFORMATION

63. GEH Letter, L. Quintana (GEH) to NRC, "Responses to RAIs 1, 13, 14-1, 18 and 22 -

Methods Interim Process," (MFN 05-038) dated May 3, 2005.

64. NRC letter, T. Blount (NRC) to R. Brown (GEH), Final Safety Evaluation for GE-

-Hitachi Nuclear Energy Americas, LLC (GHNE) Topical Report (TR) NEDC-33006P, "Maximum Load Line Limit Analysis Plus," (MFN 07-517) dated September 17, 2007.

65.. GEH Letter, G. Stramback (GEH) to NRC, "Completion of Responses to MELLLA Plus AOO RAIs," (MFN 04-026) dated March 4, 2004.

66. GE Nuclear Energy, "Reactor Stability Detect and Suppress Solutions Licensing Basis Methodology for Reload Applications," NEDO-32465-A, August 1996.

67. GE Nuclear Energy, "Backup Stability Protection (BSP) for Inoperable Option III Solution," OG 02-0119-260,.July 17, 2002.

68. GE Nuclear Energy, "Plant-Specific Regional Mode DIVOM Procedure Guideline,"

GE-NE-0000-0028-9714-R1, June 2005.

69. GE Nuclear Energy, Revision 1, "Licensing Basis Hot Bundle Oscillation Magnitude for Nine Mile Point 2," GENE-A13-00381-05, April 1998.

70. BWROG-94078, "BWR Owners' Group Guidelines for Stability Interim Corrective Action," June 6, 1994.

71. GE Nuclear Energy, "ATWS Rule Issues Relative to BWR Core Thermal-Hydraulic Stability," NEDO-32047-A, Class I (Non-proprietary);ý June 1995.

72. GE Nuclear Energy, "Mitigation of BWR Core Thermal-Hydraulic Instabilities in ATWS," NEDO-32164, Class I (Non-proprietary), December 1992.

73. GE Nuclear Energy, "Qualification of the Orie-Dimensional Core Transient Model (ODYN) for Boiling Water Reactors (Supplementi I - Volume 4),". NEDC-24154P-A, Revision 1, Supplement 1, Class III (Proprietary), February 2000.

74. GE Nuclear Energy, "Continuous Control Rod Withdrawal Transient in the Startup Range," NEDO-23842, Class I (Non-proprietary), April 1978.

75. GE Nuclear Energy, "Banked Position Withdrawal Sequehce," NEDO-21231, Class I (Non-proprietary), January 1977.

76. GE Nuclear Energy, "Constellation Generating Grou, :Nin'e Mile Point Nuclear Station Unit 2, ARTS-MELLLA: ECCS-LOCA SAFER/GESTR," GE-NE-0000-0053-6746-RO, December 2006.

77. GE Nuclear Energy, "Nine Mile Point-2 SAFER/GESTR Loss-of-Coolant Accident Analysis for GEl4 Fuel," GE-NE-0000-0024-6517-RO, March 2004.

78. NUREG-0713, "Occupational Radiation Exposure at Commeicial Nuclear Power Reactors and Other Facilities 2006," December 2007.

79. TID-14844, "Calculation of Distance Factors for Power and Test Reactor Sites," U.S.

Atomic Energy Commission, March 23, 1962. [8202010067]

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NEDO-33351 - REVISION 0 NON-PROPRIETARY INFORMATION

80. Regulatory Guide 1.174, "An Approach for using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis," Revision 1, November 2002.

81. NRC Generic Letter 88-20, "Individual Plant Examination for Severe Accident Vulnerabilities," 11/23/1988.

82. Regulatory Guide 1.200, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities," Revision 1, January 2007.

83. NEI 00-02, "Probabilistic Risk Assessment (PRA) Peer Review Process Guidance,"

Revision A3, March 2000.

84. NUREG/CR-6928, "Industry-Average Performance for Components and Initiating Events at U.S. Commercial Nuclear Power Plants," February 2007.

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NEDO-33351 - REVISION 0 NON-PROPRIETARY INFORMATION Appendix - A Limitations from Safety Evaluation for LTR NEDC-33173P Following Table lists the limitations from Safety Evaluation for LTR NEDC-33173P (Reference A-i) with their location for A-1

NEDO-33351 -REVISION 0 NON-PROPRIETARY INFORMATION 9.3 Power to Flow Ratio Plant-specific EPU and expanded operating domain applications will confirm that the core thermal power to core flow ratio will not exceed 50 MWt/Mlbm/hr at any statepoint in the allowed operating domain. For plants that exceed the power-to-flow value of 50 MWt/Mlbmihr, the application will provide power distribution assessment to establish that neutronic methods axial and nodal power distribution uncertainties have not increased.

Comply Section 2.8.2.5.2.

Consistent with Reference A5.

9.4 SLMCPR1 For EPU operation, a 0.02 value'shall be added Comply Section 2.8.2.3.1 and Section to the cycle-specific SLMCPR value. This 2.8.5.8.

adder is applicable to SLO, which is derived from the dual loop SLMCPR value.

9.5 SLMCPR2 For operation at MELLLA+, including Not Not applicable to EPU.

operation at the EPU power levels at the Applicable achievable core flow statepoint, a 0.03 value shall be added to the cycle-specific SLMCPR value.

A-2

NEDO-3335t - REVISION 0 NON-PROPRIETARY INFORMATION The plant* specific R-factor calculation at a bundle level will be consistent with lattice axial. void conditions expected for the hot channel operating. state. The plant-specific EPU/MELLLA+ application will.confirm that the R factor calculation is consistent with the hot channel axial, void conditions.

For applications requesting implementation of EPU or expanded operating domains, including MELLLA+, the small and large

,break ECCS-LOCA analyses will include top-

.peaked and mid-peaked power-shape in establishing the MAPLHGR and determining the PCT-.>Jhis limitation is applicable to both the licensing-bases PCT and the upper bound PCT. The plant-specific applications will report the -limiting small and large break licensingbasis and upper bound-PCTs.-

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NEDO-33351 - REVISION 0 NON-PROPRIETARY INFORMATION

&,till li 9.8 ECCS-LOCA 2 The ECCS-LOCA will be performed for all statepoints in the upper boundary of the expanded operating domain, including the minimum core flow statepoints, the transition statepoint as defined in Reference A-2 and the 55 percent core flow statepoint. The plant-specific application will report the limiting ECCS-LOCA results as well as the rated power and flow results. The SRLR will include both the limiting statepoint ECCS-LOCA results and the rated conditions ECCS-LOCA results.

Not Applicable Not applicable to EPU.

.1-

+

4 9.9 Transient LHGR 1 Plant-specific EPU and MELLLA+

-applications will-demonstrate and-document that during normal operation and core-wide AOOs, the T-M acceptance criteria as.

specified in Amendment 22 to GESTAR II will be met. Specifically, duringan AOO, the licensing application will demonstrate that the:

(1) loss of fuel rod mechanical integrity will not occur due to fuel melting and (2) loss of fuel rod mechanical integrity will not occur due to pellet-cladding mechanical interaction.

The plant-specific application will demonstrate that the T-M acceptance criteria are met for the both the U0 2 and the limiting GdO2 rods.

Comply Section 2.8.5.8 A-4

NEDO-33351 - REVISION 0 NON-PROPRIETARY INFORMATION oik

• ELmrntation Title ',Limitation Desciption Dispsition-Section-of NM-2 PUSAR Niuimber fWom which addresses'the NRC S--

Limitation 9.10 Transient LHGR 2 Each EPU and MELLLA+ fuel reload will Comply Section 2.8.5.8 document the calculation results of the analyses demonstrating compliance to transient T-M acceptance criteria. The plant T-M response will be provided with the SRLR or COLR, or it will be reported directly to the NRC as an attachment to the SRLR or COLR.

9.11 Transient LHGR 3 To account for the impact of the void history Comply Section 2.8.5.8 bias, plant-specific EPU and MELLLA+

applications using either TRACG or ODYN will demonstrate an equivalent to 10 percent margin to the fuel centerline melt and the 1 percent cladding circumferential plastic strain acceptance criteria due to pellet-cladding mechanical interaction for all of limiting AOO transientevents, including equipment out-of-service. Limiting transients in thisý case, refers to transients where the void reactivity coefficient plays a significant. role (such as pressurization events)- If the voidhistory bias is incorporated into the transient model within the code, then the additional 10 percent margin to the fuel centerline melt and the :1 percent cladding circumferential plastic -strain is no longer required...

A-5

NEDO-33351 -REVISION 0 NON-PROPRIETARY INFORMATION Limitation Limitation Title Limitation Description Iisposition SectionofNMP2 PUSAR Number from which addresses-the

-"NRC'SER,.

'Limitation 9.12 LHGR and In MFN 06-481, GE committed to submit Not Not required as PRIME LTR Exposure plenum fission gas and fuel exposure gamma Applicable and its application is not Qualification scans as part of the revision to the T-M approved by NRC.

licensing process. The conclusions of the plenum fission gas and fuel exposure gamma scans of GE lOxlO fuel designs as operated will be submitted for NRC staff review and approval. This revision will be accomplished through Amendment to GESTAR II or in a T-M licensing LTR. PRIME (a newly developed T-M code) has been submitted to the NRC staff for review (Reference A-3). Once the PRIME LTR and its application are approved, future license applications for EPU and MELLLA+ referencing LTR NEDC-33173P must utilize the PRIME T-M methods.

A-6 0

NEDO-33351 -. REVISION 0 NON-PROPRIETARY INFORMATION L'LimitationT Limitation TitleffJ_,,

L.jimitation Description T

Disposition Section of NMP2PUSAR SN.mberfro In"

-whichaddresses the

.'NRC SER Limitation 9.13 Application of 10 Weight Percent Gd Before applying 10 weight percent Gd to licensing applications, including EPU and expanded operating domain, the NRC staff needs to review and approve the T-M LTR demonstrating that the T-M acceptance criteria specified in GESTAR II and Amendment 22 to GESTAR II can be met for steady-state and transient conditions. Specifically, the T-M application must demonstrate that the T-M acceptance criteria can be met for TOP and MOP conditions that bounds the response of plants operating at EPU and expanded operating domains at the most limiting statepoints, considering the operating flexibilities (e.g., equipment out-of-service).

Before the use of 10 weight percent Gd for modem fuel designs, NRC must review and approve TGBLA06 qualification submittal.

Where a fuel design refers to a.design with Gd-bearing rods adjacent to vanished or water

.rods, the submittal should include specific information regarding acceptance criteria for the qualification and address any downstream impacts in terms of the safety analysis. The 10 weight percent Gd qualifications submittal can supplement this report.

Not Applicable Section 2.8.2.5.5.

A-7

NEDO-33351 -REVISION 0 NON-PROPRIETARY INFORMATION Limitation Limitation itati

-Liitation Description Disposition,,-

Section of NMP2 PUSAR Number from I

which addresses the NRC SER

_...._j--

Limitation 9.14 Part 21 Evaluation of GESTR-M Fuel Temperature Calculation Any conclusions drawn from the NRC staff evaluation of the GE's Part 21 report will be applicable to the GESTR-M T-M assessment of this SE for future license application. GE submitted.the T-M Part 21 evaluation, which is currently under NRC staff review. Upon completion of its review, NRC staff will inform GE of its conclusions.

Comply Section 3.2.6.5.8 of the SE for NEDC-33173P, "Applicability of GE Methods To Expanded Operating Domains" provides the basis discussion for this limitation. This section invokes Appendix F of the SE which contains a requirement that the Pcritical acceptance criteria be reduced by 350 psi.

This adjusted Pcritical must be used to verify that LHGR limit for the current fuel designs remains applicable with burnup.

The impact of the 350 psi reduction in Pcritical on the GEl4 thermal mechanical limit curves has been evaluated using the same methodology that was used to derive the original GE14 thermal mechanical limits. The evaluation resulted in revised LHGR versus exposure limit curves, which ensure that the A-8

NEDO-33351 - REVISION 0 NON-PROPRIETARY INFORMATION Limitation

..LimitationTitle Limitation Description Disposition7 section of NMP2 PUSAR

'Number-from which addresses the NRC SER Limitation rod pressure is maintained in conformance with the reduced Pcritical criteria.

9.15 Void Reactivity 1 The void reactivity coefficient bias and Comply For the NMP2 EPU, TRACG uncertaintiesin TRACG for EPU and is not applied in the AOO or MELLLA+ must be representative of the ATWS analysis.

lattice designs of the fuel loaded in the.corei TRACG04 is applied for the thermal-hydraulic stability analysis for the NMP2.EPU.

The void reactivity coefficient bias and uncertainties used in the stability analysis is representative of the lattice designs of the fuel loaded in the core.

The TRACG application to the RIPD analysis does not involve reactor kinetics and is therefore not affected by this limitation.

t A-9

NEDO-33351 -REVISION 0 NON-PROPRIETARY INFORMATION Limitation Limitation Title

,',"Limitation Description Dispoition Section of NMP2 PUSAR Number from which addressesthe NRC SER.

Limitation 9.16 Void Reactivity 2 A supplement to TRACG /PANAC 1I for Comply For the NMP2 EPU, TRACG AOO is under NRC staff review (Reference A-is not applied in the AOO or 4). TRACG internally models the response ATWS analysis.

surface for the void coefficient biases and uncertainties for known dependencies due to TRACG04 is applied for the the relative moderator density and exposure on thermal-hydraulic stability nodal basis. Therefore, the void history bias analysis for the NMP2 EPU.

determined through the methods review can be The TRACG04 applied to the incorporated into the response surface stability analysis incorporated "known" bias or through changes in lattice the void history bias.

physics/core simulator methods for establishing the instantaneous cross-sections.

The TRACG application to the Including the bias in the calculations negates RIPD analysis does not the need for ensuring that plant-specific involve reactor kinetics and is applications show sufficient margin. For therefore not affected by this application of TRACG to EPU and MELLLA+

limitation.

applications, the TRACG methodology must incorporate the void history bias. The manner in which this void history bias is accounted for will be established by the NRC staff SE approving NEDE-32906P, Supplement 3, "Migration to TRACG04/PANAC 11 from TRACG02/PANAC 10," May 2006 (Reference A-4). This limitation applies until the new TRACG/PANAC methodology is approved by the NRC staff.

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NEDO-33351 - REVISION 0 NON-PROPRIETARY INFORMATION

_lmitaton Li* mtation Title Limitation Description- <

i ispositiOn.

section ofNMP2 pUSAR Numerfro~

-which addresses.theý.

NRS E R Limitation.

9.17 Steady-State 5 The instrumentation specification design bases Comply Section 2.8.2.5.1.

Percent Bypass limit the presence of bypass voiding to Voiding 5 percent (LRPM levels). Limiting the bypass voiding to less than 5, -percent -for long-term steady operation ensures that instrumentation is operated within the specification. For EPU and MELLLA+ operation, the bypass voiding will be evaluated on a cycle-specific, basis to confirm that the void fraction remains -below 5 percent at all LPRM levels when operating at steady-state conditions within the MELLLAt upper boundary. The highest calculated bypass voiding at any LPRM level will be provided with the plant-specific SRLR.

9.18 Stability Setpoints The NRC staff concludes that the~presence Comply Section 2.8.3.1.

Adjustment bypass voiding at the low-flow conditions where instabilities are likely can result in, calibration errors of less than,5 percent for OPRM cells and less than 2 percent-for APRM signals. These calibration errors-must be accounted for while determining the setpoints for any detect and suppress long term methodology. The calibration values for the different long-term solutions are specified in the associated sections of this SE, discussing the stability methodology.

A-11

NEDO-33351 -REVISION 0 NON-PROPRIETARY INFORMATION Limitat.n Limtitattion TitleL on Description

.ý..-Disposition Section of NMP2 PUSAR Nubr fr

.- %::-,ý

-which 'addresses the

.ýNRC SER,7 Limitation 9.19 Void-Quality For applications involving Comply Section 2.8.5.8 and Section Correlation 1 PANACEA/ODYN/ISCOR/TASC for 2.8.3.1 operation at EPU and MELLLA+, an additional 0.01 will be added to the OLMCPR, until such time that GE expands the experimental database supporting the Findlay-Dix void-quality correlation to demonstrate the accuracy and performance of the void-quality correlation based on experimental data representative of the current fuel designs and operating conditions during steady-state, transient, and accident conditions.

9.20 Void-Quality The NRC staff is currently reviewing.

Not This limitation is applicable to Correlation 2 Supplement 3 to NEDE-32906P, "Migration to Applicable M+ applications only.

TRACG04/PANAC1 1 from Therefore, this limitation is not TRACG02/PANAC 10," dated May 2006 applicable to the EPU (Reference A-4). The adequacy of the application.

TRACG interfacial shear model qualification for application to EPU and MELLLA+ will be addressed under this review. Any conclusions specified in the NRC staff SE approving Supplement 3 to LTR NEDC-32906P (Reference A-4) will be applicable as approved.

A142

NEDO-33351 -REVISION 0 NON-PROPRIETARY INFORMATION

-Limitation Limitatio&nTitle Limitation Description Disp sition S

-sctiOn of NMP2 PUSAR

-Ndmber from which addresses the NRC.SER:

Limiitation.

9.21 Mixed Core Plants implementing EPU or MELLLA+ with Not Not applicable to NMP2 as it Method 1 mixed fuel vendor cores will provide plant-Applicable has only GE fuel in the Core.

specific justification for extension of GE's analytical methods or codes. The content of the plant-specific application will cover the topics addressed in this SE.as well as subjects relevant to application of GE's methods to legacy fuel. Alternatively, GE may supplement or revise LTR NEDC-3 3173P (Reference A-i) for mixed core application.

A-13

NEDO-33351 -REVISION 0 NON-PROPRIETARY INFORMATION

-.,Limitation Limitation Title Limitation Description

.Dispoiion Srction of NMP2 PUSAR

'Number from-

-which addresses the

"NRc SEW"

?"

°!:

Limitation 9.22 Mixed Core Method 2 For any plant-specific applications of TGBLA06 with fuel type characteristics not covered in this review, GE needs to provide assessment data similar to that provided for the GE fuels. The Interim Methods review is applicable to all GE lattices up to GE14. Fuel lattice designs, other than GE lattices up to GE 14, with the following characteristics are not covered by this review:

square internal water channels water crosses

• Gd rods simultaneously adjacent to water and vanished rods lIxIl lattices

• MOX fuel The acceptability of the modified epithermal slowing down models in TGBLA06 has not been demonstrated for application to these or other geometries for expanded operating domains.

Significant changes in the Gd rod optical thickness will require an evaluation of the TGBLA06 radial flux and Gd depletion modeling before being applied. Increases in the lattice Gd loading that result in nodal reactivity biases beyond those previously established will require review before the GE methods may be applied.

Not Applicable Not applicable to NMP2 as it has only GE fuel in the Core.

