Text

License Amendment Request for Appendix K Measurement Uncertainty Recapture - Power Uprate Request
	ML023250307
Person / Time
Site:	Cook
Issue date:	11/15/2002
From:	Joseph E Pollock; Indiana Michigan Power Co
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	AEP:NRC:2902
	Download: ML023250307 (172)
	v • d • e

Indiana Michigan Power Company Cook NudearPant One Cook Pace B1ndgman,MI 49106 6146 1 INDIANA MICHIGAN POWER November 15, 2002 AEP:NRC:2902 10 CFR 50.90 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Mail Stop O-P1-17 Washington, DC 20555-0001

SUBJECT:

Donald C. Cook Nuclear Plant Unit 2 Docket No. 50-316 License Amendment Request for Appendix K Measurement Uncertainty Recapture - Power Uprate Request

Dear Sir or Madam:

Pursuant to 10 CFR 50.90, Indiana Michigan Power Company (I&M), the licensee for Donald C. Cook Nuclear Plant (CNP) Unit 2, proposes to amend Facility Operating License (OL) DPR-74, including Appendix A, Technical Specifications (TS). CNP Unit 2 is presently licensed for a core power of 3411 megawatts thermal (MWt). Based on the implementation of more accurate feedwater flow measurement instrumentation and power calorimetric uncertainty values, approval is sought to increase the licensed core power by 1.66 percent, to 3468 MWt.

The feedwater flow measurement system to be installed at CNP Unit 2 is a Leading Edge Flow Meter (LEFMT M) CheckPlusTM ultrasonic multi-path transit time flowmeter. The design of this advanced flow measurement system was submitted by the manufacturer, Caldon Incorporated, in topical reports that were reviewed and approved by the Nuclear Regulatory Commission (NRC).

By Reference 1, I&M, the licensee for CNP Unit 1, proposed to amend OL DPR-58 to increase the maximum reactor core power level permitted by the license. By References 2 and 3, the NRC requested additional information regarding the proposed Unit 1 measurement uncertainty recapture power uprate request. I&M responded to the Reference 2 request for additional information (RAI) in a letter dated October 15, 2002 (Reference 4). In addition to the RAI responses provided by Reference 4, I&M submitted the calculation that establishes the thermal power measurement uncertainty for the proposed 1.66 percent power uprate (References 5 and 6). The thermal power measurement uncertainty calculation provided by Reference 6 incorporates information requested in References 2 and 3, and applies to both CNP Unit 1 and Unit 2 0 measurement uncertainty recapture power uprate requests.

AEP A merica's Energj' Partner

U. S. Nuclear Regulatory Commission AEP:NRC:2902 Page 2 provides an oath and affirmation affidavit. Enclosure 2 provides a detailed description and safety analysis to support the proposed changes, including the 10 CFR 50.92(c) evaluation, which concludes that no significant hazard is involved, and the environmental assessment. Attachment 1 provides marked-up OL/TS pages for CNP Unit 2. Attachment 2 provides the proposed OLUTS pages with the changes incorporated. Attachment 3 provides the information delineated in Regulatory Issue Summary 2002-03, "Guidance on the Content of Measurement Uncertainty Recapture Power Uprate Applications," to establish the appropriate scope, structure, and level of detail for this Appendix K Measurement Uncertainty Recapture (MUR) power uprate submittal. duplicates the Reference 3 responses to the NRC's RAI pertaining to the Unit 1 MUR uprate request and addresses the applicability of each question to this Unit 2 MUR uprate request. Attachment 5 contains a list of new regulatory commitments made in this letter.

I&M recognizes that various WCAPs that are part of the CNP Unit 2 licensing basis may have included explicit references to their use of "102% of licensed core power levels." These WCAPs will not be revised to reflect this requested power uprate, because it is understood that the statements provided in these WCAPs refer to the previously-required 2 percent Appendix K margin and the currently licensed power level.

I&M requests approval of this request by March 1, 2003, to support a power uprate following the April 2003 refueling outage. I&M requests a 90-day implementation period.

No previous submittals affect OUTS pages that are submitted in this request. If any future submittals affect these pages, I&M will coordinate changes to the pages with the NRC Project Manager to ensure proper OL/TS page control when the associated license amendment requests are approved.

Should you have any questions, please contact Mr. Brian A. McIntyre, Manager of Regulatory Affairs, at (269) 697-5806.

Sincerely, J. E. Pollock Site Vice President NH/jen

References:

U. S. Nuclear Regulatory Commission AEP:NRC:2902 Page 3

1. Letter from J. E. Pollock, I&M, to NRC Document Control Desk, "4Donald C. Cook Nuclear Plant Unit 1 License Amendment Request for Appendix K Measurement Uncertainty Recapture - Power Uprate Request,"

AEP:NRC:2900, dated June 28, 2002

2. Letter from J. F. Stang, NRC, to A. C. Bakken II, I&M, "Donald C. Cook Nuclear Plant, Unit 1 - Request for Additional Information Regarding License Amendment Request, 'Power Uprate Measurement Uncertainty Recapture,' dated June 28, 2002 (TAC No. MB5498)," dated October 2, 2002

3. Letter from J. F. Stang, NRC, to A. C. Bakken, Ill, I&M, "Donald C. Cook Nuclear Plant, Unit 1 - Second Request for Additional Information Regarding License Amendment Request, 'Power Uprate Measurement Uncertainty Recapture' (TAC No. MB5498)," dated November 7, 2002

4. Letter from J. E. Pollock, I&M, to NRC Document Control Desk, "Donald C. Cook Nuclear Plant, Unit 1 - Response to Nuclear Regulatory Commission Request for Additional Information Regarding License Amendment Request for Appendix K Measurement Uncertainty Recapture Power Uprate Request (TAC No. MB5498)," AEP:NRC:2900-01, dated October 15, 2002

5. Letter from J. E. Pollock, I&M, to NRC Document Control Desk, "Donald C. Cook Nuclear Plant, Units 1 and 2 - Submittal of Power Measurement Uncertainty Calculation in Support of License Amendment Request for Appendix K Measurement Uncertainty Recapture - Power Uprate Request (TAC No. MB5498)," AEP:NRC:2900-03, dated October 17, 2002

6. Letter from J. E. Pollock, I&M, to NRC Document Control Desk, "Donald C.

Cook Nuclear Plant, Units 1 and 2 - Submittal of Change to Power Measurement Uncertainty Calculation in Support of License Amendment Request for Appendix K Measurement Uncertainty Recapture - Power Uprate Request (TAC No. MB5498)," AEP:NRC:2900-04, dated November 15, 2002

U. S. Nuclear Regulatory Commission AEP:NRC:2902 Page 4

Enclosures:

1. Notarized Oath and Affirmation Statement

2. Evaluation of Proposed Changes to Facility Operating License DPR-74 Attachments:

1. Facility Operating License and Technical Specification Pages Marked to Show Proposed Changes

2. Proposed Faclity Operating License and Technical Specification Pages

3. Summary of Measurement Uncertainty Recapture Evaluation Following Guidance Provided in Regulatory Issue Summary 2002-03

4. Responses to NRC Request for Additional Information Regarding Unit 1 MUR Power Uprate Request

5. Regulatory Commitments c: K. D. Curry, AEP Ft. Wayne J. E. Dyer, NRC Region III MDEQ - DW & RPD NRC Resident Inspector J. F. Stang, Jr. - NRC Washington DC R. Whale, MPSC

U. S. Nuclear Regulatory Commission AEP:NRC:2902 Page 5 bc: G. P. Arent A. C. Bakken III M. J. Finissi S. A. Greenlee D. W. Jenkins, w/o attachments J. A. Kobyra, w/o attachments B. A. McIntyre, w/o attachments J. E. Newmiller D. J. Poupard K. W. Riches M. K. Scarpello, w/o attachments T. K. Woods, w/o attachments

Enclosure 1 to AEP:NRC:2902 AFFIRMATION I, Joseph E. Pollock, being duly sworn, state that I am Site Vice President of Indiana Michigan Power Company (I&M), that I am authorized to sign and file this request with the Nuclear Regulatory Commission on behalf of I&M, and that the statements made and the matters set forth herein pertaining to I&M are true and correct to the best of my knowledge, information, and belief.

Indiana Michigan Power Company

Iollock Site Vice President SWORN TO AND SUBSCRIBED BEFORE ME THIS j DAY OF 2002 DANIELLE M.SCHRADER Notary Public, Berrien County. Ml My Commission Expires Apr 4,2004 My CommissoNEotiares pu- )

My Commission Expires ---

"7 .7-* 7 "-

to AEP:NRC:2902 Page I Appendix K Measurement Uncertainty Recapture Power Uprate Request 1.0 Description Indiana Michigan Power Company (I&M) proposes to amend Facility Operating License (OL)

DPR-74, including Appendix A, Technical Specifications (TS), for Donald C. Cook Nuclear Plant (CNP) Unit 2. CNP Unit 2 is presently licensed for a core power of 3411 megawatts thermal (MWt). Through the use of more accurate feedwater flow measurement instrumentation, approval is sought to increase the licensed core power by 1.66 percent, to 3468 MWt.

2.0 Proposed Changes The proposed license amendment would revise the CNP Unit 2 OL and TS to increase the licensed power level to 3468 MWt, or 1.66 percent greater than the current level of 3411 MWt.

The proposed changes, which are indicated on the marked-up pages in Attachment 1, are described below:

1. Paragraph 2.C.(1) in OL DPR-74 is revised to authorize operation at a steady state reactor core power level not in excess of 3468 MWt (100 percent power).

2. The definition of RATED THERMAL POWER (RTP) in TS 1.3 is revised to reflect the increase from 3411 MWt to 3468 MWt.

3. TS 3.5.2, Action b, is revised to increase the maximum allowable core power level with a safety injection cross-tie valve closed. To reflect application of the measurement uncertainty recapture (MUR) power uprate, the maximum allowed power level in this Action Statement is revised from 3250 MWt to 3304 MWt.

4. TS Table 3.7-1, "Maximum Allowable Power Range Neutron Flux High Setpoint with Inoperable Steam Line Safety Valves during 4 Loop Operation," is revised to reflect the maximum allowed power for operation with inoperable main steam safety valves (MSSVs). With one inoperable MSSV per loop, the power reduction is revised from 61.6 percent RTP to 60.4 percent RTP. With multiple inoperable safety valves per loop, the power reduction and associated reduction in high flux reactor trip setpoints is revised to 43.0 percent (two inoperable MSSVs) and 25.7 percent (three inoperable MSSVs).

to AEP:NRC:2902 Page 2 3.0 Background CNP Unit 2 is presently licensed for a core power of 3411 MWt. Based on the implementation of more accurate feedwater flow measurement instrumentation and associated power calorimetric uncertainty values, approval is sought to increase the licensed core power by 1.66 percent, to 3468 MWt.

The 1.66 percent core power uprate for CNP Unit 2 (MUR Uprate Program) is based on recapturing measurement uncertainty currently included in the analytical margin. The analytical margin was originally required for emergency core cooling system (ECCS) evaluation models performed in accordance with the requirements set forth in 10 CFR 50, Appendix K, "ECCS Evaluation Models." In June 2000, the Nuclear Regulatory Commission (NRC) approved a change to the 10 CFR 50, Appendix K, requirements to provide licensees with the option of maintaining the 2 percent power margin between the licensed core power level and the assumed core power level for ECCS evaluations, or apply a reduced margin to the ECCS evaluations. The proposed alternative to recapture margin for ECCS evaluation has been demonstrated to account for uncertainties due to a reduction in power level instrumentation error.

I&M will be installing a more accurate feedwater flow measurement system manufactured by Caldon, Incorporated (Caldon). The NRC has approved Caldon Leading Edge Flow Meter (LEFM) CheckPlusTM flow measurement systems, similar to the system to be installed at CNP Unit 2, in a Safety Evaluation Report dated December 20, 2001 (Reference 7). The Caldon instrumentation provides the capability to determine core power level with a power measurement uncertainty of approximately 0.31 percent. Based on the use of the Caldon instrumentation and CNP Unit 2 power calorimetric uncertainty values, including retention of a 0.03 percent design margin beyond the uncertainty of 0.31 percent, I&M proposes to use a reduced margin for ECCS evaluation pursuant to the revised requirements of 10 CFR 50, Appendix K, to achieve an increase of 1.66 percent in the licensed core power level using current NRC-approved methodologies.

The impact of the MUR Uprate Program has been evaluated on the nuclear steam supply system (NSSS) and balance of plant (BOP) systems, components, and safety analyses. Attachment 3 summarizes these evaluations, analyses, and conclusions, and provides the information delineated in NRC Regulatory Issue Summary (RIS) 2002-03, "Guidance on the Content of Measurement Uncertainty Recapture Power Uprate Applications," (Reference 1) to facilitate NRC review of Appendix K MUR power uprate license amendment requests.

4.0 Technical Analysis I&M has evaluated the impact of the proposed power uprate on NSSS systems and components, BOP systems, and safety analyses. Attachment 3 summarizes the results of the comprehensive to AEP:NRC:2902 Page 3 engineering review performed to evaluate the increase in the licensed core power from 3411 MWt to 3468 MWt. Results of this analysis are provided in a format consistent with the regulatory guidance provided in RIS 2002-03.

The evaluation for the CNP Unit 2 MUR Uprate Program was implemented consistent with the methodology established in WCAP-10263, "A Review Plan for Uprating the Licensed Power of a PWR Power Plant" (Reference 2). The methodology in WCAP-10263 establishes the general approach and criteria for uprate projects, including the broad categories that must be addressed.

These include the NSSS performance parameters, design transients, systems, components, accidents, and nuclear fuel, as well as the interfaces between the NSSS and BOP systems. The methodology includes the use of well-defined analysis input assumptions and parameter values, currently-approved analytical techniques, and currently-applicable licensing criteria and standards. The results of I&M's analyses and evaluations demonstrate that applicable acceptance criteria will continue to be met following the implementation of the proposed 1.66 percent power uprate.

I&M has reviewed the proposed MUR Uprate Program to determine if these changes will result in an increase in the plant's risk profile. This review found that the installation of the LEFM CheckPlus system in the feedwater system would not affect the CNP Probabilistic Risk Assessment (PRA) model, because flow instrumentation is below the level of detail of the plant's PRA model. Setpoint rescaling required for implementation of the 1.66 percent power increase will not impact the risk profile. Furthermore, the MUR uprated core thermal power (3468 MWt) is bounded by the rated thermal power assumed in the PRA Success Criteria (Reference 6).

Therefore, the proposed MUR Uprate Program will not affect the CNP Unit 2 risk profile.

5.0 Regulator)y Safety Analysis 5.1 No Significant Hazards Consideration Indiana Michigan Power Company (I&M) has evaluated whether a significant hazards consideration is involved with the proposed amendment to increase the licensed core power level from 3411 megawatts thermal (MWt) to 3468 MWt through improved feedwater flow measurement accuracy by using more accurate ultrasonic flow measurement instrumentation. The I&M evaluation was performed by focusing on the three standards set forth in 10 CFR 50.92, "Issuance of Amendment," as discussed below:

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

Response: No to AEP:NRC:2902 Page 4 Probability of Occurrence of an Accident Previously Evaluated In support of this Measurement Uncertainty Recapture (MUR) power uprate, a comprehensive evaluation was performed for nuclear steam supply system (NSSS) and balance of plant (BOP) systems and components and analyses that could be affected by this change. A power calorimetric uncertainty calculation was performed, and the effect of increasing plant power by 1.66 percent on the plant's design and licensing basis was evaluated. The result of these evaluations is that all plant components will continue to be capable of performing their design function at an uprated core power of 3468 MWt. In addition, an evaluation of the accident analyses demonstrates that applicable analysis acceptance criteria continue to be met. No accident initiators are affected by this uprate and no challenges to any plant safety barriers are created by this change.

Consequences of an Accident Previously Evaluated This change does not affect the release paths, the frequency of release, or the source term for release for any accidents previously evaluated in the Updated Final Safety Analysis Report (UFSAR). Structures, systems, and components (SSC) required to mitigate transients remain capable of performing their design functions, and thus were found acceptable. The reduced uncertainty in the feedwater flow input to the power calorimetric measurement ensures that applicable accident analyses acceptance criteria continue to be met, to support operation at a core power of 3468 MWt. Analyses performed to assess the effects of mass and energy remain valid. The source terms used to assess radiological consequences have been reviewed and determined to bound operation at the uprated condition.

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

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

Response: No No new accident scenarios, failure mechanisms, or single failures are introduced as a result of the proposed changes. The installation of the Caldon Leading Edge Flow Meter (LEFM) CheckPlusTM system has been analyzed, and failures of this system will have no adverse effect on any safety-related system or any SSCs required for transient mitigation. SSCs previously required for the mitigation of a transient remain capable of fulfilling their intended design functions. The to AEP:NRC:2902 Page 5 proposed changes have no adverse effects on any safety-related system or component and do not challenge the performance or integrity of any safety-related system.

This change does not adversely affect any current system interfaces or create any new interfaces that could result in an accident or malfunction of a different kind than previously evaluated. Operating at a core power level of 3468 MWt does not create any new accident initiators or precursors. The reduced uncertainty in the feedwater flow input to the power calorimetric measurement ensures that applicable accident analyses acceptance criteria continue to be met, to support operation at a core power of 3468 MWt. Credible malfunctions continue to be bounded by the current accident analysis of record or evaluations that demonstrate that applicable acceptance criteria continue to be met.

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

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

Response: No The margins of safety associated with this MUR Uprate Program are those pertaining to core power. This includes those associated with the fuel cladding, Reactor Coolant System pressure boundary, and containment barriers. A comprehensive engineering review was performed to evaluate the 1.66 percent increase in the licensed core power from 3411 MWt to 3468 MWt. The 1.66 percent increase required that revised NSSS design thermal and hydraulic parameters be established, which then served as the basis for all of the NSSS analyses and evaluations. This engineering review concluded that no design transient modifications are required to accommodate the revised NSSS design conditions. NSSS systems and components were evaluated and it was concluded that the NSSS equipment has sufficient margin to accommodate the 1.66 percent power uprate. NSSS accident analyses were evaluated for the 1.66 percent power uprate. In all cases, the evaluations demonstrate that the applicable analyses acceptance criteria continue to be met. As such, the margins of safety continue to be bounded by the current analyses of record for this change.

Therefore, the proposed change does not involve a significant reduction in a margin of safety.

to AEP:NRC:2902 Page 6 In summary, based upon the above evaluation, I&M has concluded that the proposed amendment involves no significant hazards consideration under the standards set forth in 10 CFR 50.92(c), and, accordingly, a finding of "no significant hazards consideration" is justified.

5.2 Applicable Regulatory_ Requirements/Criteria The proposed MUR Uprate Program has been reviewed to ensure compliance with all applicable regulatory requirements and criteria. Specifically, the requirements of 10 CFR 50.36, 50.46, 50.48, 50.49, 50.61, 50.62, 50.63, 50.71(e),

10 CFR 50, Appendix K, and the CNP Unit 2 OL, including Appendix A, "Technical Specifications," were reviewed. The TS changes that are summarized in Section 2, "Proposed Changes," of this enclosure are required to support plant operation following implementation of the MUR Uprate Program. These changes meet the four criteria for TS LCOs specified in 10 CFR 50.36(c)(2)(ii), while allowing continued TS compliance at the uprated conditions. This MUR Uprate Program will be implemented in accordance with the revised requirements of 10 CFR 50, Appendix K, which allow recapture of measurement uncertainty that was previously included in the analytical margin. The re-allocation of measurement uncertainty will not change the analysis or reporting requirements or the acceptance criteria of 10 CFR 50.46, "Acceptance criteria for emergency core cooling systems for light-water nuclear power reactors." Changes to the UFSAR that result from the MUR Uprate Program will be submitted to the NRC as specified in 10 CFR 50.71(e). Finally, the NRC's basis for approval of the analyses performed to demonstrate compliance with NRC regulations promulgated after issuance of the OL (i.e., fire protection (10CFR50.48),

environmental qualification (10 CFR 50.49), pressurized thermal shock (10 CFR 50.61), anticipated transients without scram (10 CFR 50.62), and station blackout (10 CFR 50.63)) were reviewed to ensure I&M's approved methodology for complying with these regulations would not be impacted by the MUR Uprate Program. Based on the impact reviews that were conducted in support of the MNR Uprate Program, and the OL/TS changes that were identified as required for implementation of this change, it is concluded that I&M's compliance with applicable regulatory requirements will be maintained.

The WCAP-10263 methodology has been successfully used as the basis for power uprate projects for several Westinghouse pressurized water reactor (PWR) units, which have also implemented Caldon LEFM systems. These include Watts Bar Nuclear Plant, Unit 1 (Reference 3), Comanche Peak Steam Electric Station, Units 1 and 2 (Reference 4), and Beaver Valley Power Station, Units 1 and 2 (Reference 5). The scope and level of detail of this CNP Unit 2 license to AEP:NRC:2902 Page 7 amendment request are commensurate with that provided in the approved amendments for the referenced plants.

I&M has determined that there are no significant hazards considerations associated with the proposed change and that the change is exempt from environmental review pursuant to the provisions of 10 CFR 51.22(c)(9).

Based upon the determinations that the acceptance criteria of WCAP-10263 are met by the proposed power uprate and that there are no significant hazards considerations associated with the proposed uprate, I&M concludes that the proposed change will not endanger the health and safety of the public. Similar amendment requests have been accepted for other nuclear power plants.

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

6.0 Environmental Considerations The environmental review, pursuant to 10 CFR 51.22(b), determined that no environmental impact statement or environmental assessment needs to be prepared in connection with the proposed amendment. In accordance with the guidance provided in RIS 2002-03, the environmental considerations pertaining to this license amendment request are addressed in Attachment 3,Section VII.5, "Environmental Review."

7.0 References

1. Letter from W. D. Beckner, NRC, "NRC Regulatory Issue Summary 2002-03: Guidance on the Content of Measurement Uncertainty Recapture Power Uprate Applications,"

dated January 31, 2002

2. WCAP-10263, "A Review Plan for Uprating the Licensed Power of a PWR Power Plant," dated January 1983

3. Letter from R. E. Martin, NRC, to J. A. Scalice, Tennessee Valley Authority, "Watts Bar Nuclear Plant, Unit 1 - Issuance of Amendments Regarding Increase of Reactor Power to 3459 Megawatts Thermal (TAC No. MA9152)," dated January 19, 2001 to AEP:NRC:2902 Page 8

4. Letter from D. H. Jaffe, NRC, to C. L. Terry, TXU Electric, "Comanche Peak Steam Electric Station (CPSES), Units 1 and 2 - Issuance of Amendments Re: Increase in Allowable Thermal Power to 3458 MWt and Deletion of Texas Municipal Power Agency from the Operating Licenses (TAC Nos. MB1625 and MB1626)," dated October 12, 2001

5. Letter from L. J. Burkhart, NRC, to L. W. Myers, First Energy Nuclear Operating Company, "Beaver Valley Power Station, Unit Nos. 1 and 2 (BVPS-1 and 2) - Issuance of Amendment Re: 1.4-Percent Power Uprate and Revised BVPS-2 Heatup and Cooldown Curves (TAC Nos. MB0996, MB0997, and MB2557)," dated September 24, 2001

6. Letter from E. E. Fitzpatrick, I&M, to T. E. Murley, NRC, "Donald C. Cook Nuclear Plant Units 1 and 2, Individual Plant Examination Submittal Response to Generic Letter 88-20," dated May 1, 1992

7. Letter from S. A. Richards, NRC, to M. A. Krupa, Entergy, "Waterford Steam Electric Station, Unit 3; River Bend Station; and Grand Gulf Nuclear Station - Review of Caldon, Inc. Engineering Report ER-157P (TAC Nos. MB2397, MB2399 and MB2468)," dated December 20, 2001

ATTACHMENT 1 TO AEP:NRC:2902 FACILITY OPERATING LICENSE AND TECHNICAL SPECIFICATION PAGES MARKED TO SHOW PROPOSED CHANGES REVISED PAGES UNIT 2 Operating License Page 3 of 11 1-1 3/4 5-3 3/4 7-2

Docket No. 316 Page 3 of 11 (4) Pursuant to the Act and 10 CFR Parts 30, 40, and 70, to receivel possess and use in amounts as required any by-product, source or special nuclear material without restriction to chemical or physical form, for sample analysis or instrument calibration or associated with radioactive apparatus or components; and (5) Pursuant to the Act and 10 CFR Parts 30 and 70, to possess, but not separate, such by-product and special nuclear materials as may be produced by the operation of the facility.

C. This license shall be deemed to contain and is subject to the conditions specified in the following Commission regulations in 10 CFR Chapter I: Part 20, Section 30.34 of Part 30, Section 40.41 fo Part 40, Sections 50.54 and 50.59 of Part 50, and Section 70.32 of Part 70; and is subject to all applicable provisions of the Act and to the rules, regulations, and orders of the Commission now or hereafter in effect; and is subject to the additional conditions specified or incorporated below:

(1) Maximum Power Level Amendment Indiana and Michigan Electric Company is authorized to No. 63 operate the facility at steady state reactor core power levels not in excess of 34414 999 megawatts thermal in accordance with the conditions specified herein and in Attachment 1 to this license. The preoperational tests, start-up tests and other items identified in Attachment 1 to this license shall be completed.

Attachment 1 is an integral part of this license.

(2) Technical Specifications The Technical Specifications contained in Appendices A and B, as revised through Amendment No. 250, are hereby incorporated in the license. The licensee shall operate the facility in accordance with the Technical Specifications.

The following amendments have been issued to Paragraph 2.C(2): Amendment Nos. 1, 7, 8, 10, 12, 13, 14, 15, 16, 17, 18, 19, 20, 21,22, 23, 24, 25, 26, 27, 28, 30, 31, 32, 33, 34, 35, 36, 37, 38, 39, 40, 41, 42, 43, 44, 45, 46, 47, 48, 49, 50, 51, 53, 54, 55, 56, 57, 58, 59, 60, 61, 62, 63, 64, 65, 66, 67, 68, 69, 70, 71, 72, 73, 74, 75, 76, 77, 78, 79, 80, 81, 82, 83, 84, 85, 86, 87, 88, 89, 90, 91, 92, 93, 94, 95, 96, 97, 98, 99, 100, 101, 102, 103, 104, 105, 106,107, 108, 109, 110, 111,112, 113, 114, 115, 116, 117, 118, 119, 120, 121, 122, 123, 124, 125, 126, 127, 128, 129, 130, 131,132, 133, 134, 135, 136, 137, 138, 139, 140, 141,142, 143, 144,145, 146, 147,148,149, 150, 151,152, 153,154, 155, 156, 157, 158, 159, 160, 161,162, 163, 164, 165, 166, 167, 168, 169, 170,171,172, 173, 174, 175, 176, 177, 178, 179, 180, 181, 182, 183,184, 185, 186,187, 188, 189, 190, 191,192, 193,194, 195, 196, 197, 198, 199,200, 201,202, 203, 204,205, 206, 207, 208, 209, 210,211,212,213,214,215,216,217,218,219,220, 221,222,223, 224,225, 226, 227, 228,229, 230, 231,233, 235, 236, 240, 242, 243, 244, 245, 246, 247, 248, 249, and 250.

1.0 DEFINITIONS DEFINED TERMS 1.1 The DEFINED TERMS of this section appear in capitalized type and are applicable throughout these Technical Specifications.

THERMAL POWER 1.2 THERMAL POWER shall be the total reactor core heat transfer rate to the reactor coolant.

RATED THERMAL POWER 1.3 RATED THERMAL POWER shall be a total reactor core heat transfer rate to the reactor coolant of 3444 O MWt.

OPERATIONAL MODE 1.4 An OPERATIONAL MODE shall correspond to any one inclusive combination of core reactivity condition, power level and average reactor coolant temperature specified in Table 1.1.

ACTION 1.5 ACTION shall be those additional requirements specified as corollary statements to each principle specification and shall be part of the specifications.

OPERABLE - OPERABILITY 1.6 A system, subsystem, train, component or device shall be OPERABLE or have OPERABILITY when it is capable of performing its specified function(s). Implicit in this definition shall be the assumption that all necessary attendant instrumentation, controls, normal and emergency electrical power sources, cooling or seal water, lubrication or other auxiliary equipment that are required for the system, subsystem, train, component or device to perform its function(s) are also capable of performing their related support function(s).

COOK NUCLEAR PLANT-UNIT 2 Page 1-1 AMEENDIMENT 48

314 LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS 3/4.5 EMERGENCY CORE COOLING SYSTEMS (ECCS)

ECCS SUBSYSTEMS - Tav__>350°F LIMITING CONDITION FOR OPERATION 3.5.2 Two independent ECCS subsystems shall be OPERABLE with each subsystem comprised of:

a. One OPERABLE centrifugal charging pump,

b. One OPERABLE safety injection pump,

c. One OPERABLE residual heat removal heat exchanger,

d. One OPERABLE residual heat removal pump,

e. An OPERABLE flow path capable of taking suction from the refueling water storage tank on a safety injection signal and transferring suction to the containment sump during the recirculation phase of operation.

f. All safety injection cross-tie valves open.

APPLICABILITY: MODES 1, 2, and 3.

ACTION:

a. With one ECCS subsystem inoperable, restore the inoperable subsystem to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or be in HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

b. With a safety injection cross-tie valve closed, restore the cross-tie valve to the open position or reduce the core power level to less than or equal to 3-2150 M MW within one hour.

Specification 3.0.4 does not apply.

c. In the event the ECCS is actuated and injects water into the Reactor Coolant System, a Special Report shall be prepared and submitted to the Commission pursuant to Specification 6.9.2 within 90 days describing the circumstances of the actuation and the total accumulated actuation cycles to date.

COOK NUCLEAR PLANT-UNIT 2 Page 3/4 5-3 AMIENDMIENT 167

314 LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS 314.7 PLANT SYSTEMS TABLE 3.7-1 MAXIMUM ALLOWABLE POWER RANGE NEUTRON FLUX HIGH SETPOINT WITH INOPERABLE STEAM LINE SAFETY VALVES DURING 4 LOOP OPERATION Maximum Allowable Power Range Neutron Maximum Number of Inoperable Safety Valves Flux High Setpoint on Any Operating Steam Generator (Percent of RATED THERMAL POWER) 1 2 43-.9M 3 26-.2n2 COOK NUCLEAR PLANT-UNIT 2 Page 3/4 7-2 AMENDMENT 195

ATTACHMENT 2 TO AEP:NRC:2902 PROPOSED FACILITY OPERATING LICENSE AND TECHNICAL SPECIFICATION PAGES REVISED PAGES UNIT 2 Operating License Page 3 of 11 1-1 3/4 5-3 3/4 7-2

Docket No. 316 Page 3 of 11 (4) Pursuant to the Act and 10 CFR Parts 30, 40, and 70, to receive, possess and use in amounts as required any by-product, source or special nuclear material without restriction to chemical or physical form, for sample analysis or instrument calibration or associated with radioactive apparatus or components; and (5) Pursuant to the Act and 10 CFR Parts 30 and 70, to possess, but not separate, such by-product and special nuclear materials as may be produced by the operation of the facility.

C. This license shall be deemed to contain and is subject to the conditions specified in the following Commission regulations in 10 CFR Chapter I: Part 20, Section 30.34 of Part 30, Section 40.41 fo Part 40, Sections 50.54 and 50.59 of Part 50, and Section 70.32 of Part 70; and is subject to all applicable provisions of the Act and to the rules, regulations, and orders of the Commission now or hereafter in effect; and is subject to the additional conditions specified or incorporated below:

(1) Maximum Power Level Amendment Indiana and Michigan Electric Company is authorized to No. 63 operate the facility at steady state reactor core power levels not in excess of 3468 megawatts thermal in accordance with the conditions specified herein and in Attachment 1 to this license.

The preoperational tests, start-up tests and other items identified in Attachment I to this license shall be completed. Attachment 1 is an integral part of this license.

(2) Technical Specifications The Technical Specifications contained in Appendices A and B, as revised through Amendment No. 250, are hereby incorporated in the license. The licensee shall operate the facility in accordance with the Technical Specifications.

The following amendments have been issued to Paragraph 2.C(2): Amendment Nos. 1, 7, 8, 10, 12, 13, 14, 15, 16, 17, 18, 19, 20, 21, 22, 23, 24, 25, 26, 27, 28, 30, 31,32, 33, 34, 35, 36, 37, 38, 39, 40, 41, 42, 43, 44, 45, 46, 47, 48, 49, 50, 51, 53, 54, 55, 56, 57, 58, 59, 60, 61,62, 63, 64, 65, 66, 67, 68, 69, 70, 71, 72, 73, 74, 75, 76, 77, 78, 79, 80, 81, 82, 83, 84, 85, 86, 87, 88, 89, 90, 91,92, 93, 94, 95, 96, 97, 98, 99, 100, 101, 102, 103, 104, 105, 106, 107, 108, 109, 110, 111,112, 113, 114, 115, 116, 117, 118, 119, 120, 121, 122, 123, 124, 125, 126, 127, 128, 129, 130, 131,132, 133, 134, 135, 136, 137, 138, 139, 140, 141,142, 143, 144, 145, 146, 147, 148, 149, 150, 151,152, 153, 154, 155, 156, 157, 158,159, 160, 161,162, 163, 164, 165, 166, 167, 168, 169, 170,171,172,173,174,175,176,177,178,179,180,181, 182, 183, 184,185, 186,187, 188, 189, 190, 191,192, 193, 194, 195, 196, 197, 198,199,200, 201,202, 203, 204, 205, 206, 207, 208, 209,210,211,212,213,214,215,216, 217, 218,219, 220, 221,222,223,224,225,226,227,228,229,230,231,233,235, 236, 240, 242, 243, 244, 245, 246, 247, 248, 249, and 250.

1.0 DEFINITIONS DEFINED TERMS 1.1 The DEFINED TERMS of this section appear in capitalized type and are applicable throughout these Technical Specifications.

THERMAL POWER 1.2 THERMAL POWER shall be the total reactor core heat transfer rate to the reactor coolant.

RATED THERMAL POWER 1.3 RATED THERMAL POWER shall be a total reactor core heat transfer rate to the reactor coolant of 3468 MWt.

OPERATIONAL MODE 1.4 An OPERATIONAL MODE shall correspond to any one inclusive combination of core reactivity condition, power level and average reactor coolant temperature specified in Table 1.1.

ACTION 1.5 ACTION shall be those additional requirements specified as corollary statements to each principle specification and shall be part of the specifications.

OPERABLE - OPERABILITY 1.6 A system, subsystem, train, component or device shall be OPERABLE or have OPERABILITY when it is capable of performing its specified function(s). Implicit in this definition shall be the assumption that all necessary attendant instrumentation, controls, normal and emergency electrical power sources, cooling or seal water, lubrication or other auxiliary equipment that are required for the system, subsystem, train, component or device to perform its function(s) are also capable of performing their related support function(s).

COOK NUCLEAR PLANT-UNIT 2 Page 1-1 AMIENDMENT 48,

3/4 LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS 3/4.5 EMERGENCY CORE COOLING SYSTEMS (ECCS)

ECCS SUBSYSTEMS - T9 >-350°F LIMITING CONDITION FOR OPERATION 3.5.2 Two independent ECCS subsystems shall be OPERABLE with each subsystem comprised of:

a. One OPERABLE centrifugal charging pump,

b. One OPERABLE safety injection pump,

c. One OPERABLE residual heat removal heat exchanger,

d. One OPERABLE residual heat removal pump,

e. An OPERABLE flow path capable of taking suction from the refueling water storage tank on a safety injection signal and transferring suction to the containment sump during the recirculation phase of operation.

f. All safety injection cross-tie valves open.

APPLICABILITY: MODES 1, 2, and 3.

ACTION:

a. With one ECCS subsystem inoperable, restore the inoperable subsystem to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or be in HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

b. With a safety injection cross-tie valve closed, restore the cross-tie valve to the open position or reduce the core power level to less than or equal to 3304 MW within one hour. Specification 3.0.4 does not apply.

c. In the event the ECCS is actuated and injects water into the Reactor Coolant System, a Special Report shall be prepared and submitted to the Commission pursuant to Specification 6.9.2 within 90 days describing the circumstances of the actuation and the total accumulated actuation cycles to date.