A-14

0 NEDO-33351 - REVISION 0 NON-PROPRIETARY INFORMATION Limtaton LimtaionTile

~~~-LimtaionD ispos Sectio o~f NMP2',PISAR Number from.

-which adti resses7 te

,NRC-SER~

~.LmitatIon.

9.23 MELLLA+

Eigenvalue Tracking In the first plant-specific implementation of MELLLA+, the cycle-specific eigenvalue tracking data will be evaluated and submitted to NRC to establish the performance of nuclear' methods under the operation in the new operating domain. The following data will be analyzed:

S.H6t critical eigenvalue, Cold critical eigenvalue, Nodal power distribution (measured and calculated TIP comparison),

• Bundle power distribution (measured and calculated'TIP comparison),

• Thermal margin,

• ' Core flow and pressure drop uncertainties, and The MIP Criterion (e.g., determine if core and ffiel dsign selected is expected to produce a plant response outside the prior experience base).

Provision of evaluation of the core-tracking data will provide the NRC staff with bases to iestablish if operation at the expanded operating domain indicates: (1) changes in the performanceof nuclear -methods outside the.

EPU experience base; (2) changes in the available thermal margins; (3) need for Not Applicable This limitation is applicable to M+ applications only.

Therefore, this limitation is not applicable to the EPU° application.

-A-1I5

NEDO-33351 -REVISION 0 NON-PROPRIETARY INFORMATION Limitation

- Limitation Title LimitationDescription Dispositionf Section of NMP2 'PUSAR*

Number from which addresses the NRC SER -.

Limitation changes in the uncertainties and NRC-approved criterion used in the SLMCPR methodology; or (4) any anomaly that may require corrective actions.

9.24 Plant Specific The plant-specific applications will provide Comply Section 2.8.2.5.4.

Application prediction of key parameters for cycle exposures for operation at EPU (and MELLLA+ for MELLLA+ applications). The plant-specific prediction of these key parameters will be plotted against the EPU Reference Plant experience base and MELLLA+ operating experience, if available.

For evaluation of the margins available in the fuel design limits, plant-specific applications will also provide quarter core map (assuming core symmetry) showing bundle power, bundle operating LHGR, and MCPR for BOC, MOC, and EOC. Since the minimum margins to specific limits may occur at exposures other than the traditional BOC, MOC, and EOC, the data will be provided at these exposures.

A-16

NEDO-33351 -REVISION 0 NON-PROPRIETARY INFORMATION

References:

A-1 MFN 08-089, Ho K. Nieh, Deputy Director, Division of Policy and Rulemaking, Office of Nuclear Reactor Regulation to Robert E. Brown (GEH), "Final Safety Evaluation For General Electric (GE)-Hitachi Nuclear Energy Americas, LLC (GHNE)

Licensing Topical Report (LTR) NEDC-33173P, "Applicability Of GE Methods To Expanded Operating Domains" (TAC NO.

MD0277)," January 17, 2008.

A-2 MFN 05-141, L. M. Quintana (GEH) to NRC, "General Electric Boiling Water Reactor Maximum Extended Load Line Limit Analysis Plus," NEDC-33006P, Revision 2, November 28, 2005. (ADAMS Accession No. ML053360526).

A-3 FLN-2007-001, A. A. Lingenfelter (GNF) to NRC, "The PRIME Model for Analysis of Fuel Rod Thermal-Mechanical Performance," January 19, 2007. (ADAMS Accession No. ML070250414).

A-4 GE Nuclear Energy, "Migration to TRACG04/PANAC1 1 from TRACG02/PANAC1O," NEDE-32906P, Supplement 3, May 2006.

A-5 GEH Letter (MFN 08-693), "Implementation of Methods Limitations - NEDC-33173P (TAC No. MD0277)," September 18, 2008.

A-17

ENCLOSURE ATTACHMENT 4 Affidavit Justifying Withholding Proprietary Information in NEDC-33351P Nine Mile Point Nuclear Station, LLC May 27, 2009

GE-Hitachi Nuclear Energy Americas LLC AFFIDAVIT I, James F. Harrison, state as follows:

(1) I am Vice President, Fuels Licensing, Regulatory Affairs, GE-Hitachi Nuclear Energy Americas LLC ("GEH"). I have been delegated the function of reviewing the information described in paragraph (2) which is sought to be withheld, and have been authorized to apply for its withholding.

(2) The information sought to be withheld is contained in GEH Licensing Topical Report NEDC-33351P, "Safety Analysis Report for Nine Mile Point Nuclear Station Unit 2 Constant Pressure Power Uprate," Revision 0, Class III (GEH Proprietary Information),

May 2009. GEH proprietary information text in NEDC-33351P Revision 0 is identified by a dark red dotted underline inside double square brackets ((Thiis.s.en.tence.is.an..exyam.p1e.)).

Figures and large equation objects containing GEH proprietary information are identified with double square brackets before and after the object. In each case, the superscript notation [3) refers to Paragraph (3) of this affidavit, which provides the basis for the proprietary determination.

(3)

In making this application for withholding of proprietary information of which it is the owner or licensee, GEH relies upon the exemption from disclosure set forth in the Freedom of Information Act ("FOIA"), 5 USC Sec. 552(b)(4), and the Trade Secrets Act, 18 USC Sec. 1905, and NRC regulations 10 CFR 9.17(a)(4), and 2.390(a)(4) for "trade secrets" (Exemption 4). The material for which exemption from disclosure is here sought also qualify under the narrower definition of "trade secret", within the meanings assigned to those terms for purposes of FOIA Exemption 4 in, respectively, Critical Mass Energy Proiect v. Nuclear Regulatory Commission, 975F2d871 (DC Cir. 1992), and Public Citizen Health Research Group v. FDA, 704F2d1280 (DC Cir. 1983).

(4) Some examples of categories of information which fit into the definition of proprietary information are:

a. Information that discloses a process, method, or apparatus, including supporting data and analyses, where prevention of its use by GEH's competitors without license from GEH constitutes a competitive economic advantage over other companies;

b. Information which, if used by a competitor, would reduce his expenditure of resources or improve his competitive position in the design, manufacture, shipment, installation, assurance of quality, or licensing of a similar product;

c. Information which reveals aspects of past, present, or future GEH customer-funded development plans and programs, resulting in potential products to GEH; NEDC-33351P Revision 0 Affidavit Page I of 3

d. Information Which discloses patentable subject matter for which it may be desirable to obtain patent protection.

The information sought to be withheld is considered to be proprietary for the reasons set forth in paragraphs (4)a. and (4)b. above.

(5)

To address 10 CFR 2.390(b)(4), the information sought to be withheld is being submitted to NRC in confidence. The information is of a sort customarily held in confidence by GEH, and is in fact so held. The information sought to be withheld has, to the best of my knowledge and belief, consistently been held in confidence by GEH, no public disclosure has been made, and it is not available in public sources. All disclosures to third parties, including any required transmittals to NRC, have been made, or must be made, pursuant to regulatory provisions or proprietary agreements which provide for maintenance of the information in confidence. Its initial designation as proprietary information, and the subsequent steps taken to prevent its unauthorized disclosure, are as set forth in paragraphs (6) and (7) following.

(6)

Initial approval of proprietary treatment of a document is made by the manager of the originating component, the person most likely to be acquainted with the value and sensitivity of the information in relation to industry knowledge, or subject to the terms under which it was licensed to GEH. Access to such documents within GEH is limited on a "need to know" basis.

(7) The procedure for approval of external release of such a document typically requires review by the staff manager, project manager, principal scientist, or other equivalent authority for technical content, competitive effect, and determination of.the accuracy of the proprietary designation. Disclosures outside GEH are limited to regulatory bodies, customers, and potential customers, and their agents, suppliers, and licensees, and others with a legitimate need for the information, and then only in accordance with appropriate regulatory provisions or proprietary agreements.

(8)

The information identified in paragraph (2) above is classified as proprietary because it contains detailed results and conclusions regarding supporting evaluations of the safety-significant changes necessary to demonstrate the regulatory acceptability of the "Safety Analysis Report for Nine Mile Point Nuclear Station Unit 2 Constant Pressure Power Uprate" for a GEH Boiling Water Reactor ("BWR"). The analysis utilized analytical models and methods, including computer codes, which GEH has developed, obtained NRC approval of, and applied to perform evaluations of Constant Pressure Power Uprate analysis for a GEH BWR.

The development of the evaluation process along with the interpretation and application of the analytical results is derived from the extensive experience database that constitutes a major GEH asset.

NEDC-33351P Revision 0 Affidavit Page 2 of 3

(9) Public disclosure of the information sought to be withheld is likely to cause substantial harm to GEH's competitive position and foreclose or reduce the availability of profit-making opportunities. The information is part of GEH's comprehensive BWR safety and technology base, and its commercial value extends beyond the original development cost.

The value of the technology base goes beyond the extensive physical database and analytical methodology and includes development of the expertise to determine and apply the appropriate evaluation process. In addition, the technology base includes the value derived from providing analyses done with NRC-approved methods.

The research, development, engineering, analytical and NRC review costs comprise a substantial investment of time and money by GEH.

The precise value of the expertise to devise an evaluation process and apply the correct analytical methodology is difficult to quantify, but it clearly is substantial.

GEH's competitive advantage will be lost if its competitors are able to use the results of the GEH experience to normalize or verify their own process or if they are able to claim an equivalent understanding by demonstrating that they can arrive at the same or similar conclusions.

The value of this information to GEH would be lost if the information were disclosed to the public. Making such information available to competitors without their having been required to undertake a similar expenditure of resources would unfairly provide competitors with a windfall, and deprive GEH of the opportunity to exercise its competitive advantage to seek an adequate return on its large investment in developing and obtaining these very valuable analytical tools.

I declare under penalty of perjury that the foregoing affidavit and the matters stated therein are true and correct to the best of my knowledge, information, and belief.

Executed on this 4th day of May 2009.

James F. Harrison Vice President, Fuels Licensing, Regulatory Affairs GE-Hitachi Nuclear Energy Americas LLC NEDC-33351P Revision 0 Affidavit Page 3 of 3

ENCLOSURE ATTACHMENT 5 Regulatory Commitments Nine Mile Point Nuclear Station, LLC May 27, 2009

ATTACHMENT 5 - REGULATORY COMMITMENTS The following table identifies those actions committed to by NMPNS in this submittal. Any other statements in this submittal are provided for information purposes and are not considered to be regulatory commitments.

REGULATORY COMMITMENT DUE DATE None.

N/A 1 of 1

ENCLOSURE ATTACHMENT 6 Modifications to Support EPU Nine Mile Point Nuclear Station, LLC May 27, 2009

ATTACHMENT 6 - MODIFICATIONS TO SUPPORT EPU Modification Description Planned Outage of Completion Replace FW Heater Drain Replace pump internals N2R12 Pumps and Motors Replace pump motors Replace 4h point heater drain level control valve trim Replace 3rd Point 0

Replace three third point feedwater heaters (not an N2R12 Feedwater Heaters Extended Power Uprate (EPU) modification - the heaters require replacement before the plant operates under EPU conditions.

There is strong evidence that shows excessive wear and damage to the tube supports under current operating conditions.

The damage has worsened as time progressed and if operating conditions were more severe, the detrimental effects on the tubes and tube supports would be greater)

Improve Main 0

Install upgraded cooling system on main N2R12 Transformer Cooling generator step-up transformers Upgrade Reactor 0

Replace pump impellers N2R13 Feedwater Pumps and Gear Sets 0

Replace pump speed increasers Flow control valve changes Feedwater system setpoint setdown setting change 0

Re-rate feedwater system piping/valves Extraction Steam 0

Replace extraction steam expansion bellows for N2R13 Expansion Joints the 'B' and 'C' 1St through 4t point feedwater heater extraction lines (not an EPU modification -

being replaced due to equipment degradation, same rationale as feedwater heater replacement).

Equipment Qualification 0

Install shielding on the two standby gas treatment N2R13 Modifications system filters Isolate Abandoned Turbine o

Isolate abandoned loads N2R13 Building Closed Loop Cooling (TBCLC) Loads 0

Rebalance the TBCLC system 1 of 3

ATTACHMENT 6 - MODIFICATIONS TO SUPPORT EPU Modification Description Planned Outage of Completion Replace Feedwater Pump 0

Replace 13.8 KV power cables to the three N2R13 Motor Cables feedwater pump motors Add two 13.8 KV breakers Install/rework tray and conduit Replace Current Transformers (CT) and ammeters Revise relay settings Improve Turbine Building Installation of four additional area coolers located N2R13 Heating, Ventilation and near the condensate and condensate booster Air Conditioning (-IVAC) pumps Feedwater Heater 0

Re-rate the 5th and 6h point feedwater heaters N2R13 Requalification Replace the 6th point heater shell side safety valves Replace the scavenging steam relief valves Main Steam, Feedwater, Revise piping supports as necessary for EPU N2R13 and Balance of Plant conditions Piping Support Replacement Replace High Pressure 0

Replace the high pressure turbine for increased N2R13 Turbine steam flow at EPU conditions Replace Low Pressure 0

Replace cross around relief valves with valves N2R13 Turbine Cross Around rated for EPU conditions Relief Valves Re-rate the cross around

piping, moisture separators, drain tanks and intermediate heat exchangers Replace Low Pressure 0

Replace six low pressure turbine atmospheric N2R13 Turbine Atmospheric exhaust hood diaphragms Relief Diaphragms Temporary Vibration 0

Install accelerometers on Main Steam, Feedwater, N2R13 Monitoring Extraction Steam and BOP piping for vibration monitoring (temporary) 2 of 3

ATTACHMENT 6 - MODIFICATIONS TO SUPPORT EPU Modification Description Planned Outage of Completion Instrument Replacement 0

Replace seven instruments to meet EPU N2R13 and Modification conditions Recalibrate 227 instrument loops Change various setpoints Change various computer points Recirculation Runback 0

Revise Reactor Recirculation System (RRS)

N2R13 Initiation and Runback runback logic to initiate upon a

Rate feedwater/condensate booster pump trip Increase recirculation flow control valve runback rate to 9% per second Mitigation System Valve 0

Change valve trim to the Hydrogen Water N2R13 Changes Chemistry and Zinc Injection Passivation (ZIP) systems Generator Isolated Phase 0

Modify the isolated phase bus duct housings to N2R13 Bus Duct Cooling provide additional cooling Design Basis Document 0

Design basis reconciliation/configuration control N2R13 Updates to Support EPU No physical work involved.

Implementation Steam Dryer 0

Reinforce the inner and middle hood end cover N2R13 welds and the lifting rod upper brace to vane bank weld Condensate Demineralizer e

Install a partial bypass line around the condensate Complete Bypass demineralizers Main Steam Line 0

Install strain gauges to record the dynamic Complete Vibration Monitoring pressure fluctuations inside the main steam piping Strain Gauges in the drywell.

3 of 3

ENCLOSURE ATTACHMENT 7 EPU Test Plan Nine Mile Point Nuclear Station, LLC May 27, 2009

ATTACHMENT 7 - EPU TEST PLAN TABLE OF CONTENTS

1.0 INTRODUCTION

2.0 PURPOSE 3.0

SUMMARY

OF CONCLUSIONS 4.0 TESTING EVALUATIONS 5.0 JUSTIFICATION FOR ELIMINATION OF POWER ASCENTION TESTS 5.1 5.2 5.3 5.4 Table 4-1 Table 4-2 Table 5-1 Table 5-2 Table 5-3 Table 5-4 Table 5-5 Table 7-1 Table 7-2 Table 7-3 Figure 7-1 Figure 7-2 Figure 7-3 Figure 7-4 Figure 7-5 Figure 7-6 Figure 7-7 Figure 7-8 Figure 7-9 Guidelines of SRP 14.2.1, Paragraph III.C.2 Review and Analysis Justification for Not Performing Large Transient Testing Post EPU Industry Experience NMPNS Large Transient Testing Review and Analysis Startup Transient Tests Performed at > 80% OLTP Startup Transient Tests Performed at < 80% OLTP Justification Cross Reference Transient Testing Applicability PRA Results Operating Experience Recirculation Pump Trip Test Results Comparison of NMP Initial Startup Testing and Planned EPU Testing EPU Implementation Modifications Planned EPU Power Ascension Testing NMP2 Level Response to a Scram NMP2 Feedwater Flow Response to a Scram Single Feedwater Pump Trip (Case 1)

Single Feedwater Pump Trip (Case 2)

Single Feedwater Pump Trip (Case 3)

NMP2 Level Response to MSIVD NMP2 Feedwater Flow Response to MSIVD NMP2 Level Response to TTWBP NMP2 Feedwater Flow Response to TTWBP 1 of 65

ATTACHMENT 7 - EPU TEST PLAN

1.0 INTRODUCTION

The following information supplements the Nine Mile Point Unit 2 (NMP2) Power Uprate Safety Analysis Report (PUSAR) and provides additional information about startup testing addressed in Standard Review Plan (SRP) 14.2.1; Generic Guidelines for Extended Power Uprate Testing Programs.

2.0 PURPOSE

Background

This attachment provides detailed information on the testing Nine Mile Point Nuclear Station, LCC (NMPNS) will perform for the NMP2 Extended Power Uprate (EPU) implementation. NMPNS plans to implement a Constant Pressure Power Uprate (CPPU) to 3988 MWt.

The planned EPU is approximately fifteen percent (15%) above Current Licensed Thermal Power (CLTP) of 3467 MWt and twenty percent (20%) above Original Licensed Thermal Power (OLTP) of 3323 MWt. During the 2010 refueling outage, NMP2 will install modifications to upgrade or replace some existing plant equipment.

During the 2012 refueling outage (N2R12), NMPNS will upgrade additional plant equipment and load fuel sufficient to support testing and operation at 3988 MWt. For implementation of the EPU license amendment, NMPNS will conduct a comprehensive startup test program to ensure the safe operation of the plant. The tests that NMPNS intends to perform are described herein.

NMPNS will assure that the functions of plant equipment important to safety that rely on the integrated operation of multiple Structures, Systems and Components (SSCs) following an anticipated operational occurrence are adequately demonstrated prior to operation at the EPU power level.

The Nuclear Regulatory Commission (NRC) determines whether Large Transient Testing (i.e., testing requiring an automatic scram from high power levels) is necessary during power ascension to EPU conditions on a plant specific basis. The purpose of this report is to describe the startup testing NMPNS intends to perform in support of the NMP2 EPU to assist the NRC in making a final determination relative to Large Transient Testing at NMP2.

The NRC endorsed General Electric Licensing Topical Reports (NEDC-32424P-A, also called ELTRI and NEDC-32523P-A, also called ELTR2) for Extended Power Uprates.

The NRC also accepted the test program of the CPPU Licensing Topical Report (NEDC-33004P-A called CLTR) for EPUs, but reserved the right to consider on a plant specific basis the CLTR recommendations against Large Transient Testing. The CLTR is the controlling document for the NMP2 planned EPU.

NMPNS will comply with the startup test requirements of the CLTR, but will take exception to performing Large Transient Testing.

Objective This attachment describes the startup testing that NMPNS will conduct associated with implementation of EPU at NMP2, including integrated post modification testing and justification for not performing large transient testing. The information is organized in a manner similar to SRP Section 14.2.1.

3.0

SUMMARY

OF CONCLUSIONS Utilizing SRP 14.2.1, NMPNS has determined which.of the original startup tests described in the Final Safety Analysis Report (FSAR) need to be performed for EPU. The startup tests NMPNS intends to perform for EPU are described in Table 7-3, "Planned EPU Power Ascension Testing."

NMPNS has also determined the post-EPU modification tests that impact plant safety that will be performed.

The post-EPU modification tests are described in Table 7-2, "EPU Implementation 2 of 65

ATTACHMENT 7 - EPU TEST PLAN Modifications." Also included are tests for modifications that do not impact plant safety which are included for completeness.

As further detailed below, Large Transient Testing for NMP2 is not required for EPU because:

1) NMPNS has previously performed Large Transient Tests and has documented the results;

2) potential gains from further Large Transient Testing are minimal and produce an unnecessary and undesirable transient cycle on the primary system; 3) analytical methods and training facilities adequately simulate large transient events without the need to impose actual events; 4) plant operators will be trained in potential EPU transient events through the use of simulator models containing Balance of Plant (BOP) transients; 5) Probabilistic Risk Assessment (PRA) analysis indicates an increased risk of core damage and large early release if the tests are performed; and 6) industry operating experience indicates that plants will continue to respond to these transients as designed following EPU implementation.

In view of previous test results and the plant response to prior documented events, the EPU startup testing program, as proposed in this attachment, is considered sufficient to validate the continued ability of the plant to safely operate within the required parameters and operational limits.

NMPNS requests that the NRC concur with the exception to Large Transient Testing. NMPNS has concluded that NMP2 and industry data provide an adequate correlation to allow the effects of the EPU to be analytically determined on a plant specific basis.

4.0 TESTING EVALUATIONS Comparison to NMP2 Startup Test Program (SRP 14.2.1; III.A)

The CLTR provides the following guidance: 1) The same performance criteria will be used for EPU as in the original power ascension tests unless they have been replaced by updated criteria since the initial test program; and 2) testing of system performance affected by steam pressure or core flow is not necessary with the exception of the tests listed in Section 10.4 of the CLTR. The testing planned for NMP2 to support implementation of EPU conforms to the guidance provided in the CLTR.

Power ascension tests performed at > 80% of OLTP Table 7-1, "Comparison of NMP2 Initial Startup Testing and Planned EPU Testing," provides a comparison of the initial startup tests and the 4.3% uprate (to 3467 MWt) startup tests to the planned testing for the EPU. As indicated in Table 7-1, the following tests were performed at 80% of OLTP or greater: SUT-1, SUT-2, SUT-5, SUT-11, SUT-12, SUT-13, SUT-16, SUT-18, SUT-19, SUT-20, SUT-22, SUT-23, SUT-24, SUT-25, SUT-27, SUT-29, SUT-30, SUT-33, SUT-35, SUT-74, SUT-75, SUT-76, SUT-77, SUT-78, SUT-79, SUT-80 and SUT-81.

Additional details for planned EPU testing are provided in Table 7-3, "Planned EPU Power Ascension Testing." Justifications for relief from certain transient testing are provided in section 4.3 of this attachment. A listing of transient tests performed at 80% or greater during initial startup testing is provided below.

Power ascension transient tests performed at > 80% of OLTP Table 4-1 shows startup transient tests performed at 80% OLTP or greater. This table is provided in accordance with SRP 14.2.1, paragraph III.A. 1 and III.A.2. Initial startup tests, along with test power levels, are also provided in Table 7-1 of this attachment.

3 of 65

ATTACHMENT 7 - EPU TEST PLAN Table 4 Startup Transient Tests Performed at > 80% OLTP Power USAR*

Table 2 of EPU Initial Transient Test Test Number Level Table Tal 142.1 Testing (OLTP)

Planned Pressure Regulator SUT-22 98.1%

14.2-221 Yes Yes Feedwater Pump Trip SUT-23 99%

14.2-224 Yes No Turbine Valve Surveillance SUT-24 95%

14.2-226 No Yes Full Main Steam Isolation SUT-25 95.3%

14.2-228 Yes No Valve (MSIV) Closure Turbine Trip / Generator SUT-27 99.6%

14.2-231 Yes No Load Rejection Recirculation Flow Control SUT-29 97%

14.2-No No 233,234 Recirculation Pump Trip SUT-30 73.3/98.2%

14.2-235 Yes No (1 Pump)

I-I

• Updated Safety Analysis Report Tests at lower power invalidated by EPU In accordance with SRP 14.2.1, paragraph III.A.2, the startup tests of Table 7-1, "Comparison of NMP Initial Startup Testing and Planned EPU Testing," were reviewed for potential tests that would be invalidated by EPU. No such testing was identified for the NMP2 EPU.

Attachments 1 and 2 of the SRP 14.2.1 In accordance with SRP 14.2.1, paragraph III.A.2, Attachments 1 and.2 of SRP 14.2.1 were reviewed for consistency with the NMP2 startup testing program.

The tests in Table 4-2 and shown in of SRP 14.2.1 were performed during NMP2 startup at power levels less than 80%.

They are included here for completeness and are also discussed in the justifications of Section 5.0 of this attachment.

Table 4-2 -Startup Transient Tests Performed at < 80% OLTP Power EPU Testing Initial Transient Test Test Number Level PUaTed Reference (OLTP)

Planned (OLTP)

Reactor Core Isolation SUT-14

<50%

No Startup Report Cooling (RCIC) Functional Testing Loss of Feedwater Heating SUT-23 72.3%

No Startup Report Relief Valve Testing SUT-26 17.6%

No Startup Report Reactor Recirculation Pump SUT-30 66.4%

No Trip (2 Pumps)

(Note 1)

Startup Report Loss of Turbine Generator SUT-31 24%

No Startup Report and Offsite Power Note 1-The Two Reactor Recirculation Pump Trip Test (SUT-30) was re-performed during Generator Load Rejection Test (SUT-27) at 99.6% power as shown above and explained further in section 4.3 of this attachment.

4 of 65

ATTACHMENT 7 - EPU TEST PLAN Post Modification Testing Requirements (SRP 14.2.1; II.B)

Table 7-2, "EPU Implementation Modifications," provides a listing of EPU implementation modifications that are currently anticipated and that are being prepared for implementation through 2012. NMPNS plans to complete the necessary modifications to achieve a 120% increase above OLTP prior to the conclusion of the 2012 refueling outage (N2R13).

Modification Aggegate Impact As can be seen from an inspection of the modifications listed in Table 7-2, the aggregate impact of most of these modifications on normal plant operations is minimal.

The High Pressure Turbine replacement modification and the Feedwater Pump modifications do have an impact to the reactor plant as they are directly tied to the primary system piping and steam flow to the turbine is increased by -20%.

However their function and interrelationship is essentially unchanged.

Condensate and Feedwater System upgrades proposed in refuel outage N2R12 (2010) and N2R13 (2012) represent significant plant modifications. These changes include the replacement of feedwater pump impellers, motor power cables and speed increasers.

The heater drain pump internals and motors will also be replaced.

The individual changes will be adequately addressed during post modification testing and the aggregate impact will be addressed by feedwater system power ascension testing. See Table 7-2 EPU Implementation Modifications for a description of planned feedwater modification testing.

Startup and Test Plan Aggregate impact of EPU plant modifications, setpoint adjustments and parameter changes will be demonstrated by a test program established for a Boiling Water Reactor (BWR) EPU in accordance with startup test specifications as described in PUSAR Section 2.12.1. The startup test specifications are based upon analyses and GE BWR experience with uprated plants to establish a standard set of tests for initial power ascension for EPU.

These tests, which supplement the normal Technical Specification testing requirements, are summarized below:

Testing will be performed in accordance with the Technical Specifications Surveillance Requirements on instrumentation that is re-calibrated for EPU conditions. Overlap between the Intermediate Range Monitors (IRMs) and Average Power Range Monitors (APRM) will be assured.

Testing will be done to confirm the power level near the turbine first stage scram bypass setpoint.

EPU power increases will be made in predetermined increments of < 5% power starting at 90%

CLTP Reactor Thermal Power (RTP) so that system parameters can be projected for EPU power before the CLTP RTP is exceeded. Operating data, including fuel thermal margin, will be taken and evaluated at each step. Routine measurements of reactor and system pressures, flows and vibration will be evaluated for each measurement point, prior to the next power increment.

Radiation measurements will be made at selected power levels to ensure the protection of personnel.

Control system tests will be performed for the reactor feedwater/reactor level controls and pressure controls. These operational tests will be made at the appropriate plant conditions for that test at each of the power increments, to show acceptable adjustments and operational capability.

Steam dryer/separator performance will be confirmed within limits by determination of steam moisture content as required during power ascension testing.

5 of 65

ATTACHMENT 7 - EPU TEST PLAN Vibration monitoring of main steam, feedwater and other balance of plant piping will be performed to permit a thorough assessment of the effect of EPU on this piping.

The same performance criteria will be used as in the original power ascension tests, except where they have been replaced by updated criteria since the initial test program. Because dome pressure and core flow have not changed and recirculation drive flow may increase slightly for EPU to achieve rated conditions, testing of system performance affected by these parameters is not necessary with the exception of the tests listed above.

The EPU testing program at NMP2, which is based on the specific testing required for the NMP2 initial EPU power ascension, supplemented by normal Technical Specification testing, is confirmed to be consistent with the generic description provided in the CLTR.

Multiple Structures, Systems and Components (SSCs)

Functions important to safety that rely on integrated operation of multiple SSCs following plant events (such as plant load swings and loss of feedwater heating) are adequately addressed for NMP2, as further described in Section 5.0 below.

5.0 JUSTIFICATION FOR ELIMINATION OF POWER ASCENTION TESTS (SRP 14.2.1; ILI.C) 5.1 Guidelines of SRP 14.2.1, Paragraph III.C.2 Paragraph III.C.2 of SRP 14.2.1 provides specific guidance to be considered in order to justify elimination of large transient testing. Table 5-1 provides a cross reference between the guidance of SRP paragraph 1II.C.2 and this attachment.

Table 5 Justification Cross Reference Paragraph Guidance/Criteria Discussion/ Location in this attachment III.C.2 (a)

Power uprate operating experience Contained in Section 5.0 (b)

New thermal-hydraulic phenomena or No new thermal-hydraulic phenomena or identified system interactions new system interactions were identified as a result of the NMP2 EPU analysis. No further discussion is provided.

(c)

Conformance with limitations of NMP2 has no unique limitations associated analytical methods with conformance to analytical methods.

No further discussion is provided.

(d)

Plant staff familiarization with facility Contained in Section 5.0.

operation and EOPs (e)

Margin reduction in safety analysis Provided in Section 5.0 for specific tests, for Anticipated Operational where applicable. Discussed in the specific Occurrences (AOOs) sections under EPU Transient Analysis Results/EPU Margins (f)

Guidance in Vendor topical reports Discussed in Section 2.0 (g)

Risk implications Discussed in Section 5.0 ELTRI states MSIV Closure Events would be tested for EPU if the power uprate was more than ten percent (10%) above any previously recorded MSIV closure transient.

Similarly, ELTRI states a generator load rejection test would be performed if the uprate was more than fifteen percent (15%)

above any previously recorded generator load rejection transient. ELTRI applies to extended power 6 of 65

ATTACHMENT 7 - EPU TEST PLAN uprates whether constant pressure or otherwise.

The CLTR applies to constant pressure power uprates only.

With regard to the specific ELTR1 requirements for Large Transient Testing, NMP2 had a MSIV closure event on October 15, 2001 and a generator load rejection on August 14, 2003. Based on these two events, the ELTRI criteria to perform testing would apply to NMP2 as shown below in Table 5-2.

Table 5 Transient Testing Applicabili Event LER*

Date Power EPU Power

% Increase Required by No.

Level ELTR1 MSIV Csur 01-004 10-15-2001 3467 MWt 3988 MWt 15.03%

Yes (>10%)

Closure Generator L eject 03-002 8-14-2003 3467 MWt 3988 MWt 15.03%

Yes (>15%)

Load Reject

• Licensee Event Reports NMPNS takes exception to the ELTRI criteria and Large Transient Testing at NMP2 should not be required for EPU as outlined below.

5.2 Review and Analysis Justification for Not Performing Large Transient Testing NMPNS has previously performed transient tests and has documented results Large Transient Testing performed during initial plant startup testing determined integrated plant response after reaching full power. Startup tests were required to baseline plant responses and to individualize system performances.

Startup test results indicate SSCs perform their intended functions.

NMPNS satisfied all Acceptance Criteria necessary during initial startup testing for NMP2. During initial startup testing, NMPNS uncovered potential equipment defects for Design Basis Accident (DBA) mitigation by deliberately placing the plant in transient events. Corrective actions were taken to remedy any identified defects and the system/component was re-tested following these corrective actions. Further Large Transient Testing for EPU is not required because events have been baselined by startup testing, actual events, post modification testing and by analytical techniques.

Large Transient Testing provides information that has minor additional value to plant operation and that NMNPS has already established is duplicative, disruptive and subjects the plant to unnecessary increased risks. Large Transient Testing challenges a limited number of systems and components, all of which have a history of safe performance at NMP2. NMP2 has accumulated more than 20 years of experience dealing with plant transient response. Therefore, performance of additional testing to demonstrate plant response at EPU provides insignificant benefit.

Gains from Large Transient Testing are minimal No new transients occur as a result of EPU. Transient analyses at EPU are comparable to analyses at current plant conditions.

Changes in plant conditions for EPU are not expected to result in a significant change to current plant conditions and response. Therefore, large transient testing at NMPNS will not provide new insights and any gains from this testing are minimal.

No new thermal-hydraulic phenomena or system interactions have occurred following actual MSIV closure, turbine trip and load reject events at NMP2.

The plant has responded as expected in accordance with design features. No unexpected conditions were experienced and no latent defects were uncovered during these events, beyond the specific failures that caused the events.

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ATTACHMENT 7 - EPU TEST PLAN The proposed EPU test program tests the aggregate impact of plant modifications.

Plant modifications to support EPU have minimal safety significance. Modifications will be implemented as needed in advance of EPU implementation.

Advanced analytical methods and training facilities accurately and adequately simulate large transient events and system performance Advances in analytical techniques, methods, models, and simulators have created a high level of confidence in determining plant responses and are cost effective alternatives to actual testing.

Analyses demonstrate that plant shutdown is safely achieved under EPU conditions. NMPNS will perform simulator demonstrations to support this EPU.

The benefits from Large Transient Testing are outweighed by the potential adverse affects Large Transient Testing has on plant equipment. Large Transient Testing has a negative impact on the station and power grid, for which the unit supplies a significant base load. Large Transient Testing provides information on a limited number of plant systems.

The scram and subsequent rapid reduction in power is controlled by normal operator actions. Therefore, the need to perform Large Transient Testing at NMP2 to demonstrate safe operation of the plant is unwarranted.

NMP2 plant simulator models BOP transients The NMP2 plant simulator provides accurate BOP modeling of transients to facilitate operator training on potential EPU transients or events. Prior to EPU implementation, the simulator will be updated to model the EPU transient analyses.

NMP2 operator training on various plant upset conditions from postulated accident conditions to anticipated transients prepares them for the nature, timeline, and extent of the plant response to simulated transients. Therefore, initiating actual plant transient events for purposes of operator training will not be necessary. Simulator training has the advantage of exposing all operating shifts to the transients whereas only the on duty shift has the hands on experience of in-plant transients.

Large Transient Testing risk assessment NMPNS conducted a risk assessment for performing two plant transient tests upon NMP2 EPU implementation. The evaluated tests were a generator full load reject and an MSIV isolation event.

The risk assessment indicated the proposed tests represent an increase in the risk of core damage and large early release. This assessment does not include the potential equipment damage or challenges to the operators, which should be avoided.

Table 5 PRA Results Initiating Conditional Initiating Conditional Event Initiating Initiating Event Core Damage Large Early Release EetEvent Core Damage Poaites ReleaseReas Event Frequency Frequency Probabilities RProbabilities (CDF)

(CCDP)

Frequency (CLERP)

(CDF)__(LERF)

Turbine Trip 1.5/yr 1.3E-6/yr 8.7E-7 9.7E-8/yr 6.5E-8 MSIV Is 0.14/yr 2.OE-7/yr 1.4E-6 1.3E-8/yr 8.9E-8 Isolation The CCDPs and CLERPs for a turbine trip and for a MS1V closure event are relatively small compared to events such as loss of offsite power or a Loss of Coolant Accident (LOCA). However, they do have some risk significance.

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ATTACHMENT 7 - EPU TEST PLAN The calculated CCDPs are 8.7E-7 and 1.4E-6 for non-isolation (turbine trip) and isolation (MSIV closure), respectively. Also, the calculated CLERPs are 6.5E-8 and 8.9E-8 for the non-isolation (turbine trip) and isolation (MS1V closure), respectively. These CCDPs and CLERPs represent the additional probabilities of core damage and large early release, caused by performing the proposed tests (i.e., the initiating events occur). if both tests are performed, the total additional probabilities would thus be 2.3E-6 (CCDP) and 1.5E-7 (CLERP). Note the analyses do not credit compensatory measures that may reduce the risk of core damage given that extra operators may be staged for the proposed tests.

5.3 Post EPU Industry Experience Post EPU Steam Dryer Issues Stresses imposed on steam dryers by the higher steam flows are being addressed in Attachment 14 of the NMP2 EPU application, and therefore will not be repeated here.

Industry Post EPU Transient Events There have been no BWR-5 (such as NMP2) plants that have completed an EPU uprate. A review of industry transient events that occurred at greater than original power levels was performed. Several BWR-4 events were detailed in the Hope Creek Generating Station Extended Power Uprate submittal (ML081230581).

Additional examples of BWR-3/4/6 plant responses to MSIV closure and load reject/turbine trip events are detailed in the examples below. As indicated, the plants responded as expected in accordance with their design features. No unexpected conditions were experienced nor were any latent defects uncovered in these events beyond the specific failures that actually initiated the events. These events provide further evidence that Large Transient Testing is unnecessary.

Edwin I. Hatch Nuclear Plant - 13% Approved Power Uprate (BWR-4)

LER 2008-003 On July 4, 2008, Hatch Unit 1 was at 99.7% (113% OLTP) rated thermal power and experienced a turbine trip during testing of the Electrohydraulic Control (EHC) system. The resultant Turbine Control Valve fast closure initiated a reactor scram, as designed. Following the reactor scram, reactor pressure peaked at approximately 1,120 psig, resulting in four of the eleven Safety Relief Valves opening as designed to reduce pressure. The feedwater level control system controlled reactor water level with a minimum water level of approximately 2.5 inches above instrument zero (about 160 inches above the top of active fuel). All required safety systems functioned as expected given the water level and pressure transients caused by the turbine and reactor trips. Vessel water level was maintained well above the top of active fuel throughout the transient.

LER 2006-002 On April 5, 2006, Hatch Unit 2 was operating at 100% (113% OLTP) rated thermal power when a power-load unbalance was sensed resulting in a Turbine Control Valve fast closure and subsequent reactor scram. Reactor pressure spiked to approximately 1,125 psig which resulted in eight of the eleven Safety Relief Valves opening to relieve reactor pressure. Vessel water level was maintained well above the top of the active fuel throughout the transient and never decreased to the reactor scram actuation setpoint. Reactor water level was maintained through the use of the reactor feed pumps and manual initiation of the RCIC and High Pressure Coolant Injection (HPCI) systems. There were no automatic safety system actuations on low level.

Brunswick Steam Electric Plant - 20% Approved Power Uprate (BWR-4)

LER 2005-005 On July 13, 2005, Brunswick Unit I scrammed from 100% (120% OLTP) rated thermal power due to the failure of the Main Generator No Load Disconnect Switch (NLDS). The switch failure caused a 9 of 65

ATTACHMENT 7 - EPU TEST PLAN Turbine Trip and Turbine Control Valve fast closure which results in an Reactor Protection System (RPS) system actuation and reactor scram. Four of the Safety Relief Valves opened for one to two seconds in response to the pressure transient. The expected vessel coolant level shrink caused the vessel water level to decrease below the Low Level 1 setpoint, resulting in several containment isolation signals. Minimum water level momentarily satisfied the Low Level 2 actuation logic requirements causing an additional isolation signal and initiation of the HPCI system. The HPCI system did not inject due to water level recovering prior to the injection valve opening. Both plant and operator response to this event was as expected.

Clinton Power Station - 20% Approved Power Uprate (BWR-6)

LER 2002-003 On July 4, 2002, the Clinton Power Station tripped from 95% (114% OLTP) rated thermal power as a result of a faulty main power transformer sudden pressure relay (SPR) actuation. The SPR initiated a generator trip and lockout. The generator trip caused a Turbine Trip and a Turbine Control Valve fast closure, resulting in a reactor scram. The plant responded normally to the scram. As expected, reactor water level initially lowered below the Low Level 3 trip point and was restored in accordance with operating procedures. No safety relief valves lifted during the event.

Dresden Nuclear Power Station - 17% Approved Power Uprate (BWR-3)

LER 2006-004 On July 4, 2006, Dresden Unit 2 experienced a closure of the IA MS1V while operating at 98%

(115% OLTP) rated thermal power. The resulting redistribution of steam across the remaining steam lines caused a high steam flow condition. All MSIVs closed due to a Group I isolation signal and the plant experienced a reactor scram as designed. All systems responded as required. The Isolation Condenser was manually initiated to control reactor pressure.

LER 2004-002 On January 30, 2004, Dresden Unit 3 experienced a turbine trip and automatic reactor scram as a result of low lube oil pressure while operating at 97% (113.5% OLTP) rated thermal power.

Immediately following the scram, the position of the Feedwater regulating Valves (FRVs) increased from 56% open to 63% open. The increase in the position, combined with the post-scram decreasing reactor pressure, caused an increase in total feedwater flow that led to the trip of the 'B' feedwater pump on low suction pressure. Additionally, subsequent FRV response to increasing reactor vessel level was not fast enough to prevent the level from reaching the Reactor Feedwater Pump (RFP) High Level trip setpoint and resulted in tripping of the 'A' and 'C' feedwater pumps. Reactor water level was subsequently restored to normal and the RFPs were restarted. All other system responses were as expected.

Subsequent investigations into the event determined that water had entered the HPCI piping rendering the system inoperable. Dresden Unit 3 has a separate HPCI vessel nozzle located approximately 50 inches below the main steam line nozzles. An evaluation determined that Feedwater Level Control System (FWLCS) would not maintain the post-scram reactor water level below that which would prevent water from entering the HPCI turbine steam line. The root cause was attributed to a FWLCS that had low margin to accommodate changes to the post-scram vessel level response. The condition was not known because a model capable of predicting the dynamic interaction between the FWLCS and other factors was not available. This resulted in a failure to adequately evaluate or test the post-scram response of the FWLCS prior to implementing extended power uprate.

It should be noted that NMP2 does not utilize the same FWLCS as Dresden Unit 3 and does not have any steam nozzles lower than the main steam lines.

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ATTACHMENT 7 - EPU TEST PLAN NMPNS review of this OE determined that feedwater system modifications will influence the reactor water level response post-scram. The feedwater system level control will be modified to address the post-scram level response at EPU conditions. See Table 7-2 EPU Implementation Modifications of this attachment for details.

The scram transient was analyzed and the EPU response with modifications shows a marked improvement to ensure design limits are maintained. The results of the analysis are shown in Figures 7-1 and 7-2. A scram is initiated at the start of the transient. The vessel water level initially drops due to collapse of voids in the core. Once level recovers, the feedwater demand is lowered until feedwater flow approaches to zero. There is no pressurization during the scram; therefore, level recovers more rapidly in the transient as compared to a turbine trip with bypass. The increase in level towards the end of the transient is due to the circulation of saturated water and void generation in the core. The significance of this analysis is the demonstrated difference in the level response from CLTP to EPU and the additional improvement associated with a modified setpoint setdown (SPSD) to the feedwater level control system of both 5 and 10 inches below the existing SPSD setpoint at EPU conditions. The bounding values are conservative as a result of the modeling method used to analyze the event, and over predict the low and high level response. Therefore the resultant change in the water level response is the principal characteristic that substantiates the conclusions of this evaluation.

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ATTACHMENT 7 - EPU TEST PLAN Figure 7-1: NMP2 Level Response to a Scram 180 160 0

10 20 30 40 50 60 70 80 90 100 110 Time (sec)

Figure 7-2: NMP2 Feedwater Flow Response to a Scram 2.00+07 1.80E+07 1.60E+07 1,40E+07 1 20E+07 i 1,00E+07 800.E+06 6.00E+06 4.00E+06 2.00E+06 1.OOE+02 10 20 30 40 50 60 Time (sec) 70 80 90 100 110 12 of 65

ATTACHMENT 7 - EPU TEST PLAN 5.4 NMPNS Large Transient Testing Review and Analysis The following NMP2 tests were reviewed: Feedwater Pump Trip, Loss of Feedwater Heating, Full MSIV Closure, Turbine Trip/Generator Load Rejection, Recirculation Pump Trip(s), Relief Valve Testing, and RCIC Functional testing. The section compares original start up test data, actual past plant events (if available) and the EPU analysis performed to justify eliminating large transient testing for the EPU.

Feedwater Pump Trip Startup Test Objectives The objective of the Feedwater Pump Trip Test was to demonstrate the capability of the automatic core flow runback feature to prevent a low water level scram following the trip of one feedwater pump. The Acceptance Criteria and test methodology are detailed in USAR Table 14.2-224.

Startup Test Results The 'A' feedwater pump was tripped with reactor power at 99% (OLTP). The Feedwater Control System maintained a margin of 12.7 inches to level 3, well above the Level 2 Acceptance Criteria of greater than a 3 inch margin. The Recirculation Runback feature was actuated 7 seconds into the transient as level dropped below level 4 (approximately 5 inches below normal level).

The Recirculation Flow Control Valves closed from 82% to 15% which reduced reactor power to 60%

(OLTP), within the capacity of the remaining feedwater pump.

All Acceptance Criteria for this test were satisfied.

Operating Experience Since Startup On September 25, 2004, NMP2 experienced a trip of the 'C' feedwater pump from 81.3% (CLTP) power due to a motor electrical fault. As a result of the event, a reactor recirculation system flow control valve runback occurred as designed. Reactor power immediately lowered to 47.2% and then returned to 63.7% following the transient and a reactor scram on low level was avoided.

On December 2, 2001, NMP2 experienced a trip of the 'A' feedwater pump from 89% (CLTP) power due to a motor electrical fault. During the event, a reactor recirculation runback signal was received but only the 'A' flow control valve ran back as designed. The hydraulic power unit for the 'B' flow control valve was powered from the same supply bus as the 'A' feedwater pump and the resultant electrical transient caused the operating hydraulic power unit pump to trip and did not, allow the automatic start of the standby pump as designed. With no hydraulic power unit in operation, the 'B flow control valve "locked up" at 50% open, as designed. Without the ability of the 'B' valve to runback, the reactor was manually scrammed in response to an imminent low vessel level scram.

On January 16, 1995, NMP2 experienced a trip of the 'B' feedwater pump from 100% (OLTP) power due to a motor electrical fault. The event caused a reactor recirculation flow control valve runback, as designed, which reduced reactor power to 69%. After the plant stabilized, four control rods were inserted to further lower power to within the capacity of the remaining feedwater pump, thereby avoiding a reactor scram on low level.

EPU Transient Analysis Results/EPU Margins NMPNS plans to implement the following modifications in order to minimize the possibility of a low level scram upon loss of a single feedwater pump:

Initiation of a recirculation flow control valve runback immediately upon a feedwater pump trip. Current logic requires level to reach the Level 4 setpoint before a runback is initiated.

Increasing the recirculation flow control valve runback rate from the current 6-8% per second to 9% per second.

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ATTACHMENT 7 - EPU TEST PLAN A Single Feedwater Pump Trip (SFWPT) analysis was performed as an operational assessment to determine the ability to avoid a scram on low level. The analysis was performed as three separate cases using a variation in the feedwater flow following a pump trip in order to evaluate the impact on scram avoidance.

The transient is considered to have adequate margin to scram avoidance if the margin is at least three inches to the scram setpoint. For the three cases analyzed, margins above the level to scram were as follows: Case 1 was 2.5 inches; Case 2 was 3.2 inches; and Case 3 was 5.4 inches (see Figures 7-3, 7-4 and 7-5). The results show that Case 2, the most representative of the plant performance, and Case 3 provide adequate margin for scram avoidance. Case 1 exceeded the acceptance criteria, though the low level scram set point was avoided. Although all three cases did not demonstrate adequate margin to scram avoidance, it was concluded that, due to the planned installation of the recirculation runback modification, the margin to scram avoidance was consistent with the current margin. Even though this analysis concluded that the likelihood of scram is not increased, it was determined that this initiating event should be added to the PRA and used to perform sensitivity analyses on this initiating event. Accordingly, this initiating event was first added to the model to provide a baseline for estimating the increase in risk associated with a potential increased probability of reactor scram given that a single feedwater pump fails during normal power operation.

This analysis is discussed in PUSAR Section 2.13.1 and concludes that the additional risk in the PRA is small.

EPU Power Ascension Testing Planned power ascension testing of the feedwater control system and runback logic is described in Tables 7-2 and 7-3. Feedwater control system responses to reactor water level setpoint changes (for level setpoint change tests) are evaluated in various control modes (single element and three element).

Post Modification Testing for the proposed modification to the reactor recirculation runback circuit, as well as feedwater pump performance testing, will provide reasonable assurance in demonstrating the improved reliability of the Feedwater System for loss of feedwater events. However, power ascension testing of a feedwater pump trip is not planned because scram avoidance verification on low reactor water level is not a regulatory requirement. Actual feedwater pump trip tests to validate the modeling uncertainty are not justified because of the risk of a plant scram and the challenge to the Operations staff.

Conclusion Based on plant historical data and EPU analytical results, the capability of the recirculation system to prevent a low water level scram following the trip of a feedwater pump is preserved. Because scram avoidance is not a regulatory requirement, additional plant testing to demonstrate that a feedwater pump trip does not result in a reactor scram is not warranted. NMPNS, however, will modify the Recirculation Runback logic to minimize the chances of a reactor scram following the loss of a single feedwater pump.

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ATTACHMENT 7 - EPU TEST PLAN Figure 7-3: Single Feedwater Pump Trip Case 1: One second reduction to 55% Feedwater Flow Following Pump Trip S

• 1 0

10 20 30 40 50 60 70 80 Time (sec) 0 10 20 30 40 50 60 70 80 Time (sec) 120 100 60 40

[L 20 si 0

00 0

10 20 30 40 Time (sec) 50 60 70 80 0

10 20 30 40 50 60 70 0

Time (sec) 15 of 65

ATTACHMENT 7 - EPU TEST PLAN Figure 7-4: Single Feedwater Pump Trip Case 2: One second reduction to 58.6% Feedwater Flow Following Pump Trip a,.

0 10 20 30 40 50 60 70 80 0

10 20 30 40 Time (sec)

Time (sec)

-e-- Dome Pressure (psia)/10 Drive Flow (%)

100 "*

I 80 U.

60 40 b

40 2!

CL 20 10 20 30 40 Time (sec) 50 60 70 80 0

10 20 30 40 Time (sec) 50 60 70 80 16 of 65

ATTACHMENT 7 - EPU TEST PLAN Figure 7-5: Single Feedwater Pump Trip Case 3: One second reduction to 65% Feedwater Flow Following Pump Trip 60 t

£ S0.

U C

0.

S

-j 0

10 20 30 40 50 60 70 s0 Time (sac) 0 10 20 30 40 50 60 70 80 Time (sec) 120 100 i 80 60 40 20 o00

' 0 80 10 2 60 40 20

-e-Dome Pressure (psia)/1O

--- Drive Flow (%)

0 10 20 30 40 50 60 70 0

Time (sec) 0 10 20 30 40 so 60 70 s0 Time (sec) 17 of 65

ATTACHMENT 7 - EPU TEST PLAN Loss of Feedwater Heating Startup Test Objectives The objective of the Loss of Feedwater Heating Test was to demonstrate adequate plant response to a reduction in feedwater temperature caused by the single failure that will result in the largest loss in feedwater heating.

The Acceptance Criteria and test methodology are detailed in USAR Table 14.2-223.

Startup Test Results' The single failure scenario which would result in the largest drop in feedwater temperature was determined to be the opening of the low pressure feedwater heater string bypass valve, 2CNM-AOV101. The valve was opened at 72.3% reactor power OLTP. Final feedwater temperature was 3541F, or a total average drop of 401F, well within the Level 1 acceptance criteria of< 100°F.

The Level 1 acceptance criteria required that the peak heat flux during the transient be less than 76.6%. The actual heat flux value (76.4%) did not exceed the Level 1 value.

The Minimum Critical Power Ratio (MCPR) value decreased from 2.051 to 1.924 which was well above the Level 1 criteria of 1.06.

All Acceptance Criteria for this test were satisfied.

Operating Experience Since Startup Reduction in Feedwater Temperature events periodically occur at NMP2, causing entry into Special Operating Procedures for unplanned power changes. Power is reduced and plant conditions stabilized prior to recovery of the affected heaters.

Although most of these events are not true Loss of Feedwater Heating events as defined by the USAR, they demonstrate that there have been no significant safety consequences associated with these events and there have been no violations of cladding integrity limits or other fuel design limits.

EPU Transient Analysis Results/EPU Margins The worst case Loss of Feedwater Heating (LFWH) event for NMP2 continues to be the opening of the feedwater heater string bypass valve, 2CNM-AOV101. An analysis was performed to evaluate this transient at EPU conditions. The predicted reduction in feedwater temperature for EPU was performed and the results showed the predicted value remains below the original acceptance criteria of 100'F.

A LFWH transient analysis is also performed with each reload analysis to determine if LFWH will become a limiting transient event.

EPU Power Ascension Testing Planned EPU power ascension testing of the feedwater control system is detailed in Table 7-3, Test

23.

Feedwater control system responses to reactor water level setpoint changes are evaluated in various control modes. EPU power ascension testing does not anticipate tripping feedwater heaters, because this type of event is relatively common and typically results in mild transients that are well within the capability of the plant systems to handle.

Conclusion Testing the loss of feedwater heating is not required because the original acceptance criterion of

_< 1000 F continues to be met under EPU conditions. Reduction in feedwater temperature events occur from time to time and are relatively minor transients. Operators are trained on feedwater heater 18 of 65

ATTACHMENT 7 - EPU TEST PLAN events using the plant simulator and EPU will not significantly impact the required plant response.

Consequently, it is not necessary to test feedwater heater losses as part of EPU power ascension.

MSIV Closure Event Startup Test Objectives The objective of the Full MSIV Closure Test is to determine the reactor transient behavior that results from the simultaneous full closure of all MSIVs. The Acceptance Criteria and test methodology are detailed in USAR Table 14.2-228.

Startup Test Results A full MSIV Isolation was performed with reactor power at 95.3% OLTP and reactor pressure at 995 psig. The closure of the MSIVs resulted in a reactor scram. The average stroke time of the fastest valve in each line was 3.69 seconds. Reactor water level initially lowered to 126 inches, resulting in a Recirculation Pump transfer to slow speed using the Low Frequency Motor Generator sets (LFMG) as designed. Two, Group 1 Safety Relief Valves (SRVs) with a setpoint of 1070 psig lifted. A peak reactor pressure of 1086 psig was reached in 9.4 seconds after the initiation. The peak upset range level observed was 223 inches, which is well below the level of the Main Steam lines (250 inches).

All Acceptance Criteria for this test were satisfied.

Operating Experience Since Startup On October 15, 2001, while operating at approximately 104% OLTP (100% CLTP) power, NMP2 experienced a scram when all MS1Vs went closed. The event was the result of human performance error while restoring a steam flow transmitter to service causing the high steam flow instrumentation to actuate.

On November 11, 2002 while operating at approximately 104% OLTP (100% CLTP) power, NMP2 experienced a scram when all MS1Vs went closed. The event was the result of an MSIV disc separating from the valve stem, causing a rapid flow reduction in one of the main steam lines.

The review of the plant response compared to the USAR Section 15.2.4 transient analysis for both of these events confirms that they are bounded by the USAR analysis as evidenced by the following:

Actual neutron flux was less than predicted.

Actual peak pressure was less than predicted.

Only Group 1 SRVs lifted (analysis predicts all 5 groups lift).

The first event was classified as a full MS1V closure resulting in a Reactor Protection System Scram on MS1V position.

The second event more closely followed the single MSIV closure classification resulting in a Reactor Protection System Scram on high reactor pressure.

In both events reactor water level was controlled manually. The initial level response was comparable to that predicted in the USAR analysis.

Within minutes of event initiation, reactor water high level trips are expected because SRV pressure control swells Reactor Pressure Vessel (RPV) level to above the Level 8 trip set point. RCIC is the preferred level control method for this event.

In both events the Recirculation Pump transferred to the LFMG as designed.

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ATTACHMENT 7 - EPU TEST PLAN EPU Transient Analysis Results/EPU Margins The limiting overpressure protection event for NMP2 is the Main Steam Isolation Valve Closure with Scram on High Flux (MS1VF). The overpressure analysis description and methodology are described in ELTRI. The analysis assumes event initiation with a peak reactor dome pressure of 1050 psia, two SRVs out of service and RTP at 102% of EPU RTP. The calculated peak reactor pressure vessel pressure is 1316 psig and the corresponding calculated maximum reactor dome pressure is 1286 psig.

The peak pressure vessel dome pressure remains below the American Society of Mechanical Engineers (ASME) limit of 1375 psig and the peak dome pressure remains below the Technical Specification 1325 psig Safety Limit. The results of the EPU overpressure protection analysis for the NMP2 MSIVF event are consistent with the generic analysis in ELTR2.

The margin to the dome pressure safety limit and the reactor coolant system pressure safety limit has each been reduced by 15 psig from the CLTP values. However, there is still adequate margin to accommodate cycle-specific variations.

The NMP2 response to the MSIVF event is provided in Section 2.8.4.2 and Figure 2.8-1 of the PUSAR. The reactor water level response evaluation, discussed below predicts a pressure response change of-15 psig as well.

The reactor water level response is predicted to remain below 250" which is the level of the Main Steam Lines.

The MSIV Closure Event (MSIVD) was analyzed and the EPU response with modifications shows an improvement to ensure design limits are maintained. The MS1V Closure Event transient is illustrated in Figure 7-6 and 7-7. The MSIV closure is initiated at the start of the transient, resulting in a scram on valve position. The pressurization in the event causes void collapse and vessel water level decrease. The initial drop in level provides a demand in feedwater until normal water level is achieved. The final increase in level towards the end of the transient is due to void generation in the core. The significance of this analysis is the demonstrated difference in the level response from CLTP to EPU and the additional improvement associated with a modified setpoint setdown (SPSD) to the feedwater level control system of both 5 and 10 inches below the existing SPSD setpoint at EPU conditions. The bounding values are conservative as a result of the modeling method used to analyze the event, and over predict the low and high level response. Therefore the resultant change in the water level response is the principal characteristic that substantiates the conclusions of this evaluation.

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ATTACHMENT 7 - EPU TEST PLAN Figure 7-6: NMP2 Level Response to MSIVD 240 220 200 S180

> 160 140 120 100 0

10 20 30 40 50 60 70 80 Time (sec)

Figure 7-7: NMP2 Feedwater Flow Response to MSIVD 2.OOE+07 1.80E+07 1.60E+07 1.40E+07 1.20E+07 i

1.00E+07 8.00E+06 6OOE+06 4.OOE+06 4.OOE+06 2.00E+06 1.00E+02 0

10 20 30 40 Time (sec) 50 60 70 80 21 of 65

ATTACHMENT 7 - EPU TEST PLAN EPU Power Ascension Testing MS1V full closure testing at 100% rated power during EPU power ascension testing is not required at NMP2 because the plant response at EPU conditions is expected to be similar to the documented response during initial startup testing and during plant operation. The transient analysis performed for the NMP2 EPU demonstrates that all safety criteria are met and for EPU the MSIVF event is limiting.

Deliberately closing all MSIVs from 120% OLTP power will result in an undesirable transient cycle on the primary system that can reduce equipment service life. As demonstrated during initial startup testing and confirmed by analysis, all equipment responses to the transient are within component and system design capabilities.

However, placing accident mitigation equipment into service, under maximum loading conditions, uses available service life. Equipment service life should be retained for actual events rather than for demonstration purposes.

Additional transient testing and the resulting impact will provide no additional plant response information beyond that documented during startup testing and from the evaluation of actual plant events. These events demonstrate the analysis is conservative and actual events will not challenge safety or design limits for this event.

For EPU, the reactor pressure remains constant and the SRV set points do not change so there will be an increase in the observed peak pressure due to the increased steam flow, similar to what is predicted by the current USAR analysis, though less in magnitude.

The modifications to the feedwater system will not have an impact on this event because operational level control strategies and pressure control strategies result in a Level 8 condition which causes the feed water pumps to trip under CLTP conditions and EPU conditions due to SRV cycling. RCIC will be used to control water level and level will not approach the elevation of the main steam lines.

The modification to the main turbine and the reduction in bypass capability has no impact because the turbine and the bypass system are isolated for this event.

Conclusion Based on plant historical data and EPU analytical results, the MSIV Closure Event results in conditions that are within design limits.

In addition, no new design functions in safety related systems are required that would need large transient testing validation for EPU.

No physical modification or setpoint changes are made to the SRVs. No new systems or features are installed for mitigation of rapid pressurization events analyzed for EPU. The increase in steam flow and its impact is not significant with regard to the reactor pressure transient response. The changes to the feedwater system do not adversely change the feedwater level control response and the use of RCIC as the preferred level control system for this event.

In view of the above, the objective of determining reactor transient behavior resulting from the simultaneous full closure of all MS1Vs can be satisfied for EPU without large transient testing through analysis. In addition, limiting transient analyses are included as part of the cycle specific reload licensing analysis. The need for re-performing this test at EPU conditions is not required because plant response is not expected to significantly change from that previously documented at CLTP conditions.

Plant performance and analysis show adequate margin is available in vessel pressure and level limits that demonstrate acceptable reactor transient behavior. Therefore, this test is not warranted.

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ATTACHMENT 7 - EPU TEST PLAN Turbine Trip/Generator Load Rejection Startup Test Objectives The objective of the Turbine Trip and Generator Load Rejection test was to: 1) demonstrate the response of the reactor and its control systems to protective trips in the turbine and generator and 2) demonstrate the capacity of the turbine bypass valves. The Acceptance Criteria and test methodology are detailed in USAR Table 14.2-231.

Startup Test Results The generator load rejection was performed with the reactor operating at 99.6% of rated power by simulating a 345 KV line high differential voltage/current fault. The turbine-generator power load unbalance (PLU) logic sensed the load reject and initiated fast control valve closure. The bypass valve control system actuated to rapidly open the bypass valves. The simulated electrical fault also initiated a turbine trip which caused fast turbine stop valve closure. A reactor scram was initiated by the control valve fast closure and the recirculation pumps transferred to the LFMG as designed.

The following Level 1 and Level 2 Test Exceptions resulting-from the test performance were evaluated and subsequently accepted:

I. A verification of the feedwater control settings to prevent flooding of the main steam lines (Level 1) was not possible due to a trip of the feedwater pumps during the residual transfer of house electrical loads following the transient. The fast transfer of station auxiliary loads did not occur as expected because the initiating fault blocked the fast transfer and allowed a residual transfer, thereby shedding loads, including the feedwater pumps and condensate booster pumps. A modification was subsequently implemented to remove the fast transfer blocking signal. The test results were accepted based on Feedwater System performance demonstrated in previous testing.

2. The two recirculation pump drive flow coastdown transient, following the End of Cycle-Recirculation Pump Trip (EOC-RPT) actuation was not bounded by the limiting Level 1 criteria curves. The measured coastdown curves slightly exceeded the upper limiting curve during the first 1.25 seconds of the transient. A GE re-evaluation determined that the flow coastdown characteristics did meet the Level 1 acceptance criteria. No adjustments to the Technical Specification MCPR limits were required.

3. As a further result of the feedwater pump trip during the residual transfer of house loads, a low water level recirculation pump trip occurred and the RCIC and High Pressure Core Spray (HPCS) systems initiated, contrary to Level 2 criteria. An additional Level 2 criterion to verify that feedwater level controls avoid the loss of feedwater due to a high level (L8) trip could also not be performed. The results of both were accepted.by GE as-is due to the unexpected residual transfer of house loads.

All other Acceptance Criteria for this test were satisfied.

Operating Experience Since Startup Since initial startup, a number of turbine trip or generator load reject events from full power have occurred at NMP2, including the following examples:

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ATTACHMENT 7 - EPU TEST PLAN Table 5 Operating Experience LER Event Date Power Level Event Description No.

1 8/14/03 104% OLTP Generator load reject caused by large grid 03-002 100% CLTP disturbance in the northeast United States 104% OLTP Fast closure of turbine stop and control valves 2

4/24/99 100% CUP resulting from a generator lockout relay actuating 99-005 due to a failed volts/hertz relay Fast closure of turbine stop and control valves 3

3/12/94 100% OLTP caused by a faulty test switch in the power/load 94-001 unbalance trip circuit associated with the main turbine Electrohydraulic Control (EHC) system.

Event 1 (104% OLTP)

A review of the most recent (August 14, 2003) load rejection event determined that the scram was initiated by a Turbine Control Valve Fast Closure signal associated with the RPS logic. The Turbine Control Valve Fast Closure was caused by a large grid disturbance and subsequent generator load rejection. All control rods fully inserted following the scram as designed.

Immediately after the reactor scram, reactor pressure reached a high of 1040 psig. The turbine bypass valves were used initially to automatically control RPV pressure. During this event the SRVs did not open.

Reactor water level initially lowered to 157 inches due to the pressure and level transient (shrink) immediately following the scram. A Level 3 (159.3 inches) scram signal was received as expected due to the RPV level shrink. Reactor vessel water level then rose rapidly due to the feedwater level control valves locking at 55% open due to the electrical power transient. One feedwater pump was manually tripped in anticipation of a Level 8 trip signal while the second pump was left running as RCIC start preparations were made. The second pump subsequently tripped automatically on level

8. Reactor water level was then controlled using the RCIC system. The highest reactor water level observed during the event was 203 inches, approximately 1 inch above the Level 8 (202.3 inches) trip.

The reactor recirculation pumps tripped to zero speed in lieu of the expected transfer to slow speed upon initiation of the EOC-RPT logic. The apparent cause was due to relays failing to actuate due to the short (53 millisecond) duration of the event.

Event 2 (104% OLTP)

A review of Event 2, which characterizes more closely the analyzed load rejection event, determined that the scram was initiated by a Turbine Control Valve Fast Closure signal associated with the RPS logic. The Turbine Control Valve Fast Closure was caused by a generator lockout trip due to a failed volts/hertz relay.

All control rods fully inserted following the scram as designed.

Immediately after the reactor scram, reactor pressure reached a high of 1088 psig. The turbine bypass valves were used initially to automatically control RPV pressure. During this event the SRVs did not open.

Reactor water level lowered to 105 inches, below the Level 2 setpoint of 108.8 inches, during the level transient immediately following the scram. A Level 3 (159.3 inches) scram signal was received as expected during the RPV level reduction. Reactor vessel water level lowered as a result of the feedwater pumps tripping due to the electrical power transient. The HPCS automatically initiated 24 of 65

ATTACHMENT 7 - EPU TEST PLAN and restored level. RCIC received an initiation signal but the system was manually tripped due to equipment problems. The operators restarted a feedwater pump and controlled reactor water level post scram using the feedwater system. The highest reactor water level observed during the event was 202 inches, which is just below the Level 8 (202.3 inches) trip.

As designed, the reactor recirculation pumps initially transferred to slow speed due to initiation of the EOC-RPT logic and subsequently tripped to zero speed as a result of the Level 2 initiation logic.

Event 3 (100% OLTP)

A review of Event 3, which is a load rejection event at the original 100% thermal power level, determined that the scram was initiated by a Turbine Control Valve Fast Closure signal associated with the RPS logic. The Turbine Control Valve Fast Closure was caused by a faulty test switch in the power/load unbalance trip circuit associated with the main turbine EHC system.

All control rods fully inserted following the scram as designed.

Immediately after the reactor scram, reactor pressure reached a high of 1090 PSIG. The turbine bypass valves were used initially to automatically control RPV pressure. During this event, six of the SRVs opened. Note that the stretch uprate modification to 104% OLTP has subsequently increased the SRV relief mode lift set points an additional 27 psig.

Reactor water level lowered to 130 inches during the level transient immediately following the scram. A Level 3 (159.3 inches) scram signal was received as expected due to the RPV level reduction. Reactor vessel water level was restored and controlled post scram using the feedwater system. The highest reactor water level observed during the' event was 198 inches, approximately 4 inches below the Level 8 (202.3 inches) trip.

The reactor recirculation pumps transferred to slow speed upon initiation of the EOC-RPT logic.

These events were determined to be bounded by the transient event analysis (Generator Load Rejection with Bypass) as described in USAR Section 15.2.2.

EPU Transient Analysis Results/EPU Margins Two potentially limiting overpressure protection events are typically analyzed for EPU: 1)- Main Steam Isolation Valve Closure with Scram on High Flux (MSIVF) and 2) Turbine Trip (TT) with Bypass Failure and Scram on High Flux (ELTRI, Section 5.5.1.4). However, based on both plant initial core analyses and subsequent power uprate evaluations, the MSIVF is more limiting than the Turbine Trip event with respect to reactor overpressure. The EPU evaluations show a 24 to 40 psi difference between these two events. Only the MSIVF analysis was performed because it is limiting.

In addition, an evaluation of the MSIVF event is performed with each reload analysis. The MSIVF transient analysis has previously been discussed with the MSIV closure event above.

The margin to the dome pressure safety limit and the reactor coolant system pressure safety limit has each been reduced by 15 psig from the CLTP values. Due to this reduction in margin, the analysis predicts that the Group 1 (1,103 psig) and potentially the Group 2 (1,113 psig) SRVs Will open in the relief mode during a Turbine Trip and Generator Load Rejection Event. This would be consistent with the original thermal power limit observations. There is still adequate margin to accommodate cycle specific variations.

The reactor water level response evaluation for turbine trip with bypass(TTWBP), discussed below predicts a pressure response change of -15 psig as well and consistent with the response predicted by the conservative accident analysis discussed above.

The TTWBP Event was analyzed and the EPU response with modifications shows an improvement to ensure design limits are maintained. The TTWBP transient is illustrated in Figures 7-8 and 7-9. The 25 of 65

ATTACHMENT 7 - EPU TEST PLAN event begins with a turbine stop valve closure resulting in a scram and RPT.

The initial pressurization from the turbine stop valve closure causes a rapid drop in level providing a level mismatch signal to the feedwater control system to increase feedwater flow. The second drop in level is due to the turbine bypass valves closing and subsequent pressurization. Vessel level once again rises up to the programmed setpoint and overshoots due to the time delay associated with the FW control system and void generation in the core. The significance of this analysis is the demonstrated difference in the level response from CLTP to EPU and the additional improvement associated with a modified setpoint setdown (SPSD) to the feedwater level control system of both 5 and 10 inches below the existing SPSD setpoint at EPU conditions. The bounding values are conservative as a result of the modeling method used to analyze the event, and over predict the low and high level response. Therefore the resultant change in the water level response is the principal characteristic that substantiates the conclusions of this evaluation.

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ATTACHMENT 7 - EPU TEST PLAN Figure 7-8: NMP2 Level Response to TTWBP 200 190 180 170 a

160 C

150 140 130 120 0

10 20 30 40 50 60 70 80 Time (sec)

Figure 7-9: NMP2 Feedwater Flow Response to TTWBP U

0 10 20 30 40 50 60 70 80 Time (sec) 27 of 65

ATTACHMENT 7 - EPU TEST PLAN EPU Power Ascension Testing Turbine trip/generator load rejection events from approximately 100% core power CLTP during EPU power ascension testing is not required for NMP2. The plant response at EPU conditions is expected to be similar to those documented in the initial startup testing program and those experienced during the plant's operational period. The transient analysis performed for the NMP2 EPU demonstrates that all safety criteria are met and that EPU does not cause this event to become limiting. Deliberately causing a load reject and subsequent scram from 100% power will result in an. undesirable transient cycle on the primary system that can cause undesirable effects on equipment and grid stability. The transient loading provides no benefit to safety equipment. Additional turbine trip/load reject testing would result in plant response that has been previously observed and the test would not provide new insight into SSCs performance.

For EPU, reactor pressure remains constant and the SRV set points do not change. The steam flow is increased for EPU and there are no changes to the steam bypass capability. As a result of these changes an increase in peak reactor pressure will occur. Because of this change, the EPU analysis predicts that the Group 1 (1,103 psig) and the Group 2 (1,113 psig) SRVs will lift in the relief mode during a Turbine Trip and Generator Load Rejection Event. Opening Group 1 and 2 SRVs is consistent with the original thermal power limit observations for this event.

The modifications to the feedwater system have been evaluated for this event. Operational level control strategies as well as design requirements ensure that a Level 8 trip is avoided.

This is consistent with the original startup and test Level 2 (SUT-27) acceptance criteria. Feedwater level control response testing will ensure that level control valve response is consistent with the original start up and test requirements. Compliance with these requirements will ensure the Level 8 trip will be avoided. The feedwater control system response testing outlined in Table 7-1, Startup Testing Comparison, and Table 7-3, Planned EPU Power Ascension Testing, will verify the required system response to address the EPU modification and system changes.

Conclusion The operating history of NMP2 demonstrates that previous turbine trip/load reject transient events from full power (OLTP) are within expected peak limiting values. Based on past transient testing, past analyses and the evaluation of test or actual event results, the effects of a trip from EPU RTP can be analytically determined. No new design functions that would necessitate modifications and large transient testing validation are required of safety related systems for the EPU.

No physical modification or setpoint changes were made to the SRVs. No new systems or features are installed for mitigation of rapid pressurization anticipated operational occurrences for EPU. The increase in steam flow and its impact on bypass capacity is not significant with regard to the reactor pressure transient response. The changes to the feedwater system do not adversely change the feedwater level control response and are predicted to improve the response.

In view of the above, transient mitigation capability is demonstrated by post modification testing and Technical Specification required testing. In addition, the limiting transient analyses are included as part of the cycle specific reload licensing analysis. From a safety-significance standpoint, turbine trip/load reject testing cannot be justified in that the transient cycle on the primary plant is undesirable and the potential benefits from such a cycle are not safety-significant. The response of the reactor and its control systems following trips of the turbine and generator has been demonstrated by numerous plant events and shown by EPU analysis to be acceptable. Therefore, this test is satisfied without requiring actual plant transient testing. Therefore this test is not warranted.

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ATTACHMENT 7 - EPU TEST PLAN Recirculation Pump Trip Startup Test Objectives The objective of the Recirculation Pump Trip Test is to 1) obtain Recirculation System performance data during a recirculation pump trip, flow coastdown and pump restart transients, 2) verify that the feedwater control system can satisfactorily control water level without a resulting turbine trip/scram,

3) record and verify acceptable performance of the recirculation two-pump circuit trip system, 4) record recirculation system parameters during the power test program, 5) verify the accuracy of the recirculation runback to prevent a scram on loss of one feedwater pump with a reactor vessel level decrease to level four, and 6) verify that no recirculation system cavitation occurs in the operable region of the power-flow map. The Acceptance Criteria and test methodology are detailed in USAR Tables 14.2-235 through 14.2-239.

Startup Test Results The 'A' recirculation pump was tripped from 73.3% reactor power OLTP and the 'B' pump was tripped from 98.2% power by placing the respective pump motor breaker control switch in "Pull-to-Lock." The margins to scram measured during the pump trips and pump restart are as shown in the following table:

Table 5 Recirculation Pum Trip Test Results Simulated Heat Simulated Heat Flux Margin to High APRM Margin to Flux Margin to Margin to Trip on Pump Water Level Trip Scram on Restart Trip on Pump Trip Pump Restart (Criteria >3 Inches)

(Criteria > 7.5%)

(Criteria > 5%)

(Criteria > 5%)

'A' 10.9 Inches 41.6%

30%

16.3%

'B' 13.3 Inches 39.01%

14.66%

15.24%

The two pump trip was initially performed from 66.4% reactor power OLTP by means of a temporarily installed test switch. When the test switch was closed, both pumps switched to off. A recirculation pump trip normally transfers the recirculation pumps to slow speed but an error in the test procedure placed the switch such that the trip logic was activated but not the high to low speed transfer logic. A GE analysis was unable to accept the results and after adjustments were made to flow transmitter dampening circuits, the test was re-performed during the Generator load rejection Test (SUT-27) and the two pump trip coastdown was deemed acceptable.

A recirculation system flow control valve runback was initiated from 59.6% power OLTP. Analysis from this test verified that the recirculation drive flows in both loops runback to _< 45% of rated drive flow.

Testing was also performed to verify that logic settings were adequate to prevent operation in areas of potential cavitation by tripping the Steam-Dome-Recirculation Suction Temperature Differential Temperature and Total Feedwater Low Flow interlocks.

All Acceptance Criteria for this test were satisfied with the exception that the 'B' pump wide range level indication failed the Level 2 criteria for margin to high level trip. The issue was accepted based on the narrow range level instrumentation, which provides the level 8 trip, meeting the acceptance criteria.

EPU Transient Analysis Results/EPU Margins Recirculation pump trip events were not analyzed because they have been dispositioned as non-limiting events. In addition, as part of EPU, the recirculation flow rate to provide 100% core flow is only slightly increased.

The increase is approximately 1.9% of the CLTP recirculation rate. No 29 of 65

ATTACHMENT 7 - EPU TEST PLAN changes are proposed to the recirculation two pump circuit trip systems. The power - flow operating region is extended higher in power however these changes will not challenge pump cavitiation limits.

Past test results and administrative control have established the operational boundaries to prevent recirculation pump cavitation. No changes to these limits and boundaries are changed by EPU.

Therefore, recirculation pump testing is not necessary.

EPU Power Ascension Testing The results from startup testing and from events that have occurred during plant operations indicate recirculation pump testing is not necessary. Original startup testing verified that adequate margins exist to RPS setpoints and that the feedwater system has the capability to prevent high water level trips. The feedwater control system will be tested as part of the startup and test program. The recirculation runback logic will be tested under post modification test plans and integrated into the startup and test program for EPU.

Conclusion Recirculation pump trip events were not analyzed and are non-limiting events. Based on plant historical data and EPU analytical results the recirculation system performance with respect to pump trip is not significantly changed. EPU will not significantly impact the plant response and thus this test is not necessary to perform.

Relief Valve Testing Startup Test Objectives The objectives of the Relief Valve Test is to 1) verify that the relief valves function properly (can be opened and closed manually), 2) verify that the relief valves reseat properly after operation, 3) verify that there are no major blockages in the relief valve discharge piping and 4) functionally check the operation of the valves from the Remote Shutdown Panel.

The Acceptance Criteria and test methodology are detailed in USAR Table 14.2-230.

Startup Test Results The SRVs were tested with reactor power at 17.6% of rated OLTP and a steam dome pressure of 952 psig. The main turbine was secured and steam was routed to the condenser via the turbine bypass valves. All 18 SRVs were individually cycled open and closed with positive indication of relief valve discharge provided by changes in the Acoustic Monitoring System indicating lights, tail pipe temperatures, turbine bypass valve position and main steam line total flow.

One valve's acoustic monitor lights did not indicate closed following valve closure, contrary to Level 1 criteria. After investigation, the valve's acoustic monitor gain was reset to a lower value and the valve was successfully retested. The tail pipe temperatures of two valves did not return to within 10 degrees of their initial values, a Level 2 criterion. After reactor pressure was reduced slightly, the valve's temperatures returned to their initial temperatures.

All Acceptance Criteria for this test were satisfied.

Operating Experience Since Startup Relief valves are inspected and tested in accordance with Technical Specification requirements. In addition, SRVs have operated satisfactorily during various unplanned events since startup.

EPU Transient Analysis Results/EPU Margins Relief valve operations were not analyzed. Inadvertent relief valve openings have been determined to be non-limiting events.

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ATTACHMENT 7 - EPU TEST PLAN EPU Power Ascension Testing Relief valves will continue to be tested in accordance with Technical Specifications. Because relief valve setpoints are not changed and relief valve operations are not impacted by EPU, there is no need for any additional testing beyond the testing already required by Technical Specifications.

Conclusion Technical Specification testing demonstrates that relief valves function properly.

Plant pressure control system stability has been consistently demonstrated during relief valve operation showing no blockages existed in relief valve discharge piping. Because relief valve setpoints are not changed and relief valve operations are not impacted by EPU, there is no need for any additional testing beyond the testing already required by Technical Specifications. Further in-plant testing of relief valves as a result of EPU is not necessary.

RCIC Functional Testing Startup Test Objectives The objective of the RCIC Functional Test is to 1) verify the proper operation of the RCIC system over its expected operating pressure and flow ranges and 2) demonstrate reliability in automatic starting from cold standby when the reactor is at power conditions. The Acceptance Criteria and test methodology are detailed in USAR Table 14.2-213.

Startup Test Results A total of 8 automatic initiation tests were conducted in 4 different test configurations to prove RCIC system performance. The reliability of the RCIC system was well demonstrated by neither tripping nor isolating during any of the manual or automatic tests.

Rated pump discharge flow was achieved within 30 seconds for all RCIC automatic initiations at reactor pressure between 150 psig and 953 psig with one exception. When performing a cold auto start test with injection into the Condensate Storage Tank (CST) at 153 psig reactor pressure, the time to rated flow was 38.6 seconds.

This did not meet Level 1 acceptance criteria. This result was accepted as the excess time was attributed to the combination of high fluid resistance provided by the CST test return flow path, the low reactor pressure and the additional time required to pressurize the steam line between the steam admission valve and the turbine during a cold start. An earlier cold auto start at 161 psig with injection to the RPV achieved rated flow in 28.9 seconds.

Several Level 2 test exceptions were resolved by completion of a work request to repair steam leaks, modification to the General Electric Transient Analysis Recording System signal conditioning, and an FSAR change related to pump discharge pressure. One other test exception related to speed greater than the Level 2 requirement was accepted due to a mispositioned CST throttle return valve.

Operating Experience Since Startup During operational events, RCIC has provided acceptable performance when required to function as a result of operational events.

EPU Transient Analysis Results/EPU Margins The RCIC system evaluation for NMP2 EPU addressed system performance and hardware, net positive suction head, core cooling for limiting loss of feedwater events and inventory makeup to maintain reactor water level above top of active fuel (TAF) inside the shroud and to maintain reactor water level above the Emergency Core Cooling System (ECCS) initiation signal Level 1 in the downcomer. All system performance and hardware attributes were found acceptable, as detailed in 31 of 65

ATTACHMENT 7 - EPU TEST PLAN Section 2.8.4.3 of the PUSAR. The RCIC system does not change for EPU. Pressures, flow rates and response times are not significantly changed.

EPU Power Ascension Testing RCIC testing during EPU power ascension is not required because the EPU changes do not have a significant impact on the RCIC system. Specifically, system pressures, temperatures and flow rates remain unchanged from CLTP requirements.

RCIC testing would not provide any new data, particularly with regard to overall plant safety significance.

RCIC testing in accordance with Technical Specification requirements remains a sufficient demonstration of RCIC capability.

Conclusion Based on plant historical data and EPU analytical results, proper operation of the RCIC system over the expected operating pressures and flow ranges and the system's reliability in automatic operation when starting from cold standby with the reactor at power conditions remains unchanged for EPU.

System pressures, temperatures and flow rates remain unchanged. Additional plant testing of the RCIC other than required technical specification surveillance functional testing is not necessary.

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ATTACHMENT 7 - EPU TEST PLAN TABLE 7 Comparison of NMP Initial Startup Testing and Planned EPU Testing EPU Test Condition Percent Original St r u 4 7 M tT si gof Test No.

Original Test Description Startup 3467 MWt Testing Evaluation/

3467 oWf(CLTPj (USAR Section 14.2)

Test /

Uprate Testing Planned for Justification Notes RTP (USAR 14.3)

EPU

<90 90 100 105 110 EPU CHEMICAL AND RADIOCHEMICAL TC OV

1. To secure information on the TC HU chemistry and radiochemistry of TC 1-3 the reactor coolant.

TC 5, 6 Secured information on

2. To verify that the sampling 16%

chemistry and Yes Test will be performed.

SUT-1 equipment, procedures, and 24%

radiochemistry in the EPU Test 1A See Table 7-3 for X

x X

X analytic techniques are adequate 43%

uprate condition.

and 1B details.

to demonstrate that the chemistry 56%

of all parts of the entire reactor 65%

system meets specifications and 99%

process requirements.

RADIATION MEASUREMENT TC OV At the uprate power level,

1. To determine the background TC HU gamma dose and neutron radiation levels in the plant TC 1-3 dose rates measurements None.

environs prior to operation for TC 6 were taken at pre-Yes Test will be performed.

SUT-2 base data on activity buildup.

18%

determined locations to EPU Test 2 See Table 7-3 for X

X X

X

2. To monitor radiation at 24%

identify and assess the details.

selected power levels to assure 60%

impact of the NMP2 the protection of personnel 100%

uprate.

during plant operation.

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ATTACHMENT 7 - EPU TEST PLAN TABLE 7 Comparison of NMP Initial Startup Testing and Planned EPU Testing EPU Test Condition Percent riginal OStartup 3467 MWt Testing of Test No.

Original Test Description up37 t

Testing Evaluation/

3467 MWt (CLTP)

(USAR Section 14.2)

Test /

Uprate Testing Planned for Justification Notes RTP (USAR 14.3)

EPU

<90 90 100 105 110 EPU SUT-3 FUEL LOADING TC OV Fuel loading was Yes None.

X To load fuel safely and performed in accordance EPU Test 3 Test will be performed.

efficiently to the full core size.

with approved plant See Table 7-3 for procedures.

details.

FULL CORE SHUTDOWN MARGIN The purpose of this test is to demonstrate that the reactor can None.

be made subcritical with the Shutdown margin checks Yes Test will be performed.