COOK NUCLEAR PLANT-UNIT 2 Page 3/4 5-3 AMENDMENT 1-67,

3/4 LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS 314.7 PLANT SYSTEMS TABLE 3.7-1 MAXIMUM ALLOWABLE POWER RANGE NEUTRON FLUX HIGH SETPOINT WITH INOPERABLE STEAM LINE SAFETY VALVES DURING 4 LOOP OPERATION Maximum Allowable Power Range Neutron Maximum Number of Inoperable Safety Valves Flux High Setpoint on Any Operating Steam Generator (Percent of RATED THERMAL POWER) 1 60.4 2 43.0 3 25.7 COOK NUCLEAR PLANT-UNIT 2 Page 3/4 7-2 AMENDMENT t9,

ATTACHMENT 3 TO AEP:NRC:2902

SUMMARY

OF MEASUREMENT UNCERTAINTY RECAPTURE EVALUATION FOLLOWING GUIDANCE PROVIDED IN REGULATORY ISSUE

SUMMARY

2002-03 to AEP:NRC:2902 Page i TABLE OF CONTENTS LIST OF TABLES ........................................................................................................................ v LIST OF ACRONYMS ........................................................................................................ vi Introduction ................................................................................................................................... 1

1. Feedwater Flow Measurement Technique and Power Measurement Uncertainty ..... 17 II. Accidents and Transients for which the Existing Analyses of Record Bound Plant Operation at the Proposed Uprated Power Level ..................................................... 30 11.1 Loss of Coolant Accident and Loss of Coolant Accident-Related Events (including Steam Generator Tube Rupture) ........................................................................... 35 11.1.1 Loss of Coolant Accident Forces ................................................................... 35 11.1.2 Large Break Loss of Coolant Accident and Small Break Loss of Coolant A ccident ......................................................................................................... 36 11.1.3 Post-Loss of Coolant Accident Analyses ...................................................... 36 11.1.4 Steam Generator Tube Rupture - Thermal-Hydraulic Analysis .................... 38 11.2 Containm ent Analyses ............................................................................................ 39 11.2.1 Feedwater and Steam Line Break Mass and Energy Releases ....................... 39 11.2.2 Post-Loss of Coolant Accident Containment Hydrogen Generation ............. 40 11.2.3 Loss of Coolant Accident Mass and Energy Releases ................................... 41 11.3 Non-Loss of Coolant Accident Analyses ................................................................ 43 11.3.1 Rod Cluster Control Assembly Misalignment/Rod Cluster Control Assembly Drop (UFSAR Sections 14.1.3 and 14.1.4) ................................................... 44 11.3.2 Uncontrolled Rod Cluster Control Assembly Withdrawal from a Subcritical Condition (UFSAR Section 14.1.1) .............................................................. 44 11.3.3 Uncontrolled Rod Cluster Control Assembly Withdrawal at Power (UFSAR Section 14.1.2) .............................................................................................. 45 11.3.4 Uncontrolled Boron Dilution (UFSAR Section 14.1.5) ................................. 46 11.3.5 Loss of Reactor Coolant Flow (UFSAR Section 14.1.6.1) ............................ 46 11.3.6 Locked Rotor Accident (UFSAR Section 14.1.6.2) ..................................... 46 11.3.7 Loss of External Electrical Load or Turbine Trip (UFSAR Section 14.1.8) ..... 47 11.3.8 Loss of Normal Feedwater Flow and Loss of Offsite Power to Station Auxiliaries (UFSAR Sections 14.1.9 and 14.1.12) ........................................ 47 11.3.9 Excessive Heat Removal Due to Feedwater System Malfunctions (UFSAR Section 14.1.10) .............................................................................................. 47 11.3.10 Excessive Load Increase Incident (UFSAR Section 14.1.11) ...................... 48 11.3.11 Rupture of a Steam Pipe - Core Response Analysis (UFSAR Section 14.2.5).48 11.3.12 Rupture of a Control Rod Drive Mechanism Housing (Rod Cluster Control Assembly Ejection) (UFSAR Section 14.2.6) .............................................. 49 11.3.13 Anticipated Transients Without Scram .......................................................... 49 to AEP:NRC:2902 Page ii 11.3.14 Station Blackout ............................................................................................ 51 11.3.15 Major Rupture of a Main Feedwater Pipe (Feedline Break) (UFSAR Section 14 .2 .8) ................................................................................................................ 51 11.3.16 Flooding ............................................................................................................. 52 11.4 Design Transients ..................................................................................................... 52 11.4.1 Nuclear Steam Supply System Design Transients ........................................ 52 11.4.2 Auxiliary Equipment Design Transients ........................................................ 54 III. Accidents and Transients for which the Existing Analyses of Record do not Bound Plant Operation at the Proposed Uprated Power Level ............................................ 56 IV. Mechanical/Structural/Material Component Integrity and Design ......................... 56 IV.1 Reactor Vessel Structural Evaluation ................................................................... 56 IV.1.1 Reactor Vessel Integrity - Neutron Irradiation .............................................. 56 IV.1.2 Reactor Internals ............................................................................................ 57 IV.2 Piping and Supports ................................................................................................ 62 IV.2.1 Nuclear Steam Supply System Piping .......................................................... 62 IV.2.2 Reactor Coolant Loop Support System .......................................................... 63 IV.2.3 Leak-Before-Break Analysis .......................................................................... 63 IV.3 Control Rod Drive Mechanisms ........................................................................... 64 IV.4 Reactor Coolant Pumps and Motors ..................................................................... 65 IV.5 Steam Generators ..................................................................................................... 66 IV.5.1 Thermal-Hydraulic Evaluation ..................................................................... 66 IV.5.2 Structural Integrity Evaluation ..................................................................... 69 IV.5.3 Evaluation of Mechanical Repair Hardware ................................................. 70 IV.5.4 Steam Generator Tube Integrity ..................................................................... 72 IV.5.5 Regulatory Guide 1.121 Analysis ................................................................. 76 IV.6 Pressurizer .................................................................................................................... 78 IV.7 Nuclear Steam Supply System Auxiliary Equipment .......................................... 78 IV.8 Fuel Evaluation ............................................................................................................ 79 IV.8.1 Nuclear Design .............................................................................................. 79 IV.8.2 Fuel Rod Design ........................................................................................... 80 IV.8.3 Core Thermal-Hydraulic Design ................................................................... 80 IV.8.4 Fuel Structural Evaluation ............................................................................ 81 V. Electrical Equipment Design ......................................................................................... 81 VI. System Design ..................................................................................................................... 86 VI.1 Nuclear Steam Supply System Interface Systems ................................................. 86 VI.1.1 Chemical and Volume Control System/Boron Capability ............................. 87 to AEP:NRC:2902 Page iii VI.1.2 Auxiliary Heat Exchanger Performance ....................................................... 87 VI.1.3 Residual Heat Removal System ..................................................................... 87 VI.1.4 Emergency Core Cooling System and Containment Spray System .............. 88 VI.2 Power/Steam Systems .............................................................................................. 88 VI.2.1 Main Steam System and Steam Dump System ............................................... 89 VI.2.2 Condensate and Feedwater Systems .............................................................. 90 VI.2.3 Auxiliary Feedwater System and Condensate Storage Tank ......................... 91 VI.2.4 Feedwater Heaters and Drains ....................................................................... 92 VI.2.5 Steam Generator Blowdown System ............................................................ 92 VI.3 Cooling and Support Systems ................................................................................. 93 VI.3.1 Component Cooling Water System .............................................................. 93 VI.3.2 Essential Service Water System ...................................................................... 93 VI.3.3 Non-Essential Service Water System ............................................................ 93 VI.3.4 Turbine Auxiliary Cooling Water System ..................................................... 94 VI.3.5 Emergency Diesel Generator Aftercooler, Lube Oil, and Jacket Cooling Water System ................................................................................................................ 94 VI.3.6 Circulating Water System .............................................................................. 94 VI.3.7 Spent Fuel Pool Cooling System ................................................................... 94 VIA Heating, Ventilating and Air-Conditioning Systems ............................................ 95 VI.5 Nuclear Steam Supply Systems Control Systems ................................................ 95 VII. Other ................................................................................................................................... 99 VII.1 Control Room and Simulator .............................................................................. 99 VII.2 Operator Actions ................................................................................................... 99 VII.3 Power Uprate Modifications .................................................................................. 100 VII.4 Plant Operating Procedure Changes .................................................................... 101 VII.5 Environmental Review ........................................................................................... 102 VII.6 Programs .................................................................................................................. 103 VII.6.1 Environmental Qualification Program ............................................................. 103 VII.6.2 Motor-Operated Valve Program ...................................................................... 103 VII.6.3 Air and Hydraulic Operated Valve Program .................................................... 104 VII.6.4 Flow-Accelerated Corrosion Program ............................................................. 104 VII.6.5 High-Energy Line Break Program ................................................................... 106 VII.6.6 Fire Protection/Appendix R Programs ............................................................. 106 VII.6.7 Inservice Inspection Program ........................................................................... 107 VII.6.8 Inservice Testing Program ............................................................................... 107 VII.6.9 Radiological Environmental Monitoring Program .......................................... 107 VII.6.10 Radiological Dose Monitoring and Radiological Dose Control Programs ...... 107 to AEP:NRC:2902 Page iv VII.6.11 Probabilistic Risk Assessment Program .......................................................... 108 VII.7 Mechanical Piping Design ...................................................................................... 108 VIII. Changes to Technical Specifications, Protection System Settings, and Emergency System Settings ................................................................................................................. 109 to AEP:NRC:2902 Page v LIST OF TABLES Table Title Page Table 1 System and Program Review Summary ............................................... 3 Table 2 MUR Power Uprate Impact on CNP Unit 2 Accident/Transient A nalyses ................................................................................................. 9 Table 3 CNP Unit 2 MUR Power Uprate - NSSS Design Parameters .............. 13 Table I-1 Unit 2 Process Parameter Inputs to Reactor Thermal Power ................ 21 Table II-1 Bounding Accident and Transient Design Basis Analyses .................... 30 Table 11-2 Comparison of Unit 2 MUR Power Uprate Conditions to Values used in Design Basis Design Transients ........................................................ 53 Table IV-1 Summary of Tube Structural Limits at MUR Uprate Program Conditions .............................................................................................. 77 Table V-1 Impact of Power Uprate on Electrical Equipment ................................. 83 Table VI-1 Comparison of Unit 2 MUR Uprate Program Conditions to Values Used in Design Basis Operability Transients ........................................ 97 to AEP:NRC:2902 Page vi LIST OF ACRONYMS AC alternating current AFW auxiliary feedwater AHOV air and hydraulic operated valve AMSAC ATWS mitigation system actuation circuitry ANS American Nuclear Society AOP abnormal operating procedure ASME American Society of Mechanical Engineers ATWS anticipated transient without scram BD blowdown BIT boron injection tank BOP balance of plant BVPS Beaver Valley Power Station CCW component cooling water CEQ containment equalization CFR Code of Federal Regulations CNP Donald C. Cook Nuclear Plant CRDM control rod drive mechanism CTS containment spray system CST condensate storage tank CVCS chemical and volume control system CW circulating water DC direct current DNB departure from nucleate boiling DNBR departure from nucleate boiling ratio ECCS emergency core cooling system EDG emergency diesel generator EFPY effective full-power year EOP emergency operating procedure EPRI Electric Power Research Institute ESF engineered safety feature ESFVS engineered safety feature ventilation system ESW essential service water EQ environmental qualification FAC flow accelerated corrosion gpm gallons per minute GSU generator step-up HELB high energy line break HFP hot-full power HHSI high head safety injection hp horsepower to AEP:NRC:2902 Page vii HVAC heating, ventilating, and air conditioning HZP hot-zero power I&C instrumentation and control I&M Indiana Michigan Power Company ISI in-service inspection IST in-service testing LBB leak-before-break LBLOCA large-break loss-of-coolant accident LCO limiting condition for operation LEFM Leading Edge Flow Meter LOCA loss-of-coolant accident LOOP loss of offsite power LTOP low temperature overpressure protection MCO moisture carryover MDAFW motor-driven auxiliary feedwater MOV motor operated valve MSIV main steam isolation valve MS main steam msec milli-second MSSV main steam safety valve MTC moderator temperature coefficient MUR measurement uncertainty recapture MVA mega-volt-amperes MW megawatts MWe megawatts electric MWt megawatts thermal NEI Nuclear Energy Institute NESW non-essential service water NPDES National Pollutant Discharge Elimination System NRC Nuclear Regulatory Commission NSSS nuclear steam supply system ODSCC outer diameter stress corrosion cracking OL Operating License OPAT overpower delta T OTAT overtemperature delta T PORV power-operated relief valve PPC plant process computer PRA probabilistic risk assessment psi pounds per square inch psia pounds per square inch - atmospheric psig pounds per square inch - gauge to AEP:NRC:2902 Page viii P-T pressure-temperature PTS pressurized thermal shock PWR pressurized water reactor PWSCC primary water stress corrosion cracking RAT reserve auxiliary transformer RCCA rod cluster control assembly RCL reactor coolant loop RCP reactor coolant pump RCS reactor coolant system REMP Radiological Environmental Monitoring Program RG Regulatory Guide RHR residual heat removal RIS Regulatory Issue Summary RPS reactor protection system RSG replacement steam generator RTD resistance temperature detector RTDP revised thermal design procedure RTP rated thermal power RWFS rod withdrawal from subcritical RWST refueling water storage tank SBLOCA small-break loss-of-coolant accident SBO station blackout SCC stress corrosion cracking SER Safety Evaluation Report SFPC spent fuel pool cooling SGTP steam generator tube plugging SGTR steam generator tube rupture SI safety injection SRSS square root of the sum of the squares TDAFW turbine driven auxiliary feedwater T/H thermal and hydraulic TS Technical Specifications TSP tube support plates UAT unit auxiliary transformer UFSAR Updated Final Safety Analysis Report USE upper shelf energy VCT volume control tank WOG Westinghouse Owner's Group to AEP:NRC:2902 Page I Summary of Measurement Uncertainty Recapture Evaluation Following Guidance Provided in Regulatory Issue Summary 2002-03 Introduction I&M proposes to amend OL DPR-74, including Appendix A, TS, for CNP Unit 2. CNP Unit 2 is presently licensed for a core power rating of 3411 MWt. Through the use of more accurate feedwater flow measurement instrumentation, approval is sought to increase the licensed core power by 1.66 percent, to 3468 MWt. The proposed 1.66 percent power uprate is based on eliminating unnecessary analytical margin originally required of ECCS evaluation models developed in accordance with the requirements set forth in 10 CFR 50, Appendix K, "ECCS Evaluation Models."

In June 2000, the NRC approved a change to the 10 CFR 50, Appendix K, requirements to provide licensees with the option of maintaining the 2 percent power margin between the licensed core power level and the assumed core power level for ECCS evaluations, or apply a reduced margin to the ECCS evaluations. The proposed alternative to recapture margin for ECCS evaluation has been demonstrated to account for uncertainties due to a reduction in core power level measurement instrumentation error. I&M will be installing Caldon, Incorporated (Caldon) LEFMTM CheckPlusTM instrumentation with an installed power measurement uncertainty of less than 0.31 percent. Based on the implementation of the LEFM CheckPlus instrumentation and CNP specific power calorimetric uncertainties, I&M proposes to reduce the licensed core power uncertainty required by 10 CFR 50, Appendix K, and increase the CNP Unit 2 licensed core power level by 1.66 percent using NRC-approved methodologies.

I&M has evaluated the impact of the proposed power uprate on NSSS systems and components, BOP systems, safety analyses, and programs. The results of I&M's analyses and evaluations, which demonstrate that applicable acceptance criteria will continue to be met, are summarized in this attachment. RIS 2002-03, "Guidance on the Content of Measurement Uncertainty Recapture Power Uprate Applications," (Reference 1) was used to establish the appropriate scope, structure, and level of detail presented in this attachment.

Approach for Increasing the Plant Power Level The CNP Unit 2 MUR Uprate Program has been developed consistent with the methodology established in WCAP-10263, "A Review Plan for Uprating the Licensed Power of a PWR Power Plant" (Reference 2). This methodology has been successfully used as the basis for power uprate projects for several Westinghouse PWR units, including Watts Bar Nuclear Plant, Unit 1 (Reference 3), Comanche Peak Steam Electric Station, Units 1 and 2 (Reference 4), and Beaver Valley Power Station, Units 1 and 2 (Reference 5).

to AEP:NRC:2902 Page 2 The methodology in WCAP-10263 establishes the general approach and criteria for uprate projects, including the broad categories that must be addressed, such as NSSS performance parameters, design transients, systems, components, accidents, and nuclear fuel, as well as the interfaces between the NSSS and BOP systems. The methodology includes the use of well-defined analysis input assumptions/parameter values, use of currently-approved analytical techniques, and use of currently-applicable licensing criteria and standards.

Overview of this Attachment A comprehensive engineering review program consistent with the WCAP-10263 methodology has been performed for CNP Unit 2 to evaluate the increase in the licensed core power from 3411 MWt to 3468 MWt.Section I of this attachment describes the Caldon LEFM CheckPlus system that will be implemented to provide more accurate feedwater flow measurement.

Section II provides the results of the accident and transient analyses for which the existing analyses of record bound plant operation at the uprated power level.Section III summarizes those accidents and transient analyses that required re-analysis to produce analytical results that bound the uprated power level. There are no accident and transient analyses that require re-analysis to produce analytical results that bound the uprated power level. Therefore,Section III has been intentionally left blank, but has been maintained for format purposes. Table 2, "MUR Power Uprate Impact on CNP Unit 2 Accident/Transient Analyses," summarizes the accident and transient analyses for CNP Unit 2, and documents whether or not each analysis of record bounds plant operation at the uprated power level proposed by the MIUR Uprate Program.

Table 2 also indicates where the summary of the evaluation/analysis is addressed in Section II of this attachment.

Sections IV and V of this attachment address the impact of the power uprate on the structural integrity of major plant components and on electrical equipment.Section VI addresses the effect of the power uprate on major plant systems and Section VII addresses the identification and evaluation of impacts on the control room and simulator, operator actions, modifications, procedures, the environment, and programs resulting from the 1.66 percent power uprate.

Table 1, "System and Program Review Summary," summarizes the results of the evaluations that were performed on the CNP Unit 2 NSSS and BOP systems and components and plant programs.

The results of the analyses and evaluations addressed in Sections 11 through VII demonstrate that all acceptance criteria continue to be met.

Section VIII discusses the required changes to the CNP Unit 2 TS.

Attachment 3 to AEP:NRC:2902 Page 3 TABLE 1 - SYSTEM AND PROGRAM REVIEW

SUMMARY

SYSTEM/ PARAMETERS WITH COMPONENTS BOUNDED BY REFERENCES COMPONENT/ MUR UPRATE IMPACTED EXISTING (Report Section Number)

PROGRAM POTENTIAL IMPACT DESIGN/

ANALYSES?

STEAMIPOWER SYSTEMS Condensate Flowrate (Increase) Hotwell Pumps Yes 0 VI.2.2, VII.3 System Pressure Condensate Booster Yes 0 VI.2.2, VII.3 (Decrease) Pumps System Temperature Piping Yes 0 VI.2.2, VII.3 (Increase)

Valves and Yes 0 VI.2.2, VII.3 Miscellaneous Components Low Pressure Yes

VI.2.4, VII.3 Feedwater Heaters Feedwater Flowrate (Increase) Feedwater Pumps Yes a VI.2.2, VII.3 System Pressure Feedwater Regulating Yes

VI.2.2, VII.3 (Decrease) Valves System Temperature Feedwater Isolation Yes 0 VI.2.2, VII.3 (Increase) Valves High Pressure Yes 0 VI.2.2, VII.3 Feedwater Heaters Heater Drain Pumps Yes 0 VI.2.2, VII.3 AFW System and Required flow to steam Turbine Driven Yes 0 VI.2.3, VII.3 CST generators when normal Auxiliary Feedwater feedwater not available Pump Motor Driven Yes 0 VI.2.3, VII.3 Auxiliary Feedwater Pumps Condensate Storage Yes a VI.2.3, VII.3 Tank Main Steam Steam Flow (Increase) Steam Dump No* 0 VI.2.1, VII.3, VII.4 System Pressure Main Feed Pump Yes

VI.2.1, VII.3, VII.4 (Decrease) Turbines Steam Generator Yes

VI.2.1, VII.3, VII.4 Blowdown

Attachment 3 to AEP:NRC:2902 Page 4 TABLE 1 - SYSTEM AND PROGRAM REVIEW

SUMMARY

SYSTEM/ PARAMETERS WITH COMPONENTS BOUNDED BY REFERENCES COMPONENT/ MUR UPRATE IMPACTED EXISTING (Report Section Number)

PROGRAM POTENTIAL IMPACT DESIGN/

ANALYSES?

Main Steam Steam Flow (Increase) Steam Generator Yes 0 VI.2.1, VII.3, VII.4 Safety Valves System Pressure Power Operated Relief Yes 0 VI.2.1, VII.3, VII.4 (Decrease) Valves Main Steam Isolation Yes 0 VI.2.1, VII.3, VII.4 Valves MSIV Bypass Valves Yes 0 VI.2.1, VII.3, VII.4 Auxiliary Steam Yes 0 VI.2.1, VII.3, VII.4 System Auxiliary Feedwater Yes 0 VI.2.1, VII.3, VII.4 Pump Turbine Main Turbine Yes 0 VI.2.1, VII 3, VII.4 Main Turbine Stop Yes 0 VI.2.1, VII.3, VII.4 Valves Main Turbine Control Yes 0 V1.2.1, VII.3, VII.4 Valves Moisture Separator Yes 0 VI 2.1, VII.3, VII.4 Reheaters Feedwater Heaters Steam and Feedwater Flow Feedwater Heaters Yes 0 VI.2.4, VII.3 and Drains (Increase)

System Pressure Feedwater Heater Yes 0 V1.2.4, VII.3 (Decrease) Drains System Temperature Feedwater Heater Yes 0 VI.2.4, VII.3 (Increase) Level Control Valves COOLING/SUPPORT SYSTEMS' CCW Cooldown Flow to RHR RHR System Yes 0 V1.3.1, VII.3 Heat Exchangers (Increase)

ESW No Changes None Yes 0 VI.3.2, VII.3 NESW Required flow to SG SG Blowdown Yes 0 VI.3.3, VII.3 Blowdown Components Components (Increase)

TACW Required flow to Iso-phase Iso-phase Bus Duct Yes** 0 VI.3.4, VII.3, VII.4 Bus Duct Cooling and Stator Water Coolers Stator Water Coolers (Increase)

EDG Cooling No Changes None Yes 0 VI.3.5, VII.3

Attachment 3 to AEP:NRC:2902 Page 5 TABLE 1 - SYSTEM AND PROGRAM REVIEW

SUMMARY

SYSTEM/ PARAMETERS WITH COMPONENTS BOUNDED BY REFERENCES COMPONENT/ MUR UPRATE IMPACTED EXISTING (Report Section Number)

PROGRAM POTENTIAL IMPACT DESIGN/

ANALYSES?

CW Condenser Operating Main Condenser Yes

VI.3.6, VII.3 Pressure (Increase)

SFPC Spent Fuel Pit Decay SFPC Pumps and Heat Yes

VI.3.7, VII.3 Heatload (Increase) Exchangers Auxiliary Building Heat load in ECCS Rooms/ ESFVS Exhaust Air Yes 0 VIA, VII.3 Ventilation System Cubicles (Negligible) Fans ESF Ventilation Post-LOCA Hydrogen Hydrogen Skimmer/ Yes a VIA, VII.3 System Generation (No Change) Recirculating Fans Containment Heat load in Upper/Lower Upper/Lower Yes 0 VIA, VII.3 Ventilation System Containment (Bounded) Containment Recirculating Fan Coil Units AFW System Motor Heat load in AFW System Room A/C Units Yes

VI.4, VII.3 and Turbine Pump Pump Rooms (No Change)

Room Coolers Iso-phase Bus Duct Heat load in Bus Duct Bus Duct Fan Coil Yes** 0 VI.4, VII.3, VII.4 Cooling System Enclosures (Increase) Units ELECTRICAL SYSTEMS Turbine/Generator Generator Output (MVA Generator Yes

V, VII.3 Increase)

Iso-phase Bus Main Generator Current Iso-phase Bus Yes 0 V, VII.3, VII.4 (Increase)

Main Transformer Transformer Output (MVA Transformers Yes

V, VII 3 Increase)

Switchyard Switchyard Current Circuit Breakers Yes 0 V, VII.3 (Increase)

Offsite Power Tie Line Current (Increase) Tie Line Current Yes

V, VII.3 Feeders Rating Grid Stability N/A Main Generator Yes

V, VII.3 Impedance EDGs No Changes No Changes Yes

V, VII.3 Auxiliary Transformer Output Transformer MVA Yes

V, VII.3 Transformers Increase Station Service Transformer Output Transformer MVA Yes 0 V, VII.3 Transformers Increase

Attachment 3 to AEP:NRC:2902 Page 6 TABLE 1 - SYSTEM AND PROGRAM REVIEW

SUMMARY

SYSTEM/ PARAMETERS WITH COMPONENTS BOUNDED BY REFERENCES COMPONENT/ MUR UPRATE IMPACTED EXISTING (Report Section Number)

PROGRAM POTENTIAL IMPACT DESIGN/

ANALYSES?

Protective Relay Generator Current Increase Grid Fault Protection Yes

V, VII.3, VII.4 Settings I I Electrical Bus Current Increase 4160V Bus, Breakers, Yes

V, VII.3, VIIA Distribution System Cables NSSS SYSTEMS~

NSSS Fluid Systems Pressure, Temperature, Flow RCS Components Yes 0 IV.I - IV.6, VI.1 NSSS Auxiliary Pressure, Flow, Temperature, Various Yes

VI. 1 Systems (CVCS, Aux. Cooldown Rate HX, ECCS, CSS)

NSSS Auxiliary Pressure, Flow, Temperature, Various No**** VI.1 Systems (RHR) Cooldown Rate N§SSSIBOP'INTERFACE SYSTEMS' NSSS Control Systems Margin-to-trip Valves, heaters Yes*

VI.5 LTOP System None Valves Yes

VI.5 Reactor Vessel Fluence, temperature Pressure vessel Yes & IV.1 Reactor Internals Thermal hydraulic Reactor internals Yes

IV.1.2 Piping and Supports Stress, presssure, temperture Piping and supports Yes 0 IV.2 Control Rod Drive Pressure, temperature Housings, drive Yes 0 IV.3 Mechanisms mechanisms RCPs and Motors Pressure, temperature, amps Pumps and motors Yes 0 IV.4 SGs Thermal-hydraulic, stress Steam generators Yes

IV.5 Pressurizer Stress, fatigue Pressurizer Yes 0 IV.6 NSSS Auxiliary Pressure, temperature, Various Yes 0 IV.7 Equipment fatigue Fuel None Fuel Yes 0 IV.8 Containment Mass and Energy Release Containment and Yes 0 11.2 protection SFPC System Temperature, cooling Various Yes 0 VI.3.7 PROGRAMS Non N EQ None None Yes

VII.6.2 MOVs None None Yes

VII.6.2 AHOVs None None Yes

VII.6.3 FAG None None Yes

VII.6.4 HELB None None Yes

VII.6.5 SBO None None Yes

11.3.14, V Fire Protection and None None Yes

VII.6.6 Appendix R/Safe Shutdown

Attachment 3 to AEP:NRC:2902 Page 7 TABLE 1 - SYSTEM AND PROGRAM REVIEW

SUMMARY

SYSTEM/ PARAMETERS WITH COMPONENTS BOUNDED BY REFERENCES COMPONENT/ MUR UPRATE IMPACTED EXISTING (Report Section Number)

PROGRAM POTENTIAL IMPACT DESIGN/

ANALYSES?

ISI None None Yes

VII.6.7 IST None None Yes

VII.6.8 Individual and None None Yes

VII.6.10 Occupational Radiation Exposure Radiological None None Yes 0 VII.6.9 Environmental Assessments EOPs and AOPs None None Yes 0 VII.2 PRA None None Yes 0 VII.6.11 Mechanical Piping None None Yes

VII.7 Design

Section VI.5 is not bounded for the margin-to-trip transients that assume 40 percent steam clump capabilty.

- TACW flow to iso-phase bus duct cooling system and stator water coolers may need to be adjusted to accommodate power uprate. Adequate margin exists for power uprate.

Time for two-train RHR cooldown analysis is revised to reflect power uprate. All other RHR analysis are bounding.

Evaluation Approach for the MUR Uprate Program The licensed core power and/or NSSS thermal power are used as inputs to most plant safety, component, and system analyses. The current NSSS analyses of record for CNP Unit 2 model the core and/or NSSS thermal power in one of four ways. The approach taken for the proposed 1.66 percent power uprate for each of the four modeling approaches is provided below.

1. Some CNP Unit 2 analyses assume a nominal power level. These analyses have been evaluated for the 1.66 percent increased power level. Results of these evaluations demonstrate that the applicable analysis acceptance criteria continue to be met at the 1.66 percent uprate conditions. Evaluation of these analyses that bound the MUR power uprate are addressed in Section II.

2. A majority of CNP Unit 2 analyses already assume a core power level in excess of the proposed 3468 MWt. These analyses were performed at a higher power level (typically 3588 MWt) as part of prior plant programs. For these analyses, a portion of the available margin may be applied to offset the 1.66 percent uprate. Consequently, these analyses have been evaluated to confirm that sufficient analysis margin exists to envelop the 1.66 to AEP:NRC:2902 Page 8 percent uprate. These analyses bound this MUR power uprate, and are addressed in Section II.

3. Some CNP Unit 2 analyses apply a 2 percent increase to the initial power level to account solely for the power measurement uncertainty. These analyses have not been revised for the 1.66 percent uprate conditions because the sum of increased core power level (1.66 percent) and the reduced power measurement uncertainty (0.31 percent) fall within the previously analyzed conditions. These analyses bound the MUR power uprate, and are addressed in Section II.

The power calorimetric uncertainty calculation described in Section I indicates that with the Caldon instrumentation installed, the power measurement uncertainty, based on a 95 percent probability at a 95 percent confidence interval (i.e., 95/95 power measurement uncertainty), is approximately 0.31 percent. Therefore, these analyses only need to account for this reduced power measurement uncertainty. Accordingly, the existing 2 percent uncertainty can be allocated such that up to 1.66 percent is applied to provide sufficient margin to address the uprate to 3468 MWt, and the reduced power measurement uncertainty value is retained in the analysis to account for the uncertainty in power. Additionally, this third type of analyses often include other conservative assumptions not affected by the 1.66 percent uprated power. In summary, the use of the calculated 95/95 power measurement uncertainty and retention of other conservative assumptions ensure that the margin of safety for these analyses would not be reduced.

4. Some CNP Unit 2 analyses are performed at zero percent power conditions, or do not model the core power level. Consequently, these analyses have not been re-performed, since they are unaffected by the core power level. These analyses bound this MUR power uprate, and are addressed in Section II.

Table 2, "MUR Power Uprate Impact on CNP Unit 2 Accident/Transient Analyses," summarizes the accident and transient analyses for CNP Unit 2, and demonstrates that the existing analysis or record bounds plant operation at the proposed uprated power level. Details of these evaluations are provided in subsequent sub-sections.

to AEP:NRC:2902 Page 9 Table 2 - MUR Power Uprate Impact on CNP Unit 2 Accident/Transient Analyses CNP Unit 2 Impact of Sub-Section Accident/Transient UFSAR Uprate on of this Section Current UFSAR Attachment Analysis

- -. - -. LOCA andRelated Analyses LOCA Forces 3.2 Bounded 11.1.1 4.3.1 14.3 Large Break LOCA 14.3.1 Bounded 11.1.2 Small Break LOCA 14.3.2 Bounded 11.1.2 Post-LOCA Long-Term Core Cooling 14.3.1 Bounded 11.1.3.1 Hot Leg Switchover 14.3.1 Bounded 11.1.3.2 Steam Generator Tube Rupture 14.2.4 Bounded 11.1.4 Non-LOCA Events, "Events Evaluated Using Existing DNB Margin RCCA Misalignment 14.1.3 Bounded 11.3.1 RCCA Drop 14.1.4 Bounded 11.3.1 "Non-Limiting/Bounded Events Uncontrolled RCCA Withdrawal from a 14.1.1 Bounded 11.3.2 Subcritical Condition Uncontrolled RCCA Withdrawal at Power 14.1.2 Bounded 11.3.3 Uncontrolled Boron Dilution 14.1.5 Bounded 11.3.4 Loss of Reactor Coolant Flow 14.1.6 Bounded 11.3.5 Locked Rotor Accident 14.1.6 Bounded 11.3.6 Loss of External Electrical Load or Turbine 14.1.8 Bounded 11.3.7 Trip Loss of Normal Feedwater Flow 14.1.9 Bounded 11.3.8 Excessive Heat Removal Due to Feedwater 14.1.10 Bounded 11.3.9 System Malfunctions - from HZP Conditions Excessive Load Increase Incident 14.1.11 Bounded 11.3.10 LOOP to the Station Auxiliaries 14.1.12 Bounded 11.3.8 Rupture of a Steam Pipe - Core Response 14.2.5 Bounded 11.3.11 Analysis Rupture of a CRDM Housing (RCCA 14.2.6 Bounded 11.3.12 Ejection)

Major Rupture of a Main Feedwater Pipe 14.2.8 Bounded 11.3.15 (Feedline Break) to AEP:NRC:2902 Page 10 Table 2 - MUR Power Uprate Impact on CNP Unit 2 Accident/Transient Analyses A CNP Unit 2 Impact of Sub-Section Accident/Transient UFSAR Uprate on of this Section Current UFSAR Attachment Analysis Feedwaterand Steam Line Break Massand Energy.Releases , .

Short-Term Feedwater Line Break Inside 14.3.4.4.1* Bounded 11.2.1 Containment Short-Term Inside Containment 14.3.4.4.1* Bounded 11.2.1 Long-Term Inside Containment 14.3.4.4.2* Bounded 11.2.1 Long-Term Outside Containment/ 14.4.3.5.1 Bounded VII.6.1 Equipment Qualification "Post-LOCA'Hydrogen Generation .

Post-LOCA Hydrogen Generation Rates 14.3.6* Bounded 11.2.2 LOCA-Mass and EnergyReleaseso.

Long-Term 14.3.4.3.1.2* Bounded 11.2.3 Short-Term 14.3.4.5.1* Bounded 11.2.3

,.,Containment Integrity.

Peak Containment Pressure Transient 14.3.4.1.3.1.3* Bounded 11.2.3 Containment Subcompartment Reactor Cavity 14.3.4.2.8* Bounded 11.2.3 Pressurizer Enclosure Subcompartment 14.3.4.2.5* Bounded 11.2.3 Loop Subcompartment 14.3.4.2.7* Bounded 11.2.3 Steam Generator Enclosure 14.3.4.2.4* Bounded 11.2.3 Subcompartment Fan/Accumulator Room Subcompartment 14.3.4.2.6* Bounded 11.2.3 Analyses Performed in Accordancewith Specific RegulatoryRequirements ATWS (10 CFR 50.62) 3.3.1.7 Bounded 11.3.13 SBO (10 CFR 50.63) 8.7 Bounded 11.3.14

Common analysis is summarized in Unit 1 UFSAR sections.

Design Operating Parameters and Initial Conditions The revised NSSS design thermal and hydraulic parameters that were changed as a result of the MUR Uprate Program serve as the basis for the NSSS analyses and evaluations. These revised parameters are presented in Table 3, "CNP Unit 2 MIUR Power Uprate -'NSSS Design Parameters." The revised parameters include a full-power normal operating Tag range of 547.60 to 578.1°F, from the current design values of 547.00 to 578.7°F. The full-power Tag range was to AEP:NRC:2902 Page 11 adjusted slightly for the MUR Uprate Program to maintain the current maximum vessel Thot (611.2°F) and minimum vessel TCold (513.3*F) conditions supported by the current design parameters.

Cases I and 2 of Table 3 vary the SGTP from 0 percent to 10 percent, respectively, while maintaining a Tavg of 578.1 'F, which was calculated based upon maintaining a maximum vessel Thotof 611. 2 'F.

Cases 3 and 4 vary SGTP from 0 percent to 10 percent, respectively, while maintaining a Tavg of 547.6 0 F which was calculated based upon on maintaining a minimum vessel TCO, of 513.3°F.

Higher steam pressures than those presented in Table 3 are possible, predominantly due to lower steam generator tube fouling. Where a higher steam pressure is more limiting for a particular analysis, a greater steam pressure of 858 psia at 15.45x10 6 lb/hr has been used rather than the maximum steam pressure of 839 psia at 15.44x10 6 lb/hr listed in Table 3.

For accident analyses that are performed to demonstrate that the DNB acceptance criteria are met (RCCA Misalignment and RCCA Drop), nominal values of initial conditions are assumed. In accordance with the Westinghouse RTDP .methodology delineated in WCAP-11397-P-A (Reference 6), uncertainty allowances on power, RCS flow, temperature, and pressure are considered in the convolution of uncertainties to statistically establish the DNBR limit.

The only uncertainty that will change as a result of the MUR Uprate Program is the power measurement uncertainty, which will be changed to +/-0.31 percent. None of the other uncertainties (i.e., average RCS temperature, pressurizer pressure, and RCS flow) need to be revised.

The effect of the reduced power measurement uncertainty has been accounted for in the analysis/evaluation of the various accidents and transients discussed in Section II. For analyses that utilize the RTDP method for the calculation of the minimum DNBR, the uncertainties are accounted for in the minimum DNBR safety analysis limit, rather than being accounted for explicitly in the analyses, thereby resulting in no change to DNB-related TS.

The NSSS design parameters are the fundamental parameters used as input in all of the NSSS analyses. These design parameters are the primary and secondary side system conditions (temperatures, pressures, and flow) that are used as the basis for the NSSS analyses and evaluations. These parameters are revised to accommodate the proposed 1.66 percent increase in licensed core power from 3411 MWt to 3468 MWt. The NSSS parameters were conservatively generated for a 2 percent core power uprating to 3482 MWt (based on an assumed initial core power of 3413 MWt) to bound the actual uprating. Furthermore, the evaluations have been performed to support a power uprate such that the sum of the uprate plus uncertainty is less than to AEP:NRC:2902 Page 12 or equal to 2 percent. In support of the 1.66 percent power uprate, these parameters have been incorporated, as required, into the applicable safety analyses and NSSS system and component evaluations.

I&M notes that various WCAPs that are part of the CNP Unit 2 licensing basis, as referenced in this license amendment request, may have included explicit references to their use of "102 percent of licensed core power levels," (e.g., WCAP-11902). I&M does not consider that these WCAPs require revision to reflect this requested power uprate. Rather, it will be understood that those statements refer to the previously-required 2 percent 10 CFR 50, Appendix K, margin and the currently licensed power level.

The revised NSSS design thermal and hydraulic parameters that were changed as a result of the MUR Uprate Program are presented in Table 3, "CNP Unit 2 MUR Power Uprate - NSSS Design Parameters."

to AEP:NRC:2902 Page 13 Table 3 - CNP Unit 2 MUR Power Uprate - NSSS Design Parameters S-.-.------- ...

-2% Uprate THERMAL DESIGN PARAMETERS Case 1 Case 2 Case 3 Case 4 NSSS Power, % 102 102 102 102 MWt 3494 3494 3494 3494 106 BTU/hr 11,922 11,922 11,922 11,922 Reactor Power, MWt 3482 3482 3482 3482 106 BTU/hr 11,881 11,881 11,881 11,881 Thermal Design Flow, Loop gpm 88,500 88,500 88,500 88,500 Reactor 106 lb/hr 134.0 134.0 139.3 139.3 2250 Note 1 2250 Note 1 2250 Note I 2250 Note I Reactor Coolant Pressure, psia Core Bypass, % 7.1 7.1 7.1 7.1 Reactor Coolant Temperature, IF Core Outlet 615.7 615.7 586.7 586.7 Vessel Outlet, Tho, 611.2 611.2 581.9 581.9 Core Average 582.2 582.2 551.4 551.4 Vessel Average, Tavg 578.1 578.1 547.6 547.6 Vessel/Core Inlet, Teold 545.0 545.0 513.3 513.3 Steam Generator Outlet 544.7 544.7 513.0 513.0 Steam Generator Steam Temperature, IF 523.8 520.6 490.7 487.4 Steam Pressure, P,,,*, psia 839 817 625 607 Steam Flow, 106 lb/hr total 15.44 15.43 15.34 15.34 Feed Temperature, IF 444.6 444.6 444.6 444.6 Moisture, % max. 0.25 0.25 0.25 0.25 Tube Plugging, % 0 10 0 10 Zero Load Temperature, IF 547 547 547 547 HYDRAULIC DESIGN PARAMETERS Mechanical Design Flow, gpm 101,600 Minimum Measured Flow, gpm total 366,400 Note 1 - Plant may also operate at 2100 psia. Operating temperatures for 2100 psia have an approximate 0.2`F increase in TCold and a 0.2°F decrease in Tho.

to AEP:NRC:2902 Page 14 Core Thermal Limits and OTAT and OPAT Setpoints Two essential inputs to the non-LOCA safety analyses are the core thermal limits and the resulting OTAT and OPAT setpoints.