SUT-4 required margin at any point TC HU w

n margine ck Y

es See Table 7-3 for X

throughout the fuel cycle with the were performed.

EPU Test 4 details.

strongest worth control rod fully withdrawn and all other control rods fully inserted.

CONTROL ROD DRIVE (CRD) SYSTEM None.

1. To demonstrate that the CRD CRD dynamic friction system operates properly over the TC OV CRD dynamic friction to be determined within full range of primary coolant TC HU determined to be within Yes limits and acceptable SUT-5 temperatures and pressures from TC 1 limits and acceptable EPU Test 5 scram times verified.

ambient to operating.

TC 2 scram times verified.

See Table 7-3 for

2. To determine the initial TC 6 de tails.

operating characteristics of the entire CRD system.

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0 ATTACHMENT 7 - EPU TEST PLAN TABLE 7 Comparison of NMP Initial Startup Testing and Planned EPU Testing EPU Test Condition Percent riginal OStartup 3467 MWt Testing of Test No.

Original Test Description Saup 36MItTsigE lato!3467 MWt_(CLTP)

(USAR Section 14.2)

Test /

Uprate Testing Planned for Evaluation/ Note RTP (USAR 14.3)

EPU Justification Notes

<90 90 100 105 110 EPU SOURCE RANGE MONITOR (SRM) PERFORMANCE Not performed as part of a To demonstrate that the startup test program. Plant Not necessary to retest.

operational sources, SRM anrduedtes and Plant Normal Technical SUT-6 instrumentation, and rod TC 1HU procedures Tecnical None Specification wihrwlsqecspoieSpecifications ensure surveillances provide withdrawal sequences provide proper SRM response prior surance.

adequate information to achieve to start up.

assurance.

criticality and increase power in a safe and efficient manner.

INTERMEDIATE RANGE Not performed as part of a None.

MONITOR (IRM) startup test program. Plant Test will be performed.

SUT-10 PERFORMANCE TC HU procedures and Technical Yes See Table 7-3 for X

To adjust the IRM system to TC I Specifications ensure EPU Test 10 details.

obtain an optimum overlap with proper IRM response prior the SRM and APRM systems.

to start up.

LOCAL POWER RANGE MONITOR (LPRM)

TC 1-3 None.

CALIBRATION TC 6 Yes Test will be performed.

SUT-II To verify that the LPRM 41%

LPRMs were calibrated.

Y es See Table 7-3 for X

X detectors are properly connected 66%

EPU Test 1 details.

to the rest of the LPRM system 99%

and calibrated.

APRM CALIBRATION TC H1U To calibrate the APRM system.

TC 1-3 None.

TC 5, 6 Yes Test will be performed.

SUT-12 18%

APRMs were calibrated.

EPU Test 12 See Table 7-3 for X

X X

X X X 28%

details.

65%

98%

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ATTACHMENT 7 - EPU TEST PLAN TABLE 7 Comparison of NMP Initial Startup Testing and Planned EPU Testing Original Test No.

EPU Test Condition Percent of Original Test Description (USAR Section 14.2)

Startup Test /

RTP 3467 MWt Uprate Testing (USAR 14.3)

Testing Planned for EPU Evaluation/

Justification Notes 3467 MWt (CLTP) 105

<90 90 1100 110 1 EPU

+

+

I I

~

I NUCLEAR STEAM SUPPLY SYSTEM (NSSS) PROCESS COMPUTER To verify the performance of the NSSS process computer under plant operating conditions.

SUT-13 TC OV TC HU TC 1-3 TC 6 Not performed as part of a startup test program. The NSSS process computer was fully tested under plant operating conditions.

The functions of the computers were not changed.

None Not necessary to retest.

The NSSS process computer was fully tested under plant operating conditions.

The functions of the computers were not changed.

RCIC SYSTEM Test is not required.

1. To verify the proper operation EPU does not cause of the RCIC system over its RCIC was started and Testing any changes to RCIC expected operating pressure and TC R flows verified at 160 psig beyond system. Pressures, expetedopeatig pessre nd T HU reatobeyondr. Atemperatures, flow rates SUT-14 flow ranges.

TC 1 reactor pressure. A normal

2. To demonstrate reliability in TC 2 simulated cold quick start surveillance and timing automatic starting from cold was performed at the not r requirements are standby when the reactor is at uprated reactor pressure.

unchanged. See power conditions.

Section 4.3 for further justification.

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ATTACHMENT 7 - EPU TEST PLAN TABLE 7 Comparison of NMP Initial Startup Testing and Planned EPU Testing EPU Test Condition Percent Original Stru 47M tTsigof Test No.

Original Test Description Startup 3467 MWt Testing Evaluation/

3467 MWt (CLTP)

(USAR Section 14.2)

Test /

Uprate Testing Planned for Justification Notes RTP (USAR 14.3)

EPU

<90 90 100 105 110 EPU PROCESS MEASUREMENTS Not performed as part of a

1. To ensure that the measured startup test program.

bottom head drain temperature Maximum rod line and corresponds to bottom head recirculation operating coolant temperature during parameters were not normal operations.

significantly changed.

2. To identify any reactor There was no impact on operating modes that cause low recirculation flows or Not necessary to retest.

temperature stratification.

temperatures.

The low speed limiter

3. To determine the proper Temperature is not being changed.

setting of the low-flow control Stratifications are defined No recirculation pump limiter for the recirculation in Technical trip tests planned.

pumps to avoid coolant TC 2 Specifications.

Reactor pressure vessel SUT-16 temperature stratification in the TC 2 Engineering Analysis bottom head regions reactor pressure vessel bottom TC 5 showed the small increase None temperature data during head region.

TC 6 in reactor water and recirculation pump trips

4. To familiarize plant personnel TC 6 drywell temperature will are routinely collected with temperature differential have a negligible effect on and analyzed per limitations of the reactor system.

these parameters and existing plant

5. To measure the reference and associated systems.

procedures.

variable leg temperatures and recalibrate the instruments if the measured temperatures are different from the values assumed during the initial calibration 37 of 65

ATTACHMENT 7 - EPU TEST PLAN TABLE 7 Comparison of NMP Initial Startup Testing and Planned EPU Testing EPU Test Condition Percent riginal OStartup 3467 MWt Testing of Test No.

Original Test Description Up37 t

Testing Evaluation/

3467 t (CLTP)

(USAR Section 14.2)

Test /

Uprate Testing Planned for JustficainNotes RTP (USAR 14.3)

EPU

<90 90 100 105 110 EPU SYSTEM EXPANSION -

STo d EmonstrAteStt

-Not necessary to retest.

To demonstrate that:uprate

1. The piping system during temperature increase of system heatup and cooldown is primary system piping free to expand and move without is negligible with unplanned obstruction or Not performed as part of a respect to the thermal 2edown.startup test program. The expansion of piping SUT-17

2. The piping does shake down TC HU small increase in None that ranges from 70 to after a few thermal expansion temperature did not justify 150 degrees F. There cycles.

additional testing.

are no changes in

3. The measured values of a

ltiare nchges displacement are within the primary system limits specified by the temperatures except a responsible piping design feedwater temperature increase of 15 degrees engineer.

F.

TRAVERSING INCORE This testing is normally PROBE (TIP)

TC 6 Testing performed after Yes performedafter each To determine the reproducibility reaching 100% power.

EPU Test 18 refueling outage after of the TIP system readings.

attaining 100% power.

38 of 65

ATTACHMENT 7 - EPU TEST PLAN TABLE 7 Comparison of NM!P Initial Startup Testing and Planned EPU Testing EPU Test Condition Percent riginal OStartup 3467 MWt Testing of Test No.

Original Test DescriptionTest

/

t Testing Evaluation/

3467 MWt (CLTP)

(USAR Section 14.2)

Tet prate Testing Planned for Justification Notes RTP (USAR 14.3)

EPU

<90 90 100 105 110 EPU CORE PERFORMANCE Steady-state core thermal

1. To evaluate the core thermal (MWt) power power and flow.

measurements were made

2. To evaluate whether the near 90% of uprated power following core performance and 100% of the old rated parameters are within limits:

power (3323 MWt), and at increments of 3% power

a. Maximum Linear Heat up to the new rating (3467 Generation Rate (MLHGR).

TC 1-3 MWt). Fuel thermal TC 5, 6 margin was projected to

b. Minimum Critical Power 17%

the next test point to show None.

Ratio (MCPR).

28%

acceptable margin, and Yes Test will be performed.

SUT-19 42%

was confirmed at each test es Test wl be performX X

X X

X X

EPU Test 19 See Table 7-3 for

c. Maximum Average Planar 64%

point before advancing to details.

Linear Heat Generation Rate 65%

the full uprate conditions.

(MAPLHGR).

98%

Demonstration of fuel thermal margin was performed prior to and during power ascension to the uprated power level at each steady-state heat balance point discussed above.

39 of 65

ATTACHMENT 7 - EPU TEST PLAN TABLE 7 Comparison of NMP Initial Startup Testing and Planned EPU Testing EPU Test Condition Percent Original Startup 3467 MWt Testing of Test No.

Original Test Description Test /

Uprate Testing Planned for Evaluation/

3467 MWt (CLTP)

(USAR Section 14.2)

RTP (USAR 14.3)

EPU Justification Notes

<90 90 100 105 110 EPU STEAM PRODUCTION Not performed as part of a To demonstrate that the NSSS startup test program. This Not required. Power SUT20 provides steam sufficient to TC W was not required as there None uprate warranties will satisfy all appropriate warranties 99%

was no warranty. A be tete w

here.

as defined in the contract.

separate performance test was conducted.

40 of 65

ATTACHMENT 7 - EPU TEST PLAN TABLE 7 Comparison of NMP Initial Startup Testing and Planned EPU Testing EPU Test Condition Percent Original St r u 4 7 M tT si gof Test No.

Original Test Description Startup 3467 MWt Testing Evaluation3467 MW(L (USAR Section 14.2)

Test /

Uprate Testing Planned for Justification Notes RTP (USAR 14.3)

EPU

<90 90 100 105 110 EPU PRESSURE REGULATOR

1. To determine the optimum settings for the pressure control loop by analysis of the transients induced in the reactor pressure control system by means of the pressure regulators.

2. To demonstrate the takeover capability of the backup pressure regulator upon failure of the controlling pressure regulator and Step changes and None.

to set spacing between the TC 1-3 See Tabe p-3for SUT-22 setpoints at an appropriate value.

TC 5, 6 failures wereguo See Table 7-3 for X

X X

X X

X

3. To demonstrate smooth 98.1%

demonstrated.

EPU Test 22 details.

pressure control transition between the control valves and bypass valves when reactor steam generation exceeds steam used by the turbine.

4. To demonstrate that other affected parameters are within acceptable limits during pressure regulator-induced transient maneuvers.

41 of 65

ATTACHMENT 7 - EPU TEST PLAN TABLE 7 Comparison of NMP Initial Startup Testing and Planned EPU Testing EPU Test Condition Percent Originalof Original Original Test Description Startup 3467 MWt Testing Evaouafion 3467 MVt(CLTP)

Test No.

14n2)

Test /

Uprate Testing Planned for Justifcation Notes (USAR Section 14.2)

RTP (USAR 14.3)

EPU

<90 90 100 105 110 EPU FEEDWATER SYSTEM Setpoint changes were

1. To verify that the feedwater made in the three and control system has been adjusted single element modes at to provide acceptable reactor the previous rated power water level control.

TC 1-3 level and again at the Test will be performed.

2. To demonstrate adequate TC 5, 6 uprate power level.

See Table 7-3 for response to a feedwater 15%

details.

temperature loss.

38%

Loss of Feedwater Heating. Yes SUT-23

3. To demonstrate the capability 62%

and Feedwater Pump Trip EPU Test Loss of Feedwater X

X X

X X

of the automatic core flow 65%

testing was not performed.

23A Heating and Feedwateri runback feature to prevent low 72%

An Pump Trip testing will water level scram following the 99%

An analysis was performed not be performed. See trip of one feedwater pump.

which determines the Section 4.3 for further

4. To determine that the maximum feedwater flow justification.

maximum feedwater runout runout at power uprate capability is compatible with conditions with the reactor licensing assumptions.

feedwater control valves full open.

42 of 65

ATTACHMENT 7 - EPU TEST PLAN TABLE 7 Comparison of NMP Initial Startup Testing and Planned EPU Testing EPU Test Condition Percent riginal OStartup 3467 MWt Testing of Test No.

Original Test Description up37 t

Testing Evaluation/

3467 MWt (CLTP)

(USAR Section 14.2)

Test /

Uprate Testing Planned for Justification Notes RTP (USAR14.3)

EPU

<90 90 100 105 110 EPU TURBINE VALVE Individual main turbine SURVEILLANCE stop and control valves are To demonstrate the acceptable tested routinely during procedures and maximum power plant operation as required levels for surveillance testing of for turbine surveillance the main turbine control and stop testing. At 88% and 90%

valves without producing a of uprate power, the reactor scram.

TC 5 response of the reactor was TC 6 observed and the 62%

maximum power level for None.

SUT-24 75%

performance of these tests Yes Test will be performed.

X X

X X

X X

86%

along the maximum load EPU Test 24 See Table 7-3 for 88%

line was extrapolated.

details.

95%

Each valve test was manually initiated and reset. The rate of valve stroking and timing of the close-open sequence was such that the minimum practical disturbance was introduced.

43 of 65

ATTACHMENT 7 - EPU TEST PLAN TABLE 7 Comparison of NMP Initial Startup Testing and Planned EPU Testing EPU Test Condition Percent riginal OStartup 3467 MWt Testing of Test No.

Original Test Description up37 t

Testing Evaluation/

3467 MWt (CLTP)

(USAR Section 14.2)

Test /

Uprate Testing Planned for Justification Notes RTP (USAR 14.3)

EPU

<90 90 100 105 110 EPU MAIN STEAM ISOLATION Not performed as part of a VALVES startup test program.

1. To functionally check the MSIVs for proper operation at The functional testing was selected power levels, not performed because the

2. To determine isolation valve original test was executed closure time at rated temperature at 75% (OLTP), the and pressure.

MSIVs are not fully

3. To determine the reactor stroked at power, and there transient behavior that results is only a 2 deg F increase from the simultaneous full TC 1U in temperature and a 15 psi closure of all MS1Vs.

TC 3 increase in pressure at full Not required. See SUT-25 TC 6 power.

None Section 4.3 for further 49%

justification.

95.3%

The original full MSIV closure test results proved-that analytical methods that predicted the transient were conservative.

Because the increase in power level for power uprate was small, a repeat of the test was not warranted.

44 of 65

ATTACHMENT 7 - EPU TEST PLAN TABLE 7 Comparison of NMP Initial Startup Testing and Planned EPU Testing EPU Test Condition Percent Original Startup 3467 MWt Testing of Test No.

Original Test Description st 3

Mr t

Testing Evaluation/

3467 MWt (CLTP)

(USAR Section 14.2)

Test /

Uprate Testing Planned for Justification Notes RTP (USAR 14.3)

EPU

<90 90 100 105 110 EPU RELIEF VALVES

1. To verify that the relief valves Not performed as part of a function properly (can be opened startup test program.

Not necessary to retest.

and closed manually).

TC 1 There were no changes There are no changes SUT-26

2. To verify that the relief valves 17.6%

made to the relief valves None being made to the relief reseat properly after operation.

which would require re-valves for power

3. To verify that there are no verifying the test uprate.

major blockages in the relief objectives.

valve discharge piping.

TURBINE TRIP AND)

Not performed as part of a GENERATOR LOAD TC 2 startup test program.

Not Required REJECTION TC 6 Original test results proved Non SeeuSec SUT-27 To demonstrate the response of 21.6%

that analytical methods None See Section 4.3 for the reactor and its control 99.6%

that predicted the transient further justification.

systems to protective trips in the were conservative.

turbine and generator.

SHUTDOWN FROM OUTSIDE THE MAIN CONTROL ROOM Power uprate does not To demonstrate that the reactor Not performed as part of a change the capability of can be brought from a normal startup test program. The the plant to shut down SUT-28 initial steady-state power level TC 1 capability of the plant to None from outside the main down to the point where 17.8%

be shutdown from outside control room, nor does cooldown is initiated and is under the control room was not it alter the function or control with reactor vessel changed.

intent of the emergency pressure and water level operating procedures.

controlled from outside the main control room.

45 of 65

ATTACHMENT 7 - EPU TEST PLAN TABLE 7 Comparison of NMP Initial Startup Testing and Planned EPU Testing EPU Test Condition Percent O riginal St r u 4 7 M tT si gof Test No.

Original Test Description Startup 3467 MWt Testing Evaluation/

3t (USAR Section 14.2)

Test /

Uprate Testing Planned for Justification Notest (CLTP)

RTP (USAR 14.3)

EPU

<90 90 100 105 110 EPU RECIRCULATION FLOW Not performed as part of a The increase in CONTROL startup test program.

recirculation flow rate Additional core resistance is approximately 1.9%

system's control capability over TC 1 to flow was minimal, from CLTP. Due to the the entire flow control range, TC 3 Modification to velocity small increase in SUT-29 including core flow, neutron flux.

TC 6 feed back card was tested None recirculation rate, the

2. To derecirceutationl raterthe

2.

To determine that all electrical 97%

as part of post plant response to a compensators and controllers are modification testing.

recirculation flow set for desired system System not operated in change is not performance and stability.

Master Manual.

significantly affected.

46 of 65

0 ATTACHMENT 7 - EPU TEST PLAN TABLE 7 Comparison of NMP Initial Startup Testing and Planned EPU Testing EPU Test Condition Percent Original Stru 47MWt Tsigof Test No.

Original Test Description Startup 3467 Testing Evaluation/

3f (USAR Section 14.2)

Test /

Uprate Testing Planned for Justification Notest (CLTP)

RTP (USAR 14-3)

EPU

<90 90 100 105 110 EPU REACTOR Not performed as part of a RECIRCULATION SYSTEM startup test program. No

1. To obtain recirculation system effects that alter the performance data during the recirculation system pump trip, flow coastdown, and performance data for a pump restart.

single pump trip.

2. To verify that the feedwater Feed water control tested control system can satisfactorily per PUPA-23A The increase in control water level without a Scram avoidance not recirculation flow rate resulting turbine trip/scram.

TC 1 performed because of is approximately 1.9%

3. To record and verify TC 2 potential challenge to from CLTP. Due to the acceptable performance of the TC 3 safety systems. Data to be small increase in recirculation two-pump circuit TC 5 collected during an actual recirculation rate, the SUT-30 trip system.

TC 6 event post uprate.

None plant response to a

4. To record recirculation system 59.6%

recirculation pump trip parameters during the power test 66.4%

There are no changes that is not significantly program.

98.2%

alter the recirculation affected.

5. To verify the adequacy of the system for a two pump See Section 4.3 for recirculation runback to prevent a trip.

further justification.

scram on loss of one feedwater pump and subsequent vessel Power to Flow water level decrease to Level 4.

characteristic mapping was

6. To verify that no recirculation performed per a separate system cavitation occurs in the test.

operable region of the power flow map.

47 of 65

0 ATTACHMENT 7 - EPU TEST PLAN TABLE 7 Comparison of NMP Initial Startup Testing and Planned EPU Testing EPU Test Condition Percent Original Stru 47M tTsigof Test No.

Original Test Description Sartup 3467 t

Testing Tetng Evaluation/

3467 MWt (CLof) s (SAR Section 14.2)

Test /

Uprate Testing Planned for Justification Notes RTP (USAR 14.3)

EPU

<90 90 100 105 110 EPU LOSS OF TURBINE Power uprate will not GENERATOR AND OFFSITE change the ability of POWER Not performed as part of a the safety systems to To determine the electrical startup test program. No initiate and function equipment and reactor transient change to safety systems properly nor change the SUT-31 performance during the loss of TC 2 or emergency power diesel None ability of the electrical auxiliary power.

24%

generators that actuate distribution and diesel under the test conditions.

generator systems to The RCIC system was function properly tested by SUT-14.

during a loss of turbine-generator and offsite power event.

DRYWELL PIPING VIBRATION None.

1. To verify that the vibration of TC 1 Vibration measurements Yes Test will be performed SUT-33 the reactor recirculation is within TC 3 were taken using the EPU Test as part of EPU Test X

X X

X X

X acceptable limits.

TC 5 installed loose parts 100 100. See Table 7-3 for

2. To verify that stresses are TC 6 monitoring transducers.

details.

within code limits during operating transient loads.

RECIRCULATION SYSTEM TC 3 Recirculation system data None.

FLOW CALIBRATION TC 6 was taken and. the jet pump Yes Test will be performed.

SUT-35 To perform complete calibration 67%

and recirculation flow unit EPU Test 35 See Table 7-3 for X

of the installed recirculation 67/

instrumentation details.

95%

system flow instrumentation, recalibrated.

48 of 65

ATTACHMENT 7 - EPU TEST PLAN TABLE 7 Comparison of NMP Initial Startup Testing and Planned EPU Testing EPU Test Condition Percent riginal OStartup 3467 MWt Testing of Test No.

Originial Test Description Tet/Tsig Evaluatoion347M/

CL (USAR Section 14.2)

Test /

Uprate Testing Planned for Justification Notest (CLTP)

RTP (ISAR 14.3)

EPU

<90 90 100 105 110 EPU REACTOR WATER CLEANUP (RWCU) SYSTEM To demonstrate specific aspects Not performed as part of a of the mechanical ability of the startup test program.

Not necessary to retest.

RWCU system. (This test, stagtup test program Original test program performed at rated reactor TC 2 proved the performance None mnd the ormthe pressure and temperature, is 32%

pod the p fomne and capabilities of the actually the completion of the RWCU system in all of its RWCU system in all of preoperational testing that could rWtU syst its operating modes.

not be done without nuclear operating modes.

heating.)

RESIDUAL HEAT REMOVAL (RHR) SYSTEM Not performed as part of a Not necessary to retest.

To demonstrate the ability of the startup test program.

Original test program RHTR system to:

TC a

o Original test program proved the performance

1. Remove heat from the reactor TC 1 proved the performance and capabilities of the SUT-71 1.stemo that the rfeli and TC 2 and capabilities of the heat None heat exchanger beyond system so srefueing and TC 2 exchanger beyond design design assumptions and performed.

assumptions and its ability its ability to operate in

2. Condense steam from the to operate in the steam the steam condensing reactorn condensing mode.

mode.

49 of 65

ATTACHMENT 7 - EPU TEST PLAN TABLE 7 Comparison of NMP Initial Startup Testing and Planned EPU Testing EPU Test Condition Percent OrignalStatup 467M~tof Original Startup 3467 MWt Testing Evaluation/

3467 MWt (CLTP)

Test No.

Original Test Description Test /

Uprate Testing Planned for Justification Notes RTP (USAR 14.3)

EPU

<90 90 100 105 110 EPU OFFGAS SYSTEM TC HU The purpose of this test is to TC 1-3 None.

verify the proper operation of the TC 6 Offgas activity was Test will be performed.

SUT-74 offgas system over its expected 4%

monitored at the previous Yes See Table 7-3 for X

X X

X X

operating range.

18%

rated power level and at EPU Test 74 details.

44%

the uprate conditions.

66%

96%

DRYWELL COOLING SYSTEM To demonstrate the capability of TC HU Measurements were taken None.

the drywell cooling system to TC 2 to verify that the drywell Test will be performed.

SUT75 maintain peak and average TC 6 temperatures remain below Yes See Table 7-3 for X

X X

X X

X drywell temperatures within the 21%

Technical Specification EPU Test 75 details.

maximum design limits during 98%

limits.

power operation at rated temperature and pressure.

50 of 65

ATTACHMENT 7 - EPU TEST PLAN TABLE 7 Comparison of NMP Initial Startup Testing and Planned EPU Testing EPU Test Condition Percent Original St r u 4 7 M tT si gof Test No.

Original Test Description Startup 3467 MWt Testing Evaluation/

3467 MWt (CLof (USAR Section 14.2)

Test /

Uprate Testing Planned for Justification Notes RTP (USAR 14.3)

EPU

<90 90 100 105 110 EPU ENGINEERED SAFETY FEATURES (ESF) AREA COOLING The purpose of this test is to verify that the unit coolers serving the RCIC, RHR, LPCS, Not performed as part of a H-PCS, Standby Gas Treatment flCSy (,

auxiliarya TCeatmn 1

startup test program.

Not necessary to retest.

System (SGTS), auxiliary TC 1 Minimal impact on rooms N

EPU has no effect on SUT-76 building Motor Control Center TC 3 with main steam lines as one temperatures in the (MCC), service water bay, and TC 6 the temperature increase ESF areas.

standby diesel generator control was 2 deg F.

rooms can maintain the equipment room temperature below the maximum design limits under postulated accident conditions.

51 of 65

0 ATTACHMENT 7 - EPU TEST PLAN TABLE 7 Comparison of NMP Initial Startup Testing and Planned EPU Testing EPU Test Condition Percent Original Startup 3467 MWt Testing of Test No.

Original Test Description st 3

Mr t

Testing Evaluation/

3467 MW(CLIP

[(USAR Section 14.2)

Test /

Uprate Testing Planned for Justification Notes367M tCTP RTP (USAR 14.3)

EPU

<90 90 100 105 110 EPU BOP PIPING VIBRATION

1. To verify that steady-state and/or transient piping vibration for the main steam (including Vibration measurements relief valve discharge), RHR TC HU were taken at points on the None.

feedwater, RCIC, and condensate TC 1 feedwater piping inside the Yes Test will be performed systems is within acceptable TC 2 drywell, EHC piping to E

es as part of EPU Test SUT-77 limits.

TC 3 turbine control valve #4, EPU Test 100. See Table 7-3 for X

X X

X X

X

2. To verify that steady-state TC 5 and on the feedwater 100 details.

vibrations for small bore piping TC 6 pumps at 50%, 75%, 95%,

and essential instrumentation T6 pm at 50% poe5%

lines on main steam, nuclear 98%, and 100% power.

steam supply, feedwater, reactor plant sampling, RHR, and RCIC are within acceptable limits.

BOP SYSTEM EXPANSION Not necessary to retest.

To verify that BOP piping Power uprate systems are free to expand and temperature increases move without unplanned of primary system obstruction or restraint during Not performed as part of a piping are negligible system heatup and cooldown TC HU Startup test program. The with respect to the SUT-78 cycles, and to verify that the TC 1 smalltincrease in None thermal expansion of associated measured TC 2 temperature did not justify piping that ranges from displacements are within TC 6 temeate sti fy 70-550 degrees F.

specified limits, additional testing.

There are no changes in primary system temperatures except a 15 degree F. rise in feedwater temperature.

52 of 65

ATTACHMENT 7 - EPU TEST PLAN TABLE 7 Comparison of NMP Initial Startup Testing and Planned EPU Testing EPU Test Condition Percent riginal OStartup 3467 MWt Testing of Test No.

Original Test Description Stru 47M tTsigEvaluation/

47M~(L3 TeSt Section 14N2)

Test /

Uprate Testing Planned for uation3467 t (CLTP)

RTP (USAR 14.3)

EPU Justification Notes

<90 90 100 105 110 EPU REACTOR INTERNALS VIBRATION To provide the data required to Not performed as part of a verify the similarity between the startup test program. Core Not necessary to retest.

reactor internals design and the flow was not changed and Core flow is unchanged limited valid prototype with TC 3 therefore no changes to and the increases in SUT-79 respect to flow-induced TC 6 core flow induced None main steam, feedwater vibration. Testing is in vibrations. The 5%

and recirculation drive accordance with Regulatory increase in steam flow was flow have been Guide (RG) 1.20 for the vibration evaluated to have minimal evaluated as acceptable.

measurement program for a non-effect.

prototype Category IV plant.

EMERGENCY RECIRCULATION VENTILATION Not necessary to retest.

To verify that the emergency Not performed as part of a Evaluation has shown riruainvniainstartup test program. UnitththefetsoEP SUT-80 recirculation ventilation system TC 6 cooler capacity was None that the effects of EPU can maintain the required reactor sufficient to remove the on Reactor Building building area temperatures below small additional heat load.

temperatures are the maximum design limits under minimal.

postulated accident conditions.

53 of 65

ATTACHMENT 7 - EPU TEST PLAN TABLE 7 Comparison of NMP Initial Startup Testing and Planned EPU Testing EPU Test Condition Percent O riginal St r u 4 7 M tT si gof Test No.

Original Test Description Startup 3467 MWt Testing Evaluation3467 MWt (CL (USAR Section 14.2)

Test /

Uprate Testing Planned for Justification Notes RTP (USAR 14.3)

EPU

<90 90 100 105 110 EPU DRYWELL HIGH ENERGY Not performed as part of a PENETRATIONS startup test program. The The purpose of this test is to small increase in feedwater Not necessary to retest.

demonstrate the capability of the temperature (4'F) and The increased piping drywell high energy penetrations TC HU main steam piping temperatures for EPU SUT-81 to maintain the surrounding TC 3 temperature (2°F) was None were compared to the concrete below design TC 6 evaluated to have minimal original test results and temperature limits.

97.7%

impact on the drywell high the penetrations were energy penetration to found to be acceptable.

maintain the surrounding concrete below design temperatures.

54 of 65

ATTACHMENT 7 - EPU TEST PLAN TABLE 7 EPU Implementation Modifications Design Change Number/

Description Completion Anticipated Post-Modification Testing Title N2-02-119 Replacement of Extraction Steam expansion N2R13 In-service leak test Extraction Steam bellows for the 'B' and 'C' 1st through 4 th Expansion Joints point feedwater heater extraction lines (being replaced due to equipment degradation, not an EPU required modification)

N2-07-002 Installation of strain gauges to record the 2007 0

Functional test Install Main Steam Line dynamic pressure fluctuations inside the Main (complete) 0 Data acquisition test Vibration Monitoring Steam piping in the Drywell Strain Gauges N2-07-012 0

Installation of a partial bypass line around the 2008 In-service leak test Condensate Demineralizer Condensate Demineralizers (complete) 0 Functional test (as part of N2-08-033, Bypass Replacement of Heater Drain Pumps)

N2-07-052 0

Replace 13.8 KV power cables to the 3 N2R13 0

Cables-continuity, ground, megger and Replacement of Feedwater Feedwater pump motors hi-pot testing Pump Motor Cables 0

Add 2 13.8 KV breakers Motors-megger, Polarization Index (PI),

Install/rework tray and conduit rotation and amperage Replace current transformers and ammeters 0

Relay testing Revise relay settings N2-07-053 0

Installation of 4 additional area coolers N2R13 0

In-service leak test Improve Turbine Building located near the Condensate and Condensate Service Water local flow balance Heating, Ventilation and Booster pumps Cooler performance test Air Conditioning (HVAC)

N2-07-054 0

Re-rate the 5 tb and 6 th point feedwater heaters N2R13 0

In-service leak test Feedwater Heater 0

Replace the 5th and 6th point heater shell side 0

Bench test new relief valves Requalification safety valves Replace the scavenging steam relief valves 55 of 65

0 ATTACHMENT 7 - EPU TEST PLAN TABLE 7 EPU Implementation Modifications Design Change Number/

Description Completion Anticipated Post-Modification Testing Title N2-07-055 Revise piping supports as necessary for EPU N2R13 Non-destructive examinations and piping Mins conditions integrity tests as required Steam/Feedwater/BOP Piping Support Replacement N2-08-032 Replace pump impellers N2R13 0

In-service leak test Upgrade Reactor Feed Replace pump speed increasers 0

Pump performance curves Pumps and Gear Sets Flow Control Valve changes 0

Vibration monitoring Feedwater System Setpoint Setdown setting 0

Feedwater level control valve calibration change and functional testing N2-08-033 Replace pump internals N2R12 0

In-service leak test Replace FW Heater Drain Replace pump motors Pump performance curves Pumps and Motors 0

Replace 4"h point heater drain level control 0

Vibration monitoring valve trim 0

Motor testing Dynamic valve testing N2-08-034 0

Replace the high pressure turbine for N2R13 0

125% rotor speed factory testing Replace High Pressure increased steam flow at EPU conditions 0

Transient/steady state data recording Turbine 0

Reconfigure Steam Path 0

Overspeed trip testing In-service leak test Calibrate and Test Pressure Control Systems N2-08-035 Replace cross around relief valves with valves N2R13 0

In-service leak test Replace Low Pressure rated for EPU conditions Bench test new relief valves Turbine Cross Around 0

Re-rate the moisture separators, drain tanks Relief Valves and intermediate heat exchangers 56 of 65

ATTACHMENT 7 - EPU TEST PLAN TABLE 7 EPU Implementation Modifications Design Change Number/

Description Completion Anticipated Post-Modification Testing Title N2-08-036 Replace 6 of 12 low pressure turbine N2R13 Weld Inspection Replace Low Pressure atmospheric exhaust hood diaphragms Turbine Atmospheric Relief Diaphragms N2-08-040 0

Design basis reconciliation/configuration N/A N/A Design Basis Document modification for EPU implementation. No Updates to Support EPU physical work involved.

Implementation N2-08-066 0

Replace three third point feedwater heaters N2R12 System flush Replace 3rd Point (not an EPU modification-heaters are being 0

In-service leak tests Feedwater Heaters replaced on an accelerated timetable due to 0

Calibration and tuning of Level Control internal degradation)

System N2-08-067 0

Replace 7 instruments N2R13 Loop calibration Instrument Replacement Recalibrate 227 instrument loops and Modification 0

Various setpoint changes 0

Various computer point changes N2-08-068 0

Install accelerometers on Main Steam, N2R13 Functional checks Temporary Vibration Feedwater, Extraction Steam and BOP piping 0

Data acquisition checks Monitoring for vibration monitoring (temporary)

N2-08-100 0

Install upgraded cooling system on Main N2R12 0

Performance test Improve Main Generator Step-up Transformers Transformer Cooling N2-08-101 Revise Reactor Recirculation System (RRS)

N2R13 0

Logic system functional testing Recirculation Runback runback logic to initiate upon a 0

Flow control valve calibration Initiation and Runback feedwater/condensate booster pump trip Rate Increase Recirc Flow Control valve runback rate to 9% per second 57 of 65

ATTACHMENT 7 - EPU TEST PLAN TABLE 7 EPU Implementation Modifications Design Change Number/

Description Completion Anticipated Post-Modification Testing Title N2-08-102 0

Install shielding on the two Standby Gas N2R13 Inspection Equipment Qualification Treatment system filters Modifications N2-08-103 0

Isolate abandoned loads N2R13 0

System balance Isolate Abandoned Turbine e

Rebalance the Turbine Building Closed Loop Building Closed Loop Cooling system Cooling Loads N2-08-104 0

Revise the isolated phase bus duct housings to N2R13 System flow balance Generator Isolated Phase provide additional cooling Bus Duct Cooling N2-09-008 0

Valve trim changes to the Hydrogen Water N2R13 0

In-service leak test Mitigation System Valve Chemistry (HWC) and GE Zinc Injection 0

System performance monitoring Changes Passivation (ZIP) systems N2-09-013 0

Reinforce the inner and middle hood end N2R13

° Weld Inspection Steam Dryer Modifications cover welds and the lifting rod upper brace to vane bank weld 58 of 65

ATTACHMENT 7 - EPU TEST PLAN Table 7 Planned EPU Power Ascension Testing Title Test Number Test Description Samples will be taken and measurements made at selected EPU power levels to determine the chemical and radiochemical quality of reactor water, reactor feedwater Chemical and EPU Test I A and gaseous effluent. Testing will be performed using Radiochemical procedures N2-CSP-GEN-D 100, Reactor Water/Auxiliary Water Chemistry Surveillance, N2-CSP-2V, Turbine Chemistry Surveillance At Unit 2, N2-CSP-OFG-M333, Offgas Monthly Surveillance and N2-CSP-OFG-S330, Offgas Shiftly Surveillance.

Samples will be taken and measurements be made at selected EPU power levels to determine steam Steam Dryer/Separator dryer/separator performance (i.e., moisture carryover). For Performance EPU Test lB this testing, main steam line moisture content is considered equivalent to the steam separator-dryer moisture carryover.

Sampling and analysis will be per S-CAP-100, Steam Quality Analysis.

At selected EPU power levels, gamma dose rate and, where appropriate, neutron dose rate measurements made at specific locations throughout the plant to assess the impact of the uprate on actual plant area dose rates. Surveys will be performed in normally accessible areas adjacent to steam affected areas in the Reactor Building (62 locations),

Turbine Building (47 locations), Offgas Building (4 Radiation Measurements EPU Test 2 locations) and the Screenwell Building (6 locations). The areas to be surveyed were selected by comparing the potential impact due to the EPU (reference PUSAR Section 2.10.1) with the original plant startup and previous stretch uprate power ascension test results. USAR radiation zones will be monitored for any required changes. Testing will be performed using procedure S-RPIP-10.9, Shield Integrity Checks, Reference Measurements and Trending Surveys.

Fuel loading and core verification will be performed per Fuel Loading EPU Test 3 plant procedures N2-FHP-13.3, Core Shuffle and N2-REP-008, Core Post-Alteration Inspection and Verification.

Full Core Shutdown Full core shutdown margin demonstration shall be Flrei SEPU Test 4 performed per procedure N2-RESP-10, Subcooled Critical Margin Comparison.

CRD dynamic friction determined to be within Technical Control Rod Drive Specification limits with acceptable scram times verified at System EPU Test 5 normal TS surveillance intervals per N2-OSP-RMC-@00 1, Control Rod Drive Scram Insertion Time Testing and N2-RESP-11, Evaluation of Scram Time Testing.

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ATTACHMENT 7 - EPU TEST PLAN Table 7 Planned EPU Power Ascension Testing Title Test Number Test Description After the APRM calibration for EPU, IRM gains will be adjusted accordingly to ensure proper overlap. During the IRM Performance EPU Test 10 first controlled shutdown following EPU implementation the IRM overlap with the APRMs will be verified.

Monitoring and verification of proper overlap is currently performed per N2-OP-101 C, Plant Shutdown.

The LPRM channels will be calibrated to make the LPRM readings proportional to the neutron flux in the LPRM water gap at the chamber elevation. Calibration factors LPRM Calibration EPU Test 11 will be obtained through a process computer calculation that relates the LPRM reading to the average fuel assembly power at the chamber height. Ref. N2-RESP-4, LPRM Calibration.

Confirm the calibration of the APRMs is consistent with the rated thermal power, referenced to 100% EPU, as determined from the heat balance. Confirm/adjust the drive flow gain in Power Range Neutron Monitoring (PRNM) system during power ascension and at rated power, so that the drive flow normalization condition (i.e.,

100% drive flow is equal to 100% core flow at 100%

power) is satisfied. Assure that the APRM flow-biased scram and rod block setpoints in the PRNM system are consistent with EPU operation. Confirm all APRM trips and alarms prior to entering the EPU operating domain.

Calibration will be per Instrument Control Surveillance Procedures for LPRMIAPRM Channel Calibrations (N2-ISP-NMS-ROO1 through R004)

This testing will be performed after attaining 100% power TIP Uncertainty EPU Test 18 per N2-REP-14, TIP Uncertainty Calculation.

Routine measurements of reactor power are taken at - 25%

power and throughout the power ascension. These parameters are again monitored near 90% and 100% of CLTP along a constant flow control line to be used to increase to maximum EPU power. Core thermal power and core performance parameters are calculated using accepted methods to ensure current licensed and operational practice are maintained. Power increase is Core Performance EPU Test 19 along this constant rod pattern line in incremental steps of 5% or less of CLTP to ensure a careful, monitored approach to maximum EPU power. Measured reactor parameters and calculated core performance parameters are utilized to project those values at the next power level step.

Each step's actual values will be satisfactorily confirmed with the projected values for that step before advancing to the next step and the final confirmation at the maximum EPU power level. Ref. N2-RESP-001, Power Distribution Limits Verification.

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ATTACHMENT 7 - EPU TEST PLAN Table 7 Planned EPU Power Ascension Testing Title Test Number Test Description The pressure regulator requires only the following changes for EPU: 1) Pressure Control System, (i.e. Pressure Regulator Setpoint), and 2) Confirming the dynamic tuning parameters. Before startup, the pressure regulator system will be tested and dynamically calibrated. GE Service Information Letter (SIL) No. 589 discusses the tuning of the dynamic parameters for the pressure regulator.

Pressure Regulator EPU Test 22 Pressure control system response to the pressure setpoint change is tested at various test conditions. Testing the system requires a 6 psi down setpoint change followed by a 6 psi up setpoint change when conditions stabilize.

Pressure regulators are tested individually and sequentially.

Perform data gathering for Incremental Regulation and Turbine First Stage Pressure Scram Bypass Permissive Setpoint Validation.

The feedwater control system response to reactor water level setpoint changes are evaluated in the indicated control mode (i.e., three element, single element). At each test condition, level setpoint change testing is performed by first making an up setpoint value change, followed by a down setpoint value change of the same value, after conditions stabilize, in accordance with the following setpoint change sequence:

1) + 2 inches

3) + 3 inches

5) + 4(

1) inches

2) - 2 inches

4) - 3 inches

6) - 4 (- 1) inches The 2 and 3 inch level setpoint steps are informational and recommended to demonstrate the level control response prior to performing the formal level setpoint steps of 4 +/- 1 inch. The results from the informational level setpoint steps are utilized to anticipate the responses (i.e., power increases, level alarms) to the formal demonstration test steps. The tolerance of the formal level step permits adjustment to take into consideration the limit cycles of the control mode being tested. If the limit cycles are small enough to permit the formal steps to be at the lower end of the tolerance (i.e., 3 inches), then the informational 3" steps need not be performed.

The normal feedwater control system mode is three-element control, with single element control only being used for temporary backup situations. The feedwater control system in three-element control mode should be adjusted, not only for stable operational transient level control (i.e., decay ratio), but also for stable steady state level control (i.e., minimize reactor water limit cycles). In 61 of 65

ATTACHMENT 7 - EPU TEST PLAN Table 7 Planned EPU Power Ascension Testing Title j Test Number jTest Description single element control mode, the system adjustments must achieve the operational transient level control criteria, but for steady state level control the temporary backup nature of this mode should be considered.

For tests calling for manual flow step changes, at each test condition the feedwater control system is placed in a manual/auto configuration (i.e., feedwater flow control valve (FCV) being tested in manual and the other in automatic controlling water level). Preferably, the flow step changes are made by inserting the step demand change into the feedwater FCV controller in manual or alternately by changing the setpoint of that controller in accordance with the following setpoint change sequence expressed in percent of rated EPU feedwater flow. After completion of testing on one controller, the manual/auto configuration is switched and the sequence is repeated on the other controller.

1) Increase 5%

3) Increase 10%

2) Decrease 5%

4) Decrease 10%

The 5% flow step changes are informational and recommended to demonstrate the feedwater FCV response prior to performing the formal test flow step changes (i.e.,

4 (+/- 10%). The results from the smaller informational flow step are utilized to anticipate the responses to the formal demonstration test, so that effects on the reactor may be anticipated (i.e., level changes, power increases).

An analysis is to be performed which demonstrates the maximum feedwater flow runout at power uprate conditions with the reactor feedwater control valves full open. This calculation is then extrapolated to uprate conditions.

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ATTACHMENT 7 - EPU TEST PLAN Table 7 Planned EPU Power Ascension Testing Title Test Number Test Description Utilizing the original Standard Technical Specification (STS) methodology, initial tests are performed at two points below and near the power level at which each valve's surveillance has been performed in pre-EPU uprate tests. A maximum power test condition will be determined by projecting the initial tests' scram/trip setpoint margins Turbine Valve to the highest power level where all the margins remain Surveillance EPU Test 24 acceptable. A final test is performed at this maximum power test condition to confirm acceptable test performance. For all tests, the proximity to vessel pressure, neutron flux and heat flux scram, and main steam line flow isolation trip, will be closely monitored. Each test will be manually initiated, valve stroked and reset in accordance with the current valve surveillance procedure.

Recirculation System Recirculation system data will be recorded and jet pump FloeCaibrcation SEPU Test 35 instrumentation calibrated per N2-REP-22, Core Flow and Flow Calibration Recirc Pump Flow Gain Adjustment Calculation.

Data will be collected and a quantitative analysis Offgas System EPU Test 74 performed of the offgas system effluent per N2-CSP-OFG-S330, Offgas Shiftly Surveillance.

Measurements will be taken to verify that the Drywell Drywell Cooling EPU Test 75 temperatures remain below Technical Specification limits

__according to N2-OSP-LOG-DOO1, Daily Checks Log.

Piping vibration measurements will be taken as appropriate BOP Piping Vibration EPU Test 77 to demonstrate piping and support adequacy. See Test 100 for details.

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ATTACHMENT 7 - EPU TEST PLAN Table 7 Planned EPU Power Ascension Testing Title Test Number Test Description During the EPU power ascension, designated main steam, feedwater and balance of plant piping points (i.e., location and direction) will be monitored for vibration. Vibration monitoring points will be designated based on EPU piping vibration analysis and engineering judgment as detailed in 0. Monitoring points may be coincidental with those in the initial startup piping vibration test or be selected as those points with the highest predicted vibration. Alternately, vibration monitoring points can be coincidental with exposed piping attachments provided that acceptance criteria are established for those points based on piping system vibration analysis. Vibration measurements taken above CLTP will permit a thorough assessment of Maind

Stlnea, of ante Tethe effect of the EPU in comparison to any previous piping and Balance of Plant EPU Test 100 Piping Vibration vibration analysis or evaluation.

Baseline data is typically taken at 50%, 75% and 100% of CLTP power. During the ascent to EPU conditions from 100% CLTP, data will be collected at 1% intervals and evaluated every 2.5% increase. Hold points (96 hour0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> minimum) will be established every 5% above CLTP for Plant Operational Review Committee (PORC) and NRC reviews. In the event that measured vibrations at a given power level exceed the acceptance criteria, an evaluation will be performed to disposition the test deficiency. If appropriate, the power level would be reduced to a level where vibration amplitudes were previously shown to be acceptable until the deficiency can be corrected.

Routine measurements of the power-dependent parameters from systems and components affected by the EPU are taken near 90% and 100% of CLTP on a constant flow control line that will be used to increase to maximum EPU power. Power increase is along this constant rod pattern line in incremental steps of 2.5% of CLTP with a power ascension rate of< 1% per hour to ensure a careful, Plant Parameter monitored approach to maximum EPU power. Power-Monitoring and EPU Test 101 dependent parameters that are calculated will be calculated Evaluation using accepted methods to ensure current licensed and operational practice are maintained. Measured and calculated power-dependent parameters are utilized to project those values at the next power level step prior to increasing to the next EPU test condition. Each step's projected values will be evaluated to have satisfactorily confirmed the actual values before advancing to the next step and the final increase to maximum EPU power.