The core thermal limits, OTAT/OPAT reactor trip setpoints, and calculations supporting the DNB design bases for the current non-LOCA analyses are analyzed at a core thermal power of 3588 MWt, which bounds the MUR uprate power. The OTAT/OPAT reactor trip setpoints currently supported in the non-LOCA analysis were revised during the 3600 MWt Uprate/Revalidation program in order to generate more operating margin when transitioning to a full core of Westinghouse VANTAGE 5 fuel. The relaxed OTAT/OPAT reactor trip setpoints 37 provide larger OTAT/OPAT safety analysis limit values (i.e., Kl(SALQ=l. , Kl(nom)=1.17) than those currently contained in the CNP Unit 2 TS, which are applicable to the mixed ANF/VANTAGE 5 fuel (i.e., KI(sAL)=1.19, Kl(nom)=l.09). The relaxed OTAT/OPAT setpoints result in more limiting analysis conditions since they increase the margin to reactor trip.

Therefore, the OTAT/OPAT reactor trip setpoints assumed in the non-LOCA analysis continue to be conservative for CNP Unit 2.

Therefore, the OTAT/OPAT reactor trip setpoints in the CNP TS continue to protect the core thermal limits and remain valid at the MUR power uprate conditions.

No change to the CNP Unit 2 TS are required for the non-LOCA analyzed events for the MUR Uprate Program, with the exception of the licensed core power level.

NSSS Analysis History for CNP Unit 2 A significant number of analyses have been performed for CNP Unit 2 to support operating flexibility and potential plant uprating in the recent past. The following provides a brief history to aid in the understanding of the evaluations presented herein to support the potential 1.66 percent uprating for CNP Unit 2.

In November 1988, Westinghouse issued WCAP-11902 (Reference 7), which documented analyses to support operation of CNP Unit 1 at reduced primary system pressure and temperature. Subsequently, in September 1989, a supplement to WCAP-11902 was issued to support a rerating of CNP Units I and 2 (Reference 8). This document supported the operation of CNP Unit 2 for the range of conditions at the increased core power of 3588 MWt. This report is referred to as the Rerating Program and is referred to throughout the ensuing sections of this attachment. The Rerating Program analytical work was submitted to the NRC via Reference 9, and approved in an SER dated June 9, 1989 (Reference 10).

to AEP:NRC:2902 Page 15 In January 1990, an additional program was completed to support a fuel transition to Westinghouse 17x17 VANTAGE 5 fuel, was submitted in February 1990 (Reference 11), and approved by Reference 12. While the safety analyses redone as part of this fuel upgrade continued to support the range of operating temperatures and pressures, as with the previous analyses, some safety analyses were performed at a lower core power of 3413 MWt. For clarification, it is noted that many of the analyses were performed at the bounding core power of 3413 MWt, although the CNP Unit 2 license is currently for 3411 MWt core power.

In 1996, a program was completed to allow CNP Unit 2 to uprate to 3588 MWt core power (Reference 13). These analyses continued to support the range of operating temperatures and pressures established in the earlier analyses. Although submitted to the NRC for review in 1997, the license amendment request was later withdrawn (Reference 14). A significant portion of the evaluations and assessments presented in this attachment to support the 1.66 percent power uprate for CNP Unit 2 builds from this previous work performed to uprate the plant to a higher power level than is being requested by this license amendment request.

In March 2002, an evaluation was completed that supports operation with or without plugging devices installed in the fuel assembly guide tubes. This evaluation was adopted into the CNP Unit 2 licensing basis by a 10 CFR 50.59 evaluation. The evaluations and assessments presented in this attachment continue to support operation with or without the plugging devices installed.

References (Introduction Section)

1. Letter from W. D. Beckner, NRC, "NRC Regulatory Issue Summary 2002-03:

Guidance on the Content of Measurement Uncertainty Recapture Power Uprate Applications," dated January 31, 2002

2. WCAP-10263, "A Review Plan for Uprating the Licensed Power of a PWR Power Plant," dated January 1983

3. Letter from R. E. Martin, NRC, to J. A. Scalice, Tennessee Valley Authority, "Watts Bar Nuclear Plant, Unit 1 - Issuance of Amendments Regarding Increase of Reactor Power to 3459 Megawatts Thermal (TAC No. MA9152)," dated January 19, 2001

4. Letter from D. H. Jaffe, NRC, to C. L. Terry, TXU Electric, "Comanche Peak Steam Electric Station (CPSES), Units 1 and 2 - Issuance of Amendments Re: Increase in Allowable Thermal Power to 3458 MWt and Deletion of Texas Municipal Power Agency from the Operating Licenses (TAC Nos. MB1625 and MB1626)," dated October 12, 2001

5. Letter from L. J. Burkhart, NRC, to L. W. Myers, FirstEnergy Nuclear Operating Company, "Beaver Valley Power Station, Unit Nos. 1 and 2 (BVPS-1 and 2) -,

to AEP:NRC:2902 Page 16 Issuance of Amendment Re: 1.4 Percent Power Uprate and Revised BVPS-2 Heatup and Cooldown Curves (TAC Nos. MB0996, MB0997, and MB2557)," dated September 24, 2001

6. WCAP-11397-P-A, "Revised Thermal Design Procedure," Friedland, A. J. and Ray, S., dated April 1989

7. WCAP-11902, "Reduced Temperature and Pressure Operation for Donald C. Cook Nuclear Plant Unit 1 Licensing Report," dated October 1988

8. WCAP-1 1902, Supplement 1, "Rerated Power and Revised Temperature and Pressure Operation for Donald C. Cook Nuclear Plant Units 1 and 2 Licensing Report," dated September 1989

9. Letter from M. P. Alexich, I&M, to T. E. Murley, NRC, "Reduced Temperature and Pressure Program Analyses and Technical Specification Changes," AEP:NRC:1067, dated October 14, 1988

10. Letter from J. F. Stang, NRC, to M. P. Alexich, I&M, "Amendment No. 126 to Facility Operating License No.'DPR-58 (TAC No. 71062)," dated June 9, 1989

11. Letter from M. P. Alexich, I&M, to T. E. Murley, NRC, "Unit No. 2 Cycle 8 Reload Licensing, Proposed Technical Specifications for Unit 2 Cycle 8, and Related Unit 1 Proposals," AEP:NRC:1071E, dated February 6, 1990

12. Letter from T. G. Colburn, NRC, to M. P. Alexich, I&M, "Amendment No. 148 and 134 to Facility Operating License Nos. DPR-58 and DPR-74: (TAC Nos. 75395, 75396 and 76816)," dated August 27, 1990

13. WCAP-14489, Revision 1, "American Electric Power Company Donald C. Cook Nuclear Power Plant Unit 2 3600 MWt Uprating Program Licensing Report," dated May 1996

14. Letter from R. P. Powers, I&M, to NRC Document Control Desk, "Withdraw Operating License and Technical Specification Change Request for Increased Unit 2 Rated Thermal Power and Related Unit 1 Changes," AEP:NRC:1223N, dated September 22, 1998 to AEP:NRC:2902 Page 17

1. Feedwater Flow Measurement Technique and Power Measurement Uncertainty I. The feedwater flow measurement system being installed at CNP Unit 2 is an LEFM CheckPlus ultrasonic, multi-path, transit time flowmeter. The design of this advanced flow measurement system is addressed in detail by the manufacturer, Caldon, in Topical Reports ER-80P, Revision 0 (Reference 1.1), and ER-157P, Revision 5 (Reference 1.2).

The LEFM CheckPlus system at CNP Unit 2 will consist of one flow element installed in the common portion of the feedwater flow loops and an electronic unit installed in the PPC room. This flow element will be installed approximately 6 pipe diameters downstream from the centerline of a 900 elbow and approximately 5 pipe diameters upstream from the centerline of a vertical tee to the centerline of the metering section. The planned installation location of this flow element conforms to the requirements in Topical Reports ER-80P and ER-157P.

The Unit 2 LEFM flow-measuring device will be installed at least 70 feet upstream of the venturi and other feedwater flow instrumentation. The path between these instruments also includes at least five 90-degree elbows or tees, three flow valves, and three different pipe diameters. This is a sufficient equivalent length of pipe, in terms of the number of pipe diameters and flow resistance elements, to prevent hydraulic interference between these instruments. Therefore, there is no hydraulic communication between these instruments that would cause interference due to the installation of the new Caldon LEFM flow-measuring device.

The LEFM CheckPlus system will be used for continuous calorimetric power determination by serial link with the PPC. The serial data link consists of the hardware and software used by the PPC to acquire data and status information from the Caldon LEFM CheckPlus system output and to store this information within the PPC for use by other applications.

A serial interface device is used to interface the PPC with the LEFM equipment via serial links. The device is connected to the ethernet local area network (LAN). A separate port on the serial device is connected to each LEFM link via an RS-232 serial cable. Since there are two links from the LEFM, Port 1 of the serial device is connected to CPU-A of the LEFM, while Port 2 is connected to CPU-B of the LEFM.

The Data Link software uses specific operating system service calls to access and read the ports of the serial device. The data link does not provide any automatic update between the venturi and LEFM flowmeters. The process for adjustment between the venturi and LEFM power outputs is manual and is described in Item H.

to AEP:NRC:2902 Page 18 A. The referenced Topical Reports are:

i. ER-80P, "Improving Thermal Power Accuracy and Plant Safety While Increasing Operating Power Level Using the LEFMVTM System,"

Revision 0, dated March 1997 ii. ER-157P, "Supplement to Topical Report ER-80P: Basis for a Power Uprate with the LEFMVTm or LEFM CheckPlusTM System," Revision 5, dated October 2001 B. The NRC approved the subject Topical Reports referenced in Item (A) above on the following dates:

i. ER-80P, NRC SER dated March 8, 1999 (Reference 1.3) ii. ER-157P, NRC SER dated December 20, 2001 (Reference 1.4)

C. The LEFM CheckPlus system will be permanently installed in CNP Unit 2 in accordance with the requirements' of Topical Reports ER-80P and ER-157P.

This system will be used for continuous calorimetric power determination by serial link with the PPC and will incorporate self-verification features to ensure that hydraulic profile and signal processing requirements are met within its design basis uncertainty analysis.

The CNP Unit 2 LEFM CheckPlus system will be calibrated in a site-specific model test at Alden Research Laboratories with traceability to National Standards. The LEFM CheckPlus system will be installed and commissioned according to Caldon procedures, which include verification of ultrasonic signal quality and hydraulic velocity profiles as compared to those tested during site-specific model testing.

D. In approving Caldon Topical Reports ER-80P and ER-157P, the NRC established four criteria to be addressed by each licensee. The four criteria and a discussion of how each will be satisfied for CNP Unit 2 follow:

Criterion 1 Discuss maintenance and calibration procedures that will be implemented with the incorporation of the LEFM, including processes and contingencies for inoperable LEFM instrumentation and the effect on thermal power measurements and plant operation.

to AEP:NRC:2902 Page 19 Response to Criterion 1 Implementation of the power uprate license amendment will include developing the necessary procedures and documents required for operation, maintenance, calibration, testing, and training at the uprated power level with the new LEFM CheckPlus system. Plant maintenance and calibration procedures will be revised to incorporate Caldon's maintenance and calibration requirements prior to declaring the LEFM CheckPlus system operational and raising core power above 3411 MWt. The incorporation of, and continued adherence to, these requirements will assure that the LEFM CheckPlus system is properly maintained and calibrated.

Contingency plans for operation of the plant with the LEFM CheckPlus system out of service are described in Section G/H below.

Criterion 2 For plants that currently have LEFMs installed, provide an evaluation of the operational and maintenance history of the installed installation and

.confirmation that the installed instrumentation is representative of the LEFM system and bounds the analysis and assumptions set forth in Topical Report ER-80P.

Response to Criterion 2 This criterion is not applicable to CNP Unit 2. CNP Unit 2 currently uses venturies to obtain the daily calorimetric heat balance measurements. I&M is installing an LEFM CheckPlus system at CNP Unit 2 in anticipation of approval of this proposed amendment. Installation of this system will be completed prior to implementation of the requested license amendment.

Criterion 3 Confirm that the methodology used to calculate the uncertainty of the LEFM in comparison to the current feedwater instrumentation is based on accepted plant setpoint methodology (with regard to the development of instrument uncertainty). If an alternative approach is used, the application should be justified and applied to both venturi and ultrasonic flow measurement instrumentation installations for comparison.

to AEP:NRC:2902 Page 20 Response to Criterion 3 The total power calorimetric accuracy using the LEFM CheckPlus system is determined by evaluating the reactor thermal power sensitivity to deviations in each of the process inputs used to calculate reactor thermal power. The methodology is consistent with that used for the reactor power uncertainty described in the RTDP, WCAP-1 1397-P-A (Reference 1.5), which was applied at CNP Unit 2, using feedwater venturies. The NRC has reviewed the RTDP methodology and approved its use at CNP (Reference 1.6). In both the RTDP and LEFM CheckPlus reactor power uncertainty calculations, the instrumentation uncertainties and calculated values are determined. The reactor thermal power sensitivity is then calculated for each parameter. The individual contributions to the power uncertainty are then combined using a statistical summation to determine the total power measurement uncertainty. The methodology used for this combination is not new, and this statistical approach has been utilized in other applications based on the RTDP. Also, the use of a statistical approach in analysis complies with the recommendations of ANSI/ISA-67.04.01-2000, "Setpoints for Nuclear Safety-Related Instrumentation" (Reference 1.7).

Criterion 4 For plants where the ultrasonic meter (including LEFM) was not installed and flow elements calibrated to a site-specific piping configuration (flow profiles and meter factors not representative of the plant specific installation), additional justification should be provided for its use. The justification should show that the meter installation is either independent of the plant specific flow profile for the stated accuracy, or that the installation can be shown to be equivalent to known calibrations and plant configurations for the specific installation including the propagation of flow profile effects at higher Reynolds numbers.

Additionally, for previously installed calibrated elements, confirm that the piping configuration remains bounding for the original LEFM installation and calibration assumptions.

Response to Criterion 4 Criterion 4 does not apply to CNP Unit 2. The calibration factor for the Unit 2 spool piece will be established by tests of this spool at Alden Research Laboratory in January 2003. These tests will include a full-scale model of the CNP Unit 2 hydraulic geometry and tests in a straight pipe.

to AEP:NRC:2902 Page 21 Final acceptance of the site-specific uncertainty analyses will occur after the completion of the commissioning process. The commissioning process verifies bounding calibration test data (See Appendix F of ER-80P, Reference 1.1) and provides final positive confirmation that actual performance in the field meets the uncertainty bounds established for the instrumentation. Final commissioning is expected to be completed by May 2003.

E. By Reference 1.8, I&M submitted to the NRC calculation 1-2-01-03 CALC 2, Revision 1, Change Sheet 1, "Power Calorimetric Accuracy Using the Caldon Check Plus Feedwater Flow Measurement System and a modified PPC CALM Program," dated November 12, 2002 (Proprietary). This calculation establishes the basis for the core thermal power measurement uncertainty for both CNP Unit 1 and Unit 2. Table I-1 summarizes the core thermal power measurement uncertainty for CNP Unit 2.

Table I-1 -- Unit 2 Process Parameter Inputs to Reactor Thermal Power Parameter Bounding Uncertainty Sensitivity Value (%RTP)

FW pressure, psig 840.30 +/-15 +/-0.001813%

FW temperature, OF 422.08 +/-0.6 +/-0.082708%

FW mass flow rate, 106 lb/hr 14.68 +/-0.0427 +/-0.292820%

Average steam pressure, psig 804.00 +7.694 +/-0.037263%

Total blowdown flow, gpm 160.00 +/-10 +/-0.022541%

Charging flow, gpm 126.90 +6.8/-10.3 +/-0.000000%

Charging pressure, psig 2397.50 +49.82 +/-0.000000%

Charging temperature, OF 466.30 +/-6.5 +/-0.000000%

Letdown pressure, psig 335.60 +14.7876 / +/-0.000000%

-14.0556 Letdown temperature, OF 120.60 +/-1.3625 +/-0.000000%

Letdown flow, gpm 119.10 +5.4 / -5.9 +/-0.000000%

Pressurizer pressure, psig 2232.50 +19.752/ +/-0.000000%

-18.441 Reactor Tcold, OF 542.40 +/-2.78 +/-0.000000%

VCT temperature, OF 121.00 +/-1.5646 +/-0.000000%

SRSS Total Uncertainty +0.31% RTP (Square Root Sum of the Squares)

The "Uncertainty" and the "Sensitivity" columns of Table I-1 are directly related. The "%RTP" is intended to indicate that the units of the "Sensitivity" column are in percent of rated thermal power and not in the process units to AEP:NRC:2902 Page 22 associated with the "Parameter" column. Total uncertainty was determined by varying each process parameter about a base value and determining the corresponding sensitivity of percent rated thermal power. [As an example, at the current 100 percent RTP, the feedwater pressure is 840.30 psig. The uncertainty of the feedwater pressure input to the PPC calorimetric program is determined to be +/-15 psig. Thus, if the actual feedwater pressure is 840.30 psig, and an error as large as +/-15 psig is possible at the point that the feedwater pressure signal is input to the PPC, the corresponding error in the calculated %RTP could be as large as +/-0.001813 %RTP. Thus, Table I-1 shows that the sensitivity of %RTP to a change in feedwater pressure of +/-15 psig is

+/-0.001813 %RTP.]

F. In addition to the process inputs provided by the LEFM CheckPlus system, the PPC program uses the following process inputs to calculate thermal power:

"* Steam Pressure

"* Blowdown Flow

"* Charging Flow

"* Charging Temperature

"* Charging Pressure

"* Letdown Flow

"* Letdown Temperature

"* Letdown Pressure

"* Pressurizer Pressure

"* RCS Loop 4 Cold Leg Temperature

"* VCT Temperature Blowdown flow measurement is performed by a Caldon ultrasonic measurement system. Calibration of this ultrasonic measurement system is maintained using self-checking and self-adjusting methods. The value and status of the blowdown flow measurement are provided to the PPC. If the status of the blowdown flow measurement or the failure of the blowdown flow system indicates that the status is "bad", this is reflected in the PPC calorimetric program and results in the status of the LEFM calorimetric values also indicating a "bad" status. Control of the ultrasonic measurement system is maintained by the CNP change control process. Hardware control of the ultrasonic measurement system is provided by the CNP design change control process, which conforms to 10 CFR 50, Appendix B, and control of the system software is provided by CNP's software control process.

to AEP:NRC:2902 Page 23 The remaining process inputs are obtained from analog instrumentation channels that are maintained and calibrated in accordance with required periodic calibration procedures. Configuration of the hardware associated with these process inputs is maintained in accordance with the CNP change control process.

Instruments that affect the power calorimetric, including the LEFM inputs, are monitored by CNP's System Engineering personnel in accordance with the requirements of I&M's Corrective Action Program. Equipment problems for plant systems, including the LEFM CheckPlus equipment, fall under the site work control processes. Conditions that are adverse to quality are documented under the Corrective Action Program. Corrective action procedures, which ensure compliance with the requirements of 10 CFR 50, Appendix B, include instructions for notification of deficiencies and error reporting.

Calibration and maintenance of the LEFM CheckPlus system will be performed by CNP's I&C - Maintenance Department personnel, working under site work control processes, using site procedures. Site procedures are developed using the vendor technical manuals for the applicable equipment. Routine preventive maintenance procedures include physical inspections, power supply checks, back-up battery replacements, and internal oscillator frequency verification.

Corrective actions involving maintenance will be performed by I&C-Maintenance Department personnel, qualified in accordance with I&M's I&C Training Program.

The following information addresses specific aspects of calibration and maintenance procedures addressing the LEFM CheckPlus system.

i. Calibration and maintenance will be performed by CNP's I&C-Maintenance Department personnel, working under site work control processes, using site procedures. The site procedures will be developed using the Caldon technical manuals.

Routine preventive maintenance activities will include physical inspections, power supply checks, back-up battery replacements, and internal oscillator frequency verification.

Ultrasonic signal verification and alignment are performed automatically with the LEFM CheckPlus system. Signal verification is possible by review of signal quality measurements performed and displayed by the LEFM CheckPlus system.

to AEP:NRC:2902 Page 24 I&C-Maintenance Department personnel will be trained and qualified per the I&M INPO-accredited training program before calibration is performed and prior to raising power above 3411 MWt.

ii. The LEFM CheckPlus system is designed and manufactured in accordance with Caldon's 10 CFR 50, Appendix B, Quality Assurance Program and its Verification and Validation Program. Caldon's Verification and Validation Program fulfills the requirements of ANSI/IEEE-ANS Std. 7-4.3.2, 1993, "IEEE Standard Criteria for Digital Computers in Safety Systems of Nuclear Power Generating Stations," Annex E, and ASME NQA-2a-1990, "Quality Assurance Requirements for Nuclear Facility Applications." In addition, the program is consistent with guidance for software verification and validation in EPRI TR-103291S, "Handbook for Verification and Validation of Digital Systems," dated December 1994. Specific examples of quality measures undertaken in the design, manufacture, and testing of the LEFM CheckPlus system are provided in Caldon Topical Report ER-80P, Section 6.4 and Table 6.1.

iii. Corrective actions involving maintenance will be performed by I&C-Maintenance Department personnel, qualified in accordance with I&M's I&C Training Program, and formally trained on the LEFM CheckPlus system.

iv. Reliability of the LEFM CheckPlus system will be monitored by CNP's System Engineering personnel in accordance with the requirements of I&M's Corrective Action Program. Equipment problems for all plant systems, including the LEFM CheckPlus equipment, fall under the site work control process. Conditions that are adverse to quality are documented under the Corrective Action Program. The Caldon LEFM CheckPlus system software falls under the I&M 10 CFR 50, Appendix B, Quality Assurance Program, which includes specific software quality assurance requirements. Corrective action procedures are maintained that include instructions for notification of deficiencies and error reporting.

v. The CNP Unit 2 LEFM CheckPlus system is included in Caldon's Verification and Validation Program, and procedures are maintained for user notification of important deficiencies. The Caldon LEFM CheckPlus system purchase order included requirements that Caldon inform I&M of any deficiencies in accordance with the Caldon maintenance agreement and/or 10 CFR Part 21 reporting requirements.

to AEP:NRC:2902 Page 25 G. The proposed allowed outage time for operation at any power level in excess of the pre-uprate power level (3411 MWt) with an LEFM CheckPlus system out of service is 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months , provided steady state conditions (i.e., no power changes in excess of 10 percent) persist throughout the 48-hour period. The bases for this proposed allowed outage time period are:

" There is an on-line calibration of a set of alternate plant instruments to be used if the LEFM CheckPlus system is out of service for a longer period.

These alternate instruments will be calibrated to the last valid value provided by the LEFM CheckPlus system, and their accuracy will gradually degrade over time as a result of nozzle fouling and transmitter drift. The gradual accuracy degradation is likely to be imperceptible for a 48-hour period provided steady-state conditions persist.

During past refueling outages, the feedwater venturis were inspected for evidence of fouling. The results of these venturi inspections have consistently indicated that the Unit 2 feedwater venturis do not experience fouling. Based on this evidence, feedwater venturi fouling that would result in degradation of the accuracy of these components is not expected. Thus, venturi fouling that would degrade flowmeter accuracy would not be expected over the 48-hour period that the LEFM is not operational.

" Most repairs to the LEFM CheckPlus system can be made within an eight-hour shift. Forty-eight hours gives plant personnel time to plan the work, make repairs, and to verify normal operation of the LEFM CheckPlus system within its original uncertainty bounds at the same power level and indications as before the failure.

" Operations personnel will operate the plant based on the calibrated alternate plant instruments when an LEFM CheckPlus system is not available. It is considered prudent to provide them time to become accustomed to operation with the alternate plant instruments prior to requiring a power de-rate. The power de-rate evolution could, in many cases, be avoided altogether since a repair would be accomplished prior to the expiration of the 48-hour period.

" If the plant experiences a power change of greater than 10 percent during the 48-hour period, then the permitted maximum power level would be reduced upon return to full power in accordance with the power levels described below, since a plant transient may result in calibration changes of the alternate instruments.

to AEP:NRC:2902 Page 26

" Upon identification of LEFM failure, the venturi power calorimetric values would be adjusted (i.e., calibrated to the last valid power output of the LEFM prior to the time of LEFM failure). Expectations of instrument drift vary depending upon the manufacturer's specifications. However, values of drift are typically in the range of tenths of a percent of the calibrated span over 18 to 24 months or more. This typical drift value would not result in any significant drift for the instrumentation associated with the calorimetric measurements over a 48-hour period.

" As described in Reference 1.2, the LEFM CheckPlus system consists of two planes (8 paths) of transducers. Administrative controls will be developed to specify that if the LEFM has experienced an outage of only one plane (4 paths) of the instrument, plant operation will be consistent with a complete LEFM out-of-service condition.

H. For the LEFM out-of-service condition, the 48-hour "clock" will start at the time of LEFM failure. Failure will be annunciated in the control room on the PPC screen that displays the calorimetric power level. The status of the LEFM power calorimetric will be determined based on the status of the LEFM data points. The last "good" value of the LEFM power calorimetric will be the last retrievable data point with a status of "good." The method of identifying the status of LEFM data by the electronic unit and the alarms to the operator are described in the Caldon documentation located in the CNP vendor documentation program and the software design descriptions for the data link and the calorimetric program.

The LEFM electronic unit and central processing unit (CPU) continuously monitor, test, and/or verify the following attributes of the LEFM operation:

Acoustical processing units

Analog inputs

Test paths

Signal quality

Path-to-path sound velocity

Velocity profiles

Watchdog timer

Flowrate calculations uncertainty verified against specified system uncertainty threshold

Meter path operation (i.e., signal quality, sound velocity to specified thresholds)

Meter velocity profile (i.e., changes in hydraulic profile, verified against specified thresholds) to AEP:NRC:2902 Page 27 The procedures for power reduction will be in accordance with current operating procedures such that the plant will be operating at, or below, the pre-uprate power level limit of 3411 MWt by the time the 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months has elapsed. The 48-hour limit does not apply for the loss-of-PPC case, as discussed below.

If the 48-hour outage period is exceeded, then the plant will operate at a power level consistent with the accuracy of the alternate plant instruments.

The LEFM CheckPlus system at CNP Unit 2 consists of a single feedwater measurement spool piece installed in the feedwater header, and the associated electronics unit. Failure of the LEFM CheckPlus system will result in calculation of thermal power based on operation of the main feedwater flow measurement(s) venturies in the main feedwater lines and one or more RTDs in the feedwater system. These alternate instruments would have been calibrated to the last valid value of the thermal power calculation based on the LEFM CheckPlus flow and temperature measurements. Operation during this period would be at a power level consistent with operation entirely on these calibrated alternate instruments.

With the LEFM CheckPlus system out-of-service for greater than 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months , the thermal power uncertainty increases such that the justifiable core power level is reduced from 3468 MWt to 3411 MWt. Plant operating procedures will be revised to ensure that power reduction will occur to ensure that the plant will be at or below the pre-uprate power limit, 3411 MWt, within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months in the event of a loss-of-LEFM condition.

Venturi Flowmeter Calibration Following LEFM Loss The venturi calorimetric and the LEFM calorimetric are completely separate and are performed independently by the PPC. Each program performs independent calculations to determine core thermal power.

The venturi instrumentation is not "calibrated" on-line by a linkage to the LEFM. Instead, the venturi calorimetric calculated power is manually adjusted; i.e., calibrated to the last "good" LEFM calorimetric and the corresponding venturi calorimetric at that same time. This is performed by retrieving the last good thermal power computed by the LEFM (P3) and comparing it to the thermal power computed by the venturis (Pv) at that same time. A correction factor (CF) is then calculated by taking the ratio of the last good LEFM calorimetric power value to the venturi power value at that same time (i.e., CF = PL / Pv). For the proposed 48-hour allowable to AEP:NRC:2902 Page 28 outage period during which operation at the uprated power would be allowed as long as steady-state conditions exist, the corrected calorimetric power would be computed as being equal to the current venturi calorimetric power multiplied by the correction factor (PcoR = CF x Pv).

As part of the design change package that installs the LEFM CheckPlus system, plant operating procedures will be revised to ensure that should the LEFM out-of-service condition not be corrected, Operations will reduce plant thermal power level such that the plant is operating at or below the pre-uprate power level limit of 3411 MWt at the time that the 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months has elapsed.

Power Level Adjustment Following a PPC Failure A PPC failure would be treated as a loss of both the LEFM and the ability to obtain a corrected calorimetric power using the venturis. This would result in reducing plant power to the pre-uprated rated thermal power limit of 3411 MWt, as needed to support the mnanual calorimetric measurement using the venturies. The 48-hour time period would not apply in this specific case, as a manual calorimetric would be required. The manual calorimetric only supports operation at plant power levels up to 3411 MWt.

References (Section I) 1.1. ER-80P, Revision 0, "Improving Thermal Power Accuracy and Plant Safety While Increasing Operating Power Level Using the LEFM/TM System," Caldon, Inc., dated March 1997 1.2. ER-157P, Revision 5, "Supplement to Topical Report ER-80P: Basis for a Power Uprate with the LEFMV"TM or LEFM CheckPlusTM System," Caldon, Inc., dated October 2001 1.3. Letter from Project Directorate IV-I, Division of Licensing Project Management, Office of Nuclear Reactor Regulation, to C. L. Terry, TU Electric, "Comanche Peak Steam Electric Station, Units 1 and 2 -Review of Caldon Engineering Topical Report ER 80P, 'Improving Thermal Power Accuracy and Plant Safety while Increasing Power Level Using the LEFM System' (TAC Nos. MA2298 and 2299)," dated March 8, 1999 to AEP:NRC:2902 Page 29 1.4. Letter from S. A. Richards, NRC, to M. A. Krupa, Entergy, "Waterford Steam Electric Station, Unit 3; River Bend Station; and Grand Gulf Nuclear Station Review of Caldon, Inc. Engineering Report ER-157P (TAC Nos. MB2397, MB2399 and MB2468)," dated December 20, 2001 1.5. WCAP-1 1397-P-A, "Revised Thermal Design", approved April 1989, A. J. Friedland and S. Ray 1.6. Letter from T. G. Colburn, NRC, to M. P. Alexich, Vice President Indiana Michigan Power Company, "Amendment Nos. 148 and 134 to Facility Operating License Nos.

DPR-58 and DPR-74: (TAC Nos. 75395, 75396 and 76816)," dated August 27, 1990 1.7. ANSI/ISA-67.04.01-2000, "Setpoints for Nuclear Safety-Related Instrumentation,"

approved February 29, 2000 1.8. Letter from J. E. Pollock (I&M) to NRC Document Control Desk, "Submittal of Change to Power Measurement Uncertainty Calculation in Support of License Amendment Request for Appendix K Measurement Uncertainty Recapture - Power Uprate Request (TAC No. MB5498)," AEP:NRC:2900-04, dated November 15, 2002 to AEP:NRC:2902 Page 30 II. Accidents and Transients for which the Existing Analyses of Record Bound Plant Operation at the Proposed Uprated Power Level Table 11-1 summarizes the CNP Unit 2 accident and transient analyses that were determined to bound plant operation at the 1.66 percent power level proposed by the MUR Uprate Program.

Details of these evaluations follow in subsequent sub-sections.

Table II-1 Bounding Accident and Transient Design Basis Analyses Accident/Transient CNP Unit 2 Assumed NRC Approval UFSAR Section Core Power (Date and/or Reference Level Number)

Loss of Coolan1tAccident (LOCA) RelatedEven.ts LOCA Forces 3.2.1.2.2 N/A December 23, 1999 (Ref. 11.1) 3.2.1.3.2.2 N/A 3.2.2.3 N/A NRC approval for MULTIFLEX 14.3.3.1 3588 MWt methodology provided in 14.3.3.2 3588 MWt WCAP-8708-P/A and 14.3.3.3 3588 MWt WCAP-8709-A (Ref. 11.2) 4.3.1 N/A Large Break LOCA 14.3.1 3481 MWt February 2, 2000 ( Ref. 11.3)

August 15, 2002 (Ref. 11.4)

New analysis was provided for information via Ref. 11.3. The latest 10 CFR 50.46 Report (Ref. 11.4) identifies recent assessments.

Small Break LOCA 14.3.2 3481 MWt September 9, 1994 (Ref. 11.5)

(3315 MWt August 15, 2002 (Ref. I1.4)

High Head Previous NRC approval of Safety SBLOCA provided in (Ref. 11.5).

Injection The latest 10 CFR 50.46 Report Cross-Tie (Ref. 11.4) identifies recent Closed) assessments.

Post-LOCA Long-Term Core 14.3.1 3481 MWt December 13, 1999 (Ref. 11.6)

Cooling December 23, 1999 (Ref. II.1)

Hot Leg Switchover 14.3.1 3481 MWt December 13, 1999 (Ref. 11.6)

December 23, 1999 (Ref. II.1)

SGTR Thermal-Hydraulic Analysis 14.2.4 3588 MWt September 18, 1990 (Ref. 11.8) for Use in Determining Dose Consequences Operator Action and Margin to 14.2.4.4 3588 MWt October 24, 2001 (Ref. 11.9)

Overfill Assessment - SGTR I to AEP:NRC:2902 Page 31 Table II-1 Bounding Accident and Transient Design Basis Analyses Accident/Transient CNP Unit 2 Assumed NRC Approval UFSAR Section Core Power (Date and/or Reference Level Number)

Non-LOCA Events' Events Evaluated RCCA Misalignment 14.1.3 3413 MWt August 27, 1990 (Ref. 11.10)

RCCA Drop 14.1.4 341 3 MWt August 27, 1990 (Ref. 11. 10)

,Non-.Limiiting Events and Transients Uncontrolled RCCA Withdrawal 14.1.1 0 MWt August 27, 1990 (Ref. I1.10) from a Subcritical Condition Uncontrolled RCCA Withdrawal at 14.1.2 100%, 60%, August 27, 1990 (Ref. II.10)

Power 10% of 3588 MWt Uncontrolled Boron Dilution (CVCS 14.1.5 N/A August 27, 1990 (Ref. 11.10)

Malfunction)

Loss of Reactor Coolant Flow 14.1.6 3588 MWt August 27, 1990 (Ref. 11.10)

Locked Rotor- RCS overpressure, 14.1.6 3588 MWt August 27, 1990 (Ref. I.10) maximum cladding temperature, maximum zirconium-water reaction analysis and DNB Loss of External Electrical Load or 14.1.8 3588 MWt September 9, 1994 (Ref. 11.5)

Turbine Trip - overpressure analysis and DNB Loss of Normal Feedwater Flow 14.1.9 3660 MWt August 27, 1990 (Ref. 11.10)

Excessive Heat Removal Due to 14.1.10 0 MWt August 27, 1990 (Ref. 11. 10)

Feedwater System Malfunctions from HZP conditions.

Excessive Load Increase Incident 14.1.11 3588 MWt August 27, 1990 (Ref. 11.10)

Loss of Offsite Power to the Plant 14.1.12 3660 MWt August 27, 1990 (Ref. 11.10)

Auxiliaries Rupture of a Steam Pipe (core 14.2.5 0 MWt August 27, 1990 (Ref. 11.10) response)

Rupture of a Control Rod Drive 14.2.6 3588 MWt, August 27, 1990 (Ref. II.10)

Mechanism Housing (RCCA 0 MWt Ejection) - from HFP and HZP conditions Major Rupture of a Main Feedwater 14.2.8 3660 MWt August 27, 1990 (Ref. 11.10)

Pipe (Feedline Break) I Feedwater and Steam tLine Break'Mass and Energy Releases Short-Term Feedwater Line Break 14.3.4.4.1* 0 MWt and Containment Subcompartment Inside Containment 3588 MWt Re-analysis effort; incorporated into licensing basis by 50.59 to AEP:NRC:2902 Page 32 Table II-1 Bounding Accident and Transient Design Basis Analyses Accident/Transient CNP Unit 2 Assumed NRC Approval UFSAR Section Core Power (Date and/or Reference Level Number) evaluation.

Short-Term Inside Containment 14.3.4.4.1" 0 MWt Containment Subcompartment Re-analysis effort; incorporated into licensing basis by 50.59 evaluation Long-Term Inside Containment 14.3.4.4.2* 3660 MWt September 18, 1990 (Ref. 11.8)

December 13, 1999 (Ref. 11.6)

Long-Term Outside Containment! 14.4.3.5.1 3660 MWt December 13, 1999 (Ref. 11.6)

Equipment Qualification Post-LOCA`Hydrogen Generation' Post-LOCA Hydrogen Generation 14.3.6* 3411 MWt March 29, 2001 (Ref. 11.11)

Rates ILOCA Mass and Energy Releases ______ ____

Long-Term 14.3.4.3.1.2* 3481 MWt December 13, 1999 (Ref. 11.6)

Short-Term 14.3.4.5.1

3660 MWt Containment Subcompartment Re-analysis effort; incorporated into licensing basis by 50.59 evaluation Containment ,Integrity-,'

Peak Containment Pressure 14.3.4.1.3.1.3* 3481 MWt December 13, 1999 (Ref. 11.6)

Transient Analysis Containment Subcompartments Analyses.

Reactor Cavity 14.3.4.2.8* 3660 MWt September 10, 1973 (Ref. 11.12)

December 12, 1974 (Ref. 11.13)

Containment Subcompartment Re-analysis effort; incorporated into licensing basis by 50.59 evaluation.

Pressurizer Enclosure 14.3.4.2.5* 3660 MWt September 10, 1973 (Ref. 11.12)

Subcompartment December 23, 1977 (Ref. 11.14)

Containment Subcompartment Re-analysis effort; incorporated into licensing basis by 50.59 evaluation.