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ATTACHMENT 7 - EPU TEST PLAN Table 7 Planned EPU Power Ascension Testing Title Test Number Test Description Routine measurements and analysis will be performed for core flow, jet pump flow, recirculation loop flow and drive flow, flow control valve operating characteristics, M-ratios, Reactor Recirculation EPU Test 102 core differential pressure and resistance, etc. utilizing N2-System Performance OSP-LOG-DOOl Daily Checks Log, N2-OSP-RCS-@001 RCS Pressure/Temperature Verification, and GAI-REL-09 Jet Pump Performance Monitoring and Cleaning /

Maintenance Determination.

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ENCLOSURE ATTACHMENT 8 Grid Stability Evaluation Nine Mile Point Nuclear Station, LLC May 27, 2009

ATTACHMENT 8 - GRID STABILITY EVALUATION INTRODUCTION This document describes the results of studies that were performed to evaluate the effect of the Nine Mile Point Unit 2 (NMP2) Extended Power Uprate (EPU) on grid stability. The evaluation was based on two separate studies; System Reliability Impact Study (SRIS) - Grid study by the New York Independent System Operator (NYISO) performed in accordance with NYISO/Federal Energy Regulatory Commission (FERC) Open Access Transmission Tariff, Attachment X; Standard Large Facility Interconnection Procedures.

Nine Mile Point 2 Analysis: NRC Application for Power Uprate - An independent grid reliability study commissioned by Constellation to address specific NMP2 offsite power performance requirements.

The uprate will result in an estimated 158 megawatt-electric (MWe) increase in output with a total station gross generation of 1368.9 MWe. This uprate will be achieved primarily by increasing feedwater flow and installing a new high pressure turbine. With the existing 1399.2 Mega Volt Ampere (MVA) rated generator operating at 0.98 power factor (PF), available reactive power output will be reduced from 500 MVAR to approximately 278 Mega Volt Ampere Reactive (MVAR).

Generator output is defined by the reactive capability curve, which is not changing for EPU. To account for seasonal variations in station thermal performance, maximum generator output analyzed in the grid stability study is 1380 MWe and 233 MVAR lagging (0.986 PF).

The estimated inertia constant associated with the new high pressure turbine has been included in the grid models.

The studies incorporated the revised electrical power output of NMP2 and included steady state power flow (thermal and voltage), stability and short circuit analysis using system load, transmission, and generation baselines projected for 2011-2012. Based on the results of these studies, no new or modified transmission facilities are required to support the NMP2 EPU.

ELECTRIC SYSTEM GENERAL DESCRIPTION NMP2 is connected to the transmission grid at Scriba Station through a 25/345 kV main transformer, an onsite 345 kV switchyard and a single 345 kV transmission line. NMP2 and Scriba Station comprise a portion of those concentrated generation and transmission facilities collectively referred to in the studies as the "Oswego Complex." Scriba Station is physically located approximately one-half mile south of NMP2 and is within the NYISO1 control area. The primary transmission owner (TO) is National Grid, LLC (formerly Niagara Mohawk Power Corporation).

Scriba Station is a 345/115 kV Electric Transmission Substation to which six (6) 345kV lines and two (2) 115 kV lines terminate. It interconnects the output of four (4) generation plants; Nine Mile Point Unit 1 (NMP1), NMP2, J.A Fitzpatrick Nuclear Station and Independence Station (formerly Sithe), to the 345kV transmission system.

Scriba Station provides two (2) independent offsite 115 kV sources to NMP2. Each offsite circuit has adequate capacity and capability to supply power to start and operate emergency loads required for safe shutdown of the plant while supplying other connected loads. The offsite power sources are normally connected to the onsite emergency power distribution system and are readily available for accident mitigation. In the event of loss of either offsite source, the associated emergency power distribution system is automatically energized from its dedicated standby diesel generator.

1 Successor to the New York Power Pool (NYPP).

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ATTACHMENT 8 - GRID STABILITY EVALUATION NMP2 Updated Safety Analysis Report (USAR) Figures 8.2-1 and 8.2-9 show the transmission network within the vicinity of NMP2 including Scriba Station and the following transmission lines:

115 kV Line #05 NMP2-Scriba 115 kV Line #06 NMP2-Scriba 0

345 kV Line #09 NMP1-Scriba 345 kV Line #10 J. A. Fitzpatrick-Scriba 345 kV Line #20 Scriba-Volney 345 kV Line #21 Scriba - Volney 345 kV Line #23 NMP2-Scriba 345 kV Line #25 Scriba-Independence The design basis for the electric power system is described in the NMP2 USAR, Section 8.0, "Electric Power."

EVALUATION The System Reliability Impact Study demonstrates conformance of the NMP2 EPU to applicable national and regional reliability council criteria with the increase in generator electrical output. The study was conducted in accordance with applicable NYISO study guidelines, procedures and practices. The study was performed using Siemans PTI's PSSE and MUST software with base-case network models developed by the NYISO for both pre-uprate and post-uprate conditions. Post-uprate NMP2 models incorporated the full EPU output and planned EPU plant modifications. Of the modifications listed in, the only ones having direct impact on the grid models are the high pressure rotor replacement (increased intertia constant) and feedwater system upgrade (increase plant auxiliary load).

System load, transmission, and generation baselines were as projected for summer peak load year 2011, winter peak load 2011/2012, and light load 2011. The study included steady state power flow (thermal and voltage), stability and short circuit analysis. Simulations were performed for normal and extreme contingencies. In addition, several sensitivity cases were developed to evaluate the effect of EPU on grid stability at unusually high power transfer levels.

The technical criteria for evaluating potential reliability impacts identified during development of the SRIS are based on:

NERC Planning Standards2 NPCC criteria and guidelines 3 NYSRC Reliability Rules4 These criteria are supplemented by the NYISO Transmission Planning Guidelines attached to the NYISO Transmission Expansion and Interconnection Manual5. Any potential adverse reliability impact identified by the SRIS that can be managed through the normal operating procedures of the NYISO and transmission owner is not considered a degradation of system reliability or noncompliance with the 2 NERC Planning Standards; North American Electric Reliability Council,, September 1997 3 Basic Criteria for Design and Operation of Interconnected Power Systems (Document A-2); Emergency Operation Criteria (Document A-3); et el. Northeast Power Coordinating Council 4 NYSRC Reliability Rules for Planning and Operating the New York State Power System; New York State reliability Council, Revision I - December 14, 2007 NYISO Transmission Expansion and Interconnection Manual, Manual 23, September 1999 2 of 7

ATTACHMENT 8 - GRID STABILITY EVALUATION NERC, NPCC or NYSRC reliability standards. Based on the results of the SRIS, the NYISO concluded that the uprate does not have a significant impact on steady state power flow, system stability, or short circuit levels. In addition, the study demonstrates that, relative to the analyzed EPU conditions, there are no system stability restrictions for generator output and no transmission system upgrades are required to meet national or regional bulk power system interconnection criteria.

The NMP2 USAR requires that system and generator unit stability be maintained for a defined set of grid disturbances and faults to ensure conformance with General Design Criteria (GDC) 17. To supplement the SRIS, additional study cases were developed to specifically evaluate the impact of EPU on grid stability and offsite source voltages for selected limiting events and conditions consisting of faults with backup clearing, unit trip without fault, and pre-contingency line outages.

The following events were analyzed to evaluate the effect of the uprate project on the NMP2 offsite power supply:

Loss of NMP2 generation Loss of the largest generating unit on the 345 kV system Loss of the most critical 345 kV transmission line due to fault System Faults as described in NPCC Document A-2, "Basic Criteria for Design and Operation of Interconnected Bulk Power Systems," including criteria faults consisting of permanent three-phase normally cleared fault and permanent phase to ground fault with delayed fault clearing.

Specific design criteria of concern relative to this evaluation are associated with the voltage and stability analyses. (Because EPU will be accomplished using the existing main generator and step-up transformers, there will be no change in the short circuit current contribution of NMP2 to system faults and the overall system fault duty is not impacted.)

Voltage - Steady State: Steady-state voltages must remain within the limits established by the NMP2 USAR, NYSRC and transmission owner criteria. For Scriba Station 345 kV, the normal range (base case) is 100% to 105% and the post-contingency range is 95% to 105% of nominal voltage. Post-contingency voltage for Scriba Station 115 kV is also 95% to 105% of nominal.

Voltage - Transient: Transient voltage recovery must coordinate with degraded and loss of voltage relays to preclude inadvertent separation from offsite power due to criteria faults or unit trip.

Stability:

For a transient stability simulation to be deemed stable, oscillations in angle and voltage must exhibit positive damping within 10 seconds after initiation of the disturbance.

Results of the stability studies are summarized below:

Voltage Analysis-Steady State Steady state voltage analyses were performed to evaluate the impact of EPU on the NMP2 offsite 115 kV voltage for a) loss of critical 345 kV transmission lines in the vicinity of the plant, and b) unit trip with transfer of plant auxiliary load to the offsite source. Both summer peak and winter peak load cases were analyzed and results compared for pre-uprate and post-uprate conditions.

The most limiting 345 kV transmission line outage contingency analyzed consists of the concurrent loss of 345 kV Scriba-Fitzpatrick #10 and Scriba-Volney Line #20 with winter peak system load. In this scenario, NMP2 remains on-line and plant auxiliary load on the 115 kV offsite power system is minimal for normal plant operation. Without uprate, results show there is no change between pre-contingency and post-contingency voltages. With uprate, there is about a 0.5% change in voltage between pre-contingency 3 of 7

ATTACHMENT 8 - GRID STABILITY EVALUATION and post-contingency cases involving loss of a critical 345 kV line. Post-contingency steady state voltage is 104.4 percent, and remains well above the low limit of 95 percent.

The impact on the NMP2 offsite power due to the loss of the largest generator was evaluated by considering the trip of NMP2 with the generator modeled at full output. Because it is the largest generating unit connected to the 345 kV bulk power system in the NYISO Control Area (NYCA), and its point of interconnection is Scriba Station, loss of NMP2 generation is the limiting contingency for this part of the evaluation. In addition, this latter contingency results in the transfer of NMP2 auxiliary loads onto the 115 kV offsite source. Based on plant load studies conducted for EPU, maximum load on offsite power occurs for a unit trip without an accident.

Under this scenario, auxiliary load has been conservatively estimated to increase approximately 6 MVA from 102 MVA to 108 MVA (90 MW/60 MVAR).

Table I summarizes the results of the steady state voltage analysis for the limiting cases described above.

Post-contingency voltage is about 2% less than pre-contingency levels; however, the 115 kV voltage following the unit trip is slightly better for the post-uprate case as compared to the pre-uprate base case.

This is because tripping of the unit reduces the voltage drop associated with the total flow of power into the bulk power system at the interconnection point.

Table 1 Scriba 115 kV Voltage (%) -Winter Peak Without Uprate

'With Uprate Pre-:

Post-Pi~e-,

Post- -'

Cont e c Q iningnge n

gec o

neContingency Loss of 345 kV Fitz-105 105 104.9 104.4 Scriba and Scriba-Volney Lines Loss of NMP2 105 102.9 104.9 103 Pre-contingency and post-contingency voltage analyses show that the uprate does not cause any steady state voltage violations.

The studies demonstrate that other generators in the Oswego Complex have sufficient reactive power capacity to compensate for the reduction in MVAR output of NMP2 and no transmission system reinforcements, such as capacitor banks, are necessary to support the NMP2 EPU.

Voltage Analysis-Transient Transient analyses were performed to determine the voltage recovery times for various contingencies including loss of NMP2 generation and loss due to fault of critical 345 kV transmission lines. The reliability of the offsite power sources to the safety related buses will not be adversely impacted if it can be demonstrated that voltage recovery times are coordinated with the safety bus undervoltage protection.

Loss of voltage relays are set to dropout at a voltage of 77% following a three second time delay.

Degraded voltage relays represent the bounding case for voltage recovery based on their higher dropout and reset settings. Minimum dropout setting for the degraded voltage relays is 92.3 % and the maximum reset setting is 95% of rated bus voltage. There are two time delays associated with the degraded voltage relays; 30 seconds for non-LOCA (Loss of Coolant Accident) and eight seconds if a LOCA signal is present. Thus, if the voltage recovers to > 95% within the time delay of the degraded voltage relay (8 seconds), or > 77 % within 3 seconds for the loss of voltage relay, the results are considered acceptable.

Various contingencies were analyzed including: a) a critical 345 kV single line to ground (SLG) fault with back up fault clearing, b) three phase fault on a critical 345 kV line with a 345 kV line out of service pre-event, and c) loss of NMP2 generation without a fault. Results of selected limiting contingencies for 4 of 7

ATTACHMENT 8 - GRID STABILITY EVALUATION summer peak conditions are summarized in Table 2 and show that voltage recovery occurs within one (1) second and the differences between pre-uprate and post-uprate are not significant. Therefore, the ability of the existing plant safety related undervoltage protection to allow for voltage recovery following a plant trip and the clearing of transmission related events is not adversely impacted by EPU.

Table 2 Contingency CE99-SLG with Backup Clearing,--,'

Summer Peak Recovery time to 95 percent nominal Without Uprate With Uprate 0.75 second 0.75 second Three-Phase Fault with Pre-Event Line Out.-Summer Peak (Scriba-Volney #21 OOS/3PH on Scriba-Volney #20)

Recovery time to 95 percent nominal Without Uprate With Uprate 0.1 second 0.15 second Loss of NMP2 Generation,

,Summer Peak Recovery time to 95 percent nominal Without Uprate With Uprate N/A (voltage remains > 95%)

N/A (voltage remains > 95%)

Stability Analysis Stability analysis was performed as part of the SRIS for 2011 summer peak load and 2011 light load conditions. Twenty-three standard NYISO contingencies were performed. All simulations were transiently stable and exhibited positive damping both without and with the uprate.

Simulations for stability analyses were run for loss of the most critical (in relation to NMP2) 345 kV line due to fault with and without the uprate. Several three-phase, normally cleared faults and single-phase faults with backup clearing were evaluated based their expected severity and proximity to NMP2. Of the design contingencies evaluated, the most severe is a single line to ground fault on the nearby 345 kV Scriba-Volney Line #21 with backup clearing by the Fitzpatrick-Scriba Line #10.

This contingency is identified in the SRIS as CE99. Figure 1 shows the reaction of the large generators in the area of NMP2 (the Oswego Complex) for the more limiting light load condition in response to CE99. As shown, all generators exhibit positive damping of oscillations within 10 seconds of fault inception, and the units remain in synchronism. These results demonstrate that under a severe SLG fault with delayed clearing, the system remains stable with NMP2 modeled at full EPU output.

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ATTACHMENT 8 - GRID STABILITY EVALUATION FIGURE 1 Oswego Complex Rotor Angles - Contingency CE99 8

o Lo 0

C) 0, ci.,'

U C) 2-C I

Mo Z C-M C6 l)

Z 0

'i I

I I

i i

I I

og TIME C'(SECONDSi 0 0000

FRI, AUG 24 200'7 10:33 OSWEGO COMPLEX ROTOR ANG.

Light Load Finally, stability response was also analyzed for loss of the largest generating unit in the 345 kV system.

At both pre-and post uprate output, NMP2 is the largest single generating unit within the NYISO control area.

Simulations were run for summer peak and light load for a no-fault loss of NMP2. These study cases were modified to replicate the transfer of plant auxiliary loads to the offsite source following the unit trip. Each case resulted in a stable transient response of the power system with negligible differences between pre-uprate and post-uprate study cases.

CONCLUSIONS Grid studies have been performed to demonstrate conformance of the NMP2 power uprate to national and regional grid reliability planning criteria and plant-specific licensing and design bases. Areas evaluated included steady state power flow (thermal and voltage), stability and short circuit. The studies described demonstrate that with NMP2 dispatched at its full EPU capability:

0 Loss of NMP2 generation will result in a stable grid and offsite power will remain available to support safe shutdown.

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ATTACHMENT 8 - GRID STABILITY EVALUATION Loss of the largest generating unit on the 345 kV bulk power system is bounded by loss of NMP2 generation.

Loss of the most critical 345 kV transmission line due to fault will result in a stable transmission system and NMP2 will remain connected to offsite power.

System Faults as described in NPCC Document A-2, "Basic Criteria for Design and Operation of Interconnected Bulk Power Systems," including criteria faults consisting of permanent three-phase normally cleared fault and permanent phase to ground fault with delayed fault clearing will result in a stable transmission system and NMP2 will remain connected to offsite power.

In summary, grid stability study results have been evaluated and it is concluded that the uprate will not significantly impact the reliability of the bulk power transmission system and the NMP2 115 kV offsite power supply will continue to have adequate capacity and capability to perform its intended function in accordance with GDC-17.

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ENCLOSURE ATTACHMENT 9 Supplemental Environmental Report Nine Mile Point Nuclear Station, LLC May 27, 2009

ATTACHMENT 9 - SUPPLEMENTAL ENVIRONMENTAL REPORT Table of Contents Section 1.0 Executive Summary 2.0 Introduction 3.0 Proposed Action and Need 3.1 Proposed Action 3.2 Need for Action 4.0 Overview of Operational and Equipment Changes 5.0 Socioeconomic Considerations 5.1 Current Socioeconomic Status 5.2 Extended Power Uprate Impacts to Socioeconomics 5.3 Conclusion 6.0 Cost - Benefit Analysis 7.0 Non-Radiological Environmental Impacts 7.1 Terrestrial Impacts 7.1.1 Land Use 7.1.2 Transmission Facilities 7.1.3 Miscellaneous Waste 7.1.4 Noise 7.1.5 Terrestrial Biota 7.2 Aquatic Impacts 7.2.1 Lake Ontario 7.2.2 NMPNS Cooling Water Systems 7.2.3 Consumptive Water Use Impacts 7.2.4 Entrainment and Impingement Impacts 7.2.5 Thermal Discharge Effects 1 of 33

ATTACHMENT 9 - SUPPLEMENTAL ENVIRONMENTAL REPORT Table of Contents (continued)

Section 8.0 Radiological Environmental Impacts 8.1 Radiological Waste Streams 8.1.1 Solid Waste 8.1.2 Liquid Waste 8.1.3 Gaseous Waste 8.2 Radiation Levels and Offsite Dose 8.2.1 Operating and Shutdown In-Plant Levels 8.2.2 Offsite Doses at Power Uprate Conditions 9.0 Environmental Effects of Uranium Fuel Cycle Activities and Fuel and Radioactive Waste Transport 10.0 Effects of Decommissioning 11.0 References 2 of 33

ATTACHMENT 9 - SUPPLEMENTAL ENVIRONMENTAL REPORT List of Tables Table 4-1 Equipment Modifications to Support the NMPNS Unit 2 Extended Power Uprate 5-1 Taxes Paid by Constellation for NMPNS for Tax Years 2006-2011 7-1 SPDES Discharge Limits 7-2 EPU Impact on Thermal Discharge Parameters 8-1 Low-Level Radioactive Waste Shipped from NMPNS Unit 2, 2003-2007 8-2 Liquid Effluent Releases from NMPNS Unit 2, 2003-2007 8-3 Gaseous Effluent Releases from NMPNS Unit 2, 2003-2007 8-4 Maximum Total Annual Dose from All Effluents, 2003-2007 List of Figures Figure 3-1 50-Mile Region 3-2 6-Mile Vicinity 3-3 Site Boundary.

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ATTACHMENT 9 - SUPPLEMENTAL ENVIRONMENTAL REPORT Acronyms and Abbreviations OF degrees Fahrenheit ALARA as low as reasonably achievable AOC area of concern BTU British Thermal Units CFR Code of Federal Regulations cfs cubic feet per second CMP New York State Coastal Management Program CWS circulating water system DAW dry active waste EPU extended power uprate FES Final Environmental Statement fps feet per second FR Federal Register FWS U.S. Fish and Wildlife Service GElS Generic Environmental Impact Statement for the License Renewal of Nuclear Power Plants gpm gallons per minute kV kilovolt LLRW low-level radioactive waste MGD million gallons per day mg/I milligram per liter mrem millirem 4 of 33

ATTACHMENT 9 - SUPPLEMENTAL ENVIRONMENTAL REPORT MWd/MTU MWe MWt NEPA NMP2 NMPNS NRC NYSDEC OLTP PILOT RFO SEIS SPDES USAR WCS megawatt-days per metric tons uranium megawatt electric megawatt thermal National Environmental Policy Act Nine Mile Point Unit 2 Nine Mile Point Nuclear Station U.S. Nuclear Regulatory Commission New York State Department of Environmental Conservation Original Licensed Thermal Power Payment In-Lieu of Taxes Agreement Refueling Outage Supplemental Environmental Impact Statement State Pollution Discharge Elimination System Updated Safety Analysis Report Reactor Water Cleanup System 5 of 33

ATTACHMENT 9 - SUPPLEMENTAL ENVIRONMENTAL REPORT 1.0 Executive Summary This Supplemental Environmental Report contains Nine Mile Point Nuclear Station, LLC's (NMPNS')

assessment of the environmental impacts of the proposed Nine Mile Point Unit 2 (NMP2) extended power uprate (EPU) from 3,467 megawatts-thermal (MWt) to 3,988 MWt. The intent is to provide sufficient information for the U.S. Nuclear Regulatory Commission (NRC) to evaluate the environmental impact of the power uprate in accordance with the requirements of 10 CFR 51.

The environmental impacts of the proposed EPU are described and compared to those previously identified by the NRC in the 1985 Final Environmental Statement for the Operation of the Nine Mile Point Nuclear Station, Unit 2 and the NRC's Supplement 24 of the Generic Environmental Impact Statement for the License Renewal of Nuclear Power Plants (NUREG-1437) issued in 2006 to address the license renewal of Nine Mile Point Units 1 and 2. The comparisons show that the conclusions of the Final Environmental Statement (FES) and NUREG-1437, Supplement 24 remain valid for operation at 3,988 MWt.

The NMP2 EPU would be implemented without making extensive changes to plant systems that directly or indirectly interface with the environment. All necessary modifications would be in existing buildings at NMP2; none would involve land disturbance or new construction outside of the established facility areas. There would be no change in the amount of water withdrawn from Lake Ontario for equipment cooling, and a small increase in the amount of waste heat discharge to Lake Ontario (estimated 2'F).

Generation of low-level radioactive waste would not increase significantly over the current generation rate, and would be bounded by FES values. The change in the volume of radioactive effluents (liquid and gaseous) released to the environment and radioactive content would be proportional to the size of the power uprate, and are bounded by the FES analyses. All offsite radiation doses would remain small and within applicable standards. There would be no impact on the size of the regular workforce.

NMPNS evaluated the compliance requirements associated with implementing the proposed EPU.

NMPNS will maintain compliance with New York State requirements, permits, licenses, and approvals currently held by the Station.

NMPNS concludes that the environmental impacts of operation at 3,988 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.

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ATTACHMENT 9 - SUPPLEMENTAL ENVIRONMENTAL REPORT 2.0 Introduction Nine Mile Point Nuclear Station, LLC is committed to operating Nine Mile Point Nuclear Station in an environmentally responsible manner. Plant activities including design, construction, maintenance, and operations are conducted in a manner so as to protect the environment and responsibly manage natural resources.

NMPNS believes proper care of the environment is essential to the well-being of our corporation, its employees, its neighbors, and the broader global community. NMP2 has operated for more than 22 years in compliance with state and federal environmental regulations, while providing safe, reliable, and economical electrical power to its customers in New York.

In keeping with this commitment to environmental stewardship and in accordance with regulatory requirements, NMPNS has conducted a thorough environmental evaluation of the proposed extended power uprate of NMP2 from 3,467 MWt to 3,988 MWt. This would increase electrical output to 1,369 megawatts-electric (MWe). The proposed uprate would serve the future power requirements of the State of New York and the region.

This environmental evaluation is provided pursuant to 10 CFR 51.41 "Regulations to Submit Environmental Information" and is intended to support the NRC environmental review of the proposed uprate.

The proposed EPU would require the issuance of an operating license amendment.

The regulation (10 CFR 51.41) requires that applications to the NRC be in compliance with Section 102(2) of the National Environmental Policy Act (NEPA). There are no NRC regulatory requirements or guidance documents specific to preparation of environmental reports for EPUs.

In May 1985, the NRC published the Final Environmental Statement Related to the Operation of the Nine Mile Point Nuclear Station Unit 2 (FES; NRC 1985). The NRC concluded that the issuance of the full-term operating license, subject to certain conditions related to monitoring, was the appropriate course of action under NEPA. This decision was based on the analysis presented in the FES and the weight of environmental, economic, and technical information reviewed by the Commission.

It also took into consideration the environmental costs and economic benefits of operating NMP2. The NRC subsequently issued the operating license to NMP2 that authorized operation up to the maximum power level of 3,323 MWt.

In March 1995, the NRC published an Environmental Assessment and Finding of No Significant Impacts in the Federal Register (60 FR 11689-11692) for an increase in the Unit 2 licensed core thermal power from 3,323 MWt to 3,467 MWt, which represented an approximate increase of 4.3% over the original licensed core thermal power.

In May 2006, NRC published Supplement 24 of the Generic Environmental Impact Statement for the License Renewal of Nuclear Power Plants (GEIS) that addressed the license renewal of Nine Mile Point Nuclear Power Station Units I and 2 (NRC 2006). NRC determined that the adverse environmental impacts of license renewal (i.e., operating an additional 20 years) are not so great that preserving the option of license renewal for energy-planning decision makers would be unreasonable.

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ATTACHMENT 9 - SUPPLEMENTAL ENVIRONMENTAL REPORT General information about the design and operational features of NMP2 that are of interest from an environmental impact standpoint is available in several documents.

In addition to the FES and Supplement 24 of the GElS discussed above, another comprehensive source of information is the Updated Safety Analysis Report for NMP2 (USAR; NMPNS 2008a), prepared and maintained by NMPNS.

This Supplemental Environmental Report is intended to provide sufficient detail on both the radiological and non-radiological environmental impacts of the proposed EPU to allow NRC to make an informed decision regarding the proposed action. It does not reassess the current environmental licensing basis or justify the environmental impacts of operating at the current licensed power level of 3,467 MWt. Rather, this document demonstrates that the effects of operating under EPU conditions are bounded by the original analyses documented in the FES, the more recent Supplement 24 of the GElS or by current regulatory limits.

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ATTACHMENT 9 - SUPPLEMENTAL ENVIRONMENTAL REPORT 3.0 Proposed Action and Need The NMP2 site is in the town of Scriba, in the northwest corner of Oswego County, New York, on the south shore of Lake Ontario.

The Unit is situated on approximately 900 acres that include the powerblock area and ancillary facilities. Figures 3-1, 3-2, and 3-3 show the site location and site map.

NMP2 uses a boiling water reactor and a nuclear steam supply system designed by General Electric.

NMPNS operates NMP2 pursuant to NRC Operating License NPF-69, which will expire October 31, 2046. NMP2 received a full-term operating license on July 2, 1987. Approval for operating at 104% of original licensed thermal power (OLTP) was received April 28, 1995, and an extended license on October 31, 2006.

3.1 Proposed Action The proposed action is to increase the licensed core thermal level of the NMP2 from 3,467 MWt to 3,988 MWt, which represents an increase of approximately 15% above the current licensed thermal power or approximately 20% over OLTP. This change in core thermal level would require the NRC to amend the facility's operating license. The operational goal of the proposed EPU is a corresponding increase in electrical output, from 1,211 MWe to 1,369 MWe. The proposed action is considered an extended power uprate by NRC because it exceeds the typical 7% power increase that can be accommodated with only minor plant changes. EPUs are expected to involve significant plant modifications.

NMPNS intends to increase the power by 158 MWe in a single step following the 2012 refueling outage (RFO). This Supplemental Environmental Report evaluates environmental impacts associated with the total increase in thermal power to 3,988 MWt.

3.2 Need for Action The proposed action provides NMPNS with the flexibility to increase the potential electrical output of NMP2 and to supply low cost, reliable, and efficient electrical generation to New York State and the region.

The additional 158 MWe would be enough to power approximately 174,000 homes.

The proposed EPU at NMP2 would contribute to meeting the goals and recommendations of the New York State Energy Plan for maintaining the reserve margin and reducing greenhouse gas emissions with low cost, efficient, and reliable electrical generation.

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ATTACHMENT 9 - SUPPLEMENTAL ENVIRONMENTAL REPORT Figure 3-1 50-Mile Region Cowty Bovdwy SPrdnry Roads With Lkilted Acoess Pdmnry Roads Nine Mie Point Nuclear Station WHidlfe Manega~ent Ansem; ciie Urban, Areas Onrrogadage Indian Reservation

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ATTACHMENT 9 - SUPPLEMENTAL ENVIRONMENTAL REPORT Figure 3-2 6-Mile Vicinity

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ATTACHMENT 9 - SUPPLEMENTAL ENVIRONMENTAL REPORT Figure 3-3 Site Boundary L

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ATTACHMENT 9 - SUPPLEMENTAL ENVIRONMENTAL REPORT 4.0 Overview of Operational and Equipment Changes In general, light water reactors are designed with an as-built equipment capability to increase power up to 7% above the original licensed power level with only minor changes. For power uprates beyond this level, more extensive plant modifications are generally required to increase capability. Table 4-1 lists the modifications needed to implement the proposed EPU at NMP2.

With exception of the high-pressure turbine rotor replacement, the required modifications are generally of relatively small scope. The required modifications listed in Table 4-1 will be accomplished over the next two refueling outages: the Spring 2010 RFO and the Spring 2012 RFO. Other modifications including re-rating various balance of plant valves, piping and heaters, as well as simulator upgrades will be made while the plant is on line. Many of the modifications may be implemented without prior NRC review under 10 CFR 50.59. 10 CFR 50.59 establishes the criteria and record requirements for plant changes, test, and experiments that do not require NRC approval. Therefore, implementation of some of the EPU modifications may proceed in parallel with the NRC review of the EPU license amendment request.

The activities needed to produce thermal power increases are a combination of those that directly produce more power and those that will accommodate the effects of the power increase. The primary means of producing more power are an operational change in reactor thermal-hydraulic parameters and upgrades of the balance of plant capacity by component replacement or modification.

Other changes include replacing the high-pressure turbine, providing additional cooling for some plant systems, modifications to feedwater pumps, modifications to accommodate greater steam and condensate flow rates, and instrumentation upgrades that include replacing parts, changing setpoints and modifying software.

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ATTACHMENT 9 - SUPPLEMENTAL ENVIRONMENTAL REPORT Table 4-1 Equipment Modifications to Support the NMP2 Extended Power Uprate Spring 2010 Refueling Outage Replace Feedwater Heater Drain Pumps and Motors Improve Main Transformer Cooling Spring 2012 Refueling Outage Isolate Abandoned Turbine Building Closed Loop Cooling Loads Increase Generator Bus Duct Cooling Upgrade Feedwater Pumps and Gear Sets Install Additional Turbine Building HVAC Coolers Install shielding around the Standby Gas Treatment Equipment Pipe Support Replacements Replace LP Turbine Cross Around Piping Relief Valves Modify and/or Replace Instrumentation Install Recirc Runback Initiation and Runback Rate Requalification of Feedwater Heaters Replace Low Pressure Turbine Atmospheric Relief Diaphragms Modification to Steam Dryer Replace HP Turbine Rotor Install Piping Vibration Monitoring Program Replace Reactor Feedwater Motor Cable Mitigation System Valve Changes 14 of 33

ATTACHMENT 9 - SUPPLEMENTAL ENVIRONMENTAL REPORT 5.0 Socioeconomic Considerations The proposed EPU at NMP2 would provide economic benefits to the surrounding communities through the continuation of tax revenues, local business revenues funded by EPU installation and continued operation, and continued employment of the local population.

5.1 Current Socioeconomic Status NMPNS currently employs approximately 976 people on a full-time basis and 60 short-term contractors on a regular basis. This workforce is augmented by an additional 1,000 persons on average during regularly scheduled refueling outages. Employment at NMPNS benefits local and regional economies as employee salaries flow through the communities purchasing good and services and contributing income, sales, and personal property taxes. In addition, property taxes paid by NMPNS as the owner of NMP2 are significant. In 2001, NMPNS entered into a Payment In-Lieu of Taxes (PILOT) Agreement with Oswego County, the Town of Scriba, and the City of Oswego School District concerning tax payments for both Units 1 and 2. The terms of the Unit 1 PILOT agreement went into effect on December 10, 2001 and remain in effect through June 30, 2010 for the School District, and December 31, 2010 for the Town and County. The terms of the Unit 2 PILOT agreement remain in effect through June 30, 2011 for the School District, and December 31, 2011 for the Town and County. Beginning in 2002, the agreement set a base level of payments to the taxing entities for each year until 2010 for Unit 1 and until 2011 for Unit 2. The City of Oswego School District, Oswego County, and the Town of Scriba are to receive 57.8%, 37.2%,

and 5.0% of the base payments, respectively.

These were derived from the historical property tax payments made to the taxing entities. The PILOT agreements also set "incentive payments" to be paid to each entity should megawatt production for either Unit 1 or Unit 2 exceed certain annual benchmarks.

Incentive payments are applicable to Unit 1 from 2005 through 2009 and to Unit 2 from 2006 through 2011. Tax payment information including the amounts paid in 2006 and 2007 and estimates of what will be paid through 2011 are displayed in Table 5-1. Communities in the vicinity of NMPNS will continue to benefit from property taxes paid to the local taxing jurisdictions.

Public services such as public education, police and fire protection, roads maintenance, and other municipal services are funded in part through property tax revenues.

5.2 Extended Power Uprate Impacts to Socioeconomics The proposed EPU is not anticipated to affect the size of the regular workforce. Workforce numbers for the 2012 outage, when the majority of the EPU modifications will be completed, will be somewhat larger than previous outages, but would be of short duration and of such a magnitude as to not adversely affect housing availability, transportation services, or public utilities such as public water supply systems in the plant vicinity. Employee incomes and the purchases of goods and services afforded by those incomes along with the personal property taxes paid would continue to contribute positively to the communities in the vicinity of NMPNS. Increasing NMP2's licensed power level would not affect the assessed value of the plant under the PILOT agreement that is in effect through 2011.

Negotiations of a new PILOT agreement will consider the increased value of Unit 2 as a result of the EPU implementation.

The property tax payments made under the terms of the PILOT would continue to represent substantial contributions to the budgets of the taxing jurisdictions.

Payments made to engineering and consulting firms, equipment suppliers, and service industries for implementation of the proposed EPU would have a positive, though unsustained impact on local and regional economies. Additionally, there would be the economic benefit to both the regional and local economies of the enhanced viability of NMP2's long-term operation resulting from the additional electrical generation.

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ATTACHMENT 9 - SUPPLEMENTAL ENVIRONMENTAL REPORT 5.3 Conclusion The socioeconomic impacts of implementing the proposed EPU at NMP2 include the positive contribution to the local and regional economies of payments for goods and services associated with the proposed action.

Additionally, the continuation of employment of the local population with the associated expenditures for goods and services and contributions to income, sales, and property taxes along with the continuation of property tax payments by NMPNS Units 1 and 2 would both positively impact local and regional economies.

Table 5-1 Taxes Paid by Constellation for NMPNS for Tax Years 2006-2011 Unit 1 Property Tax Unit 2 Property Tax Paid Paid a Tax Year

($)

($)

2006 2007 2008 2009 2010 2011 5,250,000 5,350,000 5,350,000 5,350,000 4,000,000 NAb 19,400,000 20,000,000 20,000,000 20,000,000 20,000,000 20,000,000

a.

Year 2009 through 2011 payments are estimated using the maximum incentive payments set in the PILOT agreement for Unit 2.

b.

NA = not available.

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ATTACHMENT 9 - SUPPLEMENTAL ENVIRONMENTAL REPORT 6.0 Cost - Benefit Analysis The largest direct benefit resulting from of the proposed EPU to NMP2's current capacity is the additional supply of more than 158 megawatts of reliable electrical power for residential and commercial customers.

A national comparison of power-producing alternatives indicates that nuclear power generation production costs are approximately 71% of coal-fired power, and 17% of oil-fired power, and 26% of natural gas-fired power production (NEI 2008). Power production costs represent a combination of fuel, operations, and maintenance costs.

A quantitative evaluation of environmental costs of alternatives would not be necessary to recognize that significant environmental impacts would be avoided by implementing an EPU at NMP2 versus other options for additional capacity. Unlike fossil fuel plants, an EPU would not result in significant source of nitrogen oxides, carbon dioxide, or other atmospheric pollutants during normal operations.

Routine operation of NMP2 at EPU conditions would not contribute to greenhouse gases or acid rain. The radiological effects of the uranium fuel cycle are described in 10 CFR 51.51 and 51.52 and are classified as small. The tables in 10 CFR 51.52 bound that associated with the NMP2 EPU. While the proposed action would produce additional spent nuclear fuel, the additional amount would represent an approximate 28% increase in the number of spent fuel assemblies generated over of the remaining life of the plant and would be accommodated by NMPNS's current spent fuel storage strategy.

Based upon these considerations, it is reasonable to conclude the proposed NMP2 EPU would provide an economic advantage over other generation alternatives.

The proposed EPU involves a cost-effective utilization of an existing asset, with relatively minor environmental impact, making it the preferred means of securing additional generating capacity.

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ATTACHMENT 9 - SUPPLEMENTAL ENVIRONMENTAL REPORT 7.0 Non-Radiological Environmental Impacts 7.1 Terrestrial Impacts 7.1.1 Land Use The proposed EPU for NMP2 would not affect land use at the 900-acre site. No new construction is planned outside of existing facilities and no expansion of buildings, roads, parking lots, equipment storage areas, or transmission facilities would be required to support the proposed EPU. The proposed EPU is not expected to involve substantial additional volumes of industrial chemicals, fuels, or lubricants, and as a result, would not require additional space for above-or below-ground storage tanks.

As discussed in Section 5.2, the proposed EPU would not affect the size of the workforce at NMPNS.

Because no land disturbance would be required and because there would be no expansion of the existing workforce, impacts to aesthetic resources and historical/archeological resources would be negligible. The conclusions of the FES and NUREG-1437, Supplement 24 with respect to land use, aesthetics, and historical/archeological resources remain valid for the proposed EPU.

7.1.2 Transmission Facilities The proposed EPU would not require any new transmission lines and would not require changes in the maintenance and operation of existing transmission lines, switchyards, or substations. Right-of-way maintenance practices including vegetation management would not be affected by the proposed EPU.

The only change to transmission facilities would be an increase in current. Voltage would be unchanged.

The proposed EPU would not increase the probability of shock from primary or secondary currents. The increase in electrical power output would cause a corresponding current rise on the transmission system.

However, the increase is within the design margin of the lines. The induced shock analysis performed for license renewal assumed design characteristics for the lines when calculating the potential shock hazard for these lines. As noted in NUREG-1437, Supplement 24, the three single-circuit 345-kV lines that connect NMP Units 1 and 2 to the transmission grid adhere to the National Electric Safety Code's steady state current limit for preventing electric shock (NRC 2006).

The increase in electrical power output would cause a corresponding current rise on the transmission system, and this would result in an increased magnetic field. NMPNS adopts by reference the NRC conclusion that chronic effects of electromagnetic fields on humans are not quantified at this time and no significant impacts to terrestrial biota have been identified (NRC 1996).

7.1.3 Miscellaneous Waste NMPNS reviewed a number of plant systems and associated (non-radiological) discharges for potential effects from the proposed EPU. Chemical discharge limits for primary and secondary outfall systems such as roof drains, yard drains, low-volume waste, and metal cleaning waste are set in the NMPNS State Pollutant Discharge Elimination System (SPDES) permit.

Discharges from these systems are not expected to change under the proposed EPU conditions; therefore, the impact on the environment would not change.

Nonradiological parameters affected by the proposed EPU would remain within the bounding conditions established in the SPDES permit, and as a consequence no significant impacts would result from the operations of NMP2 under proposed EPU conditions.

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ATTACHMENT 9 - SUPPLEMENTAL ENVIRONMENTAL REPORT 7.1.4 Noise The proposed EPU would not produce measurable changes in the character, sources, or intensity of noises generated at NMP2. New equipment necessary to implement the proposed EPU would be installed within existing buildings at NMP2. No significant increase in ambient noise levels is expected inside or outside the plant.

7.1.5 Terrestrial Biota Terrestrial ecological resources on the NMPNS site remain substantially as described by the NRC in NUREG-1437, Supplement 24 (NRC 2006), the source of the following summary description unless otherwise noted. The NMPNS site consists of approximately 900 acres, with over 1 mile of shoreline on Lake Ontario. Approximately 188 acres are used for power generation and support facilities. Much of the remaining area is undeveloped, consisting largely of deciduous forest with some old field and shrubland areas that reflect continuing succession of old fields to secondary forest. Portions of these natural communities, including some of the forested tracts north and south of Lake Road, are wetlands, most likely the result of relatively impermeable glacial till soils that allow perched groundwater to lie at or near ground surface seasonally or during wet years. Animal species found on the NMPNS site are representative of those found within disturbed landscapes of the lower Great Lakes region, and include white-tailed deer (Odocoileus virginianus) and a variety of smaller mammals, reptiles and amphibians.

Correspondence with the U.S. Fish and Wildlife Service (FWS) in connection with the NMP Units 1 and 2 license renewal environmental review indicates that no federally endangered, threatened or candidate species are likely to occur on the NMPNS site with the exception of the Indiana bat and occasional transient individuals of piping plover and (now delisted) bald eagle (NRC 2006, Sections 2.2.1 and 2.2.6).

However, recent onsite surveys indicate that there is low likelihood of occurrence for Indiana Bat and piping plover because there is no suitable habitat on site (UniStar 2008).

EPU would not result in changes that would constitute significant initiators of adverse impact to terrestial ecological resources. In particular, planned construction-related activities primarily involve changes to existing structures, systems, and components internal to existing buildings, would not involve earth disturbance, and would be accomplished during the 2010 and 2012 refueling outages. Most of the changes will be made during the 2012 outage, which will be an extended outage. Though traffic and activity in the developed plant area during the 2012 outage would be somewhat greater than would occur during normal outages, associated changes in potential impact initiators (e.g., noise) would be minor and temporary, with little or no potential adverse impact on wildlife.

There would be no increase in operation-phase employment or noticeable changes in plant activity or external noise environment post-EPU; therefore, no potential for adverse impact on terrestrial ecological resources would exist from these sources. The only notable change in impact initiators identified with respect to terrestrial ecological resources during the operational phase is increased salt deposition on vegetation attributable to operation of the cooling tower at slightly increased cycles of concentration (i.e.,