Loop Subcompartment 14.3.4.2.7* 3660 MWt June 9, 1989 (Ref. 11.7)

December 12, 1974 (Ref. 11.13)

Containment Subcompartment Re-analysis effort; incorporated into licensing basis by 50.59 evaluation.

to AEP:NRC:2902 Page 33 Table II-1 Bounding Accident and Transient Design Basis Analyses Accident/Transient CNP Unit 2 Assumed NRC Approval UFSAR Section Core Power (Date and/or Reference Level Number)

Steam Generator Enclosure 14.3.4.2.4* N/A September 10, 1973 (Ref. 11.12)

Subcompartment - Short-Term December 23, 1977 (Ref. 11. 14)

Steam Line Break Containment Subcompartment Re-analysis effort; incorporated into licensing basis by 50.59 evaluation.

Fan/Accumulator Room 14.3.4.2.6* N/A June 9, 1989 (Ref. 11.7)

Subcompartment December 12, 1974 (Ref. 11.13)

Containment Subcompartment Re-analysis effort; incorporated into licensing basis by 50.59 evaluation.

Analyses Performed in Accordance with Specific Regulatory Requirements ATWS (10 CFR 50.62) 3.3.1.7 3411 MWt April 14, 1989 (Ref. 11.15)

August 16, 1989 (Ref. 11.16)

SBO (10 CFR 50.63) 8.7 3411 MWt October 31, 1991 (Ref. 11.17)

April 23, 1992 (Ref. 11.18)

Common analysis is summarized in Unit 1 UFSAR sections.

References (Table 11-2) 11.1. Letter from J. F. Stang, NRC, to R. P. Powers, I&M, "Issuance of Amendments Donald C. Cook Nuclear Plant, Units 1 and 2 (TAC Nos. MA6473 and MA6474),"

dated December 23, 1999 11.2. WCAP-8708-P/A (Proprietary) and WCAP-8709-A (Non-Proprietary),

"MULTIFLEX, A Fortran-IV Computer Program for Analyzing Thermal Hydraulic Structure System Dynamics," dated September 1977 11.3. Letter from M. W. Rencheck, I&M, to Nuclear Regulatory Commission, "Donald C. Cook Nuclear Plant Unit 2 Annual Report of Loss-of-Coolant Accident Evaluation Model Changes and Submittal of New Large Break Loss-of-Coolant Accident Analysis of Record for Unit 2," C0200-08, dated February 2, 2000 11.4. Letter from S. A. Greenlee, I&M, to Nuclear Regulatory Commission, "Donald C. Cook Nuclear Plant Units I and 2 Annual Report of Loss-of-Coolant Accident Evaluation Model Changes," AEP:NRC:2046-01, dated August 15, 2002 to AEP:NRC:2902 Page 34 11.5. Letter from J. B. Hickman, NRC, to E. E. Fitzpatrick, I&M, "Donald C. Cook Nuclear Plant, Unit Nos. 1 and 2 - Issuance of Amendments Re: Increased Main Steam Safety Valve Setpoint Tolerances (TAC Nos. M84979 and M84980)," dated September 9, 1994 11.6. Letter from J. F. Stang, NRC, to R. P. Powers, I&M, "Issuance of Amendments Donald C. Cook Nuclear Plant, Units I and 2 (TAC Nos. MA6766 and M6767),"

dated December 13, 1999 11.7. Letter from J. F. Stang, NRC, to M. P. Alexich, I&M, "Amendment No. 126 to Facility Operating License No. DPR-58 (TAC No. 71062)," dated June 9, 1989 11.8. Letter from T. G. Colbum, NRC, to M. P. Alexich, I&M, "Amendment No. 135 to Facility Operating License No. DPR-74: (TAC No. 76817)," dated September 18, 1990 11.9. Letter from J. F. Stang, NRC, to R. P. Powers, I&M, "Donald C. Cook Nuclear Plant, Units 1 and 2 - Issuance of Amendments (TAC Nos. MB0739 and MB0740)," dated October 24, 2001 11.10. Letter from T. G. Colbum, NRC, to M. P. Alexich, I&M, "Amendment Nos. 148 and 134 to Facility Operating License Nos. DPR-58 and DPR-74: (TAC Nos. 75395, 75396 and 76816)," dated August 27, 1990 11.11. Letter from J. F. Stang, NRC, to R. P. Powers, I&M, "Donald C. Cook Nuclear Plant, Unit 1 - Issuance of Amendment (TAC No. MB0908)," dated March 29, 2001 11.12. Safety Evaluation Report, "Safety Evaluation by the Directorate of Licensing U. S. Atomic Energy Commission in the Matter of Indiana & Michigan Electric Company and Indiana & Michigan Power Company Donald C. Cook Nuclear Plant Units 1 and 2, Docket Nos. 50-315 and 50-316," dated September 10, 1973 11.13. Supplement to Safety Evaluation Report, "Supplement No. 3 to Safety Evaluation by the Directorate of Licensing U. S. Atomic Energy Commission in the Matter of Indiana & Michigan Electric Company and Indiana & Michigan Power Company Donald C. Cook Nuclear Plant Units 1 and 2, Docket Nos. 50-315 and 50-316," dated December 12, 1974 11.14. Letter from Nuclear Regulatory Commission to Indiana and Michigan Electric Company, "Supplement 7 to Safety Evaluation Report," dated December 23, 1977 to AEP:NRC:2902 Page 35 11.15. Letter from J.'F. Stang, NRC, to M. P. Alexich, I&M, "Donald C. Cook Nuclear Plant Nos. 1 and 2, Compliance with ATWS Rule 10 CFR 50.62 (TAC No. 59082 and 59083)," dated April 14, 1989 11.16. Letter from J. Glitter, NRC, to M. P. Alexich, I&M, "Safety Evaluation for Generic Letter 83-28, Item 4.5.3, Reactor Trip Reliability - On-Line Functional Testing of the Reactor Trip System (TAC No. 53971 and 53972)," dated August 16, 1989 11.17. Letter from T. G. Colburn, NRC, to E. E. Fitzpatrick, I&M, "Station Blackout Analysis, Donald C. Cook Nuclear Plant, Units I and 2 (TAC Nos. 68532/68533),"

dated October 31, 1991 11.18. Letter from J. F. Stang, NRC, to E. E. Fitzpatrick, I&M, "Station Blackout Analysis, Donald C. Cook Nuclear Plant, Units 1 and 2 (TAC Nos. M68532 and 68533)," dated April 23, 1992 11.1 Loss of Coolant Accident and Loss of Coolant Accident-Related Events (including Steam Generator Tube Rupture) 11.1.1 Loss of Coolant Accident Forces The reactor vessel and internals have been qualified using LOCA hydraulic forces based on a minimum allowable cold leg operating temperature of 511.7'F, and a pressurizer pressure of 2250 psia, plus uncertainty of 67 psi, for a total pressure of 2317 psia. The vessel and internals are qualified on the basis of branch line breaks, notably the accumulator line, RHR system line, and pressurizer surge line, as allowed under the leak-before-break criterion. The LOCA forces on the reactor coolant loop piping remain those cited in the existing CNP Unit 2 UFSAR (Reference 11.1.1). These LOCA forces were evaluated against forces generated for (accumulator) branch line breaks at a cold leg temperature of 511.7'F, and an RCS pressure of 2250 psia, using the MULTIFLEX code and the required one millisecond break opening time.

This evaluation previously determined that the original double-ended guillotine break forces remain higher and are, therefore, bounding.

The MUR Uprate Program will use a reduced range of RCS temperatures, such that the minimum allowable RCS cold leg temperature for 102 percent power conditions at minimum thermal design flow will be 513.3°F and the normal full power RCS pressure remains 2250 psia (see Table 3). However, given a temperature uncertainty of 4.1'F and a cold leg streaming bias of 1.07F, the analyses and evaluations that support CNP Unit 2 are only valid for a minimum RCS cold leg temperature of 516.8'F (511.7 'F analysis value + 4.1°F uncertainty + 1.0 'F due to cold leg streaming bias). Note: Operation at the lower pressure of 2100 psia would reduce calculated LOCA hydraulic forces. Therefore, the existing analyses of LOCA forces remain bounding at to AEP:NRC:2902 Page 36 the MUR Uprate Program conditions for CNP Unit 2, with a 3.5"F increase in the minimum allowable TCOId from 513.3°F to 516.8°F.

The LOCA forces methodology applied in the most recent vessel and internals qualification analyses remains identical to that used in the analysis that credits control rod insertion for reactivity control in the long-term post-LOCA. This analysis was approved by the NRC in the SER for Unit 2 License Amendment No. 218 (Reference 11.1.2). The MULTIFLEX methodology applied in determining that the existing loop LOCA forces remain bounding has been reviewed and approved by the NRC (Reference 11.1.3).

11.1.2 Large Break Loss of Coolant Accident and Small Break Loss of Coolant Accident The current licensing basis LBLOCA analysis and SBLOCA analyses (HHSI cross-tie valves open and closed cases) for Unit 2 use 10 CFR 50, Appendix K, methodology. The core power assumed for LBLOCA and SBLOCA with HHSI cross-ties open is 3588 MWt. A subsequent evaluation for LBLOCA in which accumulator line/pressurizer surge line data and several code errors were evaluated, however, assumes a decreased core power level of 3413 MWt. The core power assumed for SBLOCA with HHSI cross-ties closed is 3250 MWt, which forms the basis for TS 3.5.2, Action b. Due to the original requirements of 10 CFR 50, Appendix K, all analyses employ their respective nominal core powers plus an additional 2 percent calorimetric power measurement uncertainty. Consistent with the recent change to 10 CFR 50, Appendix K, I&M proposes to reduce the power measurement uncertainty to less than 2 percent for CNP Unit 2, thereby increasing the nominal operating core power from 3411 MWt to 3468 MWt and from 3250 MWt to 3304 MWt for SBLOCA with HHSI cross-ties closed. The LBLOCA and SBLOCA analyses are conservative with respect to this uprate. Thus, the MUR power uprate continues to be bounded by the LBLOCA and SBLOCA analyses. The TS 3.5.2, Action b, power restriction applicable to operation with the HHSI cross-ties closed can be increased 1.66 percent from 3250 MWt to 3304 MWt. The associated change to TS 3.5.2, Action b, is part of this submittal.

11.1.3 Post-Loss of Coolant Accident Analyses Post-LOCA analysis issues pertaining to long-term core cooling, core subcriticality, and core boron precipitation control were resolved as part of the CNP restart effort that concluded in December 2000. Extensive analyses were performed to support containment system modifications described in Reference 11.1.4. The TS changes supported by the Reference 11.1.4 analyses were approved by Unit 2 License Amendment No. 217 (Reference 11.1.5). Section 3.5 of Attachment 10 to Reference 11.1.4 documents a detailed discussion of the comprehensive analyses performed to address post-LOCA concerns. In order to provide a reasonable amount of time for performance of the hot leg switchover evolution (i.e., between 2.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months and 7.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months after the initiation of the LOCA), it was necessary to credit the negative reactivity associated to AEP:NRC:2902 Page 37 with control rod insertion. Additional analyses (Reference 11.1.6) demonstrating the acceptability of crediting control rod insertion were approved by the NRC in Unit 2 License Amendment No. 218, dated December 23, 1999 (Reference 11.1.7). These analyses, which form the basis for the hot leg switchover time stipulated in the CNP EOPs, are confirmed to remain valid and satisfied for each core reload design, and are not impacted by the 1.66 percent power uprate, as discussed in Section 11.1.3.2.

11.1.3.1 Post-Loss of Coolant Accident Long-Term Core Cooling The Westinghouse approach for satisfying the requirements of 10 CFR 50.46(b)(5), "Long-Term Cooling," concludes that the reactor will remain shut down by borated ECCS water residing in the RCS/recirculation sump following a LOCA. Since credit for the control rods is not taken in the short term for a LBLOCA, the borated ECCS water provided by the refueling water storage tank and accumulators must have a boron concentration that, when mixed with the other sources of water, will result in the reactor core remaining subcritical, assuming all control rods out.

However, control rod insertion is credited together with the available sources of boron to offset any potential effect of sump dilution during the cold leg injection recirculation cooling mode post-LBLOCA. The calculation is based upon the reactor steady-state conditions at the initiation of a LOCA and considers cases with borated and non-borated fluid in the post-LOCA recirculation sump. The other sources of water considered in the calculation of the recirculation sump boron concentration for CNP Unit 2 are the RCS, ECCS/RHR system piping, accumulators, ice bed mass, and BIT flow path. The water volumes and associated boric acid concentrations are not directly affected by the uprate. The core reload licensing process will confirm that there are no required changes to these volumes and boron concentrations. The current long-term core cooling analysis for CNP Unit 2 employs a nominal core power level of 3481 MWt. Also, consistent with the requirements outlined in 10 CFR 50, Appendix K, the heat generation rates from radioactive decay of fission products assumed in the LOCA Long Term Core Cooling analysis is 1.2 times the values for infinite operating time in ANS Standard 5.1, "Decay Energy Release Rates Following Shutdown of Uranium-Fueled Thermal Reactors," dated 1971 (Reference 11.1.8). Therefore, there is no impact on the LOCA Long Term Core Cooling analysis, and the 1.66 percent power uprate is bounded.

11.1.3.2 Hot Leg Switchover The licensing basis methodology employs a 2 percent calorimetric power uncertainty in accordance with the original requirements of 10 CFR 50, Appendix K. The current hot leg switchover analysis employs a nominal core power level of 3481 MWt. Therefore, a power increase to 3468 MWt has no impact on the hot leg switchover analysis and the 1.66 percent power uprate is bounded.

to AEP:NRC:2902 Page 38 11.1.4 Steam Generator Tube Rupture - Thermal-Hydraulic Analysis The analysis for the SGTR event, as documented in Section 14.2.4 of the Unit 2 UFSAR, is performed to demonstrate that the off-site radiological consequences remain below the guideline values. As input to the radiological consequences analysis, an SGTR T/H analysis is performed.

The T/H analysis calculates the primary-to-secondary break flow and steam released to the environment. The SGTR analysis for on-site radiological consequences was submitted for review by Reference 11.1.9, and is currently under NRC review. This not-yet-approved analysis demonstrates compliance with the regulatory dose rates. The SGTR T/- analysis considers core powers up to 3588 MWt. Therefore, the increase in core power to 3468 MWt is bounded by the analysis.

In addition to the SGTR analysis provided in the UFSAR, a supplemental SGTR analysis has been performed for Unit 2. The supplemental SGTR analysis provides a calculation of a more realistic response to an SGTR event by modeling operator actions and operator action times. The supplemental SGTR analysis is used to evaluate the margin to steam generator overfill and provides documentation to support the conclusion that the licensing basis SGTR T/H input into the radiological consequences is conservative. The NRC issued the SER approving the supplemental SGTR analysis for CNP Unit 2 via License Amendment No. 240, dated October 24, 2001 (Reference 11.1.10).

A nominal NSSS power for Unit 2 of 3600 MWt was used in the supplemental analysis.

Therefore, the increase in CNP Unit 2 core power to 3468 MWt has more than adequately been accounted for in the analysis. Note that the supplemental SGTR evaluation limits the CNP Unit 2 Tavg window to a minimum of 573.8 *F. This limitation continues to apply with the power uprating.

Therefore, the current analyses for the steam generator tube rupture event will bound the MUR Uprate Program.

References (Section II.1) 11.1.1. Updated Final Safety Analysis Report for CNP, Units 1 and 2, Version 17.2 11.1.2. Letter from J. F. Stang, NRC, to R. P. Powers, I&M, "Issuance of Amendments Donald C. Cook Nuclear Plant, Units 1 and 2 (TAC Nos. MA6473 and MA6474),"

dated December 23, 1999 11.1.3. WCAP-8708-P/A (Proprietary) and WCAP-8709-A (Non-Proprietary),

"MULTIFLEX, A Fortran-IV Computer Program for Analyzing Thermal Hydraulic Structure System Dynamics," dated September 1977 to AEP:INRC:2902 Page 39 II.1.4. Letter from R. P. Powers, I&M, to NRC Document Control Desk, "Donald C. Cook Nuclear Plant Units 1 and 2, Technical Specification Change Request Containment Recirculation Sump Water Inventory," C1099-08, dated October 1, 1999 11.1.5. Letter from J. F. Stang, NRC, to R. P. Powers, I&M, "Issuance of Amendments Donald C. Cook Nuclear Plant, Units 1 and 2 (TAC Nos. MA6766 and MA6767),"

dated December 13, 1999 11.1.6. Letter from R. P. Powers, I&M, to NRC Document Control Desk, "Donald C. Cook Nuclear Plant Units 1 and 2, License Amendment Request for Credit of Rod Cluster Control Assemblies for Cold Leg Large Break Loss-of-Coolant Accident Subcriticality," C0999-1 1, dated September 17, 1999 11.1.7. Letter from J. F. Stang, NRC, to R. P. Powers, I&M, "Issuance of Amendments Donald C. Cook Nuclear Plant, Units 1 and 2 (TAC Nos. MA6473 and MA6474),"

dated December 23, 1999 11.1.8. Proposed ANS Standards, "Decay Energy Release Rates Following Shutdown of Uranium-Fueled Thermal Reactors," approved by Subcommittee ANS-5, ANS Standards Committee, October 1971 11.1.9. Letter from R. P. Powers, I&M, to Nuclear Regulatory Commission, "Donald C. Cook Nuclear Plant Units 1 and 2 License Amendment Request for Control Room Habitability and Generic Letter 99-02 Requirements," C0600-13, dated June 12,2000 11.1.10. Letter from J. F. Stang, NRC, to R. P. Powers, I&M, "Donald C. Cook Nuclear Plant, Units 1 and 2 - Issuance of Amendments (TAC NOS. MB0739 and MB0740)," dated October 24, 2001 11.2 Containment Analyses 11.2.1 Feedwater and Steam Line Break Mass and Energy Releases The licensing basis safety analyses related to the feedwater and steam line break mass and energy releases were evaluated to determine the effect of a 1.66 percent power uprating. The evaluation determined that the NSSS design parameters, as shown in Table 3, "CNP Unit 2 MUR Uprate NSSS Design Parameters," remain unchanged or are bounded by the current safety analyses values.

to AEP:NRC:2902 Page 40 The evaluations performed include:

"* Short-Term Feedwater Line Break Mass and Energy Releases

"* Short-Term Steamline Break Mass and Energy Releases Inside Containment

"* Long-Term Steamline Break Mass and Energy Releases Inside Containment These evaluations also included the steam generator enclosure and fan/accumulator room subcompartment analyses and long-term containment analyses, which were demonstrated to be unaffected by the MUR Uprate Program.

11.2.2 Post-Loss of Coolant Accident Containment Hydrogen Generation The CNP post-LOCA containment hydrogen generation analysis of record bounds both units and is presented in Section 14.3.6 of the Unit 1 UFSAR. The analysis determined hydrogen generation rates using a core thermal power of 3411 MWt. Evaluations supporting a core thermal power of 3588 MWt (5 percent increase) have been performed. A core power increase of 5 percent also increases the calculated hydrogen produced by radiolysis in the core and sump by 5 percent.

However, this additional hydrogen production increases the total hydrogen produced from all sources by only 1 percent during the first 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , and by 2 percent at the end of 100 hours0.00116 days 0.0278 hours 1.653439e-4 weeks 3.805e-5 months . Based on these small increases in the hydrogen produced, and existing margin, it follows that -the post-LOCA containment hydrogen concentrations will remain below the lower flammability limit of 4.0 volume percent with the start of a recombiner at or before the time at which the containment hydrogen concentration reaches 3.5 volume percent.

The containment subcompartment hydrogen concentrations would be similarly affected by an increase in the core thermal power to 3588 MWt. The calculated subcompartment hydrogen concentrations have relatively large margin to the 4.0 volume percent lower flammability limit.

Specifically, the peak hydrogen concentrations are 2.5 volume percent for the LBLOCA scenario and 2.2 volume percent for the SBLOCA scenario. The additional hydrogen production due to an increased core power of 3588 MWt would increase the total hydrogen produced at the final analysis time (36,000 seconds, or approximately 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months for the LBLOCA and 50,000 seconds, or approximately 14 hours1.62037e-4 days 0.00389 hours 2.314815e-5 weeks 5.327e-6 months for the SBLOCA) by 1.6 percent. A 1.6 percent increase in the peak hydrogen concentrations of 2.2 and 2.5 volume percent is acceptable (i.e., remains below the 4.0 volume percent lower flammability limit). It is noteworthy that short-term peak subcompartment hydrogen concentration following a LBLOCA occurs at 3 minutes after initiation of the event.

An additional 5 percent hydrogen production from core and sump radiolysis at 3 minutes increases the total hydrogen volume released during the first 3 minutes by only 0.1 percent.

Thus, an increased core power level of 3588 MWt on the short term peak following a LBLOCA has an insignificant effect on the calculated subcompartment hydrogen concentration. Therefore, the current analyses and the evaluations described above for post-LOCA containment hydrogen generation bound the 1.66 percent power uprate.

to AEP:NRC:2902 Page 41 11.2.3 Loss of Coolant Accident Mass and Energy Releases 11.2.3.1 Long-Term Loss of Coolant Accident Mass and Energy Release Analysis The methodology for the most limiting LOCA mass and energy release calculation is contained in WCAP-10325-P-A (Reference 11.2.2) up to the point of steam generator depressurization/equilibration. After steam generator depressurization/equilibration, the mass and energy release available to containment is generated directly from core boil-off/decay heat.

The evaluations in WCAP-15302 (Reference 11.2.3) together with supplemental evaluations as approved by Unit 2 License Amendment No. 217 (Reference 11.2.1), together with supplemental evaluations incorporated into the CNP Unit 2 licensing basis via 10 CFR 50.59, constitute the current licensing basis containment analyses of record.

The current analyses of record was performed at an assumed core power level of 3481 MWt, which bounds both units. This core thermal power is based on 3413 MWt, plus an additional 2 percent power measurement uncertainty. The improved thermal power measurement accuracy obviates the need for a full 2 percent power margin assumed in the analysis and reduces it to approximately 0.3 percent. Therefore, the current licensing basis remains bounding for the long-term LOCA mass and energy release and long-term containment pressure analysis.

Therefore, the current licensing basis remains bounding for the 1.66 percent power uprate.

11.2.3.2 Short-Term Loss of Coolant Accident Mass and Energy Release Analyses The analyses are conducted in two phases. In the first phase, the mass and energy releases from the postulated break are determined prior to evaluating the containment response. In the second phase, the analyses involve evaluating the subcompartment containment response to the releases.

Since the critical portion of this event lasts for less than 3 seconds, the effect of reactor power is not significant. The analyses inputs having the potential to change due to the 1.66 percent power uprate are the initial RCS fluid tempratures.

The critical flow correlation used in the mass and energy releases for this analysis will provide an increase in the mass and energy release for a slightly lower fluid temperature. For the current analysis of record, an RCS hot leg (vessel outlet temperature) of 579.1°F, minus 5°F for uncertainty (574.1°F) and a cold leg (vessel/core inlet temperature) of 511.71F, minus 5°F, both conservatively bounded low for short-term considerations, were used. The MUR Uprate Program values of 581.9°F for the hot leg temperature and 513.3°F for the cold leg temperature are both bounded by the analysis of record. Therefore, the current licensing basis remains bounding for the short-term LOCA sub-compartment pressurization analysis.

to AEP:NRC:2902 Page 42 References (Section 11.2) 11.2.1. Letter from J. F. Stang, NRC, to R. P. Powers, I&M, "Issuance of Amendments Donald C. Cook Nuclear Plant, Units I and 2 (TAC Nos. MA6766 and M6767),"

dated December 13, 1999 11.2.2. WCAP-10325-P-A, "Westinghouse LOCA Mass and Energy Release Model for Containment Design March 1979 Version," dated May 1983 11.2.3. WCAP-15302, "Donald C. Cook Nuclear Plant Units 1 and 2, Modifications to the Containment Systems, Westinghouse Safety Evaluation (SECL 99-076, Revision 3),"

dated September 1999 11.2.4. Letter from Nuclear Regulatory Commission to Indiana and Michigan Electric Company, "Supplement 7 to Safety Evaluation Report," dated December 23, 1977 11.2.5. Safety Evaluation Report, "Safety Evaluation by the Directorate of Licensing U. S. Atomic Energy Commission in the Matter of Indiana & Michigan Electric Company and Indiana & Michigan Power Company Donald C. Cook Nuclear Plant Units 1 and 2, Docket Nos. 50-315 and 50-316," dated September 10, 1973 11.2.6. Letter from J. F. Stang, NRC, to M. P. Alexich, I&M, "Amendment No. 126 to Facility Operating License No. DPR-58 (TAC No. 71062)," dated June 9, 1989 11.2.7. Supplement to Safety Evaluation Report, "Supplement No. 3 to Safety Evaluation by the Directorate of Licensing U. S. Atomoic Energy Commission in the Matter of Indiana & Michigan Electric company and Indiana & Michigan Power Company Donald C. Cook Nuclear Plant Units 1 and 2, Docket Nos. 50-315 and 50-316," dated December 12, 1974 11.2.8. Letter from J. B. Hickman, NRC, to E. E. Fitzpatrick, I&M, "Donald C. Cook Nuclear Plant, Unit Nos. 1 and 2 - Issuance of Amendments Re: Increased Steam Generator Plugging Limit (TAC Nos. M92587 and M92588)," dated March 13, 1997 to AEP:NRC:2902 Page 43 11.3 Non-Loss of Coolant Accident Analyses This section addresses the potential effects of the MUR Uprate Program on the non-LOCA analyses presented in Chapter 14 of the UFSAR and analyses performed by I&M in response to regulatory requirements promulgated after the CNP Unit 2 OL was issued [i.e., ATWS (10 CFR 50.62) and SBO (10 CFR 50.63)].

The non-LOCA design-basis events are documented in Sections 14.1.1 through 14.1.12, 14.2.5, 14.2.6, and 14.2.8 of the CNP Unit 2 UFSAR. Of these events, none required re-analysis to demonstrate that the acceptance criteria will still be met at the 1.66 percent uprated power conditions. Evaluations of the remaining non-LOCA events demonstrated that the existing analyses bound plant operation at the proposed 1.66 percent uprated power conditions. The following discussions summarize the evaluations of this latter set of non-LOCA events.

Analyses that do not explicitly consider a 2 percent power uncertainty, such as those that use the RTDP methodology, were evaluated to determine the effect of the 1.66 percent power increase.

An evaluation was sufficient to determine that the effect the 1.66 percent power increase in nominal core power has on the following events is bounded by the current analyses:

"* RCCA Misalignment (UFSAR Section 14.1.3)

"* RCCA Drop (UFSAR Section 14.1.4)

The following events continue to be bounded by related events or are otherwise unaffected by the proposed uprating:

"* Uncontrolled RCCA Withdrawal from a Subcritical Condition (UFSAR Section 14.1.1)

"* Uncontrolled RCCA Withdrawal at Power (UFSAR Section 14.1.2)

"* CVCS Malfunction (UFSAR Section 14.1.5)

"* Loss of Reactor Coolant Flow (UFSAR Section 14.1.6.1)

"* Locked Rotor Accident - overpressure, maximum cladding temperature, and maximum zirconium-water reaction (UFSAR Section 14.1.6.2)

"* Locked Rotor Analysis - DNB case (UFSAR Section 14.1.6.2)

"* Loss of External Electrical Load - overpressure analysis (UFSAR Section 14.1.8)

"* Loss of Normal Feedwater Flow (UFSAR Section 14.1.9)

"* Excessive Heat Removal Due to Feedwater System Malfunctions - zero power-cases (UFSAR Section 14.1.10)

"* Excessive Load Increase Incident (UFSAR Section 14.1.11)

"* Loss of All AC Power to the Plant Auxiliaries (UFSAR Section 14.1.12)

"* Rupture of a Steam Pipe - core response analysis (UFSAR Section 14.2.5)

"* Rupture of a CRDM Housing (RCCA Ejection) - zero-power cases (UFSAR Section 14.2.6)

"* ATWS to AEP:NRC:2902 Page 44

"* SBO

"* Major Rupture of a Main Feedwater Pipe (Feedline Break) (UFSAR Section 14.2.8)

Evaluations of Non-LOCA Events As shown in' Table 11-1, the majority of the non-LOCA events applicable to CNP Unit 2 have been evaluated as being bounding in support of the 1.66 percent power uprate. The evaluations are discussed by individual event in this section. The following subsections provide the details of the evaluations completed for the individual events.

11.3.1 Rod Cluster Control Assembly Misalignment/Rod Cluster Control Assembly Drop (UFSAR Sections 14.1.3 and 14.1.4)

The RCCA misalignment analysis includes the following events:

"* One or more dropped RCCAs within the same group

"* A dropped RCCA bank

"* Statically misaligned RCCA The dropped RCCA transients (including the dropped RCCA bank) were previously analyzed using the methodology described in WCAP-1 1394-P-A, and were reviewed to demonstrate that the DNB design bases are met.

The methodology described in WCAP-1 1394-P-A involves the use of generic statepoints for the dropped rod event. Sensitivity studies on the effect of a power increase on the generic statepoints were previously performed for a 4-loop plant. The studies quantified the effect of an approximately 5 percent increase in power on the 4-loop generic statepoints, and found that the statepoints were still applicable for use at the uprated conditions. Since the MUR power uprate is much smaller than the uprate (approximately 5 percent) used in the sensitivity studies, the generic statepoints also continue to be applicable. An evaluation of the DNB design bases using the generic statepoints with the MUR power uprate conditions confirmed that the DNB design bases continues to be met.

Therefore, the conclusions presented in the UFSAR for the RCCA misalignment and dropped rod analyses remain valid for the MUR power uprate conditions.

11.3.2 Uncontrolled Rod Cluster Control Assembly Withdrawal from a Subcritical Condition (UFSAR Section 14.1.1)

By definition, since the uncontrolled RCCA withdrawal from a subcritical condition occurs from a subcritical core condition with the RCS at no-load temperature conditions, this event is not to AEP:NRC:2902 Page 45 affected by an increase in the reactor full power level and thus was not reanalyzed for the MUR power uprate program.

Since the power range neutron flux low setpoint of 35 percent (assumed in the analysis) will continue to be defined as 35 percent for the uprating, the power level (in MWt) at which the plant trips during the event could be slightly higher dependent upon the nominal reactor power level that is assumed in the analysis. However, because the nominal core heat flux assumed in the analysis is based on a reactor power of 3588 MWt, which is higher than the MUR uprate power, the power range neutron flux low setpoint assumed in the analysis of record remains valid. The existing statepoints for the RWFS event, including the nominal core heat flux, are based on a higher nominal core power than the MIUR uprate power and remain valid. The DNB statepoint evaluation also concluded that the DNB design bases calculations are performed at a nominal reactor power of 3588 MWt and bound the MUR power uprate conditions.

Therefore, the DNIB design bases are satisfied and the conclusions presented in the UFSAR for the uncontrolled RCCA withdrawal from a subcritical condition analysis remain valid for the MUR power uprate conditions.

11.3.3 Uncontrolled Rod Cluster Control Assembly Withdrawal at Power (UFSAR Section 14.1.2)

The uncontrolled RCCA bank withdrawal at power analysis models a wide range of reactivity insertion rates from various initial power levels. The nominal hot full power level assumed in the analysis is based on a nominal core power of 3588 MWt, which is higher than the MUR uprate power.

The reactor trip functions that are confirmed to provide adequate protection for this event (i.e.,

high neutron flux, OTAT, high pressurizer pressure) and calculations supporting the DNB design bases (including the core thermal limits) are based on an assumed core thermal power of 3588 MWt.

Since the uncontrolled RCCA bank withdrawal at power analysis and supporting DNB design bases calculations are performed at a power level higher than the MUR uprate power, the current analysis results bound the MUR power uprate conditions and remain valid for the MUR Uprate Program.

Therefore, the conclusions presented in the UFSAR for the uncontrolled RCCA bank withdrawal at-power analysis remain valid for the MUR power uprate conditions.

to AEP:NRC:2902 Page 46 11.3.4 Uncontrolled Boron Dilution (UFSAR Section 14.1.5)

An evaluation of the Mode 1 power operation analysis was performed to confirm that the automatic reactor trip time assumed in the analysis is not adversely impacted by the MUR power uprate conditions. With respect to the startup, shutdown, and refueling analyses (Modes 2 through 6), the time available to terminate the dilution event (operator action time) does not assume a time delay of automatic reactor trip since these analyses are not at power.

The assumed reactor trip time is based on an uncontrolled RCCA withdrawal at power analysis in which the reactivity insertion rate is equivalent to that expected for the Mode 1 boron dilution scenario. Since the uncontrolled RCCA bank withdrawal at power analysis and reactor trip functions are based on a nominal core power of 3588 MWt, which is higher than the MUR uprate power, the reactor trip times assumed for the boron dilution event are still valid and the results of the Mode 1 analysis remain valid.

Therefore, the conclusions presented in the UFSAR for the uncontrolled boron dilution analysis remain valid for the MUR power uprate conditions.

11.3.5 Loss of Reactor Coolant Flow (UFSAR Section 14.1.6.1)

Since an increase in core power could adversely affect the minimum DNBR, an evaluation was completed for this event. Because the power level assumed in the analysis of record is based on a nominal reactor power of 3588 MWt, which is higher than the MUR uprate power, the evaluation concluded that the existing statepoints for the limiting complete loss of flow event remain valid.

The DNB statepoint evaluation also concluded that the DNB design bases calculations are performed at a nominal reactor power of 3588 MWt and bound the MUR power uprate conditions.

Therefore, the conclusions presented in the UFSAR for the loss of forced reactor coolant flow analyses remain valid for the MUR power uprate conditions.

11.3.6 Locked Rotor Accident (UFSAR Section 14.1.6.2)

Since the power level assumed in the analysis of record is based on a nominal reactor power of 3588 MWt, which is higher than the MUR uprate power, the evaluation concluded that the cases performed to confirm the RCS pressure, clad temperature, and zirconium-water reaction criteria remain bounding and the existing statepoints for the limiting rods-in-DNB case continue to be valid at the MUR power uprate conditions.

to AEP:NRC:2902 Page 47 The DNB statepoint analysis, which was previously based on a nominal reactor power of 3588 MWt and available DNB margin, concluded that the DNB design bases calculations continue to bound the MUR power uprate conditions. Therefore, it was confirmed that there continues to be no rods-in-DNB, hence, not exceeding the zero percent rods-in-DNB limit.

The conclusions presented in the UFSAR for the locked rotor analysis remain valid for the MUR power uprate conditions.

11.3.7 Loss of External Electrical Load or Turbine Trip (U-FSAR Section 14.1.8)

The current loss of load analysis assumes a nominal core thermal power of 3588 MWt, which is higher than the MUR uprate power.

The reactor trip functions that are confirmed to provide adequate protection for this event and the calculations supporting the DNB design bases (including the core thermal limits) are based on an assumed core thermal power of 3588 MWt.

Therefore, since the loss of external electrical load analysis and supporting DNB design bases calculations are performed at a power level higher than the MUR uprate power, the current analysis results bound the MUR power uprate conditions and remain valid for the MUR Uprate Program.

11.3.8 Loss of Normal Feedwater Flow and Loss of Offsite Power to Station Auxiliaries (UFSAR Sections 14.1.9 and 14.1.12)

The loss of normal feedwater and loss of offsite power to station auxiliaries analyses are performed assuming a nominal core power of 3588 MWt, which is higher than the MUR uprate power. Since the loss of normal feedwater and loss of offsite power to station auxiliaries analyses are performed at a power level higher than the MUR uprate power, the current analysis results bound the MUR power uprate conditions and remain valid for the MUR power uprate program.

Therefore, the conclusions presented in the UFSAR for the loss of normal feedwater and loss of offsite power to station auxiliaries analyses remain valid for the MUR power uprate conditions.

11.3.9 Excessive Heat Removal Due to Feedwater System Malfunctions (UFSAR Section 14.1.10)

An increase in feedwater flow can be caused by a failure in the feedwater control system that leads to the simultaneous full opening of the feedwater control valves. With the plant at zero-power conditions, the addition of relatively cold feedwater may cause a decrease in primary-side temperature, and therefore, a reactivity insertion due to the effects of the negative MTC.

to AEP:NRC:2902 Page 48 Transients initiated by increases in feedwater flow are attenuated by the thermal capacity of the primary and secondary sides. If the increase in reactor power is large enough, the primary RPS trip functions (e.g., high neutron flux, OTAT, OPAT) will prevent any power increase that can lead to a DNIBR less than the safety analysis limit value. The RPS trip functions may not actuate, if the increase in power is not large enough.

The feedwater system malfunction that causes a reduction in feedwater temperature continues to be bounded by the excessive increase in secondary steam flow event and was not re-analyzed for the MUR Uprate Program.

The maximum feedwater flow to one or more steam generators due to a control system malfunction that causes the feedwater control valves to fail in the full-open position is analyzed to address both HFP and HZP conditions. The conditions assumed in the current analysis of record are based on a nominal core power of 3588 MWt, which is higher than the MUR uprate power.

The primary reactor trip functions assumed for this event (i.e., high neutron flux, OTAT, OPAT) and calculations supporting the DNB design bases (including the core thermal limits) are based on an assumed core thermal power of 3588 MWt.

Therefore, since the analysis and supporting DNB design bases calculations are performed at a power level higher than the MUR uprate power, the current analysis of record results bound the MUR power uprate conditions and remain valid for the MUR Uprate Program.

11.3.10 Excessive Load Increase Incident (UFSAR Section 14.1.11)

This transient is defined as a rapid increase in the steam flow that causes a power mismatch between the reactor core power and the steam generator load demand. Cases are evaluated at beginning-of-life and end-of-life conditions, with and without rod control, to demonstrate that the DNB design bases are met. The transient response to this accident is relatively mild, such that the reactor stabilizes at a new equilibrium condition corresponding to conditions well above that which would challenge the DNBR limit, without generating a reactor trip.

The excessive load increase incident was analyzed assuming a core thermal power of 3588 MWt, which is greater than the MUR uprate power. Therefore the current analysis results bound the MUR power uprate conditions and remain valid for the MLUR Uprate Program.