factor by which total dissolved solids in cooling tower makeup water from Lake Ontario are concentrated in the circulating water system, and thus in cooling tower blowdown and drift). Specifically, technical reviews and analysis indicate that operation post-EPU would result in an increase in cycles of concentration from 3.11 to 3.44 (i.e., a 10.6% increase). In its operation-phase Final Environmental Statement for NMP2, the NRC evaluated impacts of cooling discharges operating at 2.5 cycles of concentration and reported a predicted maximum salt deposition rate of 0.27 pounds/acre/year (NRC 1985, Appendix G, Section 5.1). Scaling from this value to 3.44 cycles of concentration, the estimated maximum deposition rate is approximately 0.4 pounds/acre/year. This estimate is far below the rate of 1-2 kg/ha/mo (65-130 pounds/acre/year) cited by the NRC as levels below which plant damage is not 19 of 33

ATTACHMENT 9 - SUPPLEMENTAL ENVIRONMENTAL REPORT expected (NRC 1999a, Section 5.3.3.2), and is consistent with a generic conclusion of small impact rendered by the NRC for existing plants using closed cycle cooling using fresh water for makeup (NRC 1996, Sections 4.3.4, 4.3.5) and specifically for NMP Units 1 and 2 as a result of the license renewal environmental review (NRC 2006, Section 4.1, page 4-10). NMPNS concludes that adverse impacts on vegetation from increased salt deposition due to EPU, if any, would be small.

7.2 Aquatic Impacts Aquatic ecological resources on and near the NMPNS site potentially affected by the proposed EPU consists solely of those associated with Lake Ontario, the source of cooling water for the plant and the receiving water body for cooling water and process wastewater discharges from NMPNS.

Further, identified impact initiators of potential concern with respect to the lake ecosystem are limited to those associated with post-EPU operation of the NMP2 cooling water systems (i.e., circulating water system and service water system). The following subsections provide a description of Lake Ontario, NMPNS cooling water systems, changes in NMP2 cooling water system operational characteristics as a result of EPU (particularly with regard to cooling water flows and discharge quality), and associated impacts from these changes.

7.2.1 Lake Ontario Lake Ontario and associated water quality and ecological resources in the vicinity of the NMPNS site remain substantially as described by the NRC in its Supplemental Environmental Impact Statement License Renewal of NMP Units I and 2 (i.e., License Renewal SEIS, NRC 2006, Sections 2.2.5 and 4.1),

the source of the following summary description unless otherwise noted.

The smallest and most downstream of the Great Lakes, Lake Ontario has a surface area of approximately 7340 mi 2, length of approximately 190 mi., maximum width of approximately 50 mi., and an average and maximum depth of 283 ft and 802 ft, respectively. The long-term average outflow of Lake Ontario is about 240,000 cubic feet per second (cfs) (IDNR undated). At the NMPNS site, the lake bottom slopes steeply from the shoreline at 5-10% grade, flattens to a 2-3% grade to the 15-foot contour, and to a 4% grade further offshore. Coarse bottom sediments ranging from coarse sand to boulders predominate near shore, grading to finer sediments offshore. Nearshore currents are predominantly eastward.

Nearshore areas of the lake freeze during winter, while deeper offshore waters remain open. The lake exhibits thermal stratification in summer, and ambient temperatures reportedly exceeding 71'F approximately 10 percent of the time during June-September. Ambient lake temperatures range higher; for example, maximum ambient lake temperature in 2003, in August, was approximately 77'F (NRC 2006). More recently the maximum ambient temperature has approached 80'F in July of 2005 and 2006.

As noted in Section 7.2.2, the discharge of cooling water from NMP Units 1 and 2 influence lake surface water temperatures in the site vicinity.

Lake Ontario has exhibited substantially improved water quality in the past 30 years, as indicated by reductions in phosphorus, total dissolved solids, and turbidity (NRC 2006, pg 2-25). Offshore water quality of Lake Ontario is generally considered to be excellent, while inshore waters have been observed to be impacted by inflows from major rivers including the lower Oswego River and Harbor west of the NMPNS site, which was historically listed as an Area of Concern (AOC) by the International Joint Commission because of its contribution to the lake of pollutants from past industrial and municipal discharges (NYSDEC 2006a,b). However, this area was delisted as an AOC in 2006 as a result of significant environmental improvements and high water quality achievements (NYSDEC 2006b).

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ATTACHMENT 9 - SUPPLEMENTAL ENVIRONMENTAL REPORT Improvements in water quality, particularly nutrient load reductions, have allowed the Lake Ontario plankton community to evolve back to a more balanced, oligotrophic community, and have resulted in the return and increased growth of submerged aquatic vegetation, primarily the nuisance filamentous Cladophora spp. Benthic organisms of importance to NMPNS operation include the introduced zebra mussel Dreissena polymorpha, which can clog cooling water systems, for which biocide controls are needed.

The Lake Ontario fish community is in a dynamic state, affected by trophic changes triggered by invasive species as well as through manipulation by agency stocking programs for several salmonid species, including rainbow trout (Oncorhynchus tshawytscha) and coho salmon (Oncorhyhnchus kisutch). An imbalance of predators and prey has resulted, with the important forage species alewife (Alosa pseudoharengus) and rainbow smelt (Osmerus mordax) at low population levels. Abundance of fish in the vicinity of the NMPNS cooling water intakes is indicated by observed impingement rates, which have been highest for alewife, rainbow smelt, and threespine stickleback (Gasterosteus aculeatus), all forage species. Other forage species impinged at NMPNS include gizzard shad (Dorosoma cepedianum) and sculpins (Cottus sp.). Game fish such as small mouth bass (Micropterus dolomieui), white perch (Morone americana), white bass (Morone chrysops), yellow perch (Perca flavescens), lake trout (Salvelinus namaykush), and walleye (Sander vitreus) have also been impinged at NMPNS in relatively low numbers.

Early life stages of alewife have predominated in entrainment samples collected at NMPNS.

There are no known aquatic species federally listed as endangered or threatened in the vicinity of NMPNS, based on consultation with the FWS during the license renewal environmental review (NRC 2006). Further reviews conducted in 2007 and 2008 confirm this conclusion (UniStar 2008).

7.2.2 NMPNS Cooling Water Systems The NMP Units 1 and 2 cooling water systems remain substantially as described by the NRC in its Supplemental Environmental Impact Statement License Renewal of NMP Units 1 and 2 (i.e., License Renewal SEIS, NRC 2006, Sections 2.1.3 and 4.1), and is the source of the following summary description unless otherwise noted.

Cooling water systems for each of the two units consist of a circulating water system, which circulates cooling water through the main condensers to condense steam after it passes through the turbine, and a service water system, which circulates cooling water through heat exchangers that serve various plant components. Both the circulating water system and the service water system for NMIP1 are once-through systems. The service water system for NMP2 is also a once-through system. However, the Unit 2 circulating water system is a closed-cycle system that uses a natural draft cooling tower. A portion of the cooling water from the Unit 2 service water discharge is used to replace evaporative and drift losses from the cooling tower.

NMP Units 1 and 2 each have separate cooling water intake and discharge structures located offshore in Lake Ontario. Onshore, each has a separate screenwell and pumphouse structure. Unit 2 has a fish diversion system at the onshore facility to reduce potential impingement of fish on the intake screens.

The Unit 1 intake and discharge structures are each hexagonally shaped with ports on each of their six sides. The intake structure is located approximately 850 feet offshore at a water depth of approximately 20 feet. The discharge structure is located approximately 335 feet from shore in approximately 12 feet of water. The average rate of inflow into the intake structure for Unit 1 during 2003, a year that is representative of nominal operation, was 264,000 to 289,000 gpm.

Initial velocity of the combined circulating water and service water system effluent the discharge structure is approximately 4 feet per second.

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ATTACHMENT 9 - SUPPLEMENTAL ENVIRONMENTAL REPORT The Unit 2 intake and discharge structures are located generally eastward from those of Unit 1. Two identical intake structures, each having a similar hexagonal design to the Unit 1 intake and discharge structures, are located approximately 950 feet and 1,050 feet offshore. The discharge structure is a two-port diffuser located 3 feet above the bottom approximately 1,500 feet offshore. Because the Unit 2 circulating water system is closed-cycle, flows are substantially less than for Unit 1. During normal operation, an average total flow of 53,600 gpm is withdrawn from the lake, 38,675 for the service water system and makeup to the circulating water system to replace evaporation and drift losses from the cooling tower, and 14,925 gpm for operation of the fish diversion system. The estimated cooling tower evaporation rate ranges from 4,560 gpm to 13,800 gpm, and is dependent on meteorological conditions.

The cooling tower blowdown flow is similarly dependent, and blowdown design flow rate ranges from 8,445 to 20,440 gpm. Actual blowdown rates during current operations are approximately 6,000 gpm.

During icing conditions in winter, approximately 3000 gpm of blowdown is recirculated to the intake structure to prevent ice buildup. Discharge flow from Unit 2 ranges from 23,055 gpm to 35,040 gpm (33.2 - 50.5 MGD) during operation; exit velocity from the diffuser nozzles is approximately 18 feet per second. During normal shutdown, the maximum discharge is approximately 48,800 gpm.

Thermal plume surveys conducted during the first 5 years of Unit 1 operation, before Unit 2 became operational, indicate that the size of the Unit 1 plume, defined as the area or volume within the 2'C (3.6'F) isotherm, varied between 34 and 370 surface acres and 54 and 1,229 acre-feet.

NMPNS conducted thermal plume mapping in Lake Ontario over the areas affected by the Unit 1 and 2 thermal discharges over three consecutive days in October 2007 when the units were operating at full power (OSI 2008). Results were consistent with these previous surveys, and further indicate that Unit 1 is the primary contributor to the combined thermal discharge plume, as there was no specific expression of the Unit 2 discharge observed during any of the three plume mapping surveys.

The Unit 2 circulating water system and service water system are treated with sodium hypochlorite and other oxidants to control biofouling; moluscicides such as EVAC are also applied to control fouling (e.g., from zebra mussels). A variety of other chemical additives are used in the Unit 2 circulating water system to control scaling and corrosion of system components, including corrosion of copper in the main condensers.

Discharge flow and select thermal and chemical parameters of the combined service water and blowdown discharge from Unit 2 is subject to specific limits in the facility's SPDES permit issued by the New York State Department of Environmental Conservation (NYSDEC 2004) as follows:

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ATTACHMENT 9 - SUPPLEMENTAL ENVIRONMENTAL REPORT Table 7-1 SPDES Discharge Limits Parameter Discharge Limits' Flow Discharge Temperature Discharge Temperature Difference Net Addition of Heat Free Available Chlorine Copper, Total Inhibitor AZ8104 Cuprostat pf Phosphorus (as P) pH Total Residual Oxidant

a. Daily maximum unless otherwise specified 72.0 MGD 110OF 30°F 470 million BTU/hr 0.2 mg/l (daily avg), 0.5 mg/i (max.)

0.25 mg/l 8.8 mg/l 19.5 mg/i 0.5 mg/i 6.0 - 9.0 standard units (range) 0.2 mg/1 NMPNS has also received specific New York State Department of Environmental Conservation (NYSDEC) approvals for use of several other water treatment chemicals in the Unit 2 cooling water systems, including biocides (e.g., Stabrex) and deposit control agents, and are subject to use restrictions (e.g., dosages), though not specifically listed in the SPDES permit.

7.2.3 Consumptive Water Use Impacts Technical reviews and analysis indicate that cooling tower makeup water flow post-EPU based on blowdown, windage and drift, and evaporative losses, would increase from approximately 18,000 gpm by 2,000 - 2,500 gpm to approximately 20,000 gpm. However, no change in blowdown flowrate will result from the planned EPU. Therefore, this 2,000 - 2,500 gpm increase represents consumptive use of water from the Lake (e.g., from increased evaporative losses).

This loss is miniscule compared to the approximate long-term average outflow of Lake Ontario of 240,000 cfs (Section 7.2.1).

NMPNS concludes that this impact is small, consistent with the generic conclusion of small impact rendered by the NRC for existing plants using closed cycle cooling on large water bodies [10 CFR 51, Subpart A, Appendix B, (Table B-i)]

7.2.4 Entrainment and Impingement Impacts As indicated in Section 7.2.3, EPU' is expected to result in a 2000 - 2,500 gpm increase in cooling tower makeup. However, this makeup water is drawn entirely from service water discharge (Section 7.2.2), and service water intake flows will remain unchanged by EPU. As a result, there will be no increase in cooling water withdrawn from the NMP2 intake structure. NMPNS concludes that no increase in impingement would result from EPU and the increase in entrainment losses, if any, would be very small, and remain consistent with the NRC's conclusion of small impact as a result of the NMPNS license renewal environmental review (NRC 2006, Sections 4.1.1 and 4.1.2.).

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ATTACHMENT 9 - SUPPLEMENTAL ENVIRONMENTAL REPORT 7.2.5 Thermal Discharge Effects Technical reviews and analysis indicate that the combined service water and blowdown discharge from NMP2 would remain compliant with current SPDES limits for both thermal and physical-chemical parameters during both normal operation and normal shutdown conditions such that no SPDES permit modification would be necessary. For thermal parameters specifically listed in the current SPDES permit, the maximum values for current operations and maximum projected values for operations under EPU conditions are as follows:

Table 7-2 EPU Impact on Thermal Discharge Parameters Normal Operationa Normal Shutdowna Parameter Current Post-EPU Current Post-EPUa Discharge Temperature ('F) 98 100 109 109 Discharge Temperature Difference (0F) 25 25 Summer 14 16 Winter 17 19 Net Addition of Heat (million BTU/hr) 3 8 9 b 389 b Summer 350 400 Winter 170 200

a.

Design maximum daily average values unless otherwise specified.

b.

Heat discharge for normal-mode shutdown with one residual heat removal system heat exchanger; alternate shutdown mode with two residual heat exchangers results in discharge of 559 million BTU/hr both pre-and post EPU. While this value exceeds the BTU limit in the current SPDES permit, management controls would be used to maintain the addition of heat to the lake to within established permit limits.

As noted, during normal operation, discharge temperature is expected to increase by only 2°F, and heat addition is expected to increase by 30-50 million BTUs/hour, all well within existing SPDES limits. No increase in maximum values for these parameters is expected to result from EPU in a normal shutdown mode.

Modeling of the thermal plume in 2007 indicates that the minor increase in thermal discharge attributable to EPU operations does not appreciably increase the size of the combined Unit 1 and 2 thermal plume.

NMP1 is the primary contributor to the combined thermal discharge plume and masks the expression of the NMP2 plume.

Technical reviews and analysis similarly indicate that limits for chemical parameters in the permit would not be exceeded, though adjustments in feed rates and other management controls may be required. Any such adjustments requiring water treatment chemical approvals would be sought and obtained from NYSDEC in full compliance with SPDES regulations.

Considering the small increase in discharge temperature and heat addition expected, continued conformance with current SPDES permit limits established to be protective of water quality and biota, NMPNS concludes that any associated adverse impacts would be small and well within acceptable limits.

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ATTACHMENT 9 - SUPPLEMENTAL ENVIRONMENTAL REPORT 8.0 Radiological Environmental Impacts 8.1 Radiological Waste Streams The radioactive waste systems at NMP2 are designed to collect, process, and dispose of radioactive wastes in a controlled and safe manner. The design basis for these systems during normal operations is to limit discharges in accordance with 10 CFR 50, Appendix I. Adherence to these limits and objectives would continue under the proposed EPU.

Operation at the proposed EPU conditions would not result in any physical changes to the solid waste, liquid waste, or gaseous waste systems. The safety and reliability of these systems would be unaffected by the proposed EPU. Also, the proposed action would not affect the environmental monitoring of any of these waste streams or the radiological monitoring requirements of the NMPNS Radiation Protection Program.

Under normal operating conditions, the proposed action would not introduce any new or different radiological release pathways and would not increase the probability of an operator error or equipment malfunction that would result in an uncontrolled radioactive release from the radioactive waste streams. Attachment 11, Section 2.5.5, "Waste Management Systems" provides a detailed evaluation of effects that the proposed EPU may have on the solid, liquid and gaseous radioactive waste systems. The following subsections summarize the conclusions of these sections and compare the results against the impacts of the radiological waste system documented in the FES.

8.1.1 Solid Waste Solid radioactive waste streams include filter sludge, spent ion exchange resin, and dry active waste (DAW). DAW includes paper, plastic, wood, rubber, glass, floor sweepings, cloth, metal, and other types of waste routinely generated during site maintenance and outages. Table 8-1 presents the annual volume of low-level radioactive waste (LLRW) shipped at NMP2 for the most recent five-year period.

Table 8-1 Low-Level Radioactive Waste Shipped from NMP2, 2003 - 2007 Year Volume Shipped (M3) 2003 315 2004 987 2005 425 2006 740 2007 771 Sources: NMPNS 2004, 2005, 2006, 2007, 2008b m3= cubic meter.

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ATTACHMENT 9 - SUPPLEMENTAL ENVIRONMENTAL REPORT 1, Section 2.5.5.3, "Solid Waste Management Systems" provides an evaluation of effects the proposed EPU may have on the solid waste management system. This evaluation indicated that the EPU does not affect DAW generation. The effect of the EPU is primarily from increased load on the reactor water cleanup system (WCS) and condensate demineralizers.

The increased demineralizer loads are expected to increase volumes of spent ion exchange resins and filter sludge. Technical analysis indicates that the estimated increase in solid radioactive waste is 7%. As noted in Table 8-1, the generation volumes are well below the annual design generation rate of 1,100 cubic meters (39,630 cubic feet) reported in the operating license stage environmental report (Niagra Mohawk 1972) and evaluated by NRC in the FES. A 7% increase as a result of the proposed EPU would remain bounded by the FES evaluation. The proposed EPU would result in a small increase in the equilibrium radioactivity in the reactor coolant which in turn would impact the concentrations of radioactive nuclides in the waste disposal systems. Section 8.2 addresses the impact of the increase in activity on dose.

8.1.2 Liquid Waste Liquid radioactive wastes include liquids from various equipment drains, floor drains, containment sumps, chemistry laboratory, laundry drains, and miscellaneous sources.

Table 8-2 presents liquid releases from NMP2 for the most recent five-year period. As noted in Table 8-2, 1.49 million liters of liquid and 45.7 millicuries of fission and activation products were released in the year 2006. NMPNS assumes the volume to be valid for future normal operations, because as indicated in Attachment 11, Section 2.5.5.2, "Liquid Waste Management System" the proposed EPU implementation would not significantly increase the inventory of liquid normally processed by the liquid waste management system.

This conclusion is based on the fact that system functions are not changing and the volume inputs will increase less than i0%, which is not an appreciable increase when compared to the liquid radwaste system capacity. The proposed EPU would result in a small increase in the equilibrium radioactivity in the reactor coolant which in turn would impact the concentrations of radioactive nuclides in the waste disposal systems.. However, the releases would remain bounded by the FES (NRC 1985), which estimated liquid effluent releases, excluding tritium, of about 0.27 curies per year. The FES estimated about 52 curies of tritium per year would be released from the NMP2. Section 8.2 addresses the impact of increase activity on dose.

Table 8-2 Liquid Effluent Releases from NMP2, 2003 - 2007 Volume Released Activity Released Tritium Year (liters)

(Ci)

(Ci) 2003 1,400,000 9.26E-02 9.30 2004 970,200 2.14E-02 5.80 2005 0

0 0

2006 1,493,000 4.57E-04 6.9 2007 0

0 0

Sources: NMPNS 2004, 2005, 2006, 2007, 2008b.

Ci = curries.

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ATTACHMENT 9 - SUPPLEMENTAL ENVIRONMENTAL REPORT 8.1.3 Gaseous Waste Gaseous radioactive wastes principally include radioactive gases extracted from the steam condenser.

Table 8-3 presents gaseous releases from NMP2 for the most recent five-year period. The evaluation presented in Attachment 11, Section 2.5.5.1, "Gaseous Waste Management Systems" indicates that the plant gaseous waste licensing basis and the associated design criteria are unchanged by the EPU. Under EPU operating conditions, the plant will continue to satisfy this licensing basis under EPU operating conditions and will remain bounded by the FES (NRC 1985), which estimated gaseous effluent releases of about 45,000 curies per year for noble gases, 5.63 curies per year for iodines, 0.005 curies per year for particulates, and 52 curies per year for tritium. Beginning in 2002, NMPNS began to pursue an initiative to work toward being a zero-discharge facility for liquid radioactive waste. As shown in Table 8-2, liquid effluents were progressively reduced beginning in 2003 down to achieving zero discharges in 2005.

These results are reflected in the corresponding increases in gaseous effluent tritium concentrations over that evaluated in the FES. During Years 2003, 2004 and 2006, when liquid effluents were managed as designed and evaluated by NRC in the FES, tritium concentrations are bounded by the FES. Section 8.2 addresses the impact of increase activity due to EPU operations on the offsite radiation dose.

Table 8-3 Gaseous Effluent Releases from NMP2, 2003 - 2007 Noble Gases lodines Particulates Tritium Year (Ci)

(Ci)

(Ci)

(Ci) 2003 250.5 3.1OE-04 1.68E-03 66.2 2004 62.1 2.28E-04 1.29E-03 70.4 2005 174.7 4.39E-04 4.04E-04 134.0 2006 77.2 2.79E-04 2.96E-03 49.2 2007 413 1.68E-03 5.27 138.4 Sources: NMPNS 2004, 2005, 2006, 2007, 2008b.

Ci = curries.

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ATTACHMENT 9 - SUPPLEMENTAL ENVIRONMENTAL REPORT 8.2 Radiation Levels and Offsite Dose 8.2.1 Operating and Shutdown In-Plant Levels In-plant radiation levels and associated doses are controlled by the NMPNS Radiation Protection Program to ensure that internal and external radiation exposures to station personnel, contractor personnel, and the general population will be as low as reasonably achievable (ALARA), as required by 10 CFR 20.

NMPNS has a policy of maintaining occupational dose equivalents to the individual and the sum of dose equivalents received by all exposed workers to ALARA levels. 1, Section 2.10.1, "Occupational and Public Radiation Doses" provides a detailed analysis of the impact of the proposed EPU on radiation levels and shielding adequacy and the resulting occupational dose. The analysis considered the impact of increasing the core power level on neutron flux and gamma flux in and around the core, fission product and actinide activity inventory in the core and spent fuels, the Nitrogen-16 Isotope (N-16) source in the reactor coolant, neutron activation source in the vicinity of the reactor core, and fission/corrosion products activity in the reactor coolant and downstream systems. The results indicate that in-plant radiation sources are anticipated to increase linearly with the increase in core power level (approximately 15% current licensed thermal power), except for N-16 which is expected to increase approximately 30% due to increase steam flow and pressure in some components, which in turn reduces the transit and decay times for short-lived isotopes such as N-16. Shielding is used throughout NMP2 to protect personnel against radiation emanating from the reactor and their auxiliary systems and to limit radiation damage to operating equipment. NMPNS has determined that the current shielding designs would be adequate for the increase in radiation levels that may occur after the proposed EPU. The increase is offset by:

a. conservative analytical techniques typically used to establish shielding requirements,

b. conservatism in the original "design basis" reactor coolant source terms used to establish the radiation zones, and

c.

Technical Specifications that limit the reactor coolant concentrations to levels below or equal to the original design basis source terms.

For conservatism, many aspects of NMP2 were originally designed for higher-than-expected radiation sources. Thus, the increase in radiation levels would not affect radiation zoning or shielding in the various areas of NMP2 because it is offset by conservatism in the original design, source terms used, and analytical techniques. Therefore, no new dose reduction programs are planned and the ALARA program would continue in its current form.

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ATTACHMENT 9 - SUPPLEMENTAL ENVIRONMENTAL REPORT 8.2.2 Offsite Doses at Power Uprate Conditions 1, Section 2.10.1, "Occupational and Public Radiation Doses," provides an analysis of the impact of the proposed EPU on offsite doses.

The primary sources of normal operation offsite dose at NMP2 are airborne release from the Offgas System and gamma shine from the plant turbines. Implementation of EPU could increase components of offsite dose due to releases of gaseous and liquid effluents by up to 20%. The component of offsite dose due to N-16 (skyshine) could increase by as much as 30%. These increases would not have a significant increase on present offsite doses shown in Table 8-4, and the increase in offsite dose under EPU operations is expected to be less than lmrem per year. Therefore, offsite doses would remain within the limits of 10 CFR 20, 10 CFR 50, Appendix I and 40 CFR 190.

Table 8-4 Maximum Total Annual Dose from All Effluents, 2003-2007 (Most Likely Exposed Member of the Public, mrem) 2003 2004 2005 2006 2007 Organ (thyroid) 4.21E-02 1.12E-01 1.55E-01 9.28E-02 9.32E-02 Whole Body 1.9 1.80E-01 1.51 2.01 1.52 Sources: NMPNS 2004, 2005, 2006, 2007, 2008b.

mrem = millirem.

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ATTACHMENT 9 - SUPPLEMENTAL ENVIRONMENTAL REPORT 9.0 Environmental Effects of Uranium Fuel Cycle Activities and Fuel and Radioactive Waste Transport 10 CFR 51.51 (Table S-3) provides the basis for evaluating the contribution of the environmental effects of the uranium fuel cycle to the environmental impacts of licensing a nuclear power plant. 10 CFR 51.52 (Table S-4) describes the environmental impacts of transporting nuclear fuel and radioactive wastes. The tables were developed in the 1970s. Since that time, most plants have increased both their uranium-235 enrichment and the fuel's burnup limits.

In 1988, the NRC generically evaluated the impacts of extended burnup fuel and increased enrichment on the uranium fuel cycle, including transportation of nuclear fuel and wastes, to determine whether higher burnup and enrichment could result in environmental impacts greater than those derived in Tables S-3 and S-4. The environmental assessment and finding of no significant impact (53 FR 6040, February 29, 1988) concluded that burnup limits of up to 50,000 megawatt-days per metric ton of uranium (MWd/MTU) or higher (as long as the maximum rod average burnup level of any fuel rod is no greater than 60,000 MWd/MTU) and uranium-235 enrichment up to 5 weight percent would have no significant adverse environmental effects on the uranium fuel cycle or the transport of nuclear fuel and wastes, and would not change the impacts presented in Tables S-3 and S-4.

In 1999, in connection with the Generic Environmental Impact Statement for License Renewal of Nuclear Power Plants, the NRC reviewed transporting higher enrichment and higher bumup fuel to a geologic repository (NRC 1999b). The conclusion of that evaluation was that Table S-4 applies to spent fuel enriched up to 5% uranium-235 with average burnup for the peak rod to current levels approved by NRC up to 62,OOOMWd/MTU, provided higher burnup fuel is cooled for at least 5 years before being shipped.

The additional energy requirements for EPU are met by an increase in bundle enrichment, an increase in the reload fuel batch size, and/or changes in the fuel loading pattern to maintain the desired plant operating cycle length. NMP2 is currently licensed to use uranium-dioxide fuel that has a maximum enrichment of 4.95% by weight uranium-235. The typical average enrichment is approximately 4.20% by weight uranium-235. For the proposed action, the uprate core design would use a somewhat higher fuel enrichment (4.36%), which remains within the licensed maximum enrichment. The EPU fuel batch size will increase from 276 bundles to 352 bundles. The peak batch exposure would be approximately 48,000 MWd/MTU with no fuel pellets exceeding the maximum fuel rod limit of 70,000 MWd/MTU. Reload design goals would maintain the NMP2 fuel cycles within the limits bounded by the impacts analyzed in Tables S-3 and S-4. Therefore, NMPNS concludes that impacts to the uranium cycle and transport of nuclear fuel from the proposed action would be insignificant and not require mitigation.

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ATTACHMENT 9 - SUPPLEMENTAL ENVIRONMENTAL REPORT 10.0 Effects of Decommissioning The FES for NMP2 did not evaluate the environmental effects of decommissioning. In 1988, NRC published the Final Generic Environmental Impact Statement on Decommissioning of Nuclear Facilities (NUREG-0586; NRC 1988) that discusses decommissioning of nuclear power plants. Procedures for decommissioning a nuclear power plant are found in federal regulations at 10 CFR 50.75, 50.82, 51.23, and 51.95.

Prior to any decommissioning activity at NMP2, NMPNS would submit a post-shutdown decommissioning activities report to describe planned decommissioning activities, any environmental impacts of those activities, a schedule, and estimated costs. Implementation of an EPU does not affect NMPNS's ability to maintain financial reserves for decommissioning.

The potential environmental impacts on decommissioning associated with the proposed EPU would be due to the increased neutron fluence. As a result, the amount of activated corrosion products could increase, and consequently, the post-shutdown radiation levels could increase.

NMPNS expects the increases in radiation levels as a result of operations under the proposed EPU conditions to be insignificant, and would be addressed in the post-shutdown decommissioning activities report.

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ATTACHMENT 9 - SUPPLEMENTAL ENVIRONMENTAL REPORT 11.0 References IDNR (Indiana Department of Natural Resources). no date. Regulation of Great Lakes Lake Levels.

http://www.in.gov/dnr/water/9641.htm accessed September 8, 2008.

Niagara Mohawk Power Corporation.

1972. Applicant's Environmental Report Operating License Stage Conversion to Full-term Operating License. Nine Mile Point Nuclear Station Unit 1.

U.S. Atomic Energy Commission Docket No. 50-220. June.

NEI (Nuclear Energy Institute). 2008. "U.S. Electricity Production Cost, 1995-2007. Updated May.

NMPNS (Nine Mile Point Nuclear Station). 2004.

"Nine Mile Point Nuclear Station - Unit 2 Radioactive Effluent Release Report, January - December 2003". Lycoming, New York. May 1.

NMPNS (Nine Mile Point Nuclear Station). 2005.

"Nine Mile Point Nuclear Station - Unit 2 Radioactive Effluent Release Report, January - December 2004". Lycoming, New York. May 1.

NMPNS (Nine Mile Point Nuclear Station). 2006.

"Nine Mile Point Nuclear Station - Unit 2 Radioactive Effluent Release Report, January - December 2005". Lycoming, New York. May 1.

NMPNS (Nine Mile Point Nuclear Station). 2007.

"Nine Mile Point Nuclear Station - Unit 2 Radioactive Effluent Release Report, January - December 2006". Lycoming, New York. May 1.

NMPNS (Nine Mile Point Nuclear Station). 2008a. Nine Mile Point Nuclear Station Unit 2 Updated Safety Analysis Report. Revision 18. Syracuse, New York. October.

NMPNS (Nine Mile Point Nuclear Station). 2008b.

"Nine Mile Point Nuclear Station - Unit 2 Radioactive Effluent Release Report, January - December 2007". Lycoming, New York. May 1.

NRC (U.S. Nuclear Regulatory Commission). 1985.

Final Environmental Statement related to the operation of Nine Mile Point Nuclear Station Unit No. 2. Docket No. 50-410.

Office of Nuclear Reactor Regulation. May 1985.

NRC (U.S. Nuclear Regulatory Commission). 1988. Final Generic Environmental Impact Statement on Decommissioning of Nuclear Facilities. NUREG-0586.

Office of Nuclear Regulatory Research. Washington, D.C. August.

NRC (U.S. Nuclear Regulatory Commission).

1996. Generic Environmental Impact Statement for License Renewal of Nuclear Plants. NUREG-1437. Office of Nuclear Regulatory Research.

Washington, D.C. May.

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ATTACHMENT 9 - SUPPLEMENTAL ENVIRONMENTAL REPORT NRC (U.S. Nuclear Regulatory Commission). 1999a.

Standard Review Plans for Environmental Reviews for Nuclear Power Plants. NUREG-1555.

Office of Nuclear Reactor Regulation.

October 1999.

NRC (U.S. Nuclear Regulatory Commission).

1999b. Generic Environmental Impact Statement for License Renewal of Nuclear Plants. Section 6.3, "Transportation," and Table 9-1, "Summary of Findings on NEPA Issues for License Renewal of Nuclear Power Plants." NUREG-1437, Vol.

1, Addendum 1. Office of Nuclear Reactor Regulation. Washington, D.C. August.

NRC (U.S. Nuclear Regulatory Commission). 2006. Generic Environmental Impact Statement for License Renewal of Nuclear Plants - Supplement 24 Regarding Nine Mile Point Nuclear Station, Units 1 and 2. NUREG-1437 Supplement 24. Office of Nuclear Reactor Regulation. May 2006.

NYSDEC (New York State Department of Environmental Conservation).

2004.

State Pollutant Discharge Elimination System Permit No. NY0001015 Nine Mile Point Nuclear Station.

Effective dated December 1, 2004.

NYSDEC (New York State Department of Environmental Conservation). 2006a. New York State Water Quality Section 305b Report 2006.

Accessed from http://www.dec.ny.gov/chemical/23837.html. September 8, 2008.

NYSDEC (New York State Department of Environmental Conservation).

2006b.

Oswego River Remedial Action Plan Stage 3 Delisting.

January 2006.

Accessed from http://www.dec.ny.eov/lands/25587.htm. September 8, 2008.

OSI (Ocean Surveys, Inc.). 2008. Thermal Discharge Plume Characterization Nine Mile Point Nuclear Station Units 1 and 2 Lake Ontario, Oswego, New York. OSI Report No. 07ES082. Final Report. March 27, 2008.

UniStar (UniStar Nuclear Energy). 2008. Nine Mile Point 3 Nuclear Power Plant, Combined License Application, Part 3: Environmental Report. Rev 0. July.

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APPENDIX A TO ATTACHMENT 9 - COASTAL MANAGEMENT PROGRAM CONSISTENCY DETERMINATION New York has an approved coastal zone management program documented by the U.S. Nuclear Regulatory Commission (NRC) (NRC 1999a).

Nine Mile Point Nuclear Station (NMPNS) has determined that the proposed Nine Mile Point Unit 2 (NMP2) extended power uprate (EPU) complies with the New York-approved coastal management program and will be conducted in a manner consistent with such program.

Proposed Action NMPNS operates NMP2 pursuant to NRC Renewed Operating License NPF-69.

NMP2 received a full-term operating license on July 2, 1987. Approval for operating at 104% of original licensed thermal power (OLTP) was received April 28, 1995, and an extended license on October 31, 2006. NMPNS is applying to the NRC for an increase in the licensed core thermal level of the NMP2 from 3,467 megawatt thermal (MWt) to 3,988 MWt, which represents an increase of approximately 15% above the current licensed thermal power or approximately 20 percent above OLTP. This change in core thermal level would require the NRC to amend the facility's operating license. The operational goal of the proposed EPU is a corresponding increase in electrical output, from 1,211 MWe to 1,369 MWe.

The proposed action provides NMPNS with the flexibility to increase the potential electrical output of NMP2 and provides low cost, reliable, and efficient electrical generation supply for New York State and the region.

Station Description and Required Modifications NMP2 is located on the southern shore of Lake Ontario in the Town of Scriba, in the northeastern corner of Oswego County, New York, approximately 36 miles north-northwest of the City of Syracuse and 65 miles east of Rochester. The Plant is situated on approximately 900 acres that include the powerblock area and ancillary facilities. Figures 1 through 3 show site features and site location.

NMP2 utilizes a boiling water reactor and a nuclear steam supply system designed by General Electric.

The activities needed to produce thermal power increases are a combination of those that directly produce more power and those that will accommodate the effects of the power increase. The primary means of producing more power are an operational change in reactor thermal-hydraulic parameters and upgrades of the balance of plant capacity by component replacement or modification.

Other changes include replacing the high-pressure turbine, providing additional cooling for some plant systems, modifications to feedwater pumps, modifications to accommodate greater steam and condensate flow rates, and instrumentation upgrades that include replacing parts, changing setpoints and modifying software. The required modifications will be completed during the 2010 and 2012 refueling outages. Most of the modifications may be implemented without prior NRC review under 10 CFR 50.59.

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APPENDIX A TO ATTACHMENT 9 - COASTAL MANAGEMENT PROGRAM CONSISTENCY DETERMINATION Figure 1 50-Mile Region County Bondary Prinry Roads With United AcOess Primary Roads Nine Mile Poin Nuclear Station Wildliffe Manageneerd Areas Cwater Citie 8

0 86 1

Watls 2 of 11

APPENDIX A TO ATTACHMENT 9 - COASTAL MANAGEMENT PROGRAM CONSISTENCY DETERMINATION Figure 2 6-Mile Vicinity JVVateffrojectReAP I WO 1 878_ Con stellabon% I l 3-3 of 11

APPENDIX A TO ATTACHMENT 9 - COASTAL MANAGEMENT PROGRAM CONSISTENCY DETERMINATION Figure 3 Site Boundary

.g.,

p.F i U

+

1,40 Site Boundary 1,400 700 0

1,400 Feet Nine Mile Point Nuclear Station, LLC Scribae New York Figure Number 430 215 0

430 Meters CALE 03,,OZ TO.

33 Ir-15JIY N11DZ19 nle8"£-14 4 of ll

APPENDIX A TO ATTACHMENT 9 - COASTAL MANAGEMENT PROGRAM CONSISTENCY DETERMINATION Cooling Water Systems and Station Water Use The NMPNS cooling water systems include a circulating water system (CWS) and a service water system. The CWS circulates cool water through the main condensers to condense steam after it passes through the turbine. The service water system circulates cooling water through heat exchangers that serve various plant components. The service water system for NMP2 is a once-through system. However, the NMP2 CWS is a closed-cycle system that uses a Cooling Tower. A portion of the discharge from the service water system is added to the CWS to make up for losses due to evaporation and drift from the Cooling Tower. The cooling water systems of both NMP1 and NMP2 withdraw water from Lake Ontario and discharge back to the Lake.

NMPNS uses sodium hypochlorite and other oxidants to control biofouling in the cooling and service water systems that discharge to offsite surface waters. NMPNS also treats the systems with molluscicides as specified in the State Pollutant Discharge Elimination System (SPDES) permit to control zebra mussel infestations in these systems. The Wastewater Treatment Chemicals are controlled in accordance with the SPDES Pemit. All outfalls permitted under the site's current SPDES permit discharge to Lake Ontario.

The closed-loop CWS for NMP2 employs a wet-evaporative, 541 foot-high natural draft cooling tower with a counter-flow design. The CWS uses the service water system as a makeup source. Two identical submerged intake structures are located approximately 1,000 feet from the existing shoreline in Lake Ontario. Each Intake Structure is hexagonal, with a 7.5-foot wide by 3 foot high intake opening on each side, and a 1.6 foot-thick roof or velocity cap. The openings are equipped with vertical bar racks that have 10 inches of clear spacing between the bars to prevent large debris from entering the intake system.

Each bar rack consists of nine vertical bars for each opening, of which seven are electronically heated to eliminate the potential for frazil ice adhesion. Each Intake Structure is independently connected to the onshore screenwell by a 4.5-foot diameter concrete intake tunnel. At the onshore screenwell, each intake tunnel connects to a separate vertical shaft. Intake water travels at a velocity of approximately three feet per second (fps) in the intake tunnel and approximately one fps in the vertical shafts. After passing through the two vertical shafts, the water enters the onshore Screenwell Building where the shafts merge into a common Intake Forebay, which has two four-foot-wide screenbays at the downstream end. Each screenbay has an angled, flush-mounted traveling screen with up-and downstream trash racks. NMP2 is equipped with a fish diversion system which transports fish from the forebay to the Lake, minimizing the number of fish impinged upon the traveling screens. During normal operation, an average total flow of 53,600 gallons per minute is withdrawn from the lake: 38,675 gallons per minute for the service water system and 14,925 gallons per minute for the fish diversion system. The closed-loop CWS uses discharge from the service water system for its makeup requirements. The CWS is designed to convey 580,000 gallons per minute of cooling water between the main condenser and the Cooling Tower. Meteorological conditions affect makeup flow to the CWS and blowdown rates. The Cooling Tower blowdown flow design rate ranges from 8,445 to 20,440 gallons per minute (gpm); however, the station controls blowdown flow rates to approximately 6,000 gpm. Cooling Tower makeup flow under EPU operating conditions considering blowdown, windage and drift, and evaporative loses, would increase by 2,000 gpm

- 2,500 gpm from approximately 18,000 gpm to approximately 20,000 gpm. However, no change in blowdown flowrate will result from the planned EPU. Therefore, this increase represents consumptive use of the Lake (i.e., evaporative losses), which is miniscule compared to the long-term average outflow of Lake Ontario of 240,000 cfs. The increase in makeup water required under EPU conditions will be drawn entirely from the service water discharge, and service water intake flows remain unchanged by EPU. Therefore, there is no increase in cooling water withdrawn for NMP2 to support operations under EPU conditions.

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APPENDIX A TO ATTACHMENT 9 - COASTAL MANAGEMENT PROGRAM CONSISTENCY DETERMINATION The NMP2 combined plant discharge flow ranges from a minimum of 23,055 gallons per minute to a maximum of 35,040 gallons per minute during normal operation. The discharge flow consists of that portion of service water not used for makeup to the CWS and a portion of the circulating water flow that is discharged to maintain dissolved solids at an appropriate equilibrium in the system. The NMP2 discharge system consists of an onshore discharge bay, a discharge tunnel extending 1,500 feet from the existing shoreline into the Lake, and a two-port diffuser located about three feet from the lake bottom.

Discharge velocity at the diffuser nozzles is approximately 18 feet per second. The current SPDES permit allows a maximum daily discharge temperature of 1 10'F and a maximum allowable intake-discharge temperature difference of 300F. Under EPU operating conditions, the discharge temperature is expected to increase by only 20F and heat addition is expected to increase by 30-50 million BTUs/hour, all well within existing SPDES limits.

Workforce NMPNS employs a permanent workforce of approximately 976 employees with the majority of the workforce residing in Oswego and Onondaga Counties. The site workforce increases by as many as 1,000 workers for temporary (30 to 40 days) duty during staggered refueling outages that occur about every 24 months for each unit.

The majority of the activities to complete the EPU modifications are scheduled for the 2012 Refueling Outage that will require a somewhat larger outage workforce.

Transmission System Power output from NMP2 is connected to the grid by three single-circuit 345-kilovolt (kV) lines. No new transmission lines or modifications to existing transmission lines will be required to support the proposed EPU. However, as a result of operating at a higher thermal core power level, there will be an increase in current that is within the design capacity of the existing lines.

Radiation Waste Systems The radioactive waste systems at NMP2 are designed to collect, process, and dispose of radioactive wastes in a controlled and safe manner. The design basis for these systems during normal operations is to limit discharges in accordance with 10 CFR 50, Appendix I. Adherence to these limits and objectives would continue under the proposed EPU. Operation under the proposed EPU conditions would not result in any physical changes to the solid waste, liquid waste, or gaseous waste systems. As a result of operating under the proposed EPU conditions NMPNS estimates that the generation of solid radioactive waste would increase approximately 7 percent. The inventory of liquid normally processed by the liquid waste management systems would not be increased significantly because the systems functions are not changing and the volume inputs will increase less than 10 percent, which is not an appreciable increase when compared to the liquid radwaste system capacity. Under EPU operating conditions, the plant's gaseous waste processing system will continue to meet system's licensing basis and associated design criteria are unchanged by the EPU. The proposed EPU would result in a small increase in the equilibrium radioactivity in the reactor coolant which in turn would impact the concentrations of radioactive nuclides in the waste disposal systems. However, the releases would remain bounded by the NRC's analysis in the 1985 Final Environmental Statement for the Operation of the Nine Mile Point Nuclear Station Unit No. 2 (FES) (NRC 1985).

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APPENDIX A TO ATTACHMENT 9 - COASTAL MANAGEMENT PROGRAM CONSISTENCY DETERMINATION State Program New York's coastal management program is administered by the New York Department of State, Division of Coastal Resources. For federal agency activities, the Division reviews projects to ensure adherence to the State program or an approved Local Waterfront Revitalization Program. Applicants for federal agency approvals or authorizations are required to submit copies of federal applications to the Division, together with a Federal Consistency Assessment Form and consistency certification.

The Department reviews the consistency certification and proposal for consistency with the State of New York Coastal Management Program as documented in 44 specific policies established in the Department's 1982 Final Environmental Impact Statement (DOS 1982).

The policies articulate the State's vision for its coast by addressing the following areas:

Development Fish and Wildlife Flooding and Erosion Hazards General Public Access Recreation Historic and Scenic Resources Agricultural Lands Energy and Ice Management Water and Air Resources to this Appendix provides the completed Federal Consistency Assessment Form and includes discussion relative to the applicable policies of the program.

Probable Effects NMPNS has prepared a Supplemental Environmental Report which analyzes the environmental impacts associated with increasing thermal power to 3,988 MWt. This environmental evaluation is provided pursuant to 10 CFR 51.41 "Regulations to Submit Environmental Information" and is intended to support the NRC environmental review of the proposed uprate. The proposed EPU would require the issuance of an operating license amendment. The regulation (10 CFR 51.41) requires that applications to the NRC be in compliance with Section 102(2) of the National Environmental Policy Act (NEPA). The results of this evaluation are summarized below:

Surface water quality, hydrology, and use - There would be no change to the cooling water intake flow rate as a result of the proposed EPU and so there would be no impact on hydrology or water use as a result of EPU implementation. NMPNS discharges are controlled by the SPDES permit.

Chemical parameters affected by the proposed EPU would remain within the bounding conditions established in the SPDES permit and, therefore, no significant impacts to water quality would result. Operations under EPU conditions would result in slight increase in heat rejected from the condensers (2°F); however, this increase remains within the current SPDES permit conditions and does not require modification to the thermal specifications in the SPDES permit.

Aquatic ecology - No sensitive aquatic species are known to inhabit or frequent the site. The NMPNS site is not adjacent to any significant bays or other habitat features that may provide unique or important spawning or nursery areas. There are no aquatic species Federally listed as threatened or endangered under the Endangered Species Act in the vicinity of the NMPNS site.

Therefore, the proposed EPU would not affect any New York State-listed or Federally listed aquatic threatened or endangered species.

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APPENDIX A TO ATTACHMENT 9 - COASTAL MANAGEMENT PROGRAM CONSISTENCY DETERMINATION Groundwater use and quality - NMP2 does not use groundwater and none is planned as a part of the EPU, therefore, no impacts are expected.

Terrestrial resources - No federally endangered, threatened or candidate species are likely to occur on the NMPNS site. As the proposed action would not involve any land disturbance, increases in noise levels outside the plant, or increases in the NMPNS workforce, there would be no significant impacts to terrestrial biota, including state-or federally-listed protected species.

Air quality - Technical reviews and analysis indicate that operation post-EPU would result in an increase in cycles of concentration from 3.11 to 3.44 (i.e., a 10.6 percent increase). In its operation-phase Final Environmental Statement for NMP2, NRC evaluated impacts of NMP2 cooling discharges operating at 2.5 cycles of concentration and reported a predicted maximum salt deposition rate of 0.27 pounds/acre/year (NRC 1985, Appendix G, Section 5.1). Scaling from this value to 3.44 cycles of concentration, the estimated maximum deposition rate is approximately 0.4 pounds/acre/year.

This estimate is far below the rate of 1-2 kilogram/hectare/month (65-130 pounds/acre/year) cited by the NRC as levels below which plant, damage is not expected (NRC 1999b, Section 5.3.3.2), and is consistent with a generic conclusion of small impact rendered by the NRC for existing plants using closed cycle cooling using fresh water for makeup (NRC 1996, Sections 4.3.4, 4.3.5) and specifically for NMP2 as a result of its license renewal environmental review (NRC 2006, Section 4.1). NMPNS concludes that adverse impacts on vegetation from increased salt deposition is small.

Land use - The proposed EPU for NMP2 would not affect land use at the 900-acre site. No new construction is planned outside of existing facilities and no expansion of buildings, roads, parking lots, equipment storage areas, or transmission facilities would be required to support the proposed EPU. The proposed EPU is not expected to involve substantial additional volumes of industrial chemicals, fuels, or lubricants, and as a result, would not require additional space for above-or below-ground storage tanks. Because no land disturbance would be required and because there would be no expansion of the existing workforce, impacts to aesthetic resources and historical/archeological resources would be negligible.

Human health - For the proposed EPU, normal operational radiation levels would increase by no more than the percentage increase of EPU, except for N-16 which is expected to increase approximately 30 percent due to increase steam flow and pressure in some components, which in turn reduces the transit and decay times for short-lived isotopes such as N-16. For conservatism, many aspects of the plant were originally designed for higher-than-expected radiation sources.

Thus, the increase in radiation levels would not affect radiation zoning or shielding in the various areas of the plant because it is offset by conservatism in the original design, source terms used, and analytical techniques. Therefore, no new dose reduction programs are planned and the ALARA program would continue in its current form. The EPU does not involve significant increases to the offsite dose from noble gases, iodine, airborne particulates, tritium or liquid effluents. Present offsite doses are not significantly affected by operation at EPU levels and remain within the limits of 10 CFR 20, 10 CFR 50, Appendix I and 40 CFR 190.

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APPENDIX A TO ATTACHMENT 9 - COASTAL MANAGEMENT PROGRAM CONSISTENCY DETERMINATION Socioeconomics - The socioeconomic impacts of implementing the proposed EPU at NMP2 include the positive contribution to the local and regional economies of payments for goods and services associated with the proposed action. Additionally, the continuation of employment of the local population with the associated expenditures for goods and services and contributions to income, sales, and property taxes along with the continuation of property tax payments by NMPNS for NMP2 would both positively impact local and regional economies. The proposed EPU is not anticipated to affect the size of the regular or typical refueling outage workforces. Workforce numbers for the 2012 outage, when the majority of the EPU modifications will be completed, will be somewhat larger than previous outages, but would be of short duration and of such a magnitude as to not adversely affect housing availability, transportation services, or public utilities such as public water supply systems in the plant vicinity.

Uranium fuel cycle and waste management - The additional energy requirements for EPU are met by an increase in bundle enrichment, an increase in the reload fuel batch size, and/or changes in the fuel loading pattern to maintain the desired plant operating cycle length.

NMP2 is currently licensed to use uranium-dioxide fuel that has a maximum enrichment of 4.95 percent by weight uranium-235. The typical average enrichment is approximately 4.20 percent by weight uranium-235. For the proposed action, the uprate core design would use a somewhat higher fuel enrichment (4.36 percent), which remains within the licensed maximum enrichment. The EPU fuel batch size will increase from 276 bundles to 352 bundles. The average fuel assembly discharge burnup would be approximately 48,000 MWdiMTU with no fuel pins exceeding the maximum fuel rod limit of 70,000 MWd/MTU. Reload design goals would maintain the NMP2 fuel cycles within the limits bounded by the impacts analyzed in 10 CFR 51.51 (Table S-3) and 10 CFR 51.52 (Table S-4). The proposed EPU would produce additional spent nuclear fuel, which would represent an approximate 28-percent increase in the number of spent fuel assemblies generated over of the remaining life of the plant and would be accommodated by NMPNS' current spent fuel storage strategy. Therefore, NMPNS concludes that impacts to the uranium cycle and transport of nuclear fuel from the proposed action would be insignificant and not require mitigation.

Decommissioning - The potential environmental impacts of decommissioning associated with the proposed EPU would be due to the increased neutron fluence. As a result, the amount of activated corrosion products could increase, and consequently, the post-shutdown radiation levels could increase. NMPNS expects the increases in radiation levels as a result of operations under the proposed EPU conditions to be insignificant, and would be addressed in the post-shutdown decommissioning activities report.

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APPENDIX A TO ATTACHMENT 9 - COASTAL MANAGEMENT PROGRAM CONSISTENCY DETERMINATION Findings

1. Relative to impacts, the NRC has defined a small significance level as follows:

For the issue, environmental effects are not detectable or are so minor that they will neither destabilize nor noticeably alter any important attribute of the resource. For the purpose of assessing radiological impacts, the Commission has concluded that those impacts that do not exceed permissible levels in the Commission's regulations are considered small as the term is used in this table. (10 CFR Part 51, Subpart A, Appendix B, Table B-i)

NMPNS has determined that the environmental impacts associated with the EPU are small as that term is defined by the NRC.

Impact to the coastal zone, therefore, would also be small.

2. NMPNS will maintain compliance with New York licenses, permits, approvals, and other requirements as they apply to NMP2 impacts on the New York coastal zone.

3. The NMP2 EPU, and its effects, are consistent with the enforceable policies of the New York Coastal Management Program.

State Notification By this certification, the State of New York is notified that the NMP2 license amendment for the EPU is consistent with the New York Coastal Management Program. Attachment 1 to this Report is a completed New York Department of State Federal Consistency Assessment Form.

The State's concurrence, objections, or notification of review status shall be sent to the following contacts:

Rich V. Guzman Keith J. Polson, Vice President Office of Nuclear Reactor Regulation Nine Mile Point Nuclear Station U.S Nuclear Regulatory Commission P.O. Box 63 One White Flint, Mail Stop 8 C2 Lycoming, NY 13093 11555 Rockville Pike (315) 349-5200 Rockville, Maryland 20555 (301) 415-1030 10 of 11

APPENDIX A TO ATTACHMENT 9 - COASTAL MANAGEMENT PROGRAM CONSISTENCY DETERMINATION References DOS (New York Department of State). 1982. State of New York Coastal Management Program and Final Environmental Impact Statement. Albany, New York. August.

NRC (U.S. Nuclear Regulatory Commission).

1985. Final Environmental Statement Related to the Operation of Nine Mile Point Nuclear Station Unit 2. Docket No. 50-410. Office of Nuclear Reactor Regulation. Washington, D.C. May.

NRC (U.S. Nuclear Regulatory Commission).

1996. Generic Environmental Impact Statement for License Renewal of Nuclear Plants. NUREG-1437.

Office of Nuclear Reactor Regulation.

May.

NRC (U.S. Nuclear Regulatory Commission). 1999a. Procedural Guidance for Preparing Environmental Assessments and Considering Environmental Issues. Revision 2. Office of Nuclear Reactor Regulation. Washington, D.C.

NRC (U.S. Nuclear Regulatory Commission).

1999b.

Standard Review Plans for Environmental Reviews for Nuclear Power Plants. NUREG-1555.

Office of Nuclear Reactor Regulation.

October.

NRC (U.S. Nuclear Regulatory Commission). 2006. Generic Environmental Impact Statement for License Renewal of Nuclear Plants-Supplement 24 Regarding Nine Mile Point Nuclear Station, Units 1 and 2. NUREG-1437 Supplement 24. Office of Nuclear Reactor Regulation. May.

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ATTACHMENT 1 TO APPENDIX A TO ATTACHMENT 9 NEW YORK STATE DEPARTMENT OF STATE COASTAL MANAGEMENT PROGRAM Federal Consistency Assessment Form An applicant, seeking a permit, license, waiver, certification or similar type of approval from a federal agency that is subject to the New York State Coastal Management Program (CMP), shall complete this assessment form for any proposed activity that will occur within and/or directly affect the State's Coastal Area. This form is intended to assist an applicant in certifying that the proposed activity is consistent with New York State's CMP as required by U.S. Department of Commerce regulations (15 CFR 930.57). It should be completed at the time when the federal application is prepared. The Department of State will use the completed form and accompanying information in its review of the applicant's certification of consistency.

A. APPLICANT (please print)

1.

Name: Nine Mile Point Nuclear Station, LLC

2.

Address: P.O. Box 63, Lycoming, NY 13093

3.

Telephone: Area Code (315) 349-5200 B. PROPOSED ACTIVITY

1. Brief description of activity:

Nine Mile Point Nuclear Station, LLC (NMPNS) is applying to the U.S. Nuclear Regulatory Commission to increase the licensed core thermal level of the Nine Mile Point Unit 2 (NMP2) approximately 15 percent over current licensed thermal power from 3,467 megawatts thermal (MWt) to 3,988 MWt, which corresponds to an additional 158 megawatts electric.

2.

Purpose of activity:

The purpose and need for the proposed action (15 percent power uprate) is to provide NMPNS with the flexibility to increase the potential electrical output of NMP2 and to supply low cost, reliable, and efficient electrical generation to New York State and the region.

3.

Location of activity:

Oswego County Town of Scriba

4.

Type of federal permit/license required: U.S. Nuclear Regulatory Commission Operating License Amendment

5.

Federal application number, if known:

NRC Renewed Operating License, NPF-69

6.

If a state permit/license was issued or is required for the proposed activity, identify the state agency and provide the application or permit number, if known: Not Applicable 1 of 6

ATTACHMENT 1 TO APPENDIX A TO ATTACHMENT 9 C. COASTAL ASSESSMENT Check either "YES" or "NO" for each of these questions. The numbers following each question refer to the policies described in the CMP document (see footnote on page 2) that may be affected by the proposed activity.

1.

Will the proposed activity result in any of the following:

YES NO

a. Large physical change to a site within the coastal area that will require the preparation of an environmental impact statement? (11, 22, 25, 32, 37, 38, 41, 43)...................................

X

b. Physical alteration of more than two acres of land along the shoreline, land under water or coastal waters? (2, 11, 12, 20, 28, 35, 44).........................................................

X

c. Revitalization/redevelopment of a deteriorated or underutilized waterfront site? (1)...............

X

d. Reduction of existing or potential public access to or along coastal waters? (19, 20)...............

X

e. Adverse effect upon the commercial or recreational use of coastal fish resources? (9,10)........

X

f. Siting of a facility essential to the exploration, development and production of energy resources in coastal waters or on the Outer Continental Shelf? (29)..........................................

X

g. Siting of a facility essential to the generation or transmission of energy? (27).........................

X

h. Mining, excavation, or dredging activities, or the placement of dredged or fill material in coastal w aters? (15, 35)..............................................................................................................

X

i.

Discharge of toxics, hazardous substances or other pollutants into coastal waters? (8, 15, 35) X

j.

Draining of stormwater runoff or sewer overflows into coastal waters? (33).........................

X

k. Transport, storage, treatment, or disposal of solid wastes or hazardous materials? (36, 39)..... X

1. Adverse effect upon land or water uses within the State's small harbors? (4)..........................

X

2.

Will the proposed activity affect or be located in, on, or adjacent to any of the following:

YES NO

a. State designated freshwater or tidal wetland? (44)....................................................................

X

b. Federally designated flood and/or state designated erosion hazard area? (11, 12, 17,)........... X

c. State designated significant fish and/or wildlife habitat? (7)...................................................

X

d. State designated significant scenic resource or area? (24).........................................................

X

e. State designated important agricultural lands? (26)..................................................................

X

f. B each, dune or barrier island? (12)...........................................................................................

X

g. Major ports of Albany, Buffalo, Ogdensburg, Oswego or New York? (3)..............................

.X

h. State, county, or local park? (19, 20).........................................................................................

X

i.

Historic resource listed on the National or State Register of Historic Places? (23).................

.X

3.

Will the proposed activity require any of the following:

YES NO

a. W aterfront site? (2, 21, 22)......................................................................................................

X

b. Provision of new public services or infrastructure in undeveloped or sparsely populated sections of the coastal area? (5)...............................................................................................

X

c. Construction or reconstruction of a flood or erosion control structure? (13, 14, 16)................

X

d. State water quality permit or certification? (30, 38, 40)............................................................

X

e. State air quality perm it or certification? (41, 43).......................................................................

X YES NO

4.

Will the proposed activity occur within and/or affect an area covered by a State approved local waterfront revitalization program? (see policies in local program document).................................

X 2 of 6

ATTACHMENT 1 TO APPENDIX A TO ATTACHMENT 9 D. ADDITIONAL STEPS

1. If all of the questions in Section C are answered "NO," then the applicant or agency shall complete Section E and submit the documentation required by Section F.

2.

If any of the questions in Section C are answered "YES," then the applicant or agent is advised to consult the CMP, or where appropriate, the local waterfront revitalization program document*.

The proposed activity must be analyzed in more detail with respect to the applicable state or local coastal policies. On a separate page(s), the applicant or agent shall: (a) identify, by their policy numbers, which coastal policies are affected by the activity, (b) briefly assess the effects of the activity upon the policy; and, (c) state how the activity is consistent with each policy.

Following the completion of this written assessment, the applicant or agency shall complete Section E and submit the documentation required by Section F.

E. CERTIFICATION The applicant or agent must certify that the proposed activity is consistent with the State's CMP or the approved local waterfront revitalization program, as appropriate.

If this certification cannot be made, the proposed activity shall not be undertaken. If this certification can be made, complete this Section.

"The proposed activity complies with New York State's approved Coastal Management Program, or with the applicable approved local waterfront revitalization program, and will be conducted in a manner consistent with such program."

Applicant/Agent's Name: Keith J. Polson Address: P.O. Box 63, Lycoming, NY 13093 Telephone: Area Code (315) 349-5200 Applicant/Agent's Signature:_____________________ Date: S,--n F. SUBMISSION REQUIREMENTS

1. The applicant or agent shall submit the following documents to the New York State, Department of State, Division of Coastal Resources, 41 State Street - 8th Floor, Albany, New York 1223 1.

a. Copy of original signed form.

b. Copy of the completed federal agency application.

c. Other available information that would support the certification of consistency.

2.

The applicant or agent shall also submit a copy of this completed form along with his/her application to the federal agency.

3.

If there are any questions regarding the submission of this form, contact the Department of State at (518) 474-6000.

• These state and local documents are available for inspection at the offices of many federal agencies, Department of Environmental Conservation and Department of State regional offices, and the appropriate regional and county planning agencies. Local program documents are also available for inspection at the offices of the appropriate local government.

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ATTACHMENT 1 TO APPENDIX A TO ATTACHMENT 9 NINE MILE POINT NUCLEAR STATION OPERATING LICENSE RENEWAL FEDERAL CONSISTENCY ASSESSMENT FORM SUPPLEMENTAL INFORMATION The following table contains a listing of the New York State Coastal Management Program Polices affected by the proposed activity, 15 percent power uprate of the Nine Mile Point Unit 2 (NMP2). Discussion follows the table, detailing how the proposed activity affects the individual policies. Policies 2, 11, 15, and 35 are not included in the discussion because there are no plans to construct new buildings or structures or to conduct mining, excavation, or dredging in coastal waters as part of the proposed activity.

Table 1.

New York State Coastal Management Program Policies Affected by Nine Mile Point Unit 2 Extended Power Uprate Policy 7 Significant coastal fish and wildlife habitats will be protected, preserved, and where practical, restored as to maintain their viability as habitats.

Policy 8 Protect fish and wildlife resources in the coastal area from the introduction of hazardous wastes and other pollutants which bio-accumulate in the food chain or which cause significant sublethal or lethal effect on those resources.

Policy 12 Activities or development in the coastal area will be undertaken so as to minimize damage to natural resources and property from flooding and erosion by protecting natural protective features including beaches, dunes, barrier islands, and bluffs.

Policy 17 Non-structural measures to minimize damage to natural resources and property from flooding and erosion shall be used whenever possible.

Policy 33 Best management practices will be used to ensure the control of stormwater runoff and combined sewer overflows draining into coastal waters.

Policy 36 Activities related to the shipment and storage of petroleum and other hazardous materials will be conducted in a manner that will prevent or at least minimize spills into coastal water; all practicable efforts will be undertaken to expedite the cleanup of such discharges; and restitution for damages will be required when these spills occur.

Policy 39 The transport, storage, treatment and disposal of solid wastes, particularly hazardous wastes, within coastal areas will be conducted in such a manner so as to protect groundwater and surface water supplies, significant fish and wildlife habitats, recreation areas, important agricultural land, and scenic resources.

With regard to Policy 7, the 15 percent power uprate of NMP2 would have no significant effect on the coastal fish and wildlife habitat. Thermal effluents associated with NMP2 operations are regulated under the New York State Department of Environmental Conservation through the State Pollutant Discharge Elimination System (SPDES) permit program, and NMPNS has been issued a SPDES permit (NY-0001015) with effluent limitations and monitoring requirements for waste heat. Under EPU operating conditions, the discharge temperature is expected to increase by approximately 2°F and heat addition is expected to increase by 30-50 million BTUs/hour, all well within the existing SPDES limits, and is therefore, protective of fish and wildlife habitat in the vicinity of NMPNS.

With regard to Policy 8, the 15 percent power uprate of NMP2 would have no additional effect on the fish and wildlife resources through the introduction of hazardous wastes and other pollutants. Hazardous wastes and other pollutants that have the potential to bio-accumulate in the food chain that NMPNS operations would generate or have on site would be present in the following: effluent discharges from operations, pesticides used for facility and property maintenance, petroleum bulk storage, chemical bulk storage, and mixed and hazardous wastes generated by operations. State and federal programs regulate these potential sources of hazardous materials. All nonradiological effluent discharges are regulated under the New York State Department of Environmental Conservation through the State Pollutant Discharge Elimination System (SPDES) permit program and NMPNS has been issued a SPDES permit (NY-0001015) with effluent limitations, monitoring requirements, and other conditions that ensures that all discharges are in compliance with Title 8 of Article 17 of the Environmental Conservation Law of New York State.

and the Clean Water Act as amended (33 U.S.C. Section 1251 et seq.). Concentrations of radioactivity in effluents 4 of 6

ATTACHMENT 1 TO APPENDIX A TO ATTACHMENT 9 are subject to the requirements of the U.S. Nuclear Regulatory Commission. NMPNS is in compliance with its licensing requirements as well as the requirements and conditions of its SPDES permit and is, therefore, protecting fish and wildlife resources in the Lake Ontario area where the plant is located. Operations under EPU operating conditions will remain compliant with the plant's SPDES permit.

Pesticide use is regulated by the New York State Department of Environmental Conservation (NYSDEC) under 6 NYCRR Part 325. NMPNS has in place the NYSDEC Pesticide Business Registration, prepares the required annual reports to the State, and maintains appropriate applicator certifications to ensure that pesticide use and storage on site are done properly and in accordance with regulations and is, therefore, protecting fish and wildlife resources in the Lake Ontario area where the plant is located. Operations under EPU conditions will not affect pesticide use on site.

Petroleum bulk storage on site is regulated by the New York State Department of Environmental Conservation under 6 NYCRR Parts 612 to 614. NMPNS facilities have the appropriate registrations and procedures are in place for spill prevention, response, and reporting. Chemical bulk storage on site is regulated by the New York State Department of Environmental Conservation under 6 NYCRR Parts 595 to 599. NMPNS has in place a Spill Prevention, Control, and Countermeasures Plan as required under 40 CFR 112 to prevent the discharge of oil to surface waters or surface water tributaries. NMPNS facilities have the appropriate registrations and procedures in place for proper materials handling and storage; spill prevention, response, and reporting; and storage systems inspection, maintenance, and repair. NMPNS has in place processes and procedures to ensure that hazardous chemicals stored and used on site are handled and stored in accordance with applicable State and Federal regulations. None of these programs will be affected by operations under EPU conditions; therefore, NMPNS is protecting fish and wildlife resources in the Lake Ontario area.

Mixed and hazardous wastes generated on site are packaged, temporarily stored, and shipped off site for processing and disposal. The New York State Department of Environmental Conservation regulates these activities under 6 NYCRR Parts 372 and 373. NMPNS has in place processes and procedures to ensure that mixed and hazardous wastes are packaged, stored, and shipped so as to comply with the applicable State and Federal regulations, thus ensuring that fish and wildlife resources are protected. In summary, the hazardous wastes and other pollutants, which bio-accumulate in the food chain and could be introduced into the environment as a result of NMP2 operations under EPU operating conditions, are minimized through compliance with applicable environmental regulations. Fish and wildlife resources in the Lake Ontario area are, therefore, protected and the proposed activity is consistent with Policy 8.

With respect to Policies 12 and 17, the shoreline within the NMPNS protected area has been shielded from storm surge wave action by a dike between Unit 1 and the Lake and a revetment-ditch system which extends in front of both Units 1 and 2. The front slope of the revetment-ditch system is reinforced with dolos, concrete armor units, in front of Unit 2 and with rock armor in front of Unit 1. The backslope is constructed of rockfill, a layer of rock armor units, and granular filters. The top of the revetment has an elevation of 263 feet. A ditch located immediately south of the revetment collects rainfall runoff flowing north, and conveys it to both ends of the revetment, where it discharges to the Lake. The operations under EPU operating conditions will not involve any activities that would disturb the shoreline along the NMPNS property. NMPNS has no plans for activities or development along the shoreline as a part of the proposed activity, and so the proposed activity is consistent with Policies 12 and 17.

With respect to Policy 33, NMPNS has in place a SPDES permit (NY-0001015) which incorporates best management practices to control storm water runoff as part of the special conditions of the permit. The New York State Department of Environmental Conservation regulates storm water management under 6 NYCRR, Part 750, ECL 17-0701 and 17-0808, and GP-98-03. The U.S. Environmental Protection Agency has authority under 40 CFR 122. The proposed activity is, therefore, consistent with Policy 33.

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ATTACHMENT 1 TO APPENDIX A TO ATTACHMENT 9 With respect to Policy 36, NMPNS has in place procedures to ensure that petroleum and other hazardous materials used on site are safely handled and stored. The New York State Department of Environmental Conservation regulates petroleum bulk storage under the authority of 6 NYCRR Parts 612 to 614. NMPNS facilities have the appropriate registrations and procedures are in place to prevent and report spills. Chemical bulk storage on site is regulated by the New York State Department of Environmental Conservation under 6 NYCRR Parts 595 to 599.

NMPNS has in place a Spill Prevention, Control, and Countermeasures Plan as required under 40 CFR 112 to prevent the discharge of oil to surface waters or surface water tributaries. NMPNS facilities have the appropriate registrations and procedures in place for proper materials handling and storage; spill prevention, response, and reporting; and storage systems inspection, maintenance, and repair. NMPNS has in place processes and procedures to ensure that hazardous chemicals stored and used on site are handled and stored in accordance with applicable State and Federal regulations so as to prevent the release of these materials to coastal waters.

Therefore, the proposed activity is consistent with Policy 36.

With respect to Policy 39, NMPNS does not currently dispose of solid waste on site. An historic cap landfill was constructed and permitted and used for disposal of debris during plant construction. Mixed and hazardous wastes generated on site are packaged, temporarily stored, and shipped off site for processing and disposal. The New York State Department of Environmental Conservation regulates these activities under 6 NYCRR Parts 372 and 373.

NMPNS has in place processes and procedures to ensure that mixed and hazardous wastes are packaged, stored, and shipped so as to comply with the applicable State and Federal regulations, thus ensuring that groundwater and surface water supplies, significant fish and wildlife habitats, recreation areas, important agricultural land, and scenic resources are protected. The proposed activity is, therefore, consistent with Policy 39.

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ENCLOSURE ATTACHMENT 10 Flow Induced Vibration - Piping / Component Evaluation Nine Mile Point Nuclear Station, LLC May 27, 2009

ATTACHMENT 10 - FLOW INDUCED VIBRATION - PIPING / COMPONENT EVALUATION Table of Contents 1.0 Introduction 2.0 Susceptibility and Monitoring 3.0 Results from Previous Vibration Test Programs and EPU Projections 4.0 EPU Vibration Monitoring Program 4.1 Overview 4.2 Vibration Monitoring Location and Acceptance Criteria Development 4.2.1 MSS and FWS Piping (Drywell and Turbine Building) 4.2.2 CNM, ESS, HDH and HDL Piping (Turbine Building) 4.2.3 MSS Components (Drywell and Steam Tunnel) 4.3 Data Acquisition and Reduction Methodology 5.0 Summary 6.0 References Table 3-1 OLTP Results and EPU Projections for Drywell Monitoring Locations Table 3-2 OLTP Results and EPU Projections for Turbine Building Monitoring Locations Table 4-1 Drywell EPU Monitoring Locations for MSS and FWS Table 4-2 Turbine Building EPU Monitoring Locations for MSS and FWS Table 4-3 Turbine Building EPU Monitoring Locations for CNM, ESS, and HDL Table 4-4 EPU Component Monitoring Locations 1 of 16

ATTACHMENT 10 - FLOW INDUCED VIBRATION - PIPING / COMPONENT EVALUATION

1.0 INTRODUCTION

Sections 2.2.2 and 2.5.4.1 of Attachment 11 to the Extended Power Uprate (EPU) submittal briefly discuss the EPU effects on Flow Induced Vibration (FIV) for the Main Steam System (MSS) and the Feedwater System (FWS). This Attachment to the submittal provides a more detailed discussion of the analyses and testing program undertaken to provide assurance that unacceptable FIV issues are not experienced at Nine Mile Point Unit 2 (NMP2) due to EPU implementation.

Increased flow rates and flow velocities during operation at EPU conditions are expected to produce increased FIV levels in some systems. As discussed in Section 3.4.1 of Licensing Topical Report (LTR)

NEDC-33004P-A, Revision 4, "Constant Pressure Power Uprate," the MSS and FWS piping vibration levels should be monitored because their system flow rates will be significantly increased (Reference 2).

While a review of industry EPU operating experience identified very few component failures that can be attributed to EPU, most of these failures were related to FIV.

In January 2007, the Boiling Water Reactor Owners' Group (BWROG) issued NEDO-33159, Revision 1, "Extended Power Uprate (EPU) Lessons Learned and Recommendations," based on operating experience (OE) and evaluations from Boiling Water Reactor (BWR) plants that have previously implemented EPUs and from plants currently performing pre-EPU evaluations (Reference 1). NEDO-33159 states:

"Since the majority of EPU-related component failures involve flow induced vibration, the BWROG EPU Committee held a vibration monitoring and evaluation information exchange meeting of industry experts in June 2004. The committee determined that the current process of monitoring large bore piping systems in accordance with the requirements of American Society of Mechanical Engineers (ASME) Operation and Maintenance (O&M) Part 3 is sufficient to preclude challenges to safe shutdown. Increases in large bore piping vibration levels are a precursor to increased vibration levels in attached small bore piping and components."

Regulatory Guide (RG) 1.20, "Comprehensive Vibration Assessment Program for Reactor Internals during Preoperational and Initial Startup Testing," was revised in 2007.

In addition to guidance for vibration assessment of reactor internals, this regulatory guide provides helpful information on methods for evaluating the potential adverse effects from pressure fluctuations and vibrations in piping systems for boiling water reactor (BWR) nuclear power plants. However, additional guidance is provided with regard to piping vibration. The guidance is primarily directed to initial start-up of new plants, with general guidance interpreted for use in power uprate power ascension testing. Where applicable, this guidance has been incorporated into the EPU monitoring program for piping vibration at NMP2.

In addition to MSS and FWS, the related Extraction Steam, Condensate and Heater Drain systems also experience similar flow increases under EPU conditions and are included in the EPU vibration monitoring program. Other systems experience insignificant or no increase in flow and; therefore, are not included in this program.

Review of previous vibration data collected during initial start-up testing and power ascension to current uprated power levels indicates relatively low vibration levels.

The plant has not experienced any abnormal piping vibration at power levels up to 104 percent of original licensed thermal power (OLTP).

Extrapolation of this earlier data to EPU power levels indicates that vibration of piping and components will not be adversely affected by EPU operation.

This document describes the piping vibration monitoring program to be implemented at NMP2 during power ascension to confirm acceptable vibration levels at EPU power. It addresses systems impacted by EPU. It compares previously collected vibration data to conservative projections for EPU vibration levels based on increases in vibration being proportional to increases in flow rate squared. This document also describes the techniques to be used for collecting and storing the vibration data as well as the acceptance criteria to be used for evaluation of that data.

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ATTACHMENT 10 - FLOW INDUCED VIBRATION - PIPING / COMPONENT EVALUATION 2.0 SUSCEPTIBILITY AND MONITORING The MSS and FWS piping will experience higher mass flow rates and flow velocities under EPU conditions. When power is increased from current licensed thermal power (CLTP to EPU conditions, steady state FIV levels are conservatively expected to increase in proportion to the mass flow rate squared.

Thus, the vibration levels of the MSS and FWS piping are expected to increase by approximately 38% based on a steam flow increase of 17.6%.

Other possible sources of increased vibration, such as flow instabilities or acoustic resonance as a result of increased flow velocities, may contribute to EPU vibration levels.

Flow rates in portions of the Condensate (CNM), Extraction Steam (ESS), High Pressure Heater Drain (HDH) and Low Pressure Heater Drain (HDL) systems increase similarly to MSS and FWS, and are therefore susceptible to increased vibrations at EPU conditions.

Based on the potential for significantly increased vibrations on the systems identified above, a confirmatory test program will be implemented to monitor piping and attached component vibration levels on the identified systems during initial power ascension to EPU conditions.

Piping in the drywell and inaccessible piping outside containment will be monitored using accelerometers installed at selected locations on the piping and attached components. The accelerometers will be wired to remote data acquisition systems located in the reactor and turbine buildings.

Piping outside containment that is accessible during plant operation will be monitored by performing visual observations and by taking vibration measurements using hand-held vibration instruments during power ascension to EPU conditions.

Small bore branch piping is susceptible to the effects of the associated large bore piping FlV.

Modifications to small branch piping to reduce susceptiblility to header-induced vibrations have been made as a result of NMP2 operating experience. Walkdowns of the systems impacted by EPU flow increases will be performed to identify if there are any additional potentially susceptible small bore line configurations. Any necessary small bore line modifications will be made prior to EPU power ascension.

Selected small bore branch lines will be monitored for vibration during EPU power ascension using a combination of accelerometers and visual inspection to confirm that vibrations are within acceptable limits.

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ATTACHMENT 10 - FLOW INDUCED VIBRATION - PIPING / COMPONENT EVALUATION 3.0 RESULTS FROM PREVIOUS VIBRATION TEST PROGRAMS AND EPU PROJECTS Vibration levels at Original Licensed Thermal Power (OLTP, 3323 MWt) and at Current Licensed Thermal Power (CLTP, 3467 MWt) were obtained during initial plant start-up testing and power ascension to the first NMP2 power uprate (stretch uprate), respectively. The initial startup and stretch uprate vibration monitoring results form part of the basis for the vibration monitoring to be performed during EPU power ascension.

The vibration monitoring program implemented during initial plant startup of NMP2 included systems in the EPU vibration monitoring scope. The number of monitoring locations for systems within the EPU vibration monitoring scope is summarized below:

Remote Monitoring Inside Containment MSS: 6 locations, 18 measurements (3 directions per location)

FWS: 2 locations, 6 measurements (3 directions per location)

Remote Monitoring Outside Containment MSS: 4 locations, 12 measurements (3 directions per location)

CNM: 3 locations, 9 measurements (3 directions per location)

Visual Monitoring Outside Containment FWS: 4 locations For stretch uprate, the locations within the EPU vibration monitoring scope that were monitored were the two FWS locations inside containment.

Remote monitoring during initial startup was accomplished using lanyard potentiometers, which measure displacement directly, but have a limited frequency response.

For stretch uprate, accelerometers were used in lieu of lanyard potentiometers at the two FW locations. The measured accelerations were double-integrated to obtain displacements.

Due to the limited number of points within the EPU vibration monitoring scope that were monitored for stretch uprate, as well as differences in the lanyard potentiometer and accelerometer sensitivities and frequency responses, and the effects of double-integration of the acceleration data, clear vibration trends between OLTP and stretch uprate power levels cannot be established. However, the results from both test programs indicated low levels of piping steady-state vibration.

The OLTP vibration levels and projected EPU vibration levels are summarized in Tables 3-1 and 3-2.

The stretch uprate vibrations measured at the two FWS locations are not included because they are bounded by the corresponding OLTP data. The projected EPU vibration levels are calculated using the following equation:

EPU vibration level = (OLTP vibration level) * (EPU MSS flow rate / OLTP MSS flow rate) 2 The projected EPU vibration levels are also presented in terms of the acceptance criteria established for the EPU vibration monitoring program. Table 3-1 includes the drywell monitoring locations. Table 3-2 includes the turbine building monitoring locations.

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ATTACHMENT 10 - FLOW INDUCED VIBRATION - PIPING / COMPONENT EVALUATION Table 3-1 OLTP Results and EPU Projections for Drywell Monitoring Locations OLTP EPU Projected %

Monitoring Measured Projected of EPU System Piping Segment Location-MesrdPoctdf U

SP g ection Vibration Vibration Acceptance Direction (mils pk-pk)

(mils pk-pk)

Criteria' MSS 2-MSS-026-43-1 18-X 5

8 28 MSS 2-MSS-026-43-1 18-Y 5

8 59 MSS 2-MSS-026-43-1 18-Z 4

6 19 MSS 2-MSS-026-43-1 42-X 5

8 18 MSS 2-MSS-026-43-1 42-Y 7

11 27 MSS 2-MSS-026-43-1 42-Z 5

8 9

MSS 2-MSS-750-350-2 126-X 4

6 17 MSS 2-MSS-750-350-2 126-Y 6

9 24 MSS 2-MSS-750-350-2 126-Z 4

6 17 MSS 2-MSS-026-45-1 40-X 2

3 11 MSS 2-MSS-026-45-1 40-Y 5

8 48 MSS 2-MSS-026-45-1 40-Z 2

3 13 MSS 2-MSS-026-45-1 75-X 2

3 10 MSS 2-MSS-026-45-1 75-Y 4

6 24 MSS 2-MSS-026-45-1 75-Z 4

6 23 MSS 2-MSS-026-45-1 124-X 9

14 32 MSS 2-MSS-026-45-1 124-Y 4

6 22 MSS 2-MSS-026-45-1 124-Z 7

11 82 FWS 2-FWS-012-54-1 85-X 5

8 31 FWS 2-FWS-012-54-1 85-Y 4

6 31 FWS 2-FWS-012-54-1 85-Z 4

6 24 FWS 2-FWS-024-60-1 190-X 4

6 27 FWS 2-FWS-024-60-1 190-Y 4

6 38 FWS 2-FWS-024-60-1 190-Z 4

6 41 Some of the monitoring locations have been moved for EPU based on configuration changes (e.g., snubber reduction) since initial plant startup and improved analysis techniques available for establishing the EPU monitoring locations and acceptance criteria.

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ATTACHMENT 10 - FLOW INDUCED VIBRATION - PIPING / COMPONENT EVALUATION Table 3-2 OLTP Results and EPU Projections for Turbine Building Monitoring Locations OLTP EPU Projected %

Monitoring Measured Projected of EPU System Piping Segment Location-Vibrai Vratio Accept Vibration Vibration Acceptance Direction (mils pk-pk)

(mils pk-pk)

Criteriai MSS 2-MSS-028-6-4 209-X 4

6 12 MSS 2-MSS-028-6-4 209-Y 9

14 5

MSS 2-MSS-028-6-4 209-Z 5

8 20 MSS 2-MSS-028-6-4 7082-X 5

8 7

MSS 2-MSS-028-6-4 7082-Y 5

8 14 MSS 2-MSS-028-6-4 7082-Z 11 17 33 MSS 2-MSS-028-8-4 521-X 2

3 1

MSS 2-MSS-028-8-4 521-Y 2

3 5

MSS 2-MSS-028-8-4 521-Z 4

6 17 MSS 2-MSS-018-34-4 135-X 5

8 10 MSS 2-MSS-018-34-4 135-Y 4

6 11 MSS 2-MSS-018-34-4 135-Z 7

11 11 CNM 2-CNM-036-222-4 60-X 13 20 31 CNM 2-CNM-036-222-4 60-Y 4

6 5

CNM 2-CNM-036-222-4 60-Z 4

6 4

CNM 2-CNM-020-41-4 220-X 4

6 5

CNM 2-CNM-020-41-4 220-Y 5

8 8

CNM 2-CNM-020-41-4 220-Z 4

6 15 CNM 2-CNM-030-22-4 241-X 4

6 13 CNM 2-CNM-030-22-4 241-Y 2

3 NA CNM 2-CNM-030-22-4 241-Z 2

3 13 T*Some of the monitoring locations have been moved for EPU based on configuration changes (e.g., snubber reduction) since initial plant startup and improved analysis techniques available for establishing the EPU monitoring locations and acceptance criteria.

As shown in Table 3-1, all of the OLTP vibration levels measured in the drywell were less than 10 mils pk-pk. Based on the "velocity-squared" projection for EPU conditions, only two of the locations would be expected to experience vibrations greater than 50% of the EPU acceptance criteria. At each of these locations, only one of the three measurement directions has a projected vibration level above 50% of the acceptance criteria, while the projected vibrations in the other two directions are well below 50% of the acceptance criteria.

The maximum measured OLTP vibration levels in the turbine building were slightly higher than in the drywell, but still less than 15 mils pk-pk. Higher vibrations in the turbine building are expected because the piping is generally less rigidly restrained than in the drywell. Projecting to EPU conditions, the turbine vibrations are expected to be less than 50% of the EPU acceptance criteria.

The results presented in Tables 3-1 and 3-2 illustrate the relatively low levels of previously-measured vibrations. Based on conservative projections, vibrations at EPU conditions are expected to remain well within acceptable limits.

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ATTACHMENT 10 - FLOW INDUCED VIBRATION - PIPING / COMPONENT EVALUATION 4.0 EPU VIBRATION MONITORING PROGRAM 4.1 Overview Vibration levels at Original Licensed Thermal Power (OLTP, 3323 MWt) and at Current Licensed Thermal Power (CLTP, 3467 MWt) were documented during initial plant start-up testing and power ascension to the first NMP2 power uprate. Vibration measurement locations and levels from the earlier vibration testing are summarized in Tables 3-1 and 3-2. These earlier test programs form part of the basis for the vibration monitoring to be performed during EPU power ascension.

Additional analyses using more detailed methods have been performed to establish EPU vibration monitoring locations and acceptance criteria. The monitoring points identified in Tables 3-1 and 3-2 have been modified, as applicable, based on the analysis results. Additional monitoring points have been identified on systems not previously instrumented that have significant flow increases as a result of EPU.

The EPU analysis and flow increase evaluation results form the rest of the bases for EPU vibration monitoring.

Several MSS-associated components will also be monitored. Although NMP2 does not have a history of safety-relief valve maintenance issues due to vibration, selected relief valves will be instrumented with accelerometers, as well as three other power-operated valves. This is in response to industry OE from an earlier EPU project.

Locations in the drywell and inaccessible locations outside containment will be monitored using accelerometers installed at selected locations on the piping and attached components. The accelerometers will be wired to remote data acquisition systems located in the reactor and turbine buildings. Piping outside containment that is accessible during plant operation will be monitored by performing visual observations and by taking vibration measurements using hand-held vibration instruments during power ascension to EPU conditions.

4.2 Vibration Monitoring Location and Acceptance Criteria Development 4.2.1 MSS and FWS Piping (Drywell and Turbine Building)