11.3.11 Rupture of a Steam Pipe - Core Response Analysis (UFSAR Section 14.2.5)

The postulated rupture of a steam pipe is analyzed at HZP conditions to demonstrate that any return to power resulting from the uncontrolled steam release does not result in a violation of the DNB design basis. Because the rupture of a steam pipe is analyzed at shutdown conditions, the to AEP:NRC:2902 Page 49 increase in nominal core power does not impact this analysis. Furthermore, since the analysis assumes HZP conditions consistent with a nominal core thermal power of 3588 MWt, which is higher than the MUR uprate power, any return to power condition at the MUR power uprate conditions will continue to be bounded by the current analysis of record. Therefore, the current licensing basis remains bounding for the 1.66 percent power uprate.

11.3.12 Rupture of a Control Rod Drive Mechanism Housing (Rod Cluster Control Assembly Ejection) (UFSAR Section 14.2.6)

Rupture of a CRDM housing is the result of a mechanical failure of a CRDM pressure housing, such that the RCS pressure would eject the control rod and drive shaft to the fully-withdrawn position. The transient responses for the hypothetical RCCA ejection event are analyzed at beginning and end-of-life, for both HFP and HZP power operation, in order to bound the entire fuel cycle and expected operating conditions. The analyses are performed to show that the fuel and cladding limits are not exceeded. Since this study is not performed to evaluate the minimum DNBR, the RTDP methodology is not utilized as the limiting fuel rod is conservatively assumed to undergo DNB very early in the transient, thus maximizing fuel temperature response.

Since the rupture of a CRDM housing analyses are performed assuming a core thermal power of 3588 MWt, which is greater than the MUR uprate power, the current analysis results are not impacted by the MUR power uprate conditions.

11.3.13 Anticipated Transients Without Scram For Westinghouse-designed PWRs, the licensing requirements pertaining to ATWS are those specified in 10 CFR 50.62, "Requirements for Reduction of Risk from Anticipated Transients Without Scram (ATWS) Events for Light-Water-Cooled Nuclear Power Plants." The requirement set forth in 10 CFR 50.62(c) is that all Westinghouse-designed PWRs must install AMSAC. In compliance with 10 CFR 50.62(c), AMSAC has been installed and implemented at CNP Unit 2.

As documented in SECY-83-293 (Reference 11.3.2), the analytical bases for the final ATWS rule are the generic ATWS analyses for Westinghouse PWRs generated by Westinghouse in 1979.

These generic ATWS analyses were formally transmitted to the NRC via letter NS-TMA-2182 (Reference 11.3.4) and were performed based on the guidelines provided in NUREG-0460 (Reference 11.3.3).

In the generic ATWS analyses documented in NS-TMA-2182, ATWS analyses were performed for the various ANS Condition II events (i.e., Anticipated Transients) considering various Westinghouse PWR configurations applicable at that time. These analyses included 2, 3, and 4-Loop PWRs with various steam generator models. The generic ATWS analyses documented in NS-TMA-2182 also support the analytical basis for the NRC-approved generic AMSAC to AEP:NRC:2902 Page 50 designs generated for the WOG as documented in WCAP-10858-P-A, Revision 1. For the purpose of these AMSAC designs, the generic ATWS analyses for the 4-Loop PWR configuration with Model 51 steam generators were used to conservatively represent all of the various Westinghouse PWR configurations contained in NS-TMA-2182. For CNP Unit 2, WCAP-10858-P-A AMSAC Logic 2, AMSAC Actuation on Low Main Feedwater Flow, has been employed.

The generic ATWS analyses applicable to CNP Unit 2 are provided for a four-loop PWR with Model 51 steam generators modeling an NSSS power of 3423 MWt (3411 MWt core power).

These conditions are summarized in Table 3-1-a of NS-TMA-2182. For this plant configuration, the peak RCS pressure reported in NS-TMA-2182 for the limiting loss-of-load ATWS event is 2974 psia resulting in 226 psi margin to the peak RCS limit of 3200 psia.

The combined effect of the higher reactor power (+46 psi) for the MUR, additional available pressurizer PORV (-166 psi), and a reduced AFWS capacity (+40 psi) for CNP Unit 2 at the MUR uprate conditions result in an overall peak RCS pressure benefit of 80 psi relative to the peak RCS pressure of 2974 psia reported in the generic ATWS analysis. This results in a net peak RCS pressure of 2894 psia (i.e., 2974 psia - 80 psi), or a margin to the ATWS peak RCS pressure limit of 3200 psia of 306 psi (i.e., 3200 psia- 2894 psia).

As prescribed by NUREG-0460, the 1979 generic ATWS analyses for Westinghouse PWRs documented in NS-TMA-2182 assumes a full power MTC of-8 pcm/°F. A sensitivity analysis including the use of an MTC of-7 pcm/°F was also provided as prescribed by NUREG-0460. At that time, the MTC values of-7 pcrnI/F and -8 pcm/°F represented MTCs that were bounding for Westinghouse PWRs over 99 percent and 95 percent of the cycle, respectively. The base case of 95 percent represents a 95 percent confidence interval on favorable MTC for the fuel cycle. CNP Unit 2 currently operates with a more negative MTC at beginning of life than that assumed in the 1979 generic analysis. For CNP Unit 2, the maximum beginning of life MTC is approximately

-11 pcm/°F (based upon the cycle 13 core analysis). Therefore, the MTC assumption in the generic analysis remains bounding for CNP Unit 2. Although this is for a specific cycle, similar MTC behavior is expected from cycle to cycle. Additionally, based upon sensitivities documented in letters NS-EPR-2833 and NS-TMA-2182, the MTC would have to increase by approximately 6.4 pcmr0 F in order for the peak pressure to approach the limit (based upon 306 psi available margin for CNP Unit 2 and the fact that the 1979 generic analysis (peak pressure of 2974 psia) modeled an MTC of-8 pcm/°F). Thus, smaller cycle-to-cycle variations from the -11 pcm/°F MTC will not result in a violation of the peak pressure limit.

Based on the above, it is concluded that operation of CNP Unit 2 MUR power uprate remains within the bounds of the generic Westinghouse ATWS analysis documented in NS-TMA-2182 and, therefore, will remain in compliance with the final ATWS rule, 10 CFR 50.62(c).

to AEP:NRC:2902 Page 51 11.3.14 Station Blackout A review was performed to determine if the current licensing basis for an SBO event remains bounding for the MUR Uprate Program.

The condensate inventory required for decay heat removal is bounded by the original 102 percent analysis. There are no changes to DC-powered components or inverter-fed AC-powered components; therefore, the Class 1E battery capacity is not impacted. No changes to the instrument air system or components fed by instrument air are associated with this 1.66 percent power uprate.

The main steam temperature remains the same and no other new heat loads are added; therefore, there is no impact on the loss of ventilation in the dominant areas of concern. The 1.66 percent power uprate will not impact the current containment isolation evaluations. Finally, the 1.66 percent power uprate will not impact the three areas of concern in the RCS inventory evaluations:

RCP seal leak rates, the normal TS leak rates from the RCS, or letdown isolation capabilities. The ability of CNP Unit 2 to respond to an SBO event will not be impacted by the Unit 2 MUR Uprate Program. Therefore, the components required to cope with the SBO will not be impacted by the 1.66 percent power uprate, and the current licensing basis remains bounding for the MUR Uprate Program.

11.3.15 Major Rupture of a Main Feedwater Pipe (Feedline Break) (UFSAR Section 14.2.8)

A major feedwater line rupture is defined as a break in a feedwater line large enough to prevent the addition of sufficient feedwater to the steam generators to maintain shell side fluid inventory in the steam generators. If the break is postulated in a feedwater line between the check valve and the steam generator, fluid from the steam generator may also be discharged through the break. Further, a break in this location could preclude the subsequent addition of emergency feedwater to the affected steam generator. A break upstream of the feedwater line check valve would affect the NSSS only as a loss of normal feedwater, as discussed in Section 11.3.8 above.

Depending upon the size of the break and the plant operating conditions at the time of the break, the break could cause either an RCS cooldown (by excessive energy discharge through the break) or an RCS heatup. Potential RCS cooldown resulting from a secondary pipe rupture is evaluated in the steamline break event that bounds these cooldown effects. Therefore, only the RCS heatup effects are evaluated for a feedwater line rupture.

The major rupture of a main feedwater pipe analysis is performed assuming a nominal core power of 3588 MWt, which is higher than the MUR uprate power. Since the major rupture of a main feedwater pipe analysis is performed at a power level higher than the MUR uprate power, the current analysis results bound the MUR power uprate conditions and remain valid for the MUR Uprate Program.

to AEP:NRC:2902 Page 52 Therefore, the conclusions presented in the UFSAR for the major rupture of a main feedwater pipe analysis remain valid for the MUR power uprate conditions.

11.3.16 Flooding Protection from flooding is afforded by features of CNP Unit 2 that are not affected by the changes associated with the 1.66 percent power uprate. These features include: the physical relationship between the plant grade and lake elevation, condenser circulating water pump and piping location, the ESW pump and piping location, and site building construction.

In addition, the 1.66 percent power uprate does not affect the features associated with leakage detection and isolation, or the frequency of natural events such as seiche. No piping configuration or pump modifications for the CNP Unit 2 water systems are necessitated by the 1.66 percent power uprate. Therefore, the leakage conditions with the maximum flood potential (i.e., pipe break with pump runout) for the high volume water systems (essential and non-essential service water, circulating water, component cooling water, fire protection water, etc.) are not impacted by the proposed power uprate. Therefore, the changes associated with the MUR Uprate Program do not impact flooding.

References (Section 11.3) 11.3.1. WCAP-11394-P-A, "Methodology for the Analysis of the Dropped Rod Event,"

dated January 1990 11.3.2. SECY-83-293, "Amendments to 10 CFR 50 Related to Anticipated Transients Without Scram (ATWS) Events," W. J. Dircks, dated July 19, 1983 11.3.3. NUREG-0460, "Anticipated Transients Without Scram for Light-Water Reactors,"

dated December 1978 11.3.4. Letter from T. M. Anderson, Westinghouse, to S. H. Hanauer, NRC, "ATWS Submittal," submittal number NS-TMA-2182, dated December 30, 1979 11.4 Design Transients 11.4.1 Nuclear Steam Supply System Design Transients The basis for the NSSS design transient definitions is the analytical work performed for the CNP Unit 1 and Unit 2 3600 MWt Rerating, and was documented in WCAP-12135, Appendix III (Reference 11.4.6). This work, which is referred to as the Rerating Program, was done in support of WCAP-1 1902, including Supplement 1 (References 11.4.1 and 11.4.2). The Rerating Program to AEP:NRC:2902 Page 53 analytical work was submitted to the NRC in conjunction with a fuel change via Reference 11.4.3, and approved in an SER dated August 27, 1990 (Reference 11.4.4).

A comparison of the plant operating conditions used in the Rerating Program against the operating conditions for the MUR Uprate Program is shown in Table 11-2.

Table 11-2 Comparison of Unit 2 MUR Power Uprate Conditions to Values Used in Design Basis DesignTransients Unit 2 MUR Power Uprate Rerating Program Program (from Table 3) (References 11.4.2 and 11.4.6)

Parameter High T.,9 Low Tav, High TaV Low Tag NSSS Thermal Power, MWt 3494 3494 3600 3600 RCS Flow, gpm/loop 88,500 88,500 88,500 88,500 RCS pressure, psia 2250/ 2100 2250 /2100 2250/ 2000 2250 /2000 Tto, OF 611.2 581.9 616.9 582.3 T5 v2, OF 578.1 547.6 583.1*** 547.0 Tcold, 'F (SG outlet) 544.7 513.0 549.3 511.7 Tstnam, °F

520.6 487.4 521.0 481.8 Psteam, psia

817 607 819.7 575.8 Feedwater Temperature, 'F ** 444.6 444.6 435 435

Unit 2 Uprating values for limiting 10 percent steam generator tube plugging condition; Rerating Program values for 15 percent steam generator tube plugging condition.

- - 435'F is listed in table at beginning of the design transient description in Reference 11.4.2, but a review of the analyses and the transient figures indicate 440'F was used.

- - - Higher Tavg value used than the high-end of TV, window for the Rerate Program, which was 581.3 0 F.

The following can be noted from Table 11-2:

" The maximum Thot, minimum TCold, and minimum Tam bound the values for the MUR Uprate Program.

"* The RCS pressure values considered (2000 and 2250 psia) bound the values for the MUR Uprate Program.

"* The 3600 MWt power level result in more severe transient parameter variations than is the case for the MUR Uprate Program.

to AEP:NRC:2902 Page 54 The MUR Uprate Program for Unit 2 has a higher feedwater temperature (by 9.6 0 F) than the 435'F design value and higher feedwater temperature (by 4.6'F) than the value of 440'F actually used in the design transient analyses. This higher feedwater temperature for the MUR Uprate Program would result in a larger temperature variation during any of the design transients.

Based upon this comparison, the existing design transients remain bounding and applicable for the Unit 2 MUR Uprate Program except for the feedwater temperature transients. Therefore, all design transients showing a feedwater temperature change were revised for the MUR Uprate Program. These revised design transients were then used as input for component and system evaluations. No other design transient changes were made.

The design limit for the primary to secondary pressure differential is 1600 psid and is discussed in Section VI4.

11.4.2 Auxiliary Equipment Design Transients The review of the NSSS auxiliary equipment design transients was based on a comparison between the NSSS design parameters for the MUR Uprate Program described in Table 3 and the NSSS design parameters that make up the current auxiliary equipment design transients.

An evaluation of the current design transients was performed to determine which transients could be potentially impacted by the MUR Uprate Program. The evaluation concluded that the only design transients that could be potentially impacted by power uprate are those temperature transients impacted by full-load RCS design temperatures.

These temperature transients are defined by the differences between the temperature of the coolant in the RCS loops and the temperature of the coolant in the auxiliary systems connected to the RCS loops. The greater the temperature difference, the greater the impact these temperature transients have on auxiliary component design and fatigue evaluation processes.

The current design temperature transients are based on a full-load Thot of 630'F and a full-load TCold of 560'F. These full-load temperatures were assumed for equipment design to ensure that the temperature transients would be conservative for a wide range of NSSS design parameters.

A comparison of the range of NSSS design temperatures for the MUR Uprate Program at full-load, that is Thot (581.9 - 611.2'F) and TCOld (vessel inlet temperature of 513.5'F - 545.0°F) with the T,,t and Tro~a values used to develop the current design transients, indicates that the MUR Uprate Program temperature ranges are lower as was specified in the operating conditions for the MIUR Uprate Program. These lower full-load operating temperatures result in less severe to AEP:NRC:2902 Page 55 transients, since the temperature differences between RCS loop temperatures and the lower operating temperatures in the auxiliary systems connected to the RCS are less.

The only auxiliary equipment transients that can be potentially impacted by power uprate are those temperature transients related to full-load NSSS design temperatures. A review of these temperature transients indicates that, if these transients were based on the MUR Uprate Program design parameters, they would be less severe. Therefore, the current auxiliary equipment design transients for CNP Unit 2 remain bounding for the MUR Uprate Program.

References (Section 11.4) 11.4.1. WCAP-1 1902, "Reduced Temperature and Pressure Operation for Donald C. Cook Nuclear Plant Unit 1 Licensing Report," dated October 1988 11.4.2. WCAP-1 1902, Supplement 1, "Rerated Power and Revised Temperature and Pressure Operation for Donald C. Cook Nuclear Plant Units 1 and 2 Licensing Report," dated September 1989 11.4.3. Letter from M. P. Alexich, I&M, to T. E. Murley, NRC, "Unit No. 2 Cycle 8 Reload Licensing, Proposed Technical Specifications for Unit 2 Cycle 8, and Related Unit 1 Proposals," AEP:NRC: 1071 E, dated February 6, 1990 11.4.4. Letter from T. G. Colburn, NRC, to M. P. Alexich, I&M, "Amendment No. 148 and 134 to Facility Operating License Nos. DPR-58 and DPR-74: (TAC Nos. 75395, 75396 and 76816)," dated August 27, 1990 11.4.5. WCAP-15608, Rev. 1, "D. C. Cook Unit 1 Replacement Steam Generator Safety Analysis Program Engineering Report," dated March 2001 11.4.6. WCAP-12135, "Donald C. Cook Units 1 and 2 Rerating Engineering Report," dated September 1989, Appendix III, "Cook Nuclear Plant Units 1 and 2 Rerating NSSS Design Transients" 11.4.7. WCAP-14285, "Donald C. Cook Nuclear Power Plant Unit 1 Steam Generator Tube Plugging Program Licensing Report," dated May 1995 11.4.8. Letter from J. B. Hickman, NRC, to E. E. Fitzpatrick, I&M, "Donald C. Cook Nuclear Plant, Unit Nos. 1 and 2 Issuance of Amendments Re: Increased Steam Generator Plugging Limit (TAC Nos. M92587 AND M92588)," dated March 13, 1997 to AEP:NRC:2902 Page 56 III. Accidents and Transients for which the Existing Analyses of Record do not Bound Plant Operation at the Proposed Uprated Power Level There are no accidents and transients requiring re-analysis for which existing analyses of record do not bound plant operation at the proposed uprated power level.

IV. Mechanical/Structural/Material Component Integrity and Design IV.1 Reactor Vessel Structural Evaluation The CNP Unit 2 reactor vessel was evaluated for impact due to the MUR Uprate Program. There is no change to any of the design inputs that were previously considered in the reactor vessel evaluations for the Rerating Program (WCAP-11902, Supplement 1 [Reference IV.1.1]).

Therefore, the MUR Uprate Program has no effect on the results in the CNP Unit 2 reactor vessel analytical report.

Results of the reactor vessel head penetration examinations performed during the CNP Unit 2 Cycle 13 refueling outage do not impact the reactor vessel structural evaluations that were conducted for this MUR Uprate Program. In accordance with NRC Bulletin 2001-01, "Circumferential Cracking of Reactor Pressure Vessel Head Penetration Nozzles," 'these examination results were submitted to the NRC by Reference IV. 1.2. The CNP Unit 2 reactor vessel continues to satisfy the applicable requirements of Section III (Nuclear Vessels) of the ASME Boiler and Pressure Vessel Code, 1968 Edition through the Summer 1968 Addenda, in accordance with the reactor vessel design requirements.

IV. 1.1 Reactor Vessel Integrity - Neutron Irradiation Reactor vessel integrity is affected by any changes in plant parameters that affect neutron fluence levels or temperature/pressure transients. The neutron fluence projections resulting from the CNP Unit 2 MUR Uprate Program have been evaluated to determine the potential effect on reactor vessel integrity. Typically, such an evaluation is performed by direct comparison of the neutron fluence projections from the analyses of record to the uprated neutron fluence projections. However, prior to the Unit 2 MUR Uprate Program, Westinghouse revised the current reactor vessel integrity analyses of record for CNP Unit 2. These revisions were done to update fluence methodology, to account for the use of "Calculated" fluence projections (as opposed to "Best Estimate" fluences), and to increase the applicability limits of the pressure temperature (P-T) limit curves. I&M submitted these revised Unit 2 P-T limit curves to the NRC in a letter dated July 23, 2002 (Reference IV.1.3). The updated reactor vessel integrity evaluations used neutron fluence projections that correspond to 3800 MWt, and thus bound the MUR power uprate.

to AEP:NRC:2902 Page 57 Thus, the Unit 2 reactor vessel integrity evaluation for the MUR Uprate Program consists of replacing the current licensing basis analyses of record with updated analyses that have been submitted. More specifically, that includes the following evaluations:

"* Assessment of the new reactor vessel surveillance capsule removal schedule to confirm it is based on vessel fluence projections that bound the MUR Uprate Program.

"* Assessment of the new P-T limit curves to confirm they are based on vessel fluence projections that bound the MUR Uprate Program.

" Review of the existing RTprs values to determine if the effects of the uprated fluence projections result in an increase in RTprs for the beltline materials in the CNP Unit 2 reactor vessel at the end of license (EOL, 32 EFPY).

"* Review the USE values at EOL for all reactor vessel beltline materials in the CNP Unit 2 reactor vessel to assess the impact of the uprated fluence projections.

The calculated fluences used in the MUR Uprate Program evaluation comply with RG 1.190 (Reference IV.l .4). As these calculations are performed on a plant-by-plant basis, there is no generic topical for approved method - the methodology used is that of RG 1.190.

It is concluded that the MUR Uprate Program for CNP Unit 2 will not have a significant effect on the reactor vessel integrity.

IV. 1.2 Reactor Internals The reactor internals support the fuel and control rod assemblies, absorb control rod assembly dynamic loads, and transmit these and other loads to the reactor vessel. The internals also direct flow through the fuel assemblies, provide adequate cooling to various internals structures, and support in-core instrumentation. The changes in the RCS temperatures produce changes in the boundary conditions experienced by the reactor internals components. Also, increases in core power may increase nuclear heating rates in the lower core plate, upper core plate, and baffle-barrel former region. This section describes the analyses performed to demonstrate that the reactor intemals can perform their intended design functions at the 1.66 percent power uprate conditions.

IV.1.2.1 Thermal-Hydraulic Systems Evaluations A key area in the evaluation of core performance is the determination of the hydraulic behavior of the coolant flow and its effect within the reactor internals system. The core bypass flow is defined as the total amount of reactor coolant flow which bypasses the core region, and is not considered effective in the core heat transfer process. Consequently, the effect of increasing core to AEP:NRC:2902 Page 58 bypass flow is a reduction in core power capability. The RCCA scram time is affected by the flow and temperature conditions. The hydraulic lift forces are critical in the assessment of the structural integrity of the reactor internals and hold-down spring functionality. Baffle plate gap momentum flux and fuel stability is affected by pressure differences between the core and baffle former region.

The results of these evaluations are discussed below.

Core Bypass Flow Calculation Bypass flow is the total amount of reactor coolant flow bypassing the core region. The principal core bypass flows are the barrel-baffle region, vessel head spray nozzles, vessel outlet nozzle gap, baffle plate core cavity gap, and the fuel assembly thimble tubes.

The design core bypass flow limit is 7.1 percent of the total reactor vessel flow. The effect of the MUR Uprate Program has an insignificant effect on the core bypass flow. Therefore, the current total design core bypass flow value of 7.1 percent remains bounding.

RCCA Drop Time An evaluation was performed to demonstrate that the RCCA drop time is still within the current value of 2.7 seconds (required by the TS) for the revised design conditions. The revised design conditions for the RCCA drop time consist of the core power and the core inlet temperature (ToId). The core power increased due to the 1.66 percent power uprate from 3411 MWt to 3468 MWt. The lowest core inlet temperature has remained unchanged at 513.3°F for the uprate condition. The effect of the increase in core power increased RCCA drop time less than 0.01 seconds. This change is considered negligible and the RCCA drop time will still be less than the TS limit of 2.7 seconds.

Hydraulic Lift Forces and Pressure Losses The reactor internals hold-down spring is essentially a large Belleville-type spring of rectangular cross section. The purpose of this spring is to maintain a net clamping force between the reactor vessel head flange and the upper internals flange and the reactor vessel shell flange and the core barrel flange of the internals. An evaluation was performed to determine the hydraulic lift forces on the various reactor internal components to ensure that the reactor intemals assembly would remain seated and stable for all conditions. The results indicate that the downward force remains essentially unchanged, indicating that the reactor internals would remain seated and stable for the 1.66 percent power uprate conditions.

to AEP:NRC:2902 Page 59 Baffle Joint Momentum Flux and Fuel Rod Stability Baffle jetting is a hydraulically-induced instability or vibration of fuel rods caused by a high velocity jet of water. This jet is created by high-pressure water being forced through gaps between the baffle plates that surround the core. The baffle jetting phenomenon could lead to fuel cladding damage.

A number of experimental tests have been performed to study the interaction between baffle joint jetting and the response of the fuel rod. These tests indicated that there are two vibration levels that can result in fuel rod damage. Lower levels of vibration amplitude can inflict damage in the form of vibration wear at the rod/grid interface. Large amplitude vibration (whirling), caused by fluid elastic instability, can result in fuel rod damage due to cladding fatigue failure, rod-to-rod contact, or even rod-to-baffle plate wall contact.

In order to guard against fuel rod failures from flow-induced vibration, the cross-flow emanating from baffle joint gaps must be limited to a specific momentum flux, V2h; that is, the product of the gap width, h, and the square of the baffle joint jet velocity, V2 . This momentum flux varies from point to point along the baffle plate due to changes in pressure differential across the plate and the local gap width variations. In addition, the modal response of the vibrating fuel rod must be considered. That is, a large value of local momentum flux impinging near a grid is much less effective in causing vibration than the same V2h impinging near the mid-span of a fuel rod.

Baffle joint momentum flux is dependent upon the pressure differential across the baffle plate, the baffle-to-baffle gap width, and the modal response of the fuel assembly. Any increase in baffle joint momentum flux would require an increase in at least one of these.

The pressure differential across the baffle plate remains unchanged due to the 1.66 percent power uprate, likewise the baffle gap width and fuel assembly modal response. Therefore, the baffle joint momentum flux will not change as a result of the 1.66 percent power uprate.

IV. 1.2.2 Mechanical Evaluations The 1.66 percent power uprate conditions do not affect the current design bases for seismic and LOCA loads. Therefore, it was not necessary to re-evaluate the structural effects from the seismic operating basis earthquake and safe-shutdown earthquake loads and the LOCA hydraulic and dynamic loads.

With regards to flow-induced vibration, the lowest vessel/core inlet coolant temperature remains unchanged. The corresponding vessel outlet coolant temperature increases 1.30F. This temperature change causes a change in water density that has a negligible impact on the vibratory response of the reactor internals. The design power capability parameters for the current design basis and the MUR uprate essentially remain the same. Therefore, it is reasonable to conclude to AEP:NRC:2902 Page 60 that there is no significant impact on the performance of the reactor internals with regard to flow-induced vibration.

IV.1.2.3 Structural Evaluations Evaluations were performed to demonstrate that the structural integrity of the reactor components is not adversely affected by the 1.66 percent power uprate conditions. The presence of heat generated in reactor internal components, along with the various fluid temperatures, results in thermal gradients within and between components. These thermal gradients result in thermal stresses and thermal growth, which must be accounted for in the design and analysis of various components.

The core support structure components affected by the MUR Uprate Program are discussed below. The primary inputs to the evaluations are the revised RCS temperatures (as indicated in Table 3) and the gamma heating rates. The gamma heating rates take into account the 1.66 percent increase in core power.

The reactor internal components subjected to heat generation effects (either directly or indirectly) are the upper core plate, the lower core plate, and the baffle-barrel region. For all of the reactor internal components, except the lower core plate and the upper core plate, the stresses and cumulative fatigue usage factors were unaffected by the 1.66 percent uprate conditions, because the previous analyses remain bounding.

Lower Core Plate Structural Analysis The lower core plate is a perforated circular plate that supports and positions the fuel assemblies. The plate contains numerous holes to allow fluid flow through the plate. The fluid flow is provided to each fuel assembly and the baffle-barrel region.

Due to the lower core plate's proximity to the core, it is subjected to the effects of heat generation. The heat generation rates in the lower core plate due to gamma heating can cause a significant temperature increase in this component. A structural evaluation was performed to demonstrate that the structural integrity of the lower core plate is not adversely affected by the revised design conditions. The cumulative fatigue usage factor of the lower core plate, including the effects of the increase in the heat generation rates, is small (0.237), and the lower core plate is structurally adequate for the 1.66 percent power uprate conditions.

Baffle-Barrel Region Evaluations The baffle-barrel regions consist of a core barrel into which baffle plates are installed. They are supported by bolting interconnecting former plates to the baffle and core barrel.

to AEP:NRC:2902 Page 61 The baffle-to-former bolts restrain the motion of the baffle plates that surround the core.

These bolts are subjected to primary loads consisting of deadweight, hydraulic pressure differentials, LOCA and seismic loads, as well as secondary loads consisting of preload and thermal loads resulting from RCS temperatures and gamma heating rates. The baffle-to-former bolt thermal loads are induced by differences in the average metal temperature between the core barrel and baffle plate. In addition to providing structural restraint, the baffles also channel and direct coolant flow such that a coolable core geometry can be maintained.

The thermally induced displacements of the baffle-former bolts for the 1.66 percent power uprate relative to the original design conditions were calculated for a bounding range of conditions. The results demonstrated that the 1.66 percent power uprate conditions have smaller thermally-induced bolt displacement than the original design conditions. Therefore, the baffle-barrel region thermal and structural analysis results are still bounding for the revised design conditions associated with the MUR Uprate Program.

Upper Core Plate Structural Analysis The upper core plate positions the upper ends of the fuel assemblies and the lower ends of the control rod guide tubes. It serves as the transitioning -member for the control rods for entry into and retraction from the fuel assemblies. It also controls coolant flow in its exit from the fuel assemblies and serves as a boundary between the core and the exit plenum. The upper core plate is restrained from vertical movement by the upper support columns, which are attached to the upper support plate assembly. The lateral movement is restrained by four equally-spaced core plate alignment pins.

The maximum stress contributor in the upper core plate is the membrane stress resulting from the average temperature difference between the center portion of the upper core plate and the rim. The increased stress from the increased gamma heating was determined as a function of the heat generation rate increment. The fluid temperature effect due to the 1.66 percent power uprate is small. The results show that the structural integrity of the upper core plate is maintained for the 1.66 percent power uprate conditions. The cumulative fatigue usage factor of the upper core plate caused by the increase in the heat generation rates remains less than unity and the plate is structurally adequate for the 1.66 percent power uprate conditions.

References (Section IV. 1)

IV.1.1. WCAP-1 1902, Supplement 1, "Rerated Power and Revised Temperature and Pressure Operation for Donald C. Cook Nuclear Power Plant Units 1 and 2 Licensing Report,"

dated September 1989 to AEP:NRC:2902 Page 62 IV.1.2. Letter from M. W. Rencheck, I&M, to NRC Document Control Desk, "Donald C. Cook Nuclear Plant Unit 2 Additional Information Requested by Nuclear Regulatory Commission Bulletin 2001-01 (TAC Nos. MB2624 and MB2625),"

AEP:NRC:2054, dated March 28, 2002 IV.1.3. Letter from J. E. Pollock, I&M, to NRC Document Control Desk, "Donald C. Cook Nuclear Plant, Unit 2 Docket No. 50-316 License Amendment Request for Unit 2 Reactor Coolant System Pressure-Temperature Curves, and Request for Exemption from Requirements in 10 CFR 50.60(a) and 10 CFR 50, Appendix G,"

AEP:NRC:2349-01, dated July 23, 2002 IV.1.4. Regulatory Guide 1.190, "Calculational and Dosimetry Methods for Determining Pressure Vessel Neutron Fluence," dated March 2001 IV.2 Piping and Supports IV.2.1 Nuclear Steam Supply System Piping Parameters associated with the MUR Uprate Program were reviewed for impact on the existing analyses of the RCL piping and the pressurizer surge line including the effects of thermal stratification.

The MUR Uprate Program NSSS performance parameters (discussed in the "Introduction" Section, including Table 3) are bounded by the NSSS performance parameters from WCAP-1 1902, including Supplement 1 (Reference IV.2.1), and the existing design basis piping analyses are still applicable for the MUR Uprate Program. The equipment nozzle and support loads, and the piping stresses are not affected by the MUR Uprate Program.

The existing RCL LOCA analysis and RCL analysis with compartment pressures due to the main steam and feedwater breaks are not affected by the MUR Uprate Program because of the following:

"* LOCA hydraulic forcing functions are unchanged as discusssed in Section IIl..1.

"* Steam generator secondary side steam pressure and feedwater pressure for the MUR Uprate Program are bounded by the pressures used in the existing piping analyses.

Therefore, the jet forces due to a main steam or feedwater nozzle break from the existing analysis are still applicable.

"* Compartment pressures and mass and energy releases are not affected by the MUR Uprate Program (as discussed in Section 11.2).

to AEP:NRC:2902 Page 63 Since the existing piping analysis is still applicable, there are no changes in the steam generator or RCL displacements, or the primary equipment nozzle and support loads due to the MUR Uprate Program.

The operating temperature window of the RCL due to the MUR Uprate Program is bounded by the existing operating temperature window. With the continued applicability of the existing design transients, the impact of the MUR Uprate Program on the NRC Bulletin 88-08 evaluation of the auxiliary spray piping and NRC Bulletin 88-11 evaluation of the pressurizer surge line piping is judged as insignificant.

Hence, with the continued applicability of the design transients and the insignificant changes due to the thermal analysis, the impact of the MUR Uprate Program on the Auxiliary Class 1 branch nozzle displacements from the deadweight, thermal, seismic, and LOCA analyses is negligible.

IV.2.2 Reactor Coolant Loop Support System The steam generator, reactor coolant pump, reactor vessel, and pressurizer supports have been qualified for piping and component loads resulting from the restart efforts. Since the MUR Uprate Program does not change the loads exerted upon the support structures, the supports will continue to be qualified for the 1.66 percent power uprate condition.

IV.2.3 Leak-Before-Break Analysis By References IV.2.2 and IV.2.4, the NRC approved CNP's use of the LBB methodology. The LBB analyses justified the elimination of large primary loop pipe rupture and pressurizer surge line pipe rupture from the structural design basis for CNP Unit 2. To demonstrate the continued acceptability of the elimination of RCS primary loop pipe rupture and pressurizer surge line pipe rupture from the structural design basis for the MUR Uprate Program, the following objectives must be achieved:

"* Demonstrate that margin exists between the "critical" crack size and a postulated crack that yields a detectable leak rate.

"* Demonstrate that there is sufficient margin between the leakage through a postulated crack and the leak detection capability.

"* Demonstrate margin on applied load.

"* Demonstrate that fatigue crack growth is negligible.

These objectives were met by the analyses discussed in References IV.2.2, IV.2.3 and IV.2.4.

to AEP:NRC:2902 Page 64 There is no change in loads on the primary loop piping due to the uprating parameters. The effect of material properties due to the changes in temperature will have a negligible impact on the existing LBB analysis margins. Additionally, there is no significant impact on loads in the pressurizer surge line LBB analysis due to the MUR Uprate Program.

Therefore, the existing LBB analyses conclusions that were approved by References IV.2.2 and IV.2.4 remain applicable for the Unit 2 MUR Uprate Program.

References (Section IV.2)

IV.2.1. WCAP-11902, "Reduced Temperature and Pressure Operation for Donald C. Cook Nuclear Plant Unit 1 Licensing Report," October 1988 and WCAP-11902, Supplement 1, "Rerated Power and Revised Temperature and Pressure Operation for Donald C. Cook Nuclear Power Plant Units 1 and 2 Licensing Report," dated September 1989 IV.2.2. Letter from J. F. Stang, NRC, to R. P. Powers, I&M, "Donald C. Cook Nuclear Plant, Units 1 and 2 - Review of Leak-Before-Break for the Pressurizer Surge Line Piping as Provided by 10 CFR Part 50, Appendix A, GDC 4 (TAC Nos. MA7834 and MA7835)," dated November 8, 2000 IV.2.3. Letter from M. W. Rencheck, I&M, to Nuclear Regulatory Commission, "Donald C. Cook Nuclear Plant Units 1 and 2 - Request to Apply Leak Before Break (LBB) Methodology to the Pressurizer Surge Line," C0800-04, dated August 22, 2000 IV.2.4. Letter from J. F. Stang, NRC, to R. P. Powers, I&M, "Issuance of Amendments Donald C. Cook Nuclear Plant, Units 1 and 2 (TAC Nos. MA6473 and MA6474),"

dated December 23, 1999 IV.3 Control Rod Drive Mechanisms The CRDMs are subjected to hot leg temperatures and RCS pressures. There is no change to the maximum operating reactor coolant pressure of 2250 psia (which bounds operation at 2100 psia).

These are the only NSSS design parameters considered in the CRDM evaluation.

Higher temperatures are more limiting for the CRDM structural design qualification because it results in a decrease in the margin to the allowable design stress limits. The maximum Thot from the MUR Uprate Program NSSS design parameters (Table 3) for any case is 611.2°F.

Furthermore, the possible RCS operating pressure values continue to remain at either 2100 psia or 2250 psia for the MUR Uprate Program.

to AEP:NRC:2902 Page 65 The Model L-106A full length CRDMs were evaluated in the Rerating Program (Reference IV.3.1 and IV.3.2) for 618'F, which is higher than the 611.2°F associated with the MUR Uprate Program. Therefore, the evaluations performed for the full length CRDMs in the Rerating Program are bounding and applicable to the MUR Uprate Program.

References (Section IV.3)

IV.3.1. WCAP-1 1902, "Reduced Temperature and Pressure Operation for Donald C. Cook Nuclear Plant Unit 1 Licensing Report," dated October 1988 IV.3.2. WCAP-1 1902, Supplement 1, "Rerated Power and Revised Temperature and Pressure Operation for Donald C. Cook Nuclear Plant Units I and 2 Licensing Report," dated September 1989 IV.4 Reactor Coolant Pumps and Motors The RCPs and RCP motors were evaluated to determine the impact of the revised RCS conditions to demonstrate that the RCP structural integrity is not adversely affected.

Reactor Coolant Pump The RCPs are located between the steam generator outlet and reactor vessel inlet in the RCL.

The maximum vessel inlet (RCP outlet) temperature is 545.0°F for the MUR Uprate Program conditions, as shown in Table 3. This temperature is lower than the vessel inlet temperature of 547°F used in the rerate program evaluations (References IV.4.1 and IV.4.2). Higher temperatures are more limiting for the RCP structural design; therefore, this represents a less limiting condition.

The revised pressure changes and temperature changes are less than those previously evaluated and are bounded for the MUR Uprate Program.

Reactor Coolant Pump Motor The limiting design parameter for the RCP motor is the horsepower loading at continuous hot and cold operation. The new hot load of 6458 hp for the revised operating conditions was evaluated, as it exceeds the 6000 hp nameplate rating, and found to be acceptable. The new cold load of 8057 hp for the revised operating conditions was also evaluated, as it exceeds the 7500 hp cold loop nameplate rating, and found to be acceptable. The starting temperature rise for the rotor cage winding was calculated for starting the motor under cold loop conditions with 80 percent voltage and reverse flow due to the other RCPs running at full speed. The results show that the temperatures of the rotor bars and the resistance rings will reach 230.8°C and to AEP:NRC:2902 Page 66 38.82°C, respectively. These temperatures do not exceed the design limits of 300'C for the bars and 50'C for the resistance rings. Therefore, the motor can safely start and accelerate under the worst case conditions associated with the uprating. The loads on the motor thrust bearings were also determined for the uprated conditions and determined to be acceptable. The existing analyses and evaluations of the RCP flywheels are dependent upon several parameters, none of which are impacted by the MUR Uprate Program. Based upon the evaluations of the RCP motors as described above, the motors are acceptable for the MUR Uprate Program conditions.

References (Section IV.4)

IV.4.1. WCAP- 11902, "Reduced Temperature and Pressure Operation for Donald C. Cook Nuclear Plant Unit 1 Licensing Report," dated October 1988 IV.4.2. WCAP-1 1902, Supplement 1, "Rerated Power and Revised Temperature and Pressure Operation for Donald C. Cook Nuclear Power Plant Units 1 and 2 Licensing Report,"

dated September 1989 IV.5 Steam Generators Evaluations of the thermal-hydraulic performance, structural integrity, and steam generator tube wear have been performed to address operation at the MUR Uprate Program conditions. It is noted that in 1988 the original Westinghouse Model 51 steam generators were modified. The lower assembly, including the tube bundle, was replaced with those of a Model 54F design while the upper shell and internals remained the original Model 51 design with upgraded internals. As a result, the steam generators are sometimes referred to as Model 51 and other times as Model 54F. Therefore, to avoid confusion, the CNP Unit 2 steam generators will be referred to as the RSGs in this section of the report.

IV.5.1 Thermal-Hydraulic Evaluation The thermal-hydraulic evaluation of the RSGs focused on the changes to secondary-side operating characteristics at the MUR Uprate Program conditions. The operating parameters at these conditions are shown in Table 3. This evaluation considered four uprated power plant operating cases, two with steam generator inlet temperatures of 611.20 and two with an inlet temperature of 581.9 0 F. SGTP levels of 0 percent and 10 percent were considered for both temperatures. A constant feedwater temperature of 444.6'F was used for all four uprated power cases.

The steam generator performance code GENF was used to calculate the secondary side operating characteristics. The three-dimensional flow field analysis code ATHOS was used to assess the DNB transition on the tube wall. To serve as a reference for acceptable generator to AEP:NRC:2902 Page 67 thermal-hydraulic performance, operating characteristics for the four current operating condition cases at an RCS pressure of 2250 psi were calculated. These cases are referred to as Cases 1 to 4.

Note that the applicable parameters that effect steam generator thermal-hydraulic performance (e.g., Thot, TCOmd, and Tsteam) are essentially the same for both the 2250 psi and the 2100 psi approved plant operating conditions. As such, Cases 1 to 4 represent both 2250 psi and 2100 psi RCS pressure operation.

In addition to the current plant operating condition Cases 1 to 4, the operating parameters used previously as the basis for the RSG Stress Report were also analyzed. This Stress Report design base case is designated as Case 0. The four cases at the MUR Uprate Program conditions are designated as Cases 5 to 8, respectively.

Acceptable steam generator performance is demonstrated by: (1) no excessive moisture carryover; (2) no hydrodynamic instability; and (3) no local dryout on tube walls. These criteria are satisfied at the uprated power conditions as demonstrated by a comparison of the secondary side characteristics at the previously-accepted 100 percent power conditions (base case) and at the proposed MIUR Uprate Program conditions stated above. These results are the basis for the MUR Uprate Program evluations.

Bundle Mixture Flow Rate The product of the steam flow rate and circulation ratio, which equals the bundle mixture flow rate, remains essentially the same after the 1.66 percent power uprate. Therefore, it was concluded that the proposed uprate has essentially no effect on the mixture flow in the tube bundle.

Steam Pressure Comparing the corresponding cases with respect to Th0 t and SGTP, the MUR Uprate Program has a small effect on the steam pressure. Steam pressure is affected by the level of tube plugging, and more so by a reduction in primary coolant temperatures. Operating at the low Tavg of 547.6°F, with 10 percent tube plugging, the steam pressure is reduced from the base case of 820.8 psia to approximately 610 psia. The minimum allowable steam pressure, based on the steam generator design specification, is 679 psia. This indicates that for operation at 102 percent power, when SGTP approaches 10 percent, it may be necessary to restrict Tavg to higher values. However, the RSGs are currently at 0.1 percent tubes plugged; therefore, the current configuration bounds the MUR Uprate Program.

Heat Flux Average heat flux is inversely proportional to the heat transfer area in service, and increases proportionally with the MUR Uprate Program. A measure of the margin for DNB transition to AEP:NRC:2902 Page 68 in the bundle is the ratio of the local quality (X) to the estimated quality at DNB transition, or (X/Xab). A ratio of unity at a location in the bundle implies that DNB transition would occur at that location. Three-dimensional flow field analyses were performed for the secondary side of the steam generator. The analyses determined that sufficent margin remains for the MUR Uprate Program.

Moisture Carryover CNP Unit 2 has the Westinghouse Model 51 moisture separator design with modifications for improved moisture separation performance as part of the RSGs. Specified steam generator performance criteria limit MCO to 0.25 percent for these generators. MCO tests were performed in operating plants with this separator package. The test data have been extensively analyzed and correlated with a Separator Parameter, which is a function of the steam flow rate and steam pressure.

At the uprated conditions, with high Tavg, the resulting steam pressure is high, and the predicted MCO is well below the 0.25 percent limit. For the worst case with the uprate (lowest steam pressure, or the highest Separator Parameter value), the projected mean MCO is 0.103 percent, but the upper bound 90 percent confidence value at that operating condition is 0.376 percent. That is, there is only a 10 percent probability that the moisture carryover might be as high as 0.376 percent, when the steam pressure at the uprating is below 800 psia.

Since water erosion downstream of the steam generator is not a concern at a MCO level below 0.5 percent, the present upper bound MCO performance prediction for the MUR Uprate Program is acceptable.

Other Secondary-Side Parameters The secondary-side pressure drop, liquid mass, and steam mass show only minor variations between the 100 percent power conditions and the MUR Uprate Program conditions. The damping factor, a measure of the hydrodynamic stability of the steam generator, remains a large negative number. A negative value of this parameter indicates a stable unit. That is, a small perturbation of the steam pressure or circulation ratio will dissipate rather than grow in amplitude. A larger negative value implies more stable operation. The proposed MUR Uprate Program would have a small effect on these secondary-side parameters.

Thermal-Hydraulic Conclusions This evaluation of the RSGs considered operation at both 100 percent and 102 percent power levels, with SGTP of 0 percent and 10 percent and a Tav. range of 547.6'F to 578.1'F. It was concluded that all thermal-hydraulic performance parameters will remain acceptable for the MUR Uprate Program. It was noted that the potential exists for steam pressure to fall below the minimum value (679 psia) during operation at uprated power, when SGTP approaches to AEP:NRC:2902 Page 69 10 percent at the low Tag conditions. If SGTP approaches this level, it will be necessary to verify actual steam pressure, and reconsider the Tavg conditions for full power operation.

Additional analyses may be needed to address the potential for reduced steam pressure.

However, the RSGs currently have a low percent of tubes plugged; therefore, the current configuration bounds the MUR Uprate Program.

IV.5.2 Structural Integrity Evaluation The structural evaluation focused on the critical steam generator components as determined by the stress ratios and fatigue usage. The following discussions address the evaluations of the primary side and secondary side components. Comparisons of previous CNP uprate reports were performed to determine if the results from these reports enveloped the proposed MUR Uprate Program. The proposed plant operating parameters for this uprating are shown on Table 3.

The evaluations discussed in the paragraphs below were performed to confirm the acceptability of the critical primary and secondary side components when subjected to the uprated operation conditions defined by the NSSS design parameters in Table 3, and the applicable design transients discussed in Section II.

Input Parameters and Assumptions The RSGs have been previously evaluated for operation at increased power levels. The first evaluation was performed as a part of a plant Rerating Program that took place in 1989. At that time, the steam generators were evaluated for both 3425 MWt and 3600 MWt NSSS power operating conditions. This program included an increase in the operating primary temperature range, plant operation at NSSS pressures of 2000 psia and 2250 psia, and (SGTP) of up to 15 percent.

In 1995, a 3600 MWt uprating program was performed for CNP Unit 2. As part of this 1995 effort, certain steam generator design transients were revised to account for a +/-3 percent pressurizer safety valve setpoint tolerance. Other operating parameters were already enveloped by the work done for the previous rerating analysis.

The MUR Uprate Program parameters (Table 3) are enveloped by the conditions previously addressed in the aforementioned uprating programs. The applicable design transient set for the MUR Uprate Program is discussed in Section II of this attachment. For the majority of the design transients, the design transient set considered for the 1989 rerating program remained applicable since the maximum Thot, minimum TCO.d, and minimum steam temperature considered for that program bound the values for the MUR Uprate Program. For the pressurizer pressure and the RCS pressure response for the loss of load and loss of power, the 3600 MWt uprating program revised these curves to reflect a 3 percent pressurizer safety valve tolerance. It was also noted that a higher feedwater temperature is specified for the to AEP:NRC:2902 Page 70 rerating program as compared to the MUR Uprate Program; however, the feedwater temperature considered for the 3600 MWt program still envelopes that of the MUR Uprate Program. On this basis, the analyses conducted to support the rerating, as supplemented by the consideration of the 3 percent pressurizer safety valve tolerance in the 3600 MWt uprating program, bound the MUR Uprate Program.

Structural Integrity Conclusions A review of the revised temperature parameters in Table 3 showed that the changes in the plant operating parameters are very small and are enveloped by the stress analysis of record.

No changes resulting from the MUR Uprate Program were made to the design transients, other than providing new feedwater temperature versus time curves to replace those considered for the rerating evaluation. The feedwater temperature specified was 449°F, which is more conservative than the 444.6°F for the MUR Uprate Program. Therefore, the transients specified in power rerate reports are still applicable. For this reason, it was concluded that the revised parameters would not have any impact on the steam generator stress analysis and fatigue analysis.

It is concluded that the steam generator components meet the stress/fatigue analysis requirements of the ASME Boiler and Pressure Vessel Code,Section III, 1968 Edition, through Winter 1968 Addenda 'for the plant operation at the MUR Uprate Program conditions. The primary to secondary pressure differential remains below the design value of 1600 psid. For operations at 2250 psia, the primary to secondary pressure differential remains below the design value of 1600 psid, provided the secondary side steam pressure is limited to 679 psia or higher.

The CNP Unit 2 MUR Uprate Program analyzed conditions with the secondary side steam pressure as low as 607 psia. A subset of the activities I&M will perform as part of the design change to install and implement the LEFM CheckPlus system includes procedure revisions that address impacts. The 679 psia full-power steam pressure limitation for operation with reactor coolant pressure controlled to 2250 psia will be included in CNP Engineering Control Procedure ECP-2-05-01, "Precautions, Limitations, and Setpoints - Unit 2" and in the UFSAR as part of the LEFM CheckPlus system design change package. Once it is incorporated into the UFSAR and the Precautions, Limitations, and Setpoints documents, future plant changes will be required to consider this limitation.

IV.5.3 Evaluation of Mechanical Repair Hardware The RSGs entered service in 1989. During the fabrication on one of the steam generators, two Westinghouse shop-welded plugs were installed. These components were re-evaluated for the operating conditions and transients associated with a 2 percent uprate. In anticipation of future to AEP:NRC:2902 Page 71 tube plugging needs, both "long" and "short" 7/8-inch ribbed mechanical plugs were also qualified for installation in the RSGs.

Mechanical Plugs The enveloping condition for the Westinghouse mechanical plug (Alloy 690 shell material) results in the largest pressure differential between the primary and the secondary sides of the steam generators. Both the NSSS design parameter changes and the NSSS design transients were used to determine the effect of the MUR Uprate Program on the mechanical plugs. The most critical set of parameters for the mechanical plug evaluation is based on the primary side hydrostatic pressure test, in which the pressure differential across the plug is 3107 psid, independent of power uprate.

The critical parameter for the design of mechanical plugs is the primary-to-secondary differential pressure. This evaluation was based on a primary design pressure of 2500 psia, which is equivalent to a conservative design pressure differential across the mechanical plug of 2485 psi.

Note that the maximum design primary-to-secondary differential is 1600 psi.

All stress/allowable ratios were found to be less than unity, indicating that all primary stress limits are satisfied for the plug shell wall between the top land and the plug end cap. The plug meets the Class 1 fatigue exemption requirements per N-415.1 of the ASME Code (Reference IV.5.2). It was also determined that adequate preload and friction are available to prevent dislodging of the plug for the limiting steady-state and transient loads.

Since this is a hardware item that maybe installed in the steam generator after initial operation, and it was not part of the original steam generator, these plugs are typically fabricated to the requirements of the 1989 ASME Code Edition (Reference IV.5.3). As such, an evaluation was conducted based on the 1989 code year requirements. It was determined that the mechanical plug is also acceptable for use at the MUR Power Uprate Program conditions based on the 1989 ASME Code edition.

Results of the analyses performed for the mechanical plug for CNP Unit 2 show that both the long and short mechanical plug designs satisfy all applicable stress and retention acceptance criteria for the MUR Power Uprate Program.

Shop Weld Plugs A structural evaluation of the Westinghouse shop weld plugs was performed to update the design basis analysis to reflect the operating conditions and transients that are applicable for plant operation at the MUR conditions. The evaluation was performed to the applicable requirements of ASME Boiler and Pressure Vessel Code (Reference IV.5.2). The Westinghouse shop weld plugs that were installed during generator fabrication were evaluated for the effects of transient to AEP:NRC:2902 Page 72 changes that will result from the proposed MIvR Uprate Program. The primary stresses due to design, normal, upset, and test conditions must remain within the respective ASME Code allowable values (Reference IV.5.2).

The evaluation of the weld plug first addressed the design condition. A vertical failure plane around the perimeter of the weld plug at the minimum throat was considered in the stress calculation. The specified design condition pressure differential of 1600 psi between the generator primary-to-secondary side was applied to the plug.

Limiting test conditions for the Primary Hydrostatic and Secondary Hydrostatic tests were evaluated. Values for primary stresses, primary stresses plus secondary stresses, and primary-to-secondary stress range intensities were calculated. All stress values were found to be acceptable.

For the normal/upset load conditions the controlling transient was the "Loss of Load" transient, for which the differential pressure is 1691 psid. It was determined that with the 1691 psid limiting normal/upset differential pressure, the stress limits were still satisfied.

The last step.in the evaluation process was a review for fatigue concerns. The approach used was to investigate if the weld plug would satisfy the ASME requirements for fatigue exemption. The six required fatigue exemption conditions were found to be satisfied. Therefore, , it was concluded that the welded plug does meet the ASME Code cycle load fatigue limits for the MUR Uprate Program.

All primary stresses are satisfied for the weld between the weld plug and the tube sheet cladding.

The primary plus secondary stresses for the enveloping transient case of "Loss of Load" was found acceptable. The maximum primary plus secondary stress intensity was found to be acceptable. The fatigue evaluation for the weld plug utilized the ASME fatigue exemption rules (Reference IV.5.2). It was found that the fatigue exemption rules were met, and therefore, fatigue conditions are acceptable.

IV.5.4 Steam Generator Tube Integrity The original CNP Unit 2 steam generators used Alloy 600 mill-annealed tubing, partial depth mechanical roll expansion, drilled tube holes and separate drilled flow holes, and carbon steel tube support plates. The original CNP Unit 2 steam generators experienced ODSCC in the tube to-tubesheet crevice, denting at the top of tubesheet region with PWSCC in this area, and ODSCC at tube support plate intersections.

Currently, Unit 2 operates with RSGs. The RSGs have 3592 Alloy 690 thermally treated tubes.

The tube-to-tubesheet gap is closed by a hydraulic expansion process. The tube support plates are constructed of 405 stainless steel, with quatrefoil design tube holes. The quatrefoil tube hole to AEP:NRC:2902 Page 73 design allows for bulk fluid flow axially along the tube, and thus, no interstitial flow holes are required. The Row 1 U-bend minimum bend radius is 3.141 inches, which is greater than the original steam generator Row I U-bend minimum bend radius of 2.19 inches. The larger bend radius reduces residual stresses due to fabrication. Additionally, the first nine rows of tubes received a supplemental thermal treatment of the U-bend region following bending. This thermal treatment was intended to reduce the residual stresses from bending to near straight leg residual stress levels.

Tube Vibration and Wear The impact of the MUR Uprate Program on the steam generator tubes was evaluated based on the current design basis analysis and included the changes in the thermal-hydraulic characteristics of the secondary-side of the steam generator resulting from the uprate. The effects of these changes on the fluidelastic instability ratio and amplitudes of tube vibration due to both vortex shedding and turbulence were addressed. In addition, the potential effect of the 1.66 percent power uprate on future tube wear was considered.

The analysis of the RSGs indicates that significant levels of tube vibration will not occur from the fluidelastic, vortex shedding, or turbulent mechanisms as a result of the proposed 1.66 percent power uprate. The projected level' of tube wear as a result of vibration would be expected to remain small, and would not result in unacceptable wear.

The original RSG vibration analysis, performed in 1988, demonstrated that the maximum fluidelastic stability ratio for the expected tube support conditions (i.e. all anti-vibration bars active) was less than the allowable limit of 1.0. The original tube vibration analysis also determined that negligible tube responses occurred due to the vortex shedding mechanism. The amplitudes of vibration due to turbulence were also found to be reasonably small with maximum displacements found to be on the order of a few mils (5.6 mils). The maximum expected tube wear that could occur over the remaining period of operation was found to range from approximately 3 to 6 mils depending upon actual fit up, length of operation and actual operating conditions.

The results of the vibration and wear analysis were modified to account for anticipated changes in secondary side operating conditions due to the 1.66 percent power uprate. For the expected support conditions (i.e. all tube support plates, both with and without the flow distribution baffle, active) it was found that straight leg stability ratios were not significantly impacted. The uprating scaling factor calculated for the straight leg region was 1.005 (a 0.5 percent increase).

However the stability ratios for U-bend conditions increased from approximately 0.3 to 0.41, which are still less than the allowable limit of 1.0. As a result, the analysis indicated that large amplitudes of vibration are not projected to occur due to the fluidelastic mechanism while operating the steam generator in at the MUR Power Uprate Program condition.

to AEP:NRC:2902 Page 74 The maximum displacement values for turbulence excitation calculated in the original analysis were modified to account for uprate induced changes in the operating conditions. For the most limiting tube support condition it was determined that the turbulence-induced displacement could increase from approximately 6 mils to approximately 10 mils. Displacements of this magnitude are not sufficient to produce tube-to-tube contact. However, the potential for tube wear must be considered. As in the original analysis the vortex shedding mechanism was found not to be a significant contributor to tube vibration.

The potential for tube wear was addressed in the original analysis that evaluated wear in both the straight leg and U-bend portions of the steam generator. These calculations were updated to reflect operation of the steam generators for the MUR Power Uprate Project with NSSS power output of 3494 MWt. The calculation for the uprated conditions determined that the level of tube wear that could occur would increase from approximately 3 mils to 5.5 mils at the uprated conditions. From these calculations it can be concluded that although there may be an increase in the level of wear that would occur at the uprated operating conditions, this increase would not be significant. Any increase in the rate of tube wear would progress over many cycles and would be observable during normal eddy current inspections.

Loose Part Analysis/Degraded Tube Analysis During recent foreign object search and retrieval activities, various foreign objects were retrieved from inside two Unit 2 steam generators. An evaluation determined the acceptability of leaving several unretrievable objects inside the steam generators during future operation. With changes to the steam generator operation due to a power uprate, it is possible that sufficiently large differences will occur such that the previous justification of leaving the loose object inside the steam generator may have been affected. The evaluation for the MUR operating conditions is discussed below.

In addition to the foreign objects, during pressure pulse cleaning operations that were performed in 1994, it was determined that the suction return nozzles impacted certain tubes during the cleaning process. As a result of these impacts, several tubes were found to have degraded zones where the nozzle impacted the tubes. An analysis was performed shortly after the event that determined that stabilization of these tubes was not required and plugging only would be sufficient. However, since CNP Unit 2 will be operated at an uprated condition, it is necessary to determine if the revised secondary side operating conditions would affect the previous justification not to stabilize the affected tubes. The evaluation for the MUR operating conditions is discussed below.

The loose parts analysis has determined that the earlier justification permitting operation with the previously-identified loose object present inside the steam generator will not be impacted with operation of the steam generator at the MUR Uprate Program conditions. In addition, these calculations have determined that the power uprate will not affect the stabilization to AEP:NRC:2902 Page 75 recommendation made in 1994 to address the tubes affected by the pressure pulse cleaning suction return nozzle. As a result, it can be concluded that the tubes affected by the pressure pulse cleaning suction return nozzle will not have to be stabilized.

Other Potential Modes of Degradation The RG 1.121 analysis, which is discussed in more detail in Section IV.5.5, establishes the limiting safe condition of degradation in the tubes beyond which tubes found defective by the established in-service inspection shall be removed from service. The allowable tube repair limit includes an allowance for degradation growth until the next scheduled inspection. The RG 1.121 analysis performed for the proposed 1.66 percent uprate of CNP Unit 2 considered parameter ranges that bound the 1.66 percent uprate conditions (see Section IV.5.5, Table IV-1). Thus, the effects of the 1.66 percent uprate on steam generator tube degradation modes, such as axial or circumferential cracking, have been incorporated into the tube structural limits determined in accordance with RG 1.121.

CNP Unit 2 steam generators are designed and analyzed for a range of parameters and power levels that bound the conditions applicable to the proposed 1.66 percent uprate. Specifically, parameters representative of an uprated power condition (i.e., 3600 MWt NSSS power condition) have been considered in the structural integrity evaluation, as discussed in Section IV.5.2 of to this, letter. Therefore, the proposed 1.66 percent power uprate of CNP Unit 2 remains bounded by the current structural design analyses and no new modes of steam generator tube degradation are introduced.

Steam Generator Tube Integrity Conclusions Based on the design features inherent to the RSGs, accumulated EFPY since replacement, and operating temperature following uprating, no appreciable number of steam generator tubes are expected to require plugging within the current CNP Unit 2 license period. Maintenance of secondary side water chemistry within guidelines established by the EPRI Secondary Water Chemistry Guidelines should further reduce the potential for SCC mechanisms to affect steam generator operability.

Previously reported tube support plate wear indications did not change over the last operating cycle and no anti-vibration bar wear has been reported to date. An evaluation of the CNP Unit 2 RSGs indicates that significant levels of tube vibration will not occur from either the fluidelastic, vortex shedding or turbulent mechanisms as a result of the MUR Uprate Program. The projected level of tube wear as a result of vibration is expected to remain small. Operating history from similar replacement steam generators indicates extremely low growth rates for these wear mechanisms. On the basis of the historical evidence, coupled with an ongoing steam generator tube inspection plan, it is concluded that steam generator tube wear is not expected to jeopardize tube integrity when operating at the MUR Uprate Program conditions.

to AEP:NRC:2902 Page 76 Steam Generator Tube Inspection Frequency Steam generator tube inspections will be conducted at a frequency that is the more restrictive of either TS 3/4.4.5, "Reactor Coolant System, Steam Generators," or EPRI publication TR-107569-V1R5, "PWR Steam Generator Examination Guidelines," (Reference IV.5.4). I&M adopted EPRI publication TR-107569-V1R5 in accordance with the implementation guidance of NEI 97-06, "Steam Generator Program Guideline," (Reference IV.5.5). An increase in inspection frequency in terms of the number of steam generators inspected and the sample size of tubes inspected depends on the progression (if any) of degradation. None of the potential degradation mechanisms are significantly affected by the 1.66 percent power uprate conditions; therefore, the required frequency of inspection is also not affected significantly by the proposed Unit 2 MUR power uprate.

IV.5.5 Regulatory Guide 1.121 Analysis The heat transfer area of steam generators comprises over 50 percent of the total primary system pressure boundary. The steam generator tubing, therefore, represents a primary barrier against the release of radioactivity to the environment. For this reason, conservative design criteria have been established for the maintenance of tube structural integrity under the postulated design-basis accident condition loadings in accordance with Section III of the ASME Code.

Over a period of time, under the influence of the operating loads and environment in the steam generator, some tubes may become degraded in local areas. Partially-degraded tubes are satisfactory for continued service provided that defined stress and leakage limits are satisfied, the prescribed structural limit is adjusted to take into account possible uncertainties in eddy current inspection, and an operational allowance for continued tube degradation until the next scheduled inspection is defined.

RG 1.121 (Reference IV.5.1) describes an acceptable method for establishing the limiting safe condition of degradation in the tubes beyond which tubes found defective by the established in-service inspection shall be removed from service. The level of acceptable degradation is referred to as the "repair limit."

An analysis was performed to define the "structural limits" for an assumed uniform thinning mode of degradation in both the axial and circumferential directions. The assumption of uniform thinning is generally regarded to result in a conservative structural limit for all flaw types occurring in the field. The allowable tube repair limit, in accordance with RG 1.121, is obtained by incorporating into the resulting structural limit a growth allowance for continued operation until the next scheduled inspection, and an allowance for eddy current measurement uncertainty.

to AEP:NRC:2902 Page 77 An evaluation was performed which demonstrated that the results of the RG 1.121 analysis are acceptable for the 1.66 percent power uprate. The resultant tube structural (minimum wall) limits are summarized in Table IV-1. These limits may be combined with measurement uncertainty and continued growth estimates to calculate plant specific tube repair limits. In addition to establishing structural limits, the evaluation confirmed that leakage monitoring using the EPRI PWR Primary-to-Secondary Leak Guidelines will provide a reasonable likelihood that the plant can be shut down before the single tube postulated to be leaking would rupture under either normal or accident conditions.

Table IV Summary of Tube Structural Limits at MUR Uprate Program Conditions High Tavg High Tavg Low T.v, Low T,,g Location /Wear Parameter High Low High Low Scar Length Pressure Pressure Pressure Pressure t,,, (inch) 0.021 0.019 0.023 0.022 Structural Limit (%)No"e 58.0 62.0 54.0 56.0 Anti-Vibration t,, (inch) 0.019 0.017 0.021 0.020 2

Bar1Noe / 1.00" Structural Limit (%)N'Ot 62.4 66.2 58.6 60.6 "FlowDistributioh t,. (inch) 0.017 0.015 0.019 0.018 Baffle / 0.75" Structural Limit (%)Ncte 1 66.4 69.8 62.8 64.6 Tube Support tn (inch) 0.020 0.018 0.022 0.021 Plate / 1.125" Structural Limit (%)Notel 61.0 64.8 57.0 59.0 Notes:

(1) Structural Limit = [(t1 0 m - tmm,) / tonm] X 100%; where tnom = 0.050 in (2) The tube repair limits and minimum thickness specified for the anti-vibration bar applies only for tube rows 16 and higher. For tube/anti-vibration bar intersections for tube rows 1 to 15, the repair limits and minimum thickness for the flow distribution baffle locations are to be used.

Reference (Section IV.5)

IV.5.1. Regulatory Guide 1.121, "Bases for Plugged Degraded PWR Steam Generator Tubes (for Comment)," dated August 1976 IV.5.2. ASME B&PV Code Section III, "Rules for Construction of Nuclear Vessels,"

American Society of Mechanical Engineers, New York, NY, 1968, plus Addenda through Winter 1968 to AEP:NRC:2902 Page 78 IV.5.3. ASME B&PV Code Section III, "Rules for Construction of Nuclear Vessels,"

American Society of Mechanical Engineers, New York, NY, 1989 edition IV.5.4. EPRI TR-107569-V1R5, "EPRI PWR Steam Generator Examination Guidelines,"

September 1997 IV.5.5. NEI 97-06, "Steam Generator Program Guideline" IV.6 Pressurizer A review of the revised temperature parameters presented in Table 3 showed that any changes in Th.t and TCOId are small, and are bounded by the existing pressurizer stress analysis performed for CNP Unit 2.

The design operating temperatures analyzed for the pressurizer were 653°F and 643°F, which correspond to the normal operating pressures of 2250 psia and 2100 psia, respectively. The original design basis analysis considered a design temperature drop (AT) of 125°F for the two critical components, the spray nozzle and the surge nozzle. In 1989, a rerating evaluation was performed for the pressurizer. That evaluation investigated other AT conditions for the critical components.

For the components at a normal operating pressure of 2250 psia, affected by Thot (e.g., the surge nozzle), the temperature difference of 71.1°F for the revised parameter is bounded by the original design basis. This is because the AT associated with the 1.66 percent uprate (ATMtJ) is less than that listed in the original design basis. The limiting component affected by changing TCojd is the spray nozzle, for which the rerating evaluation addressed a AT of 141.3°F. This AT bounds the ATmuR (for the spray nozzle) of 139.7°F. The components operating at a normal operating pressure of 2100 psia are bounded by the same AT values discussed above as well.

The changes made to the design transients that affect the pressurizer are insignificant relative to the pressurizer components analysis. For this reason, it is concluded that the revised parameters will not have any impact on the pressurizer stress and fatigue analyses. It is concluded that the pressurizer components meet the stress/fatigue analysis requirement of the ASME Boiler and Pressure Vessel Code,Section III, 1968 Edition through 1968 Winter Addenda, for plant operation at the MUR uprate conditions.

to AEP:NRC:2902 Page 79 IV.7 Nuclear Steam Supply System Auxiliary Equipment The NSSS auxiliary equipment includes the heat exchangers, pumps, valves, and tanks. An evaluation was performed to determine the potential effect that the revised design conditions will have on the equipment.

Only the SI accumulators and BITs have transients associated with them. None of the transients associated with these tanks are impacted by the MUR Uprate Program; therefore, these tanks are not affected by the MUR Uprate Program. Additionally, the MUR Uprate Program has no effect on the pressurizer relief tank or the VCT.

The revised design conditions have been evaluated with respect to the impact on the auxiliary heat exchangers, valves, pumps, and tanks. The results of this review concluded that the auxiliary equipment continues to meet the design pressure and temperature requirements, as well as the fatigue usage factors and allowable limits for which the equipment is designed.

IV.8 Fuel Evaluation This section summarizes the evaluations performed to determine the effect of the MUR Uprate Program on the nuclear fuel. In general, the fuel evaluation for CNP Unit 2 is performed for each specific fuel cycle and varies according to the needs and specifications for each cycle, consistent with WCAP-9272-P-A (Reference IV.8.1). However, some fuel-related analyses are not cycle-specific. The nuclear fuel review for the MUR Uprate Program evaluated the nuclear design, fuel rod design, core thermal-hydraulic design, and fuel structural integrity.

Reload-specific evaluations that confirm the loading patterns and associated fuel types utilized in future reload designs will be performed. In addition, prior to implementing this uprate, a reload safety evaluation will be performed to ensure that the core design bounds the uprated condition.

IV.8.1 Nuclear Design The neutronics impacts of an uprate (less than 2 percent) for CNP Unit 2 were analyzed and/or evaluated and are discussed in the following paragraphs.

I&M currently plans to perform this MUR power uprate in the beginning of CNP Unit 2 Cycle 14. The HFP inlet temperature of the core will be decreased by approximately 0.6°F in order to maintain HFP vessel average moderator temperature of the core at its original value of 574°F and to minimize the thermal-hydraulic impacts of the uprate. System pressure will remain at the current value of 2250 psia. The MUR Uprate Program will result in proportionally higher burnups and feed fuel inventories assuming that future fuel management maintains the required effective full power days of a typical cycle as a constant. The net impact of the power to AEP:NRC:2902 Page 80 uprate, including associated T/H parameter changes and the feed fuel enrichment increase, is that small changes to the axial and radial power distributions in the core and to the critical boron concentrations will result.

For the scenario described above, changes to the power distribution are small compared to typical cycle-to-cycle variability and are small compared to typical margins-to-peaking factor limits.

Also, changes to boron concentrations, reactivity coefficients, shutdown margin, and to other safety analysis inputs will be minimal. It should be noted that each future CNP Unit 2 cycle will be routinely analyzed in order to confirm that all applicable limits are met. Any future differences in key parameters, beyond what was considered in this report, will be routinely addressed via the standard reload design process.

IV.8.2 Fuel Rod Design The fuel rod design criteria evaluated for a standard reload design have been evaluated at the MUR Uprate Program conditions for both the Cycle 14 core and a representative future cycle core for CNP Unit 2. The results of these evaluations demonstrated that the fuel would be expected to meet all fuel rod design criteria at the MUR Uprate Program conditions.

Fuel rod design analyses are performed on a cycle-specific basis considering the plant conditions of the specific cycle as well as the fuel duty of each of the fuel regions in the core during the cycle. These analyses are performed using NRC-approved models in References IV.8.2 to IV.8.4, and methods in References IV.8.5 to IV.8.7 to demonstrate that all fuel rod design criteria will be met. The results of the fuel rod design analyses are reported in the cycle-specific Reload Safety Evaluation report as part of the normal reload design process.

IV.8.3 Core Thermal-Hydraulic Design The CNP Unit 2 core T/H analysis and evaluations were performed at a core power level of 3482 MWt, which bounds the proposed 1.66 percent uprate. The DNBR design limits and safety analysis limits were kept unchanged from the values used in the non-uprate analysis.

The DNBR analysis of CNP Unit 2 at the MUR Uprate Program conditions showed that the DNBR design basis continued to be met.

to AEP:NRC:2902 Page 81 IV.8.4 Fuel Structural Evaluation The 17x17 Vantage 5 assembly design was evaluated to determine the impact of the MUR Uprate Program on the fuel assembly structural integrity. The original core plate motions remain applicable for the MUR Uprate Program. Therefore, there is no effect on the fuel assembly seismic/LOCA structural evaluation. The MUR Uprate Program has an insignificant impact on the operating and transient loads, such that there is no adverse effect on the fuel assembly functional requirements. Therefore, the fuel assembly structural integrity is not affected, and the seismic and LOCA evaluations for the 17x 17 Vantage 5 fuel assembly design remain applicable.

References (Section IV.8)

IV.8. 1. WCAP-9272-P-A, "Westinghouse Reload Safety Evaluation Methodology," dated July 1985 IV.8.2. Weiner, R. A. et al, "Improved Fuel Performance Models for Westinghouse Fuel Rod Design and Safety Evaluations," WCAP-10851-P-A (Proprietary) and WCAP-1 1873-A (Non-proprietary), dated August 1988 IV.8.3. Davidson, S. L., and D. L. Nuhfer, "VANTAGE+ Fuel Assembly Reference Core Report," WCAP-12610-P-A, dated April 1995 IV.8.4. Foster, J. P., et al, "Westinghouse Improved Performance and Analysis Design Model (PAD 4.0)," WCAP-15063-P-A, Revision 1 (Proprietary) and WCAP-15064-NP-A, Revision 1 (Non-proprietary), dated July 2000 IV.8.5. D. H. Risher, Ed., "Safety Analysis for the Revised Rod Internal Pressure Design Basis," WCAP-8963-P-A, dated August 1978 IV.8.6. Davidson, S. L., et al, "Extended Bumup Evaluation of Westinghouse Fuel,"

WCAP-10125-P-A, dated December 1985 IV.8.7. Kersting, P. J., et al, "Assessment of Clad Flattening and Densification Power Spike Factor Elimination in Westinghouse Nuclear Fuel," WCAP-13589-A, dated March 1995 V. Electrical Equipment Design The plant presently operates with approximate gross and net electrical outputs of 1138 MWe and 1100 MWe respectively. The generator rated maximum output is 1333 MVA. The impact of increasing the output power by 1.66 percent will result in the generator maximum output increasing to AEP:NRC:2902 Page 82 to approximately 1157 MWe. The increased output is accomplished by opening the turbine control valves further, admitting more steam to the turbine.

The increase in steam flow and generator electrical output will result in increased loading of other plant equipment. Components that deliver the electrical output to the grid will be subjected to an increase in current flow. Also, certain generator auxiliary equipment will have increased electrical power requirements as will the motors for certain mechanical equipment necessary to support the increased steam and feedwater flow requirements.

The output of the generator is fed, via isophase bus, to the station service transformers and to the GSU transformer. The station service transformers provide power needed to operate all the plant auxiliary equipment and will, therefore, see an increase in loading. The generator step-up transformer connects the generator output to the grid via the 765 kV switchyard and through an autotransformer to the 345 kV switchyard, which also connects to the grid. As a result of the power up-rate, the isophase bus, the station service transformers, the GSU and the switchyard equipment, including the auxiliary transformers, will be required to handle additional power. Also, the offsite power feeders will see an increase in amperes being transmitted.

The following evaluation addresses the increased loading of various electrical equipment and identifies whether or not there is sufficient margin to accommodate the 1.66 percent power increase as indicated in Table V-1.

to AEP:NRC:2902 Page 83 Table V Impact of Power Uprate on Electrical Equipment Component ' . ' 1 100 Percent Power 1.7 Percent Uprate DesignfRating' L°,(Note Generator 1) !j!A,ti

":*;;::*/:*÷:;-,-:*}:!:o 1138 1198 1036 I* 1218.2 1133 1333

.Isophase Bus *, 26,600 amps 27,052 amps 29,844 amps

-Main Transformer TR2 1198 MVA 1218.2 MVA 1300 MVA

'Switchyard Breakers 904 amps 919 amps 3000 amps

ý(Note 2) ___________________ _____________

Protected by

'Offsite Power Feeders 904 amps 919 amps Switchyard Breakers Grid Stability N/A Unaffected N/A EDIGs , Unaffected 3500 kW RATs 201AB 201CD 201AB 201CD TR201AB &TR2O1 CD 24.9 MVA 28.3 MVA 25.3 MVA 28.7 MVA

-UATs: ,TR2AB & Same as 30

'TR2CD ,(Note 3) RAT 201AB RAT 201CD Emergency :Transformer Uf

-1 T IT-12EPi, Unaffected Unaffected 7.5 MVA

,Switchyard Protection - N/A Unaffected N/A

ýPlant Electrical Distribution Acceptable Insignificant Various bilstnibutlo :i ,=I::** :ii: '

Station Service Transformers - 115 TR4 Acceptable Unaffected MVA/phase JTR5 Acceptable Unaffected 150 MVA Table V-1 Notes: 1 Generator design ratings are at 0.85 PF.

2 Amps shown for 100 percent and 1.7 percent uprate are the maximum value if the entire GSU output were being carried by a single 765 KV breaker.

3 RATs see the same loading upon a fast transfer as their respective UATs.

In each case, the current design of these components and systems continue to bound the 1.66 percent power uprate conditions. Major components and impacts of the uprate are discussed in further detail below.