Hydraulic and structural models of the MSS and FWS piping were created for determination of the vibration monitoring locations and development of the vibration acceptance criteria.

The hydraulic analyses were, performed to generate piping leg force time histories simulating loading due to dynamic pressure fluctuations that cause piping steady-state vibrations. The generated force time histories were used as input for force time history analyses performed to provide piping structural responses. The intent of the hydraulic and structural dynamic analyses was to apply loading that is similar to the loading due to steady-state vibration, and generate responses that are based on the piping system acoustic and structural properties. Because the exact forcing functions are unknown, the analytical responses are not predicted responses.

However, the deflected shape of the piping and the resulting stress distribution will correspond to the appropriate type of loading.

The vibration monitoring locations were selected where, based on the structural time history analysis results, significant displacements occurred relative to other locations. The measurement locations were also selected such that the general overall piping response would be reflected in the data and it would not be likely that significant vibrations would be missed. The analysis results at the previously established initial startup monitoring locations were reviewed to determine their applicability for the EPU vibration monitoring program. Changes to the previously established locations were made, as necessary, based on the analysis results. Where applicable, symmetry between trains or loops was considered to reduce the overall number of monitoring locations. The EPU vibration monitoring locations determined for the MSS and FWS piping from the analyses are summarized in Tables 4-1 (drywell) and 4-2 (turbine building).

Allowable displacement (mils pk-pk) and acceleration (g's-pk) limits at the selected measurement locations were calculated based on the analysis results and ASME code fatigue stress limits for steady 7 of 16

ATTACHMENT 10 - FLOW INDUCED VIBRATION - PIPING / COMPONENT EVALUATION state vibration per ASME O&M-Standards and Guidelines (S/G) Part 3 (Reference 3). The primary acceptance criteria are in terms of displacement, which is directly proportional to pipe stress. Secondary acceptance criteria in terms of acceleration were determined for use in the event of difficulties that may occur in accurately double-integrating the measured accelerations to displacements.

The displacement limits are applicable for vibration frequencies up to 50 Hz, which corresponds to the frequency range in which the most significant structural displacement responses are expected. Piping displacements due to excitation frequencies above 50 Hz are typically insignificant relative to the lower frequency displacements. The MSS acceleration limits are applicable for vibration frequencies up to 250 Hz, which envelops the main steam safety relief valve (SRV) branch acoustic frequencies. The FWS acceleration limits are applicable for frequencies up to 50 Hz, because significant forcing frequencies and structural responses above 50 Hz are not expected in the FWS system.

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ATTACHMENT 10 - FLOW INDUCED VIBRATION - PIPING / COMPONENT EVALUATION Table 4-1 Drywell EPU Monitoring Locations for MSS and FWS Monitoring System Piping Segment Location-Description Direction MSS 2-MSS-026-43-1 18-XS MSS 2-MSS-026-43-l 18-Y Main Steam Line (MSL) A elbow MSS 2-MSS-026-43-1 18-ZS upstream of SRVs MSS 2-MSS-026-43-1 1392-X MSL A riser downstream of MSS 2-MSS-026-43-1 1392-Y S~

SRVs MSS 2-MSS-026-43-1 1392-Z MSS 2-MSS-750-350-2 943-XS MSS 2-MSS-750-350-2 943-Y MSL A flow venturi sensing line MSS 2-MSS-750-350-2 943-ZS MSS 2-MSS-026-45-1 45-XS MSS 2-MSS-026-45-1 45-Y MSL C elbow upstream of SRVs MSS 2-MSS-026-45-1 45-ZS MSS 2-MSS-026-45-1 80-XS MSL C horizontal run MSS 2-MSS-026-45-1 80-Y dstremof run downstream of SRVs MSS 2-MSS-026-45-1 80-ZS MSS 2-MSS-026-45-1 1124-X MSL C riser downstream of MSS 2-MSS-026-45-1 1124-Y S~

SRVs MSS 2-MSS-026-45-1 1124-Z FWS 2-FWS-012-54-1 85-XS FWS 2-FWS-012-54-1 85-Y FWS Loop B 12-inch lead FWS 2-FWS-012-54-1 85-ZS FWS 2-FWS-024-60-1 190-XS FWS 2-FWS-024-60-1 190-Y FWS Loop B header FWS 2-FWS-024-60-1 190-ZS 9 of 16

ATTACHMENT 10 - FLOW INDUCED VIBRATION - PIPING / COMPONENT EVALUATION Table 4-2 Monitoring Locations for MSS and FWS Turbine Building EPU Monitoring System Piping Segment Location-Description Direction MSS 2-MSS-028-6-4 229-X MSL A riser downstream of MSS 2-MSS-028-6-4 229-Y Main Steam Isolation Valve MSS 2-MSS-028-6-4 229-Z (MSIV)

MSS 2-MSS-028-6-4 730-X MSS 2-MSS-028-6-4 730-Y MSL turbine lead downstream of Turbine Control Valve (TCV) 4 MSS 2-MSS-028-6-4 730-Z MSS 2-MSS-028-8-4 521-X MSL turbine lead downstream of MSS 2-MSS-028-8-4 521-YTC2 TCV 2 MSS 2-MSS-028-8-4 521-Z MSS 2-MSS-018-34-4 935-X MSS 2-MSS-018-34-4 935-Y 18-inch line to turbine steam MSS 2-MSS-018-34-4 935-Z bypass chest MSS 2-MSS-018-34-4 9316-X W upBdshreln FWS 2-FWS-024-9-4 3161-X FWS 2-FWS-02-9-4 3055-X

'1FWS Pump B discharge line FWS 2-FWS-024-39-4 3055-Y in FWS 2-FWS-020-39-4 3055-X

'B' 6th point FWS heater inlet FWS 2-FWS-020-39-4 3055-Y line FWS 2-FWS-020-40-4 7656-X FWS 2-FWS-020-40-4 6187-X

'C' 6th point FWS heater inlet line FWS 2-FWS-020-40-4 7656-Z line FWS 2-FWS-020-41-4 6187-X

'C' 6th point FWS heater outlet FWS 2-FWS-020-41-4 6187-Z line FWS 2-FWS-030-42-4 6120-X FWS 2-FWS-030-42-4 6120-Y header FWS 2-FWS-030-42-4 6120-Z LoopAsupplyheader FWS 2-FWS-024-27-4 550-X FWS 2-FWS-024-27-4 550-Y FWS Loop A supply header FWS 2-FWS-024-27-4 550-Z FWS 2-FWS-024-28-4 2226-X FWS 2-FWS-024-28-4 2226-Z FSLo upyhae 4.2.2 CNM, ESS, HDH and HDL Piping (Turbine Building)

Significant flow increases occur in portions of the condensate, extraction steam and heater drain systems as a result of EPU. Monitoring locations were selected on the basis of locations previously monitored during initial plant startup, percent flow increase due to EPU, projected EPU flow rates, piping configuration and similarity between trains.

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ATTACHMENT 10 - FLOW INDUCED VIBRATION - PIPING / COMPONENT EVALUATION Condensate:

The condensate system experiences flow increases similar to FWS as a result of EPU. The same as for initial startup, three locations were selected for EPU vibration monitoring which are in the vicinity of the initial startup monitoring locations. One location will be instrumented in each of the following three portions of the condensate system: condensate pumps to condensate booster pumps, condensate booster pumps to feedwater heaters, and feedwater heaters to feedwater pumps.

Extraction Steam:

The extraction steam system will experience significant flow increases in several areas. The highest increases are also in the highest energy lines. There are 12 lines in total that make uj the extraction steam system from the high pressure (HP) turbine to the three trains of the 6th point and 5t point heaters. Flow in the extraction steam lines increases to the 6th point heaters by 35 percent and to the 5th point heaters by 23 percent.

The extraction steam lines from the HP turbine to the 6th point feedwater heaters extend from the turbine exhaust as twol4-inch lines, which merge into a single 20-inch line. Three 12-inch lines extend from the 20-inch line to the feedwater heaters. These 12-inch lines have similar configurations. Therefore, one 12-inch line will be instrumented with accelerometers. The 20-inch and 14-inch extraction steam lines to the 6th point heaters will not be instrumented. Abnormal vibration levels of the 20-inch and 14-inch lines can be inferred by instrumentation on the 12-inch line.

The extraction steam lines from the HP turbine to the 5h point feedwater heaters extend from the turbine exhaust as 18-inch lines, which merge into a single 24-inch line. Three 16-inch lines extend from the 24-inch line to the 5th point heaters. These 16-inch lines are symmetric for a significant distance. Therefore, one 16-inch line is instrumented with accelerometers. The 18-inch and 24-inch extraction steam lines to the 5th point heaters are not instrumented. Abnormal vibration levels of the 18-inch and 24-inch lines can be inferred by instrumentation on the 16-inch line.

Heater Drain:

The heater drain system will experience significant flow increases in several areas. Monitoring locations on the HDH and HDL piping were selected as discussed below.

HDH The heater drain lines from the 6th point to the 5th point heaters will experience an increase in flow of approximately 24 percent. However, the maximum flow velocity at EPU conditions is less than six feet per second. Because the absolute flow velocities at EPU conditions are low, these lines will not be instrumented.

HDL The heater drain lines from the 5th point to the 4th point heaters will experience an increase in flow of approximately 24 percent. All three trains are symmetric. Therefore, one train will be instrumented with accelerometers.

In addition, one heater drain pump discharge line will be instrumented with accelerometers. The absolute flow velocities in the other HDL lines at EPU conditions are less than six feet per second and, therefore, those lines will not be instrumented.

The EPU vibration monitoring locations determined for the condensate, extraction steam and heater drain piping are summarized in Table 4-3.

Allowable displacement limits at the selected measurement locations were calculated using the simplified methods delineated in ASME O&M-S/G Part 3 (Reference 3).

Piping that is accessible during plant operation will be monitored by performing visual observations and by taking vibration measurements using hand-held vibration instruments during power ascension to EPU conditions.

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ATTACHMENT 10 - FLOW INDUCED VIBRATION - PIPING / COMPONENT EVALUATION Table 4-3 Turbine Building EPU Monitoring Locations for CNM, ESS and HDL Monitoring System Piping Segment Location-Description Direction CNM 2-CNM-030-22-4 320-X CNM header between condensate (CD) and condensate booster CNM 2-CNM-030-22-4 320-Z (CB) pumps CNM 2-CNM-020-40-4 175-X CNM 2-CNM-020-40-4 175-Y CB Pump B discharge line CNM 2-CNM-020-40-4 175-Z CNM 2-CNM-020-64-4 50-X CNM 2-CNM-020-64-4 50-X

'C' 5th point FWS heater outlet CNM 2-CNM-020-64-4 50-Y ln line CNM 2-CNM-020-64-4 50-Z ESS 2-ESS-012-9-4 105-X ESS 2-ESS-012-9-4 105-Y ESS to 'C' 66' point FWS heater ESS 2-ESS-012-9-4 105-Z ESS 2-ESS-016-16-4 270-X EISS 2-ESS-016-16-4 270-Z ESS to 'A' 5t" point FWS heater HDL 2-HDL-012-502-4 60-X HDL from 'A' 5h point FWS heater to 'A' 4th point FWS HDL 2-HDL-012-502-4 60-Y heater HDL 2-HDL-012-424-4 193-X HDL 2-HDL-012-424-4 193-Y HDL Pump B discharge line HDL 2-HDL-012-424-4 193-Z 4.2.3 MSS Components (Drywell and Steam Tunnel)

NMP2 operating history and analyses and scale model testing performed for NMP2 EPU indicate that excessive component vibrations are not expected at EPU conditions. In order to provide confirmation that component vibrations will be within acceptable limits at EPU conditions, selected components will be instrumented with accelerometers. The selected components include four safety-relief valves, two main steam isolation valves and the inboard isolation valve for the reactor core isolation cooling steam supply line, which is attached to the MSS piping. The EPU component vibration monitoring locations are summarized in Table 4-4.

Component vibration acceptance criteria are based on the dynamic characteristics of the specific components, as well as the frequency content of the excitation vibrations. In order to obtain sufficient frequency data for acceptance criteria development, baseline vibration monitoring of the selected components will be performed prior to EPU power ascension. The component vibration acceptance criteria, which will consider fatigue and wear potential of the components, will be developed following collection of the baseline vibration data.

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ATTACHMENT 10 - FLOW INDUCED VIBRATION - PIPING / COMPONENT EVALUATION Table 4-4 EPU Component Monitoring Locations System Valve ID Monitoring Description System__VaveI Direction MSS 2-MSS*PSV120 X

MSS 2-MSS*PSV120 Y

MSL A SRV #1 MSS 2-MSS*PSV120 Z

MSS 2-MSS*PSVI23 X

MSS 2-MSS*PSV123 Y

MSL A SRV #4 MSS 2-MSS*PSV123 Z

MSS 2-MSS*PSV129 X

MSS 2-MSS*PSV129 Y

MSL C SRV #1 MSS 2-MSS*PSV129 Z

MSS 2-MSS*PSV133 X

MSS 2-MSS*PSV133 Y

MSL C SRV #5 MSS 2-MSS*PSV133 Z

MSS 2-MSS*AOV6A X

MSS 2-MSS*AOV6A Y

MSL A Inboard MSIV MSS 2-MSS*AOV6A Z

MSS 2-MSS*AOV7A X

MSS 2-MSS*AOV7A Y

MSL A Outboard MSIV MSS 2-MSS*AOV7A Z

ICS*

2-ICS*MOVl28 X

ICS 2-ICS*MOV128 Y

ICS inboard isolation valve ICS 2-ICS*MOV128 Z

• Reactor Core Isolated Cooling System 13 of 16

ATTACHMENT 10 - FLOW INDUCED VIBRATION - PIPING / COMPONENT EVALUATION 4.3 Data Acquisition and Reduction Methodology The accelerometer data will be collected during EPU power ascension at pre-determined power levels using two PC-based digital data acquisition systems (DAS's). One DAS will be located in the reactor building and another DAS will be located in the turbine building. Each data set will be recorded using a minimum sample rate of 2000 samples per second per channel for a minimum duration of one minute.

The raw time history data for each power level will be processed for comparison to applicable acceptance criteria. The data processing will include integration, determination of peak, peak-to-peak and root mean square (rms) values, and high and low pass filtering, as applicable for specific monitoring locations and acceptance criteria bases. Additional data processing, such as frequency analysis, will be performed to aid data analysis, as required.

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ATTACHMENT 10 - FLOW INDUCED VIBRATION - PIPING / COMPONENT EVALUATION 5.0

SUMMARY

Review of previous vibration data collected during initial start-up testing and power ascension to current uprated power levels, as discussed in Section 3, indicates relatively low vibration levels. Extrapolation of this earlier data to EPU power levels indicates that vibration of piping and components will not be adversely affected by EPU operation.

A confirmatory test program will be implemented to perform vibration monitoring during power ascension to EPU conditions. Large and small bore piping, as well as attached components, on systems experiencing significant flow increases as a result of EPU will be included in the monitoring program.

Piping vibration acceptance criteria is based on ASME OM-S/G Part 3. Component vibration acceptance criteria will be based on component-specific dynamic characteristics and baseline vibration monitoring results.

Monitoring of inaccessible piping and components will be accomplished using accelerometers wired to data acquisition systems located in the reactor and turbine buildings. Accessible piping will be monitored by performing visual observations and by taking vibration measurements using hand-held vibration instruments during power ascension to EPU conditions.

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ATTACHMENT 10 - FLOW INDUCED VIBRATION - PIPING / COMPONENT EVALUATION

6.0 REFERENCES

1.

BWR Owners' Group EPU Committee, Extended Power Uprate (EPU) Lessons Learned and Recommendations, NEDO-33159 Revision 1, January 2007.

2.

GE Nuclear Energy, "Constant Pressure Power Uprate," Licensing Topical Report NEDC-33004P-A, Revision 4, Class III (Proprietary), July 2003; and NEDO-33004, Class I (Non-proprietary), July 2003.

3.

ASME OM-S/G, Standards and Guides for Operation and Maintenance of Nuclear Power Plants, Part 3, 2007 Edition, "Requirements for Preoperational and Initial Start-up Vibration Testing of Nuclear Power Plant Piping Systems."

16 of 16

ENCLOSURE ATTACHMENT 12 Affidavit Justifying Withholding Proprietary Information in the Steam Dryer Evaluation Nine Mile Point Nuclear Station, LLC May 27, 2009

<cz3z2DD-Continuum Dynamics, Inc.

(609) 538-0444 (609) 538-0464 fax 34 Lexington Avenue Ewing, NJ 08618-2302 AFFIDAVIT Re:

C.D.I. Report 08-08P "Acoustic and Low Frequency Hydrodynamic Loads at CLTP Power Level on Nine Mile Point Unit 2 Steam Dryer to 250 Hz,"

Revision 1; and C.D.I. Report 08-24P "Stress Assessments of Nine Mile Point Unit 2 Steam Dryer," Revision 0 I, Alan J. Bilanin, being duly sworn, depose and state as follows:

1.

I hold the position of President and Senior Associate of Continuum Dynamics, Inc. (hereinafter referred to as C.D.I.), and I am authorized to make the request for withholding from Public Record the Information contained in the documents described in Paragraph 2. This Affidavit is submitted to the Nuclear Regulatory Commission (NRC) pursuant to 10 CFR 2.390(a)(4) based on the fact that the attached information consists of trade secret(s) of C.D.I. and that the NRC will receive the information from C.D.I. under privilege and in confidence.

2.

The Information sought to be withheld, as transmitted to Constellation Energy Group as attachments to C.D.I. Letter No. 09039 dated 24 March 2009, C.D.I.

Report 08-08P "Acoustic and Low Frequency Hydrodynamic Loads at CLTP Power Level on Nine Mile Point Unit 2 Steam Dryer to 250 Hz,"

Revision 1; and C.D.I. Report 08-24P "Stress Assessments of Nine Mile Point Unit 2 Steam Dryer," Revision 0.

3.

The Information summarizes:

(a) a process or method, including supporting data and analysis, where prevention of its use by C.D.I.'s competitors without license from C.D.I. constitutes a competitive advantage over other companies; (b) Information which, if used by a competitor, would reduce his expenditure of resources or improve his competitive position in the design, manufacture, shipment, installation, assurance of quality, or licensing of a similar product; (c) Information which discloses patentable subject matter for which it may be desirable to obtain patent protection.

The information sought to be withheld is considered to be proprietary for the reasons set forth in paragraphs 3(a), 3(b) and 3(c) above.

4.

The Information has been held in confidence by C.D.I., its owner.

The Information has consistently been held in confidence by C.D.I. and no public disclosure has been made and it is not available to the public. All disclosures to

third parties, which have been limited, have been made pursuant to the terms and conditions contained in C.D.I.'s Nondisclosure Secrecy Agreement which must be fully executed prior to disclosure.

5.

The Information is a type customarily held in confidence by C.D.I. and there is a rational basis therefore. The Information is a type, which C.D.I. considers trade secret and is held in confidence by C.D.I. because it constitutes a source of competitive advantage in the competition and performance of such work in the industry. Public disclosure of the Information is likely to cause substantial harm to C.D.I.'s competitive position and foreclose or reduce the availability of profit-making opportunities.

I declare under penalty of perjury that the foregoing affidavit and the matters stated therein are true and correct to be the best of my knowledge, information and belief.

Executed on this ____

day of

.ac 2009.

C'ontinuum amics, Inc.

Subscribed and sworn before me this day:

MOYLct,,.

iA 4 L.?

Barbara A. Agans, Notary Public BARBARA A. AGANS NOTARy PUBLIC OF NEW JERSEY MY COMM. EXPIRES MAY 6.2012

<75DJ

- Continuum Dynamics, Inc.

(609) 538-0444 (609) 538-0464 fax 34 Lexington Avenue Ewing, NJ 08618-2302 AFFIDAVIT Re:

C.D.I. Report 08-13P "Flow-Induced Vibration in the Main Steam Lines at Nine Mile Point Unit 2 and Resulting Steam Dryer Loads," Revision 1 I, Alan J. Bilanin, being duly sworn, depose and state as follows:

1.

I hold the position of President and Senior Associate of Continuum Dynamics, Inc. (hereinafter referred to as C.D.I.), and I am authorized to make the request for withholding from Public Record the Information contained in the document described in Paragraph 2. This Affidavit is submitted to the Nuclear Regulatory Commission (NRC) pursuant to 10 CFR 2.390(a)(4) based on the fact that the attached information consists of trade secret(s) of C.D.I. and that the NRC will receive the information from C.D.I. under privilege and in confidence.

2.

The Information sought to be withheld, as transmitted to Constellation Energy Group as attachments to C.D.I. Letter No. 09041 dated 26 March 2009, C.D.I.

Report 08-13P "Flow-Induced Vibration in the Main Steam Lines at Nine Mile Point Unit 2 and Resulting Steam Dryer Loads," Revision 1.

3.

The Information summarizes:

(a) a process or method, including supporting data and analysis, where prevention of its use by C.D.I.'s competitors without license from C.D.I. constitutes a competitive advantage over other companies; (b) Information which, if used by a competitor, would reduce his expenditure of resources or improve his competitive position in the design, manufacture, shipment, installation, assurance of quality, or licensing of a similar product; (c) Information which discloses patentable subject matter for which it may be desirable to obtain patent protection.

The information sought to be withheld is considered to be proprietary for the reasons set forth in paragraphs 3(a), 3(b) and 3(c) above.

4.

The Information has been held in confidence by C.D.I., its owner.

The Information has consistently been held in confidence by C.D.I. and no public disclosure has been made and it is not available to the public. All disclosures to third parties, which have been limited, have been made pursuant to the terms and conditions contained in C.D.I.'s Nondisclosure Secrecy Agreement which must be fully executed prior to disclosure.

5.

The Information is a type customarily held in confidence by C.D.I. and there is a rational basis therefore. The Information is a type, which C.D.I. considers trade secret and is held in confidence by C.D.I. because it constitutes a source of competitive advantage in the competition and performance of such work in the industry. Public disclosure of the Information is likely to cause substantial harm to C.D.I.'s competitive position and foreclose or reduce the availability of profit-making opportunities.

I declare under penalty of perjury that the foregoing affidavit and the matters stated therein are true and correct to be the best of my knowledge, information and belief.

Executed on this c26 day of _

_________4 2009.

Alan J. Bilanin Continuum Dynamics, Inc.

Subscribed and sworn before me this day:

e6.,

(j~e~e'b We4 otarYPublic EILEEN P. BURMEISTER NOTARY PUBLIC OF NEW JERSEY MY COMM. EXPIRES MAY 6; 2012

Continuum Dynamics, Inc.

(609) 538-0444 (609) 538-0464 fax 34 Lexington Avenue Ewing, NJ 08618-2302 AFFIDAVIT Re:

Structural Integrity Associates, Inc. Calculation Package NMP-26Q-302 "Nine Mile Point Unit 2 Main Steam Line Strain Gage Data Reduction" I, Barbara Agans, being duly sworn, depose and state as follows:

I1.

I hold the position of Director, Business Administration of Continuum Dynamics, Inc. (hereinafter referred to as C.D.I.), and I am authorized to make the request for withholding from Public Record the Information contained in the document' described in Paragraph 2. This Affidavit is submitted to the Nuclear Regulatory Commission (NRC) pursuant to 10 CFR 2.390(a)(4) based on the fact that the attached information consists of trade secret(s) of C.D.I. and that the NRC will receive the information from C.D.I. under privilege and in confidence.

2.

The Information sought to be withheld, as transmitted to Constellation Energy Group as attachments to C.D.I. Letter No. 09044 dated 27 March 2009, Structural Integrity Associates, Inc. Calculation Package NMP-26Q-302 "Nine Mile Point Unit 2 Main Steam Line Strain Gage Data Reduction".

3.

The Information summarizes:

(a) a process or method, including supporting data and analysis, where prevention of its use by C.D.I.'s competitors without license from C.D.I. constitutes a competitive advantage over other companies; (b) Information which, if used by a competitor, would reduce his expenditure of resources or improve his competitive position in the design, manufacture, shipment, installation, assurance of quality, or licensing of a similar product; (c) Information which discloses patentable subject matter for which it may be desirable to obtain patent protection.

The information sought to be withheld is considered to be proprietary for the reasons set forth in paragraphs 3(a), 3(b) and 3(c) above.

4.

The Information has been held in confidence by C.D.I., its owner.

The Information has consistently been held in confidence by C.D.I. and no public disclosure has been made and it is not available to the public. All disclosures to third parties, which have been limited, have been made pursuant to the terms and conditions contained in C.D.I.'s Nondisclosure Secrecy Agreement which must be fully executed prior to disclosure.

5.

The Information is a type customarily held in confidence by C.D.I. and there is a rational basis therefore. The Information is a type, which C.D.I. considers trade secret and is held in confidence by C.D.I. because it constitutes a source of competitive advantage in the competition and performance of such work in the industry. Public disclosure of the Information is likely to cause substantial harm to C.D.I.'s competitive position and foreclose or reduce the availability of profit-making opportunities.

I declare under penalty of perjury that the foregoing affidavit and the matters stated therein are true and correct to be the best of my knowledge, information and belief.

Executed on this ___

day ofj1-2009.

Barbara A. Agans Continuum Dynamics, Inc.

Subscribed and swom before me this day:

0c1? c9&C00 eln turmieister otary Pblic EILEEN P. BURMEISTER NOTARy PUBLIC OF NEW JERSEY MY COMM. EXPIRES MAY 6, 2012

ENCLOSURE ATTACHMENT 13 Steam Dryer Evaluation Nine Mile Point Nuclear Station, LLC May 27, 2009

ATTACHMENT 13 - STEAM DRYER EVALUATION Table of Contents 1.0 Introduction 2.0 Screening to Assess Potential for MSL Acoustic Excitation at Power 3.0 Defining MSL Local Pressure Fluctuation Based on In-Plant Tests 4.0 Steam Dryer Fluctuating Pressure Loading from In-Plant MSL Pressure Measurements 5.0 Steam Dryer Structural Response and Stress Margin 6.0 Power Ascension Monitoring/Data Evaluation 7.0 References 8.0 Attachments 3.1 3.2 3.3 3.4 3.5 3.6 3.7 3.8 3.9 CDI Report No.08-24P (Proprietary), Stress Assessments of Nine Mile Point Unit 2 Steam Dryer 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 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 SIA calculation NMP-26Q-302 (Proprietary), Nine Mile Point Unit 2 Main Steam Line Strain Gage Data Reduction 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 SIA Report No. 0800528.402, Nine Mile Point Unit 2 Steam Dryer ASME Stress Analysis CDI Report No. 08-24NP (Non-proprietary), Stress Assessments of Nine Mile Point Unit 2 Steam Dryer 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 SIA calculation NMP-26Q-302 (Non-proprietary version), Nine Mile Point Unit 2 Main Steam Line Strain Gage Data Reduction 1 of 7

ATTACHMENT 13 - STEAM DRYER EVALUATION 1.0 Introduction The Nine Mile Point Unit 2 (NMP2) steam dryer has been evaluated for extended power uprate (EPU) steam flow conditions consistent with the guidance provided in BWRVIP-182, "Guidance for Demonstration of Steam Dryer Integrity for Power Uprate," issued January, 2008, including the responses to the U. S. Nuclear Regulatory Commission's (NRC's) request for additional information (RAI) in April 2009.

BWRVIP-1 82 was created at the request of the NRC to provide guidance that can be followed by boiling water reactor (BWR) utilities applying for a power uprate of greater than 2% of current licensed thermal power (CLTP) in demonstrating the structural integrity of their steam dryer up to the highest planned power level. BWRVIP-182 provides the overarching approach for demonstrating the structural integrity of BWR steam dryers at power uprate conditions and was developed by representatives of Boiling Water Reactor Vessel and Internals Project (B'WRVIP) utilities, Electric Power Research Institute (EPRI), General Electric, and Continuum Dynamics Incorporated (CDI).

This document was submitted for NRC review in January 2008, the RAI received in December -2008 with responses in April 2009. The NMP2 steam dryer evaluation is in full conformance to these guidelines and the RAI responses as approved by the BWRVIP process.

The document requires that prior to submittal of an application for power uprate, the loading on the steam dryer and associated stresses be defined at power uprate conditions and that appropriate stress margin be demonstrated. The NRC RAI No. 182-4 (c) clarification relative to the required margin in BWRVIP-182 is as follows: "In Section 7, the BWRVIP is requested to clarify the minimum required alternating stress ratio.

Considering all end-to-end bias errors and uncertainties (in recent EPU approved license amendment requests such as Hope creek) as well as stress concentration factors, a minimum stress ratio of 2 shall be maintained in steam dryer components, when fluctuating pressure load prediction on dryer relies on MSL measurements. The minimum alternating stress ratio is defined as the endurance limit of the material divided by the maximum alternating stress. The stress margin as a percentage is defined as (minimum alternating stress ratio-i) * (100).

Specifically, either the alternating stress ratio > 2.0; or stress margin on alternating stress > 100 percent." The NMP2 steam dryer applies this NRC approved margin as stated in the above RAI.

BWRVIP-182 defines an overall approach for demonstrating steam dryer structural integrity that allows the use of subscale and full scale tests and analytical models. The document requires that the technical basis for and benchmarking of any analytical or testing methodologies utilized in demonstrating steam dryer integrity be documented and submitted to NRC for review, and that specific acceptance criteria and values for key parameters to be used in the evaluation of steam dryers be defined. The BWRVIP-182 document guidance is intended to comply with the guidance provided in NRC Regulatory Guide (RG) 1.20, Rev. 3, "Comprehensive Vibration Assessment Program for Reactor Internals during Preoperational and Initial Startup Testing," issued in March 2007.

BWRVP-182 was issued with implementation guidance that states: "In accordance with the implementation requirements of Nuclear Energy Institute (NEI) 03-08, Guideline for the Management of Materials Issues, sections 2 through 10 of this report are "needed" and the remaining sections are for information only. The guidance provided herein shall be followed by any BWR utility submitting an application for a power uprate exceeding 2 % of CLTP after the date of publication of this report."

BWRVIP-182 refers to BWRVIP-181, Steam Dryer Repair Design Criteria, and states that for structural evaluation of existing and replacement steam dryers for power uprate, the applicant is referred to the load types, load combinations and corresponding allowable stresses defined in Section 7 of BWRVIP-181.

The NMP2 steam dryer analysis for EPU was performed consistent with the original steam dryer loads adjusted for the higher EPU normal operating loads and EPU reactor internal pressure difference (RIPD) values including the flow induced vibration (F1V) load added to the design basis load combinations as recommended section 7 ofBWVIP-181.

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ATTACHMENT 13 - STEAM DRYER EVALUATION NOTE BWRVIP-194, "BWR Vessel and Intemals Project, Methodologies for Demonstrating Steam Dryer Integrity for Power Uprate" is referenced throughout this attachment.

BWRVIP-194 was submitted for NRC review in October 2008; however, it has not been completely reviewed nor accepted by the staff for use as a basis document for dryer evaluation methodologies. Because BWRVIP-194 is an excellent single point source for many of the techniques used during evaluation of the NMP2 steam dryer, this document is referenced to provide additional detail of the NMP2 specific analyses performed and not as a justification for the analysis methodologies.

BWRVIP-182 requires that the technical basis for and benchmarking of any analytical or testing methodologies utilized in demonstrating steam dryer integrity be documented and submitted to NRC for review and that specific acceptance criteria and values for key parameters to be used in the evaluation of steam dryers are defined. The NMP2 steam dryer evaluation has been performed using the methodology documented in BWRVIP-194. The plant specific analyses references to BWRVIP-194 relative to the documentation meets this requirement.

The NMP2 steam dryer evaluation followed the BWRVIP-182 guidance using the methods described in BWRVIP-194. Section 3 of BWRVIP-194 provides the summary of the key steps. The details of the NMP2 specific evaluations are provided in supplemental stand alone documents included in this attachment. Only the summary conclusion related to each step of the evaluation are summarized with reference to the specific details in the included or referenced reports.

2.0 Screening to Assess Potential for MSL Acoustic Excitation at Power Uprate Nine Mile Point Nuclear Station, LLC (NMPNS) performed the screening evaluation using both the analytical techniques described in BWRVIP-182 section 3 and BWRVIP-194 section 4. Refined acoustic modeling of MSL standpipes was performed as described in section 4.3 of BWRVIP-194 for the main steam safety relief valve (SRV) standpipe. The NMP2 steam lines are configured with no dead leg mounted SRVs or blind flange SRV locations. As required by BWVIIP-182, all the MSL piping branch connections such as drain lines or Reactor Core Isolation Cooling (RCIC) steam line connections greater than two inches in diameter were screened and determined to be outside the Strouhal Number range for acoustic excitation (0.25 - 0.60) for the full range from 80% CLTP through 120% of EPU power level.

NOTE Due to the nature of CDI Report 08-13P, the entire document is classified as proprietary.

For this reason, a non-proprietary version of this report is not included in this attachment.

The NMP2 SRVs are mounted to a nozzle forging with a contoured entrance radius as depicted in CDI Report 08-13P (Attachment 13.3), figure 4.5, reference 7.3. The inlet radius is included in the refined calculations for the onset velocity.

CDI Report 08-13P (Attachment 13.3) documents the calculated NMP2 SRV standpipe excitation frequency using the BWRVIP-194 refined modeling as 224 Hz at normal operating conditions of pressure and temperature with an onset velocity of 262 ft/sec.

The original licensed thermal power (OLTP) steam flow velocity is 143 ft/sec and the EPU steam flow is 177 ft/sec at 120% of OLTP steam flow velocity. This places the onset for SRV standpipe resonance at greater than 45% above the EPU power level, which meets the BWRVIP-182 screening for exclusion of SRV standpipe resonance.

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ATTACHMENT 13 - STEAM DRYER EVALUATION Additional subscale test screening validation was performed using the BWRVIP-194 1/8th scale test method. This test models all 4 steam lines from the steam dome to the turbine inlet and includes a scale model of the NMP2 steam dryer. The 1/8th scale testing is documented in CDI 13P. The testing confirms no single or double vortex onset in the CLTP to EPU steam flow range and confirms the excitation frequency of 219.5 Hz with an onset Mach number of 0.16, which is a 1.9% difference between calculated and the subscale testing. In addition, the plant data from MSL measurement confirm that the double vortex peak possible at 1/2 the Mach number of the single vortex (approximately 90% power) is not present in the data taken through CLTP conditions which includes data taken at 69%, 88%, 90%,

94%, 97% and 100% CLTP. The conclusion is that the SRV standpipe double vortex is not significant load for NMP2 at CLTP or EPU conditions.

3.0 Defining MSL Local Pressure Fluctuation Based on In-Plant Tests NOTE The non-proprietary version of SAI calculation NMP-26Q-302 is provided as 3.9. The non-proprietary version of CDI Report No.08-08P is provided as 3.8.

BWRVIP-194, section 5.0, describes in detail the methodology applied at NMP2 to obtain, filter and interpret the data.

The Structural Integrity Associates (SIA) calculation NMP-26Q-302 (Attachment 13.4) documents the strain gauge installation details, the background noise floor evaluation for the data acquisition system (DAS), and the data processing, including the raw data micro strain waterfall plots. The SIA analysis documents the data sets taken, including the electrical interference data sets taken with each power data set.

The CDI loads definition report, CDI Report 08-08P (Attachment 13.2) applies the coherence filters and applies the low steam flow filter to eliminate non acoustic noise signals as described in BWRVIP-194.

4.0 Steam Dryer Fluctuating Pressure Loading from In-Plant MSL Pressure Measurements CDI Report 08-08P (Attachment 13.2) applies the BWRVIP-194, section 6, ACM rev. 4, to the NMP2 steam dryer and main steam line geometry. Strain gauge data obtained from the four main steam lines is used to define pressure levels on the NMP2 full-scale dryer at CLTP. BWRVIP-194 includes the benchmark and validation of the methods applied at NMP2 and defines the required model bias and uncertainty methodology.

CDI Report 08-08P (Attachment 13.2), Table 5.1, defines the NMP2 loads including the bias and uncertainty for specified frequency intervals consistent with BWRVIP-194 requirements and previously accepted bias and uncertainty for the CDI ACM rev. 4 model.

CDI Report 08-08P (Attachment 13.2) includes the coherence filtering and low power filtering of the CLTP data set and defines the CLTP Power Spectral Density (PSD (psid /Hz)) versus frequency (Hz) for each MSL strain gauge location. The report concludes, based on the CLTP strain gauge data using the ACM rev. 4 model: a) The steam dryer maximum differential pressure loads, based on the validated Modified Bounding Pressure model, are less than 0.13 psid (CLTP). The maximum load is found on the lower corner of an inner hood opposite main steam line A; b) Predicts that the loads on dryer components are largest for components nearest the main steam line inlets and decrease inward into the reactor vessel.

The scaling of the CLTP FIV pressure loading is performed based on velocity squared scaling for the full frequency range, because the NMP2 screening concluded that no resonance is predicted for EPU conditions. The NMP2 velocity squared scaling bump-up factor is 1.39. Application of the velocity squared scaling is consistent with the NRC RAI 182-2. Consistent with the BWRVIP-194 methodology, 4 of 7

ATTACHMENT 13 - STEAM DRYER EVALUATION the bump-up for EPU based on velocity squared is performed on the final stress analysis. Because the bump-up is constant through-out the frequency range, a redundant finite element analysis is eliminated.

5.0 Steam Dryer Structural Response and Stress Margin CDI Report No.08-24P, reference 7.1, SIA Report No. 0801273.401, reference 7.5, and SIA Report No.

0800528.402, reference 7.6, define the steam dryer structural response and stress margin for design basis service levels A, B,C and D. The F1V load has been added to the design basis loading per the guidance in BWRVIP-181 and as described in BWRVIP-194.

The NMP2 steam dryer stress analysis was performed using the methodology described in BWRVIP-194.

The validation and methodology detailed discussion is not duplicated in the plant specific reports. The NMP2 specific reports provide the plant specific analysis results and plant specific application of the BWRVIP-194 methods. BWRVIP-194 describes in detail how the methods satisfy all the requirements of BWRVIP-182, and is consistent with the recommendation of RG 1.20.

In addition, the dryer stress analysis is consistent with NRC RAI-182-4a&b and RAI-182-5a for inclusion of supporting documentation of all known end-to-end bias and uncertainties; and RAI 182-5b for inclusion of documentation for evaluation of existing flaws and their impact on steam dryer operation at EPU. It is noted that both of these BWRVIP-182 RAIs are addressed in BWRVIP-194 sections 9 and 10.

NOTE The non-proprietary version of CDI Report No.08-24P is provided as Attachment 13.7.

The service level A stress analysis is documented in CDI Report No.08-24P. The limiting alternating stress ratio locations are defined in CDI Report 08-24P (Attachment 13.1), Table 9b. The lowest ratio is 2.02 at EPU conditions after consideration of all frequency shifts for all non reinforced locations. This ratio is at location 1, a hood support location, as shown in CDI Report 08-24P (Attachment 13.1), figure 14e. It is important to note that this is a conservative ratio, because detailed sub-modeling to refine the actual stress was not performed. Similar locations have been evaluated for similar steam dryers with an approximate improved margin of 27%. The next lowest ratio occurs at location 6, which is a closure plate inner hood location, has a CLTP ratio of 3.19 or an EPU margin of 2.30.

In order to address a recent NRC concern, NMP2 performed a re-evaluation of dryer stresses utilizing a refinement of biases and uncertainties applied over the frequency interval 60 to 100 Hertz.

This evaluation confirmed that the existing NMP2 stress reports are valid as the limiting alternating stress ratio remained greater than 2.0. Because the purpose of this evaluation was a validation of results, the existing stress reports have not been revised.

Steam Dryer Reinforcements:

The analysis determined that two components on the steam dryer require reinforcement of selected attachment welds to meet the 100% margin on alternating stress for the normal EPU operating condition.

The components are the inner and middle hood end cover welds and the lifting rod upper brace to vane bank weld. The locations are detailed in Appendixes A and B of CDI Report 08-24P (Attachment 13.1).

The end cover reinforcement is the addition of a 0.25" inner weld over the upper 18 inches on the vane bank to closure plate and the addition of a 0.125" inner weld on the closure plate to hood side. The lifting rod reinforcement is an increase in the attachment weld from 0.25" to 0.375" for the upper brace on each of the 4 lifting rods.

The evaluation of these locations applied detailed sub modeling to evaluate the reinforcement and establish the limiting alternating stress margin. CDI Report 08-24P (Attachment 13.1), Table 9b locations 2 and 3 are the lifting rod attachment weld with a ratio of 2.81 for CLTP or 2.03 at EPU conditions. CDI Report 08-24P (Attachment 13.1), Table 9b location 4 is the limiting location on the end cover to vane 5 of 7

ATTACHMENT 13 - STEAM DRYER EVALUATION bank reinforcement with a CLTP ration of 2.83 (EPU =2.04) and location 5 is the limiting location on the end cover to hood weld reinforcement with a CLTP ratio of 2.95 (EPU=2.13).

Steam Dryer Cracking:

The baseline inspections of the NMP2 steam dryer identified steam dryer cracking consistent with the BWR fleet operating history, as described in section 2.4 of BWRVIP-139. The indications that require assessment relative to EPU service conditions are the indications located in the upper support ring, the drain channel to skirt vertical weld, and in the tie bar to hood weld heat affected zone (HAZ). Indications in the anti-rotation tack welds associated with the tie rod cam nut washers and the lifting lug have been identified as repair locations prior to EPU service.

SIA Report No. 0801273.401, Reference 7.5, documents the flaw evaluation and vibration assessment performed consistent with BWRVIP-139, BWRVIP-182 including RAIs and BWRVIP-194 requirements for the observed indications at EPU service conditions. The evaluation concludes that these locations do not change the dynamic modal response of the dryer structure and therefore, the FEA model remains applicable to the current condition of the NMP2 steam dryer. The flaw evaluations for the indications in the ring and the indication in the dryer skirt adjacent to a drain channel remain well below the largest R ratio curve potential fatigue crack growth for austenitic stainless steel and therefore, essentially no fatigue crack growth is predicted for EPU operating conditions. Because the indications are characterized as IGSCC they were also evaluated conservatively assuming further intergranular stress corrosion cracking (IGSCC) growth using BWRVIP-14A methods. The IGSCC crack growth assumes an inspection interval of one cycle resulting in an insignificant change in the section thickness and the remaining ligament. The conclusion is that these components remain well within the required code safety factors for the all service conditions, including the limiting upset and faulted conditions with the EPU FlY load included.

The tie bar IGSCC cracking is located in the HAZ of several tie bars. This cracking was originally identified during the initial BWRVIP-139 baseline inspection in 2004.

The locations have been monitored in the 2006 and 2008 refuel outages with no measured crack growth. This cracking is located in the HAZ of the attachment weld, which is not typical of the industry experience related to fatigue of the tie bar locations.

The tie bar attachment location is identified in CDI Report 08-24P (Attachment 13.1), Table 9b, and has a primary stress ratio of 1.59 with an alternating stress ratio of 9.05.

This indicates significant margin for both CLTP and EPU conditions. However, because of the industry experience at this location and the FEA conclusion that it is at one of the higher stress locations in the steam dryer; corrective measures for the IGSCC condition involving an overlay weld will be performed prior to EPU service.

6.0 Power Ascension monitoring/data Evaluation BWRVIP-182, section 9, defines two approaches that can be taken to confirm that steam dryer stresses are within acceptable limits during power ascension: 1) Pre-established limit curves or 2) Conduct Stress Analysis during Power Ascension. BWRVIP-194, section 9.1.4, describes the application of the real time stress analysis methodology and BWRVIP-194, section 13, describes the pre-established limit curve method. The power ascension monitoring for NMP2 will be implemented consistent with both of these guidance documents.

The NMP2 steam dryer monitoring plan is to develop, prior to power ascension, limit curves generated from the CLTP strain gauge data. This approach is a lesson learned from the Hope Creek EPU power ascension where plant noise profiles and refurbished strain gags impacted the limit curves, requiring the regeneration of the curves. In addition, the NMP2 plan is to implement the BWRVIP-194, section 13.3, option where the plant may perform reanalysis and produce new limit curves whenever it is felt that the Level 2 limit curve is being challenged.

Additionally, the plan is to implement the BWRVIP-194, section 9.1.4, real time power ascension stress analysis option at selected hold points.

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ATTACHMENT 13 - STEAM DRYER EVALUATION Based on the CDI Report 08-24P (Attachment 13.1) stress analysis and the CDI Report 08-08P (Attachment 13.2) loads, sample limit curves have been prepared with level 1 and level 2 criteria. The sample limit curves are included as an appendix to CDI Report 08-08P (Attachment 13.2). Consistent with NRC RAI 182-6 the NMP2 action to be taken at level 1 and level 2 is as follows: If Level 2 criteria is reached, reactor power ascension is to be suspended until an engineering evaluation concludes that further power ascension is justified. Should Level 1 be reached or exceeded, reactor power is returned to a previously acceptable power level that satisfies level 2 criteria while an engineering evaluation is undertaken.

7.0 References 7.1 CDI Report No.08-24P, "Stress Assessments of Nine Mile Point Unit 2 Steam Dryer," Rev. 1 7.2 CDI Report No.08-08P, "Acoustic and Low Frequency Hydrodynamic Loads at CLTP Power Level on Nine Mile Point Unit 2 Steam Dryer to 250 Hz," Rev. 1 7.3 CDI Report No.08-13P, "Flow-Induced Vibration in the Main Steam Lines at Nine Mile Point Unit 2 and Resulting Steam Dryer Loads," Rev. 1 7.4 SIA calculation NMP-26Q-302, "Nine Mile Point Unit 2 Main Steam Line Strain Gage Data Reduction," Rev. 0 7.5 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," Rev. 1 7.6 SIA Report No. 0800528.402, "Nine Mile Point Unit 2 Steam Dryer ASME Stress Analysis,"

Rev. 0 7.7 BWRVIP-14A, "Evaluation of Crack Growth in BWR Stainless Steel RPV Internals,"

September 2008 7.8 BWRVIP-139, "Steam Dryer Inspection and Flaw Evaluation Guidelines," April 2005 7.9 BWRVIP-181, "Steam Dryer Repair Design Criteria," November 2007 7.10 BWRVIP-182, "Guidance for Demonstration of Steam Dryer Integrity for Power Uprate,"

(including RAIs and responses), January 2008 7.11 BWRVIP-194, "Methodologies for Demonstrating Steam Dryer Integrity for Power Uprate,"

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