Turbine-Generator The proposed 1.66 percent power uprate will yield an increased turbine generator output.

to AEP:NRC:2902 Page 84 The Unit 2 main generator is a steam turbine driven, four-pole machine rated at 1333 MVA, 26,000 volts +/- 5 percent, 29,608 amps, 0.85 PF. This is equivalent to an electrical output of 1133 MWe.

At the present thermal rating of 3411 MWt, the Unit 2 main generator electrical output has typically been 1136 MWe and has been as high as 1140 MWe as shown in the Unit 2 Main Generator System Performance Monitoring Plan. During the monitored period, from October 2, 2000, to January 3, 2002, the actual generator stator phase currents never exceeded 26,600 amps, which equates to 1198 MVA at 26,000 volts.

The 1.66 percent power uprate will allow the reactor core thermal power to be increased by 57 MWt, from its present output of 3411 MWt to 3468 MWt. If it is conservatively estimated that as a result of the MUR Uprate Program, the actual generator output increased by 1.7 percent, it would increase to 1218 MVA, which is still 115 MVA below the 1333 MVA rating of the generator.

The generator stator cooling and hydrogen gas systems, which prevent damage due to overheating, have additional capacity to handle the increase in output. A review of historical stator cooling outlet temperature performance data indicated a temperature range of 45'C to 52°C during the monitoring period. This is below the expected range of 45'C to 60'C, thus indicating the existence of additional heat removal capacity. Further evaluations of turbine support systems, summarized in Sections VI.2 and VI.3 of this attachment, demonstrate that design of these systems bounds the 1.66 percent power uprate.

Main Transformer Main transformer TR2 steps up the generator output voltage from 26,000 volts to the transmission system voltage of 765,000 volts. TR2 consists of a bank of three single phase, 433 MVA transformers, delta connected on the low voltage side and grounded wye connected on the high voltage side. The maximum rating of the main transformer bank is therefore 1300 MVA.

The main generator is rated for 1333 MVA, 0.85 PF, which equates to 1133 MWe output.

Empirical data identifies that the main generator output has reached 1140 MWe at times which is attributed to operation at greater than 0.85 PF to meet transmission system conditions. However, as previously indicated, during that time, generator stator phase currents have been no higher than 26,600 amps, which is below rated current (29,608 amps) at 1333 MVA. This equates to 1198 MVA, which is below the Forced Oil and Air rating of 1300 MVA for TR2. If it is conservatively estimated that the generator output increased by 1.7 percent, it would equate to 1218 MVA, which is still below the Forced Oil and Air rating of TR2.

to AEP:NRC:2902 Page 85 Offsite Power Feeders The output of CNP Unit 2 connects to the offsite 765 kV and 345 kV transmission lines through switchyard circuit breakers which all have a continuous current rating of 3000 amps. If it is assumed that the entire output of Unit 2 is transmitted to the grid via the Dumont 765 kV line, the current would be approximately 904 amps. A 1.7 percent power uprate would result in an increase in output current of 15.3 amps at 765 kV. This small increase in current is within the 3000 amp rating of the 765 kV circuit breakers, which function to protect the switchyard buses and the Dumont transmission line.

If the entire amount of the increase goes to the 345 kV switchyard for distribution, the total increase in current would be approximately 34 amps. Since the 345 kV buses and all of the offsite 345 kV transmission lines are protected by the 345 kV switchyard circuit breakers, the 345 kV transmission lines will not be impacted by the slight increase in current.

Grid Stability The CNP Unit 2 connection to the 765 kV and 345 kV grids is through seven transmission lines.

One transmission line connects at the 765 kV switchyard and six lines connect at the 345 kV switchyard. Each line is capable of being isolated from its respective switchyard by circuit breakers.

With an increase of 1.7 percent, the output of main transformer TR2 will be 919.4 amps, which is an increase in output current of 15.3 amps at 765 kV. If it is assumed that the 15.3 amps is divided equally between the two switchyards, then 7.7 amps would be delivered to the 765 kV grid and 16.9 amps would be delivered to the 345 kV grid. Given the insignificant increase in current from a 1.7 percent power uprate, the impact on the stability of either grid system would also be insignificant. Therefore, the proposed 1.66 percent power uprate will not impact the grid stability analysis.

Emergency Diesel Generators Existing accident analyses bound the increase in reactor core decay heat. The heat removal systems, including the RHR, CCW, and ESW system pumps, have been evaluated and found to have insignificant effects on system flow due to the proposed 1.66 percent power uprate, and thus on motor loads. The BOP and NSSS system and component performance reviews determined that there is no need to increase EDG loading as a result of the 1.66 percent power uprate.

to AEP:NRC:2902 Page 86 Station Blackout and Environmental Qualification The effect of the MUR Uprate Program on the SBO event and the plant's ability to cope with a complete loss of AC electric power has been reviewed. The ability of CNP Unit 2 to respond to an SBO event will not be impacted by the Unit 2 MUR Uprate Program. This review is further documented in Section 11.3.14 of this attachment. Similarly, there is no impact on the EQ of electrical equipment, or the EQ Program. This review is further documented in Section VII.6.1 of this attachment.

VI. System Design VI.1 Nuclear Steam Supply System Interface Systems This section discusses the evaluations performed on the NSSS fluid systems using the revised design parameters presented in Table 3, "CNP Unit 2 MUR Uprate - NSSS Design Parameters."

For this evaluation, calculations were evaluated to determine whether the NSSS would be impacted by the MUR Uprate Program.

The following parameters have been determined to be bounded by analyses performed for the 3588 MWt rerating in WCAP-12135 (Reference VI.1):

0 RTD bypass delay times 0 pressurizer surge line pressure drop 0 pressurizer relief line pressure drop 0 pressurizer spray flow capability 0 RCS loop pressure drops In addition, a calculation was performed at 3588 MWt to verify that the boration volumes in the TS and UFSAR are adequate at that power level. The calculation demonstrates that boration capabilities for cold shutdown bound the MUR Uprate Program conditions. These boration volume requirements are verified on a cycle-specific basis.

The natural circulation cooldown capability is not affected because the Thot and TCOId, and therefore the no-load AT between the RCS and the steam generator, values for the MUR Uprate Program are bounded by the current analysis. The loss of offsite power event, which credits the natural circulation process, was analyzed with 2 percent power measurement uncertainty, which bounds the 1.66 percent power uprate.

to AEP:NRC:2902 Page 87 VI.I.1 Chemical and Volume Control System/Boron Capability The Thot and Tco.d values for the 1.66 percent power uprating are bounded by the Rerating Program values; therefore, the operating temperatures and boron capability of the CVCS associated with MUR Uprate Program are acceptable.

VI.1.2 Auxiliary Heat Exchanger Performance The impact of the MUR Uprate Program on the performance of the regenerative, letdown, excess letdown, and seal water heat exchangers was evaluated. The NSSS performance parameters for the MUR Uprate Program are bounded by the Rerating Program performance parameters for these components; therefore, auxiliary heat exchanger performance will not be impacted by the MUR Uprate Program.

VI.1.3 Residual Heat Removal System Single-Train Cooldown Various CNP TS Action Statements require that, if the applicable LCO is exceeded, the plant must be placed in cold shutdown (Tavg< 200'F, Mode 5) within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . To demonstrate that the plant has the capability to meet these requirements, an analysis of the time required to cool the RCS from Mode 1 to Mode 5 was performed assuming a single train of the RHR system and associated cooling support system equipment. The single train cooldown analysis requirement is the standard Westinghouse assumption for RHR cooldown analyses.

The current single-train analysis assumes a core power of 3411 MWt. Therefore, the current single-train cooldown analysis was reanalyzed for the Unit 2 MUR Uprate Program. The results of the single-train cooldown analysis demonstrate that the plant can be cooled from Mode 1 to Mode 5 (200°F) within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months , which is within TS requirements.

Two-Train Cooldown CNP's current licensing basis requires that, under normal operating conditions, the RHR system will be capable of reducing RCS temperature from the 350'F RHR cut-in temperature to 140°F within 20 hours2.314815e-4 days 0.00556 hours 3.306878e-5 weeks 7.61e-6 months following a reactor shutdown (UFSAR Section 9.3.1). The capability to cool the RCS temperature to 140'F within 20 hours2.314815e-4 days 0.00556 hours 3.306878e-5 weeks 7.61e-6 months following a reactor shutdown for the two-train cooldown was reanalyzed.

The current two-train analysis assumes a core power of 3411 MWt. Therefore, the current two-train cooldown analysis was reanalyzed for the Unit 2 MUR Uprate Program. The new analysis results demonstrate that the plant will be cooled down following a trip to less than 140'F to AEP:NRC:2902 Page 88 within 23 hours2.662037e-4 days 0.00639 hours 3.80291e-5 weeks 8.7515e-6 months . Based on the current UFSAR, the MUR power uprate will increase the time to cool down the RCS. The longer cooldown times for two-train operation are considered acceptable considering the design bases for the 20 hours2.314815e-4 days 0.00556 hours 3.306878e-5 weeks 7.61e-6 months was based on economic considerations only. That is, minimizing the time required for cooldown versus the size and cost of the RHR system and CCW system components (i.e., heat exchangers, pumps, etc.). Any impact that longer plant cooldown times may have on plant economics is more than compensated by the economic benefits of the power uprate. Therefore, the UFSAR will be updated to reflect the new result.

VI.1.4 Emergency Core Cooling System and Containment Spray System The MUR Uprate Program design operating parameters for RCS temperature, pressure, and flow are bounded by the previous uprating program values. The current long-term core cooling analysis for CNP employs a nominal core power high enough to cover both Unit 1 and Unit 2 (3481 MWt). Also, consistent with the requirements outlined in 10 CFR 50, Appendix K, the decay heat model assumed in the LOCA long-term core cooling analysis is 1.2 times the values for infinite operating time in the 1971 ANS Standard. Therefore, there is no impact due to decay heat considerations on the ECCS system, and there is no affect on the performance of the ECCS or the CTS.

VI.2 Power/Steam Systems As part of the CNP Unit 2 MUR Uprate Program, the following BOP fluid systems were reviewed to assess compliance with the Westinghouse NSSS/BOP interface guidelines:

"* Main Steam System

"* Steam Dump System

"* Condensate and Feedwater System

"* Auxiliary Feedwater System

"* Steam Generator Blowdown System The review was performed based on the range of NSSS design parameters presented in Table 3, "CNP Unit 2 MUR Uprate - NSSS Design Parameters." The various interface systems were reviewed to provide interface information that could be used in the BOP analyses.

Input Parameters and Assumptions The parameters in Table 3 were compared with the non-uprated parameters previously evaluated for the Plant Safety Analysis to support the thimble plug removal for the Unit 2 Cycle 13 core reload. The comparison indicated differences that could impact the performance of the BOP systems identified above. For example, the increase in core power of 2.0 percent coupled with zero steam generator tube plugging would result in about a 2.4 percent increase in to AEP:NRC:2902 Page 89 steam/feedwater mass flow rates. Additionally, the average steam generator tube plugging level of 10 percent in combination with the upper limit on Tavg (578.1°F) would result in a reduction in full-load steam pressure from 829 psia to 817 psia. Currently, a minimal number of tubes are plugged in the Unit 2 steam generators (0.1 percent).

Evaluation of the interface systems, delineated below, indicates that, except for the steam dump valves, the design of these systems bounds operation at the uprated core power level, 3468 MWt.

Description of Analyses and Results Evaluations of the above BOP systems relative to compliance with Westinghouse NSSS/BOP interface guidelines were performed to address the NSSS design parameters for the 1.66 percent power uprate analyses. NSSS design parameters for power uprate analyses include ranges for parameters such as Tavg (547.6°F to 578.1°F) and steam generator tube plugging (0 percent to 10 percent). These ranges on NSSS design parameters result in ranges on BOP parameters such as steam generator outlet pressure (607 psia to 858 psia). The NSSS/BOP interface evaluations were performed to address these NSSS and BOP design parameters. The following is a brief summary of the NSSS/BOP interface evaluation conclusions for the MUR Uprate Program.

VI.2.1 Main Steam System and Steam Dump System Major piping, valves, tanks, and turbines of the MS system were evaluated to determine the overall system capability due to the power uprate. The MS system has sufficient capacity to accommodate the anticipated steam flow increase and reduced full-load operating steam pressure impacts from the 1.66 percent uprated power.

Westinghouse sizing criterion recommends that the steam dump system (valves and pipe) be capable of discharging 40 percent of the rated steam load at full-load steam pressure to permit the NSSS to withstand an external load reduction of up to 50 percent of plant-rated electrical load without a reactor trip. The current design requirement stated in the UFSAR is for the steam dumps, or turbine by-pass system, to have a capacity of approximately 40 percent of full-load steam flow. The 1.66 percent power uprate affects the steam dump capability in several ways.

First, the full-load steam flow value increases with the uprate, so for a fixed steam flow through the steam dump valves, the capacity in terms of full-load steam flow is reduced. Secondly, the full-power steam pressure is reduced for increased steam flow conditions, given other parameters remain constant (e.g., Tag and RCS flow rate). The net effect of the 1.66 percent power uprate is a slight reduction in the available steam dump capability, for a given set of RCS parameters.

The steam dump valves are currently gagged to limit valve travel to 2.75 inches. A final steam dump valve flow capacity analysis is in progress to determine the appropriate steam dump travel stop position. Based upon a Westinghouse evaluation, a capability of approximately 41 percent to AEP:NRC:2902 Page 90 of full-load steam flow can be achieved with the travel stops removed, even if a conservatively low steam pressure of 607 psia is assumed. The uprated steam pressure will remain above 679 psia, as discussed in Section IV.5.2 of this Attachment. The steam dump travel stop position will be adjusted to the proper position prior to implementing the 1.66 percent power uprate.

The maximum operating design pressure and temperature of the MS system are not changed for the proposed increase in plant power conditions. The system full-load operating pressure is expected to decrease; therefore, the MUR Uprate Program will have no impact on the existing structural evaluations of the MS system piping and supports.

The MS system has been reviewed for the proposed power uprate operating conditions and found to be acceptable. Based on the results of analyses that bound the impacts of the proposed 1.66 percent power uprate, changes to UFSAR Chapter 14 Sections 14.2.4, "Steam Generator Tube Rupture," and 14.2.5, "Rupture of a Steam Pipe," are not required for the MUR Uprate Program.

CNP Unit 2 TS LCO 3.7.1.1, "Turbine Cycle - Safety Valves," specifies the operability requirements for the main steam line code safety valves. TS Table 3.7.1, "Maximum Allowable Power Range Neutron Flux High Setpoint with Inoperable Steam Line Safety Valves During 4 Loop Operation," specifies the maximum allowable Power Range Neutron Flux High setpoints with inoperable MSSVs. To support the MUR Uprate Program, a calculation was performed to identify changes to the maximum allowable power limits with inoperable MSSVs. Using the equation provided in the Bases for TS 3/4.7.1.1, with a revised NSSS power rating, Q, of 3489 MWt (3469 MWt core power plus 20 MWt RCP pump power), a revised set of setpoints was calculated for cases assuming one, two, or three inoperable MSSVs on one operating steam generator loop. The results of this calculation are reflected in the proposed changes to TS Table 3.7-1 (see Section VIII of this attachment).

VI.2.2 Condensate and Feedwater Systems A comparison between operating requirements for the 3468 MWt conditions generated by heat balances compared to historical operating data demonstrates that the following pumps have more than sufficient design and operational margin to accommodate the MUR uprated conditions:

"* Hotwell pumps

"* Condensate booster pumps

"* Main feedwater pumps

"* Heater drain pumps In addition, the margin in the design and operation of the feedwater regulating and isolation valves will continue to bound the uprated conditions. Finally, the uprated flow rates for the condensate and feedwater heaters have been demonstrated to be bounded by the design flowrates for these to AEP:NRC:2902 Page 91 components. Also, the lower system pressures ensure that the piping and support systems are not affected by the 1.66 percent power uprate.

The condensate and feedwater systems have been reviewed for the proposed 1.66 percent power uprate operating conditions and were found to be acceptable. Components within these systems are bounded by previous analyses.

VI.2.3 Auxiliary Feedwater System and Condensate Storage Tank The AFW system supplies feedwater to the secondary side of the steam generators at times when the normal feedwater system is not available, thereby maintaining the steam generator as a heat sink. The system provides feedwater to the steam generators during normal unit startup, hot standby, and cooldown operations and also functions as an ESF. In the latter function, the AFW system is required to prevent core damage and system overpressurization during transients and accidents, such as a loss of normal feedwater or a secondary system pipe break. The minimum flow requirements of the AFW system are dictated by accident analyses, and since the uprating impacts safety analyses performed at the current 100 percent power rating, evaluations were performed to confirm that the AFW system performance is acceptable at the 1.66 percent power uprate conditions. These evaluations show acceptable results.

The AFW system pumps are normally aligned to take suction from the CST. To fulfill the ESF design functions, sufficient feedwater must be available during transient or accident conditions to enable the plant to be placed in a safe shutdown condition.

The limiting transient with respect to CST inventory requirements is the LOOP transient. The CNP Unit 2 licensing basis requires that, in the event of a LOOP, sufficient CST usable inventory must be available to bring the unit from full power to hot standby conditions, and maintain the plant at hot standby for 9 hours1.041667e-4 days 0.0025 hours 1.488095e-5 weeks 3.4245e-6 months . In addition, Westinghouse recommends that, in the event of a LOOP, sufficient CST useable inventory be available to bring the unit from full power to hot standby conditions, hold the plant at hot standby conditions for two hours, and then cooldown the RCS to the RHR system cut-in temperature (350'F) in 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . In light of these design bases requirements, the CNP Unit 2 CST TS (3/4.7.1.3) and the CNP Administrative Technical Requirements ensure a usable volume of 175,000 gallons.

The minimum required useable inventory of 175,000 gallons is based on reactor trip from 102 percent of maximum calculated power of about 3482 MWt (or 1.02 X 3413 MWt). Since the MUR Uprate Program is based on a reduced calorimetric error, no change in the plant TS is required for operation at the uprated power level.

The maximum operating design pressure and temperature of the AFW system are not changing based on the 1.66 percent power uprate conditions. Therefore, the 1.66 percent power uprate will have no impact on the existing structural evaluations of the AFW system piping and supports.

to AEP:NRC:2902 Page 92 There are no component level impacts due to the 1.66 percent power uprate. The normal unit startup, hot standby, and cooldown functions of the AFW system remain unchanged since the power uprate has no significant impact on the feedwater flow in these modes.

VI.2.4 Feedwater Heaters and Drains I&M evaluated the nominal and maximum nozzle velocities for the feedwater heater and drain system. The results of these evaluations indicated that fluid velocities in the feedwater heaters and drains do not exceed maximum limits in industry standards. Therefore, I&M concludes that corrosion of these nozzles will not become an issue at the uprated conditions. In addition, current heat exchanger and system engineering system health monitoring programs will identify any issues with these heat exchangers.

Feedwater heater design temperatures and pressures were compared to the temperatures and pressures that were determined via a heat balance for this system. None of the temperatures and pressures indicated on the heat balance, for either the current or 1.66 percent power uprate conditions, exceed the design temperatures and pressures for these components.

The effect on the feedwater heater drain lines was evaluated. Each drain line contains an installed regulating valve to control the level of the associated feedwater heater, except Feedwater Heater No. 1. Feedwater Heater No. 1 drain lines do not contain regulating valves; level is controlled by a loop seal. The flow rates through each of these valves will increase by approximately 1 to 4 percent due to the MUR Uprate Program. Since none of the drain line valves are more than 85 percent open, on average, no valve modifications are needed. The design flow velocity for steel pipe is not exceeded for any of the drain lines at the 1.66 percent power uprated condition.

Since the maximum operating pressures and temperatures of the feedwater heaters are not changing, the existing code piping analyses are not impacted by the 1.66 percent power uprate and will have no effect on qualification or adequacy of piping components.

The feedwater heater and drain systems have been reviewed for the 1.66 percent power uprate operating conditions and found to be acceptable. Components within the system are either unaffected or are bounded by previous analyses.

VI.2.5 Steam Generator Blowdown System The inlet pressure to the steam generator BD system varies with steam generator operating pressure. As steam generator full-load operating pressure decreases, the inlet pressure to the BD system control valves decreases and the valves must open to maintain the required blowdown flow rate into the system flash tank. The current NSSS design parameters permit a maximum to AEP:NRC:2902 Page 93 decrease in steam pressure from no-load to full-load of 413 psid (i.e., from 1020 psia to 609 psia). Based on the revised range of NSSS design parameters approved for the MNR Uprate Program, the no-load steam pressure (1020 psia) remains the same and the minimum full-load steam pressure (607 psia) is 2 psi lower than the original full-load pressure at 10 percent SGTP.

This decrease in BD system inlet pressure at 10 percent SGTP will not impact the required maximum lift of the blowdown flow control valves. Therefore, the range of design parameters approved for the 1.66 percent power uprate will not impact blowdown flow capability.

VI.3 Cooling and Support Systems VI.3.1 Component Cooling Water System The CCW system has been reviewed for the proposed power uprate operating conditions and found to be acceptable. Most components cooled by the CCW system are not impacted by the proposed power uprate, while existing design analyses bound the proposed power uprate for the remaining cases. New analysis results demonstrate that the plant will be cooled down following a trip to less than 1407F within 23 hours2.662037e-4 days 0.00639 hours 3.80291e-5 weeks 8.7515e-6 months with two trains of RHR. The extended cooldown period does not impact the required CCW system flow requirements. Based on the current UFSAR, the.

1.66 power uprate will increase the time to cooldown the RCS with two trains of "RHR.

Therefore, as part of the implementation of the LEFM design change, the UFSAR will be updated to reflect the result of the revised cooldown analysis. Additionally, margin exists in the current system design for the current cooling water flow requirements.

VI.3.2 Essential Service Water System The ESW system has been reviewed for the 1.66 percent power uprate operating conditions and found to be acceptable. Most components cooled by the ESW system are not impacted by the MUR Uprate Program, while existing design analyses bound the proposed power uprate for the remaining components. Additionally, margin exists in the current system design for the current cooling water flow requirements.

VI.3.3 Non-Essential Service Water System The existing NESW system capacity has been reviewed and determined to be capable of accommodating the 1.66 percent power uprate. There is margin in the system to accommodate increased cooling flow from the steam generator blowdown system that would result from operation at increased power levels.

to AEP:NRC:2902 Page 94 VI.3.4 Turbine Auxiliary Cooling Water System Evaluation of the TACW system shows that this system is currently sufficient to support the 1.66 percent power uprate for all generator-specific component cooling. The system, as designed, is capable of accommodating additional iso-phase bus duct enclosure and stator water cooler flow requirements. There is no effect on the steam packing exhauster as a result of the MUR Uprate Program.

Therefore, the TACW system is capable of accommodating the MUR Uprate Program.

VI.3.5 Emergency Diesel Generator Aftercooler, Lube Oil, and Jacket Cooling Water System The EDG aflercooler, lube oil and jacket cooling water system, as designed, is capable of accommodating the proposed power uprate. There is currently margin between the existing required cooling water flowrates and the original design flowrates. Furthermore, the EDGs will not be subjected to any additional loading requirements as a result of the MUR power uprate.

Therefore, the EDG aflercooler, lube oil, and jacket cooling water system is capable of accommodating the proposed 1.66 percent power uprate, and no additional cooling is required.

VI.3.6 Circulating Water System The only CW system impact would be that the main condensers will operate at a slightly higher back pressure (approximately 0.1 psi) and condenser hotwell temperature will increase (approximately 0.5°F), thereby resulting in an increase in the CW heat rejection rate. The current system design and operation bound these changes. A review of the thermal discharge limits (Section VII.5 of this Attachment) concluded that there was no impact from the MIUR Uprate Program to Lake Michigan since the current thermal discharge permit bounds the 1.66 percent power uprated conditions.

Therefore, there is no impact to the CW system as a result of the MUR Uprate Program.

VI.3.7 Spent Fuel Pool Cooling System The only potential impact to the SFPC system resulting from the MUR Uprate Program is the amount of additional decay heat resulting from operation at higher power. Existing analyses assumed 102 percent of the current power level, which bounds the MUR Uprate Program conditions (Reference VI.2 and VI.3). Additionally, to ensure compliance with the CNP Unit 2 TS requirements for spent fuel pool loading, reviews are performed or confirmed to be bounding prior to each off-load. Therefore, there is no impact to the SFPC system as a result of the MUR Uprate Program.

to AEP:NRC:2902 Page 95 VIA Heating, Ventilating and Air-Conditioning Systems I&M has evaluated the radiological consequences of the Chapter 14 design basis events and concluded that the increased power output is fully bounded by the existing analyses. Therefore, there will be no effect on the ability of the ESFVS to perform its functions.

The proposed generating capability increase, in conjunction with typical summer temperatures, will increase the temperatures inside the iso-phase bus ducts. To support reliable power transmission at the increased output, the cooling capacity of the generator bus duct cooling system will be monitored during plant operation. High temperatures will indicate the need to increase the flow of TACW to the fan coil units. This action will increase the temperature difference between the air entering the coil and the air leaving the coil. The fans have been verified to have more than sufficient capacity to meet system design basis requirements. The evaluation of TACW performance indicates that there is sufficient margin in system capacity to provide additional flow.

Air flow, in conjunction with increased TACW flow, will assure adequate supply and return air temperature difference necessary to maintain the temperature inside all three ducts within established operating limits following implementation of the MUR Uprate Program.

The iso-phase bus duct cooling system, which is non-safety related but required for transmission of power, will need to be monitored for the additional heat load due to increased amperage passing through the bus as a result of the MUR Uprate Program. High temperatures in the bus ducts will need to be compensated for by adjustment of the flow of TACW to the fan coil units. There are no UFSAR or TS changes for the generator bus duct cooling system associated with the Unit 2 MUR Uprate Program.

The auxiliary building ventilation system, ESFVS, containment ventilation system, MDAFW/TDAFW room coolers and the iso-phase bus duct coolers were reviewed to evaluate the impact of the 1.66 percenit power uprate on these systems. Only the ESFVS, CEQ fans, and the MDAFW/TDAFW room coolers serve a licensing basis function. The conclusions presented in the UFSAR related to these systems will not change as a result of the 1.66 percent power uprate. No changes to the TS are required.

VI.5 Nuclear Steam Supply Systems Control Systems Evaluations of the instrumentation and control capabilities of the individual systems discussed in sections VI. 1 through VIA were determined to be unaffected by the 1.66 percent power uprate.

This section specifically addresses the effects of the 1.66 percent power uprate on the NSSS control systems.

ANS Condition I transients (as described in Reference VIA ) are evaluated to confirm that the plant can respond to these transients without generating a spurious reactor trip or ESF actuation.

to AEP:NRC:2902 Page 96 The design basis for the analyses used to determine NSSS control setpoints is the 3600 MWt rerating effort documented in References VI.1 and VI.5. These are, therefore, the design basis operability analyses, which will be used to evaluate the continued acceptability of the plant control system operation for the MUR Uprate Program.

The limiting transients analyzed in References VI.1 and VI.5 are the following:

Ramp load increase of a maximum of 1 percent per minute between 20 percent and 100 percent power.

Ramp load decrease of a maximum of 5 percent per minute between 100 percent and 20 percent power, without steam dump actuation.

10 percent load decrease at a maximum rate of 200 percent per minute.

0 Approximately 40 percent load rejection (from 100 percent to 60 percent power) at a maximum rate of 200 percent per minute with steam dump actuation.

The following transient was analyzed in References VI.1 and VI.5 to determine the acceptable operation of the Plant/Turbine Trip Controller mode of steam dump operation:

Turbine and reactor trip transients initiated from 100 percent power with steam dump actuation assuming 27 percent steam dump capacity.

The analyses performed in References VI.1 and VI.5 were reviewed for continued acceptability for the MUR Uprate Program conditions discussed in the Introduction (Table 3) and were concluded to bound the MUR Uprate Program.

As discussed in Section VI.2.1, MS System and Steam Dump System, additional analyses will be performed to determine the acceptability of the actual steam dump capacity for the 1.66 percent power uprating.

Condition I Transient Evaluations The analyses performed to support the rerating program (Reference VI.5) were based on a nominal power level of 3600 MWt. Table VI.1 contains a comparison of the plant operating condition used to support the rerating program to the plant operating conditions identified in Table 3. The operating conditions used in the rerating analyses bound those for the 1.66 power uprate. Therefore, the rerate analyses are also valid and bounding for the 1.66 power uprate.

Rerate analyses were done for the limiting beginning-of-life (BOL) fuel condition and for a lower bound Tavg and steam pressure below those expected for the 1.66 power uprate. The analyses demonstrated that there is acceptable margin to the reactor trip setpoints and ESF actuation system setpoints for all of the above limiting operability transients except for potentially the load rejection from 100 percent to 60 percent power. This transient could to AEP:NRC:2902 Page 97 potentially result in a reactor trip for the limiting lower bound full power Tayg values and beginning of life conditions with the overtemperature AT setpoint values of either:

a) aKI of 1.09, aK2 of 0.01331 and aTavg lead/lag of 28 sec/4 sec, or b) aKI of 1.17, aK2 of 0.0268 and aTavg lead/lag of 22 sec/4 sec.

The "relaxed" setpoints (set "b" above) provide a slight gain in margin, but not a sufficient amount to ensure load rejection success over the entire Tavg operating range identified for the MUR Uprate Program. The rerate analyses noted that this could be the case with a 40 percent steam dump capability; the results would be slightly aggravated by the reduced steam pressure.

Operation at higher values of TVg and/or higher core burnups would tend to result in the limiting 100 percent to 60 percent load rejection at 200 percent/minute being able to be accommodated (i.e., without a reactor trip occurring). Also, the rerate analyses concluded that if the load rejection rate is reduced to on the order of 20 percent/minute, any value of full power Tag within the analysis range and any cycle burnup could be accommodated. However, as discussed above, those transients which credit steam dump actuation will be reanalyzed for actual plant operation at the MUR power uprate conditions to best ensure continued acceptability of the current NSSS control system setpoints.

Table VI.1 Comparison of Unit 2 MUR Uprate Program Conditions to Values used in Design Basis Operability Transients Unit 2 MUR Uprate Program Rerating Program (Reference (from Table 3) VI.6)

Parameter High Tavg Low Tavg High Ta., Low Tavg NSSS Thermal Power, MWt 3494 3494 3600 3600 RCS Flow, gpm/loop 88,500 88,500 88,500 88,500 RCS pressure, psia 2250/2100 2250/2100 2250/2100 2250/2100 Thor, F 611.2 581.9 615.2 582.3 Tavg, OF 578.1 547.6 581.3 547.0 TCOrd, F (SG outlet) 544.7 513.0 547.1 511.7 Psteam,psia* 817 607 820 587 Feedwater Temperature, 'F 444.6 444.6 449 449

Unit 2 MUR Uprate Program values for limiting 10 percent steam generator tube plugging condition; Rerating Program values for 10 percent steam generator tube plugging condition.

Nuclear Steam Supply System Pressure Control Component Sizing I&M evaluated the sizing of NSSS pressure control components to determine if the installed capacity of the various pressure control components is still acceptable for the 1.66 percent power to AEP:NRC:2902 Page 98 uprate conditions. The results obtained from the 3600 MWt rerating effort were used as the primary basis for the evaluation.

The following pressure control components were each evaluated separately:

"* Pressurizer heaters

"* Pressurizer spray

"* Pressurizer PORVs The heatup time from cold shutdown to hot standby is not impacted by the MUR Uprate Program; the heatup maneuver would be essentially the same as that presently experienced.

Therefore, the installed pressurizer heater capacity is acceptable for the MU`R Uprate Program.

The rerate analyses (Reference VI.5) demonstrated that transients affecting the pressurizer sprays could be accommodated for a design NSSS power level of 3600 MWt without challenging the pressurizer PORVs. These analyses were performed based on a maximum pressurizer spray flow of 736 gpm, rather than the design analysis value of 800 gpm used for the MUR Uprate Program.

The 3600 MWt power level analysis has sufficient conservatism to bracket the 1.66 percent uprate conditions with a steam dump capacity as low. as .25.5 percent of nominal full-power steam flow (steam dump limitations discussed in Section VI.2.1). Based on the higher power level and lower spray flow capacity, the rerate analyses are bounding for the MUR Uprate Program.

Low Temperature Overpressure Protection System The MUR Uprate Program does not change any plant conditions that would impact the LTOP system. For low temperature/overpressure events, the plant is in a shutdown condition; therefore, the uprating does not impact the plant response for these events. Therefore, there is no direct impact on the LTOP system due to the MUR Uprate Program.

References (Section VI)

VI.1. WCAP-12135, "Donald C. Cook Units 1 and 2 Rerating Engineering Report," dated September 1989 VI.2. Letter from W. M. Dean, NRC, to E. E. Fitzpatrick, I&M, "Donald C. Cook Nuclear Plant, Units 1 and 2 - Amendment Nos. 169 and 152 to Facility Operating License Nos. DPR-58 and DPR-74 (TAC Nos. M80615 and M80616)," dated January 14, 1993 to AEP:NRC:2902 Page 99 VI.3. Letter from J. F. Stang, NRC, to R. P. Powers, I&M, "Donald C. Cook Nuclear Plant Amendment No. 260 to Facility Operating License No. DPR-58 and Amendment No.

243 to Facility Operating License No. DPR-74: Indiana Michigan Power Company Donald C. Cook Nuclear Plant, Units 1 and 2; Docket Nos. 50-315 and 50-316 (TAC Nos. MB1975 and MB1976)," dated November 30, 2001 VI.4. ANS-51.1/N18.2-1973, "Nuclear Safety Criteria for the Design of Stationary Pressurized Water Reactor Plants," dated August 1973 VI.5. WCAP-1 1902, "Reduced Temperature and Pressure Operation for Donald C. Cook Nuclear Plant Unit 1 Licensing Report," October 1988 and WCAP-11902, Supplement 1, "Rerated Power and Revised Temperature and Pressure Operation for Donald C. Cook Nuclear Plant Units 1 and 2 Licensing Report," dated September 1989 VII. Other VII.1 Control Room and Simulator There are no annunciators being added to the control room as a result of the MUR Uprate Program. Notification of the operators of the LEFM CheckPlus system condition will be through computer alarms and annotation of the computer display. Response to this computer alarm will be proceduralized. This will be finalized in the design change to implement the MUR Uprate Program in coordination with Operations to ensure that implementation meets operations and design requirements. Control room instrumentation and displays will be re-scaled as a result of implementation of the 1.66 percent power uprate. This will be addressed in the design change package that implements the installation of the LEFM CheckPlus system.

The CNP simulator, which reflects the design of the Unit 2 control room, will be modified during the Unit 2 modification.

VII.2 Operator Actions No changes are required to the CNP EOP program as a result of the MUR Uprate Program.

Specific procedures within the EOP program may require review and revision based upon the MUR Uprate Program plant parameters for thermal power, temperature, and pressure values. These changes will be identified and implemented under the design change process to implement the MUR Uprate Program. Specifically, values in the EOPs, the EOP Footnotes document, and the AOPs may need to be revised based upon the 1.66 percent power uprate levels. Any changes to values that are referenced in the EOPs or AOPs will be revised by the EOP/AOP control program, to fully implement the MUR Uprate Program.

to AEP:NRC:2902 Page 100 The MUR Uprate Program will have no impact on the time available for operator actions as assumed in the accident analysis. Specific impacts on operating procedures are further discussed in section VII.4 of this license amendment request.

VII.3 Power Uprate Modifications As demonstrated in Sections II through VI, the current plant analyses, design, and operation ensure that the applicable acceptance criteria are met for the MUR Uprate Program. No changes to the RCS or NSSS systems are required to support the MUR Uprate Program. An adjustment of the steam dump valve travel stop position will be required, in addition to the installation of the LEFM flow instrumentation system itself, as discussed below.

With the exception of the steam dump valves, there is no impact to the MS system, and no other modifications are required to implement the MUR Uprate Program. Because of small changes in main steam pressure, the uprate results in a slightly reduced steam dump capability. Westinghouse has evaluated the capability of the steam dump valves to satisfy their design basis function at the 1.66 percent power uprate level. The preliminary conclusion from this evaluation is that the steam dump valves have sufficient flow capacity in the current configuration for the 1.66 percent power uprate. A final analysis of the steam dump valve flow capacity is being performed. If the final analysis determines that these valves do not have sufficient capacity, then the steam dump valves' travel stop position will be changed to ensure that the reduced steam dump capability is adequate.

The adequacy of the steam dump valve flow capacity will be confirmed prior to increasing plant power above 3411 MWt, and if necessary, the steam dump travel stop position will be changed to ensure that the reduced steam dump capability is adequate.

The changes in flowrates, pressures, and other operating parameters can be accommodated by all existing equipment in the condensate or feedwater systems. Therefore, no plant changes/modifications are required to the condensate or feedwater systems to implement the MUR Uprate Program other than the installation of the LEFM flow instrumentation itself.

As the impacts of the MUR Uprate Program are bounded by the current design and operation of the AFW system, no modifications are required to this system for implementation of the MUR Uprate Program.

None of the existing feedwater heaters, nozzles, and drain lines, including regulating valves, will have to be replaced or modified to accommodate the uprated flows, temperatures, and pressures.

No plant changes/modifications are required to the feedwater heaters and drains for implementation of the MUR Uprate Program.

The 1.66 percent power uprate will result in minimal changes in the CCW system flow requirements. These changes are bounded by current system design; therefore, no plant changes/modifications are required to the CCW system to implement the MUR Uprate Program.

to AEP:NRC:2902 Page 101 Since there is no impact on the ESW system, no plant changes/modifications are required to implement the MUR Uprate Program.

There are no impacts to the NESW system that are not bounded by current system design; therefore, no NESW system changes will be required as a result of the MUR Uprate Program.

The only plant change for the TACW system is the potential additional flow requirement to the iso-phase bus duct and stator water cooling systems, which may require increased flow from the TACW system. No TACW system modifications are required to support the IMR Uprate Program.

Because the EDGs will not be subjected to additional loading as a result of the MUR Uprate Program, no changes are required to the EDG cooling water systems. Therefore, no EDG cooling water systems modifications are required to support the MUR Uprate Program.

The 'only CW system impact would be that the main condensers will operate at a slightly higher back pressure (approximately 0.1 psi backpressure) and condenser hotwell temperature will increase (approximately 0.5'F), thereby resulting in an increase in the CW heat rejection rate. The existing system design, including instrumentation, bounds the uprated operating conditions; therefore, no CW system modifications are required to support the MUR Uprate Program..

The MUR Uprate Program will not impact the SFPC system; therefore, no SFPC system modifications are required to support the MUR Update Program.

No HVAC system modifications are required to implement the MUR Uprate Program. The iso-phase bus duct cooling system will be monitored to ensure the increased amperage through the iso-phase bus duct does not increase the system temperature above allowable limits. If so, increased TACW system flow may be required to the iso-phase bus duct coolers. Changes in flowrates can be accommodated by existing equipment. However, no modifications are required to the HVAC systems, including the ESFVS, to implement the MUR Uprate Program.

The review of electrical systems in support of the proposed uprate indicates that no changes are required to support the MUR Uprate Program.

VII.4 Plant Operating Procedure Changes Procedural impacts for the RCS and NSSS systems will be identified in the process for the implementation of the design change package that installs the LEFM CheckPlus system. Impacts are anticipated to normal operating, alarm response, AOP and EOP procedures. In particular surveillance procedures for reactor thermal power will be affected, as well as operator responses to AEP:NRC:2902 Page 102 to an out-of-service condition on the LEFM CheckPlus system, as described in Section I. These changes will be implemented prior to raising plant core power above 3411 MWt.

There are no main steam operating procedural changes required to implement the 1.66 percent power uprate level. The changes in flowrates, pressures, and other parameters due to the 1.66 percent power uprate will not necessitate equipment or operational changes outside of the existing MS system equipment design and operation. For the potential steam dump valve limit stop change, there may be a change in the installed position but this will not impact the operation of the steam dump system and so there are no anticipated changes to the plant operating procedures.

If increased TACW flow to the generator bus duct and stator cooling water systems is required, the changes in flowrates will necessitate revisions to procedures that direct the operation of the TACW, iso-phase bus duct, and stator cooling water systems.

No other procedural impacts were identified in the review of NSSS, BOP, and support systems and their associated analyses.

VII.5 Environmental Review I&M has evaluated this license amendment request against the criteria for identification of licensing and regulatory actions requiring environmental assessment in accordance with 10 CFR 51.21. I&M has determined that this license amendment request meets the criteria for a categorical exclusion set forth in 10 CFR 51.22(c)(9). This determination is based on the fact that this change is being proposed as an amendment to a license issued pursuant to 10 CFR 50 that changes a requirement with respect to installation or use of a facility component located within the restricted area, as defined in 10 CFR 20, or that changes an inspection or a surveillance requirement, and the amendment meets the following specific criteria:

(i) The amendment involves no significant hazards consideration.

As demonstrated in Enclosure 2, Section 5.1, No Significant Hazards Consideration, this proposed amendment does not involve a significant hazards consideration.

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

The MUR Uprate Program thermal power increase will not alter or increase the inventory of radionuclides in the RCS. This change will not alter the fuel cladding in a way that affects its mechanical and structural integrity or affects its leakage characteristics. This power uprate will not alter or increase the primary pressure or temperature, so there is no additional challenge to the RCS or other fission product barriers. Additionally, increasing core thermal power by 1.66 percent will not affect or increase water to AEP:NRC:2902 Page 103 production or inventory use in any way that will affect effluent volume or production.

Finally, the 1.66 percent uprated plant heat discharge combined with the existing Unit 1 discharge will remain below the site NPDES limit of 17,300 million Btu/hr (Reference VII.5). The 1.66 percent power uprate is bounded by the previously-evaluated NPDES thermal effluent limits. Therefore, this change will not result in a significant change in the types or significant increase in the amounts of any effluent that may be released offsite.

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

The MUR Uprate Program thermal power increase will not alter or increase the inventory of radionuclides in the RCS. The radionuclide source terms applicable to personnel dose determination were calculated assuming a core thermal power of 3588 MWt, which bounds the uprated core power of 3468 MWt. This change will not alter the fuel cladding in a way that affects its mechanical and structural integrity or affects its leakage characteristics; therefore, there is no additional challenge to the RCS or other fission product barriers. Finally, no new effluents or effluent release paths are created by the MUR Uprate Program. Therefore, this change will not result in an increase in individual or cumulative occupational radiation exposures.

Therefore, pursuant to 10 CFR 51.22(b), no environmental -impact statement or environmental assessment need be prepared in connection with the proposed amendment.

VII.6 Programs VII.6.1 Environmental Qualification Program The CNP EQ Program has been reviewed in support of the Unit 2 MUR Uprate Program. This review has determined that no EQ Program changes are required to be implemented as a result of the MUR Uprate Program. The development of the EQ parameters bound the 102 percent core thermal power; therefore, the programs, activities, elements and philosophy that are currently in place are not affected by the 1.66 percent power uprate. In accordance with CNP's design change process, any specific component modifications or changes that may be required to support the MUR Uprate Program will be evaluated against the EQ Program requirements.

VII.6.2 Motor-Operated Valve Program Design basis review calculations for feedwater, main steam, and plant cooling systems (i.e., CCW, ESW, and NESW) were reviewed to determine potential impacts on the MOV Program. The limiting (bounding) differential pressures were based on system capacities and setpoints (e.g.,

steam generator safety valve setpoints, pump shutoff head), which will not change due to the proposed 1.66 percent power uprate to be implemented by the MUR Uprate Program.

to AEP:NRC:2902 Page 104 Therefore, the 1.66 percent power uprate does not challenge the capability of valves in the MOV Program to satisfy their design functions. No changes are required to the MOV Program as a result of the MUR Uprate Program.

VII.6.3 Air and Hydraulic Operated Valve Program A review of heat balances that reflect the effect of the 1.66 percent power uprate on system design function parameters indicates that there is no impact on the ability of AHOVs to perform their design function in the systems affected by the MUR power uprate. No additional AHOVs were identified as impacted by the MUR Uprate Program. No changes will be required to the AHOV Program as a result of the MUR Uprate Program. Subsequent design analyses will be developed for normal plant operating conditions at a value as high as 102 percent of the plant's current RTP. The 1.66 percent power uprate to be implemented by the MUR Uprate Program will not affect the design basis of valves in the AHOV Program, because the analysis of these valves will remain bounded by the design basis requirements of their respective system-related functions.

VII.6.4 Flow-Accelerated Corrosion Program FAC Program - Purpose and Scope The purpose of the FAC Monitoring Program is to predict, detect, monitor, and mitigate FAC in plant piping. The scope of the program consists of all piping and components that cannot be demonstrated to be non-susceptible to FAC as documented in the current FAC System Susceptibility Evaluation.

The main elements of the program are as follows:

Scope Identification Based on an evaluation of plant piping systems, piping and components that are susceptible to FAC are identified and included within the scope of the FAC Program.

Evaluation and Modeling Once identified, each susceptible line of plant piping is evaluated and addressed to ensure that the probable level of degradation is ascertained and appropriate action is taken. This is normally accomplished by modeling the line using the EPRI software program, CHECWORKSTM. Some FAC-susceptible lines and components cannot be modeled in to AEP:NRC:2902 Page 105 CHECWORKS due to uncertain operating conditions, software limitations, or other factors.

These lines are addressed in the "susceptible non-modeled" (SNM) sub-program.

Inspection Components are selected for inspection, based on CHECWORKS predictions, SNM selection criteria, past inspection results, and operating experience. Selected large-bore components (nominal diameter greater than 2 inches) are inspected during refueling outages using ultrasonic testing. Small-bore components (nominal diameter 2 inches or less) are typically inspected on-line using radiography. While radiography is preferred, ultrasonic testing is also an acceptable methodology for these components.

Data Analysis The inspection results for CHECWORKS-modeled components are entered into the CHECWORKS model to calibrate the model. In addition, the component's remaining life is calculated by comparing the inspection results to the acceptance criteria. The results of this analysis are compared to the procedural acceptance criteria to determine:

if a follow-up inspection is required and when it should be scheduled,

if inspections at additional locations are needed in the current outage, and

if the component requires repair or replacement - either immediately or during a future outage.

The operating pressure, temperature, and flowrate are inputs to the CHECWORKS model, which is used to predict the FAC wear rate in the susceptible components. The MUR power uprate will result in changes to these operational values. The values will be revised in the CHECWORKS model to predict future wear rates. These changes will be minimal, and the system operating parameters will remain within the limits specified in the CNP design specifications.

The EPRI CHECWORKS software is used by CNP's FAC Program to model the piping systems.

The source of the input parameters is actual cycle-specific values, and the FAC Program directs these values to be changed and maintained in the software if the values change in the field.

A review of heat balances that reflect the effect of the MUR power uprate on FAC-related parameters indicates that no additional systems, piping, or other components need to be added to the FAC Program as a result of the MIUR power uprate. The FAC Program will direct changes to the CHECWORKS input parameters for changes to system flowrates, temperatures, and pressures. A revised plant heat balance calculation indicates that the changes are minimal and the MUR uprate is not expected to significantly affect the current wear predictions of the CHECWORKS software.

to AEP:NRC:2902 Page 106 The activities, elements, and philosophy that are currently in place are not affected by the MUR Uprate Program. No specific TS or operating procedure changes were identified by the FAC Program review for the MUR Uprate Program. No changes are required to the FAC Program as a result of the MUR Uprate Program.

VII.6.5 High-Energy Line Break Program The CNP HELB Program was reviewed in support of the MUR Uprate Program. This review determined that no HELB program changes are required to be implemented as a result of the MUR Uprate Program. The activities, elements, and philosophy that currently constitute the HELB Program are not affected by the MUR Uprate Program. In accordance with CNP's design change process, the design change package for installing the LEFM CheckPlus system will be evaluated against the HELB Program requirements as required in the CNP plant modification process. No new piping is added, no postulated break locations changed, and no changes are made to the assumed blowdown from any currently-postulated breaks; therefore, there is no impact on the current CNP Unit 2 HELB analysis.

The proposed 1.66 percent power uprate is bounded by the existing HELB analysis-of-record.

These analyses are consistent with the requirements of Generic Letter 87-11 (Reference VII.1) and the CNP current licensing basis, as indicated in Unit 2 License Amendment Nos. 225 and 230 (References VII.2 and VII.3). No specific TS or operating procedure changes were identified by the HELB Program review for the MUR Uprate Program. No changes are required to the HELB Program as a result of the MUR Uprate Program.

VII.6.6 Fire Protection/Appendix R Programs The activities and elements currently in place to implement the Fire Protection Program are not affected by the MUR Uprate Program or continued plant operation at the uprated thermal power level.

The post-fire safe shutdown aspect of the Fire Protection Program is in place to meet the requirements of 10 CFR 50, Appendix R. The addition of the LEFM CheckPlus system will not change the circuit separation nor adversely impact any systems credited for an Appendix R safe shutdown (i.e., AFW, RHR, MS). No new cables for credited components will be added or deleted.

The safe shutdown analysis methodology and acceptance criteria previously developed to demonstrate compliance with 10 CFR 50, Appendix R, remains unchanged.

No changes are required to the Fire Protection or Appendix R/Safe Shutdown Programs as a result of the MUR Uprate Program. In accordance with CNP's design change process, the design change package for installing the LEFM CheckPlus system will be evaluated against the Fire Protection/Appendix R Program requirements as required in the CNP plant modification process.

to AEP:NRC:2902 Page 107 VII.6.7 Inservice Inspection Program The CNP ISI Program was reviewed in support of the MUR Uprate Program. No impacts were identified for the ISI Program system or component scope, boundaries, exemption or selection criteria, examinations, or acceptance standards. No changes are required to the ISI Program as a result of the MUR Uprate Program.

VII.6.8 Inservice Testing Program The CNP IST Program has been reviewed in support of the MUR Uprate Program. The MUR Uprate Program does not impact the requirements, criteria, and philosophy that currently constitute the IST Program. The operating condition changes required by the MUR Uprate Program do not affect component or system design conditions; therefore, no changes to the IST Program pump or valve scope, selection criteria, tests, or acceptance standards are required. No changes are required to the IST Program as a result of the MUR Uprate Program.

VII.6.9 Radiological Environmental Monitoring Program No changes will be required to the REMP for monitoring the types or amounts of any effluents that may be released offsite. The current UFSAR Chapter 14 radiological accident analysis fully bounds the MUR Uprate Program. Also, the power uprate will not increase the inventory of radionuclides in the RCS above analyzed limits, nor will it affect the fuel cladding in a way that alters its structural integrity or leakage characteristics. The radionuclide activity core inventory used in the radiological consequences analyses was calculated at a core thermal power of 3588 MWt. Therefore, no changes are required to CNP's REMP as a result of the MURJ Uprate Program.

VII.6.10 Radiological Dose Monitoring and Radiological Dose Control Programs No changes will be required to the current programs for monitoring individual and cumulative occupational radiation exposure along with radiological dose control program. Plant programs and procedures will continue to ensure that dose and effluent releases are maintained within the limits of applicable regulations. The MUR Uprate Program does not change radiological source terms; therefore, the current UFSAR Chapter 14 radiological accident analysis fully bounds the 1.66 percent power uprate. The radionuclide activity core inventory used in the radiological consequences analyses was calculated at a core thermal power of 3588 MWt, which bounds plant operation following the 1.66 percent power uprate. No changes are required to the individual or cumulative occupational radiation exposure programs as a result of the MUR Uprate Program.

to AEP:NRC:2902 Page 108 VII.6.11 Probabilistic Risk Assessment Program The CNP PRA Program was evaluated in support of the MUR Uprate Program. A review of the PRA Success Criteria (Reference VII.4) indicates that the rated thermal power used in the analyses is 3493 MWt. Therefore, the existing analyses bound the proposed MUR power uprate.

Additionally, the only physical change to the plant will be the installation of an improved feedwater flow instrument (i.e., installation of LEFM CheckPlus system in the feedwater system). This modification will not affect the plant's PRA model, because flow instrumentation is below the level of detail of the plant's PRA model. Therefore, there is no impact on the PRA model or the CNP PRA Program as a result of the MUR Uprate Program.

VII.7 Mechanical Piping Design Maximum operating pressures and temperatures will not change as result of the 1.66 percent power uprate. Therefore, existing code piping analyses are not affected by the proposed power uprate and will have no effect on qualification or adequacy of piping components. No changes are required to the mechanical piping design and code piping analyses as a result of the MUR Uprate Program.

References (Section VII)

VII.1. Generic- Letter 87-11, "Relaxation in Arbitrary Intermediate Pipe, Rupture Requirements," dated June 19, 1987 VII.2. Letter from J. F. Stang, NRC, to R. P. Powers, I&M, "Donald C. Cook Nuclear Plant, Units I and 2 - Issuance of Amendments (TAC Nos. MA8183 and MA8184)," dated April 25, 2000 VII.3. Letter from J. F. Stang, NRC, to R. P. Powers, I&M, "Donald C. Cook Nuclear Plant, Units 1 and 2 - Issuance of Amendments (TAC Nos. MA8893 and MA8894)," dated November 21, 2000 VII.4. Letter from E. E. Fitzpatrick, I&M, to T. E. Murley, NRC, "Donald C. Cook Nuclear Plant Units 1 and 2, Individual Plant Examination Submittal Response to Generic Letter 88-20," AEP:NRC:1082B, dated May 1, 1992 VII.5. Letter from W. E. McCracken, PE, Michigan Department of Environmental Quality, to Indiana Michigan Power Company, "NPDES Permit No. M10005287," dated September 28, 2000 to AEP:NRC:2902 Page 109 VIII. Changes to Technical Specifications, Protection System Settings, and Emergency System Settings The proposed license amendment would revise the CNP Unit 2 OL and TS to increase licensed power level to 3468 MWt, or 1.66 percent greater than the current level of 3411 MWt. The proposed changes, which are indicated on the marked-up pages in Attachment 1, are described below:

1. Paragraph 2.C.(1) in OL DPR-74 is revised to authorize operation at a steady state reactor core power level not in excess of 3468 MWt (100 percent power).

2. The definition of RATED THERMAL POWER in TS 1.3 is revised to reflect the increase from 3411 MWt to 3468 MWt.

3. TS 3.5.2, Action b, is revised to increase the maximum allowable core power level with a safety injection cross-tie valve closed. To reflect application of the measurement uncertainty recapture (MUR) power uprate, the maximum allowed power level in this Action Statement is revised from 3250 MWt to 3304 MWt.

4. TS Table 3.7-1, "Maximum Allowable Power Range Neutron Flux High Sctpoint with Inoperable Steam Line Safety Valves during 4 Loop Operation," is revised to reflect the maximum allowed power for operation with inoperable MSSV's. With one inoperable MSSV per loop, the power reduction is revised from 61.6 percent RTP to 60.4 percent RTP. With multiple inoperable safety valves per loop, the power reduction and associated reduction in high flux reactor trip setpoints is revised to 43.0 percent (two inoperable MSSVs) and 25.7 percent (three inoperable MSSVs).

ATTACHMENT 4 TO AEP:NRC:2902 RESPONSES TO NRC REQUEST FOR ADDITIONAL INFORMATION REGARDING UNIT 1 MUR POWER UPRATE REQUEST By letter dated June 28, 2002 (Reference 1), Indiana Michigan Power Company (I&M), proposed to amend the Unit 1 operating license and Technical Specifications (TS), to allow a 1.66 percent increase in the licensed core power, to 3304 MWt. By Reference 2, the Nuclear Regulatory Commission (NRC) requested additional information regarding the changes proposed in Reference 1. The responses to the NRC's questions, which were submitted to the NRC by Reference 3, are provided in this attachment. In addition to duplicating the responses provided in Reference 3, this attachment addresses the applicability of each question to this Unit 2 Measurement Uncertainty Recapture (MUR) power uprate request, and indicates where the information pertaining to each question is located within this letter.

NRC Question 1 Westinghouse recently issued three Nuclear Service Advisory Letters (NSALs), NSAL 02-3 and Revision 1, NSAL 02-4 and NSAL 02-5, to document the problems with the Westinghouse designed steam generator water level setpoint uncertainties. NSAL 02-3 and its revision, issued on February 15, and April 8, 2002, respectively, deal with the uncertainties caused by the mid-deck plate located between the upper and lower taps usedfor steam generatorwater level measurements. These uncertaintiesaffect the low-low level trip setpoint (used in the analysesfor events such as the feedwater line break, anticipated transient without scram (ATWS) and steamline break). NSAL 02-4, issued on February 19, 2002, deals with the uncertaintiescreated because the void content of the two-phase mixture above the mid-deck plate was not reflected in the calculationand affects the high-high level trip setpoint. NSAL 02-5, issued on February19, 2002, deals with the initial conditions assumed in the steam generatorwater level related safety analyses. The analyses may not be bounding because of velocity head effects or mid-deck plate differential pressures which have resulted in significant increases in the control system uncertainties. Discuss how D. C Cook Unit 1 accountsfor these uncertaintiesdocumented in these advisory letters in determining the steam generatorwater level setpoints. Also, discuss the effects of the water level uncertaintieson the analyses of recordfor the loss-of-coolant accident (LOCA) and non-LOCA transientsand the ATWS event, and verify that with consideration of all the water level uncertainties, that the current analyses are still adequate with regard to the power uprate.

Response to Question 1 The Westinghouse Electric Company (Westinghouse) Nuclear Safety Advisory Letters (NSALs) that identified steam generator level concerns (i.e., NSAL 02-3, including Revision 1, NSAL 02-4, and NSAL 02-5) have been entered into the Donald C. Cook Nuclear Plant (CNP)

Plant Operating Experience database, and have been evaluated in accordance with the CNP to AEP:NRC:2902 Page 2 Corrective Action Program. Each of these NSALs applies to plants with Westinghouse-designed steam generators. The CNP Unit 1 steam generators were replaced in 2000 with Babcock &

Wilcox Model 51R steam generators. The internals of the Model 5iR steam generators differ from the original Westinghouse Model 51 steam generators. Major differences include the separator unit, improved internal feedwater distribution system, use of lattice grid support plates, and improved tubing material. Furthermore, the Model 51R steam generators have major physical design differences in the narrow range level region. Since the CNP Unit 1 steam generators are not of Westinghouse design and differ significantly from a Westinghouse designed steam generator, especially in the narrow range level region, the identified NSALs are not applicable to CNP Unit 1, and consequently, the concerns addressed in the subject NSALs have no effect on the CNP analyses-of-record.

NRC Question 2 Upon reviewing large-break LOCA models for power uprates, the Nuclear Regulatory Commission (NRC) recently found plants that require changes to their operating procedures because of inadequatehot leg switch-over times and boron precipitationmodeling. Discuss how your analyses accountfor borc acid buildup during long-term core cooling and discuss how your predicted time to initiate hot lcg injection corresponds to the times in your operating procedures.

Response to Question 2 "Post-LOCA analysis issues pertaining to long-term core cooling, core subcriticality, and core boron precipitation control were resolved as part of the CNP restart effort that concluded in December 2000. Extensive analyses were performed to support containment system modifications described in Reference 3. The TS changes supported by the Reference 3 analyses were approved by Unit 1 License Amendment No. 234 (Reference 4). Section 3.5 of 0 to Reference 3 documents a detailed discussion of the comprehensive analyses performed to address post-LOCA concerns. In order to provide a reasonable amount of time for performance of the hot leg switchover evolution (i.e., between 2.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months and 7.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months after the initiation of the LOCA), it was necessary to credit the negative reactivity associated with control rod insertion. Additional analyses (Reference 5) demonstrating the acceptability of crediting control rod insertion were approved by the NRC in December 1999 (Reference 6). These analyses, which form the basis for the hot leg switchover time stipulated in the CNP Emergency Operating Procedures, are confirmed to remain valid and satisfied for each core reload design, and are not impacted by the 1.66 percent power uprate, as discussed in Section 11.1.3.1 of to this letter.

to AEP:NRC:2902 Page 3 NRC Question 3 Regulatory Issues Summary (RIS) 2002-03, "Guidance on the Content of Measurement Uncertainty Recapture Power Uprate Applications," Section L.J.E, indicates that a calculation of the totalpower measurement uncertaintyat the plant, explicitly identifying allparametersand their individual contribution to the power uncertainty should be submitted with the uprate application. Please provide your plant-specific calculations of the total power measurement uncertaintyat the plant.

Response to Question 3 Calculation 1-2-01-03 CALC 2, Revision 1 "Power Calorimetric Accuracy using the Caldon Check Plus Feedwater Flow Measurement System and a modified PPC CALM Program" will be provided under separate cover.

NRC Question 4 RIS 2002-03, Section 11.1.5, "Steam Generator Tube Rupture (SGTR) - Thermal-Hydraulic Analysis, " indicates that a change in power has negligible effect on the SGTR margin-to-overfill analysis. You fitrther indicate that you performed a sensitivity study -to show that an SGTR occurring with a power level increase of 2 percent remains bounded by your "supplemental SGTR analysis." However, the supplemental SGTR analysis was performed at a normal power level. Please describe the methodology of the sensitivity study to indicate why it remains bounded by the supplemental SGTR analysisperformed at a lowerpower level.

Response to Question 4 Based upon Westinghouse's analytical experience with power uprate efforts, the change in power has a negligible effect on the Steam Generator Tube Rupture (SGTR) margin-to-overfill analysis.

A higher power tends to reduce the initial secondary pressure, thereby increasing the break flow rate. This has a small impact on the transient since, after reactor trip, the secondary pressure rises to the power-operated relief valve (PORV) setpoint. The higher power also tends to prolong the transient due to the higher decay heat level, requiring more time for the cooldown and final depressurization stages of the transient. The changes in primary and secondary conditions associated with the increased power also impact the secondary water inventory, tending to result in a lower initial inventory. For a small uprate, such as the proposed 1.66 percent power uprate, these impacts are not significant.

Westinghouse's generic power uprate experiences discussed above were confirmed specifically for the CNP Unit 1 MUR Uprate Program. The models and methods used in the evaluation of the impact of the 1.66 percent uprate on the CNP Unit 1 supplemental SGTR analyses are the same as those used for the current analysis supporting Unit 1 License Amendment No. 256 to AEP:NRC:2902 Page 4 (Reference 7). Nominal and initial conditions were revised to model a 2 percent increase in nuclear steam supply system (NSSS) power. Values assumed for steam generator pressure and water mass correspond to the increased power condition using models and methods currently licensed for CNP Unit 1. The nominal NSSS power was increased by 2 percent from 3262 megawatts-thermal (MWt) to 3327 MWt. The increased power results in a lower secondary pressure and lower secondary water mass. The nominal steam pressure was reduced from 688 pounds per square inch absolute (psia) to 682 psia. The nominal (and initial) secondary water mass was reduced from 105,461 pounds-mass per steam generator (lbm/SG) to 104,826 lbm/SG.

The nominal vessel average temperature was not changed. RCS temperatures were calculated by the LOFTTR2 computer code, based upon the revised nominal and initial conditions. By Reference 7, the NRC approved the use of LOFTTR2 for the CNP Unit 1 supplemental overfill analysis.

The analysis modeling the 2 percent uprated power showed a negligible difference in the time the overtemperature delta-T reactor trip signal was generated. Operator action modeling was unchanged. Break flow termination was achieved at 3152 seconds, compared to 3144 seconds in the previous analysis. Integrated break flow increased from 160,424 Ibm to 161,034 Ibm. As noted above, the nominal and initial steam generator water mass is less under the uprated conditions compared to the exiting analysis. The net effect was a slightly less limiting transient relative to steam generator overfill.. Specifically, the margin-to-overfill increased from 51 cubic feet (ft3) to 65 R't. Thus, this sensitivity analysis 'confirmed for CNP Unit I that a 2 percent power increase has a negligible impact on the SGTR margin-to-overfill analysis. Therefore, the conclusion presented in Section 11.1.5 of Reference 1 remains valid.

NRC Question 5 In RIS 2002-03, Section JV.5.2, "StructuralIntegrity Evaluation," you state that "Mechanical repairhardware was not evaluatedfor the D. C. Cook Nuclear Plant Unit 1 steam generators because they are new replacements with no installed repair hardware and minimal tube plugging (less than 0.03 percent steam generator tube plugging (SGTP). " The NRC staff believes that the number of tube plugs currently installed in the steam generators is irrelevant and the licensee should evaluate the effect of the Measure UncertaintyRecapture (MUR) Power Uprateon the tube plugs.

Response to Question 5 There are currently four tubes plugged among the four CNP Unit 1 Model 51R steam generators.

Specifically, there are two plugs in SG 11, one plug in SG 13, and one plug in SG 14. The type of plugs used are Framatome Inconel 690 rolled plugs. The stress analysis and specifications for these plugs used parameters applicable to the original plant design and uprated power conditions (i.e., 3264 MWt and 3600 MWt NSSS thermal power conditions) that have been considered in the structural integrity evaluation, as discussed in Section IV.5.2 of Attachment 3 to Reference 2.

to AEP:NRC:2902 Page 5 Thus, the plugs in use in the CNP Unit 1 steam generators have been analyzed to conditions that bound the 1.66 percent MUR power uprate conditions. Therefore, the effect of the MUR uprate on the tube plugs has been addressed by the existing bounding analyses.

NRC Question 6 In RIS 2002-03,Section IV 5.2, "StructuralIntegrity Evaluation," you state that "Results of the analyses performed on the BWI Series 51 steam generators show that all steam generators components continue to meet American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code,Section III, 1989 Edition, limits for the 1.66 percent uprate conditions with the reactor coolant system (RCS) pressure at 2100 psia. The primary-to-secondary pressure differential remains below the design value of 1600 psid. For operation with the RCS at 2250 psia, the primary-to-secondarypressure differential remains below the design value of 1600 psid,provided the secondary side steam pressure is limited to 679 psia." Based on the last sentence, the NRC staff believes you are stating the ASME limits will not be met under the uprate conditions when the RCS pressure is 2250 psia and the secondary side steam pressure is not limited to 679 psia. The staff's understanding,based on their review of Table 3, Case 2, is that it is possible that the secondary side steam pressure may be as low as 618 psia. Based on this conclusion, explain why the power uprate conditions are acceptable. If the intent is to control the secondary side steam pressure such that it is limited to 679 psia, describe the vehicle under which this will be performed.

Response to Question 6 The NRC staff's understanding that American Society of Mechanical Engineers (ASME) limits would not be met under the uprate conditions (i.e., RCS pressure at 2250 psia) if the secondary side steam pressure is not limited to 679 psia is correct. The CNP Unit 1 MUR Uprate Program analyzed conditions with the secondary side steam pressure as low as 618 psia. A subset of the activities I&M will perform as part of the design change to install and implement the Leading Edge Flow Meter (LEFMTM ) CheckPlusTM system includes procedure revisions that address impacts. The 679 psia full-power steam pressure limitation for operation with reactor coolant pressure controlled to 2250 psia will be included in CNP Engineering Control Procedure ECP-1-05-01, "Precautions, Limitations, and Setpoints - Unit 1." In addition, the 679 psia limitation will also be incorporated into the Updated Final Safety Analysis Report (UFSAR) as part of the CNP Unit 1 LEFM CheckPlus system design change package. Once it is incorporated into the UFSAR and the Precautions, Limitations, and Setpoints documents, future plant changes will be required to consider this limitation. Although these changes were not specifically addressed in Attachment 4, "Commitments," of Reference 2, identification and resolution of UFSAR and procedural impacts are required under I&M's design change process, as specified in the first commitment in Attachment 4. Therefore, no new regulatory commitments will be initiated to track these procedure/UTFSAR changes.

to AEP:NRC:2902 Page 6 NRC Question 7 In RIS 2002-03,Section IV 5.3, "Tube Vibration and Wear, " you stated that "...the projected level of tube wear as a result of vibration would be expected to remain small, and will not result in unacceptablewear. " Provide the staff with additionaldetails (e.g., actualpossible increase in wear as a result of power uprate conditions). In addition, describe the basis used to conclude that "unacceptablewear" would not occur.

Response to Question 7 The CNP Unit 1 steam generators were designed and analyzed to conditions that bound the 1.66 percent MJR power uprate conditions. Specifically, the steam generator tube vibration and wear evaluations were performed for individual steam generator power values of 816 MWt, 856 MWt, and 900 MWt (which correspond to total NSSS power levels of 3264 MWt, 3424 MWt, and 3600 MWt, respectively). Thus, the conditions assumed for the existing tube wear analyses bound the 1.66 percent power uprate conditions. Evaluations were also performed to estimate the potential for tube wear, as indicated by the determination of a fretting wear damage parameter, as defined in Reference 8. These evaluations show that the potential fretting wear would remain low. Specifically, the calculations for the 816 MWt individual steam generator power (i.e., 3264 MWt total NSSS power) indicate that the fretting wear damage parameter is 2.17E-3 kg-sec13, which is less than the Reference 8 limit of 4.OE-3 kg-sec' 3.

Evaluations for the 1.66 percent power uprate condition indicate that an increased level of tube wear would result. The increase in the fretting wear damage parameter value was determined to result in a fretting wear damage parameter of approximately 3.3E-3 kg-sec"1 , which continues to remain below the previously established limit of 4.0 E-3 kg-secI" . From these evaluations, it was concluded that the increased level of wear that would occur at the uprated operating conditions would not be significant.

NRC Question 8 In RIS 2002-03,Section IV.5.4, "'RegulatoryGuide 1.121 Analysis, " you state "The Regulatory Guide 1.121 analysis establishes minimum wall requirements for transient conditions correspondingto the 30 percent Steam GeneratorTube Plugging (SGTP) case, which envelopes the primary-to-secondary pressure gradients for the 0 percent SGTP condition." In this analysis, is the assumed reactor coolantpressure 2250 psia (as seen in Table 3,) or 2100 psia?

State whether the assumed reactor coolant pressure bounds all possible pressures during operation (i.e., is the most bounding), and if not, analyze the bounding case and provide the results.

to AEP:NRC:2902 Page 7 Response to Question 8 The Regulatory Guide (RG) 1.121 analysis performed for CNP Unit I in support of the MUR Uprate Program determined tube structural limits for a full range of "at power" operating conditions as shown in the following table. The extremes of the full-power average reactor coolant temperature (i.e., High Tavg and Low Tavg) were considered, as well as reactor coolant pressure values at both 2100 psia and 2250 psia. The analysis assumed a 30-percent steam generator tube plugging level, since this configuration envelopes the primary-to-secondary pressure gradients for the zero plugging condition.

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tf a 0i flt fflI*n High Tavg Low Tayg High Low High Low Condition Parameter Pressure Pressure Pressure Pressure Normal P. (psia) 2250 2100 2250 2100 Operation Po(psia) 765 765 690 618 AP (psi) 1485 1335 1560 1482 tmin (in) 0.022 0.020 0.023 0.022 Transient P, (psia) 2702 2787 2723 2824 Conditions P.(psia) 1133 1133 1133 1133 AP (psi) 1569 1654 1590 1691 tmn (in) 0.018 0.019 0.018 0.019 Faulted P, (psia) 2500 2500 2500 2500 P.(psia) 15 15 15 15 AP (psi) 2485 2485 2485 2485 tm.. (in) 0.018 0.018 0.018 0.018 tmi. (inches) 0.022 0.020 0.023 0.022 Structural Limit (%) 55.1 59.2 53.1 55.1 Note:

Structural Limit = [(tnom - tmn) / tnoM] X 100%

tnom = 0.049 inch Legend for "Summary of Tube Structural Limits MUR Power Uprate Program Conditions" TaVg - vessel average temperature P, steam generator tube inside pressure (primary side pressure)

PO - steam generator tube outside pressure (secondary side pressure)

AP -P, -P 0 tmrn - minimum steam generator tube thickness tnom - nominal steam generator tube thickness to AEP:NRC:2902 Page 9 NRC Question 9 In RIS 2002-03,Section IV.5.3, "Tube Vibration and Wear, "you describethe potential effects of the 1.66 percent MUR on steam generator tube wear. Discuss the potential effects of the 1.66percent MUR on other potential modes of steam generator tube degradation (e.g., axial and/orcircumferentialcracking, etc.).

Response to Question 9 The RG 1.121 analysis establishes the limiting safe condition of degradation in the tubes beyond which tubes found defective by the established in-service inspection shall be removed from service. The allowable tube repair limit includes an allowance for degradation growth until the next scheduled inspection. The RG 1.121 analysis performed for the proposed 1.66 percent uprate of CNP Unit 1 considered parameter ranges that bound the 1.66 percent uprate conditions (as discussed further in the response to Question 8). Thus, the effects of the 1.66 percent uprate on steam generator tube degradation modes, such as axial or circumferential cracking, have been incorporated into the tube structural limits determined in accordance with RG 1.121.

CNP Unit 1 steam generators are designed and analyzed for a range of parameters and power levels that bound the conditions applicable to the proposed 1.66 percent uprate. Specifically, parimeters representative of both original plant design and uprated power . conditions (i.e., 3264 MWt and 3600 MWt NSSS power conditions) have been considered in the structural integrity evaluation, as discussed in Section IV.5.2 of Attachment 3 to Reference 2. Therefore, the proposed 1.66 percent power uprate of CNP Unit 1 remains bounded by the current structural design analyses and no new modes of steam generator tube degradation are introduced.

NRC Question 10 Discuss the impact the power upratewill have on the requiredfrequencyof steam generatortube inspections.

Response to Question 10 Steam generator tube inspections will be conducted at a frequency that is the more restrictive of either TS 3/4.4.5, "Reactor Coolant System, Steam Generators," or Electric Power Research Institute (EPRI) publication TR-107569-VlR5, "PWR Steam Generator Examination Guidelines," (Reference 9). I&M adopted EPRI publication TR-107569-VlR5 in accordance with the implementation guidance of NEI 97-06, "Steam Generator Program Guideline,"

(Reference 10). An increase in inspection frequency in terms of the number of steam generators inspected and the sample size of tubes inspected depends on the progression (if any) of degradation. None of the potential degradation mechanisms are significantly affected by the to AEP:NRC:2902 Page 10 1.66 percent power uprate conditions; therefore, the required frequency of inspection is also not affected significantly by the proposed Unit 1 MUR power uprate.

NRC Question 11 RIS 2002-03, Section VIL.6.4 discusses the Flow-Accelerated Corrosion (FAC) Program. The NRC staffhas the following questions related to the FAC Program:

"* Briefly describe the purpose and elements of the FAC Program.

" The submittal states that "Flowrates and temperaturesfor piping components within the scope of the FAC Program remain within the system design specifications." Explain how the system design specifications are used in the FAC Program (e.g., what decisions/assessments are made based on designflowrates and temperatures).

" Identify the software utilized as part of the FAC Program to model the piping systems.

Identify the source (e.g., design values, actual values, etc.) of the input parameters (e.g.,

operatingpressures,flowrates and temperatures) to the softwareprogram.

" Please discuss whether any additionalsystems will need to be added to the FAC Program as

a. result of the power uprate. Also discuss whether the power uprate will result in. any changes to the software input parameters. If software input parameters will be affected, summarize the significance of the overall impact on FAC Program activities.

Response to Question 11

Flow-Accelerated Corrosion (FAC) Program - Purpose and Scope The purpose of the FAC Monitoring Program is to predict, detect, monitor, and mitigate FAC in plant piping. The scope of the program consists of all piping and components that cannot be demonstrated to be non-susceptible to FAC as documented in the current FAC System Susceptibility Evaluation.

The main elements of the program are as follows:

Scope Identification Based on an evaluation of plant piping systems, piping and components that are susceptible to FAC are identified and included within the scope of the FAC Program.

to AEP:NRC:2902 Page I11 Evaluation and Modeling Once identified, each susceptible line of plant piping is evaluated and addressed to ensure that the probable level of degradation is ascertained and appropriate action is taken. This is normally accomplished by modeling the line using the EPRI software program, CHECWORKSTM. Some FAC-susceptible lines and components cannot be modeled in CHECWORKS due to uncertain operating conditions, software limitations, or other factors.

These lines are addressed in the "susceptible non-modeled" (SNM) sub-program.

Inspection Components are selected for inspection, based on CHECWORKS predictions, SNM selection criteria, past inspection results, and operating experience. Selected large-bore components (nominal diameter greater than 2 inches) are inspected during refueling outages using ultrasonic testing. Small-bore components (nominal diameter 2 inches or less) are typically inspected on-line using radiography. While radiography is preferred, ultrasonic testing is also an acceptable methodology for these components.

Data Analysis The inspection results for CHECWORKS-modeled components are entered into the CHECWORKS model to calibrate the model. In addition, the component's remaining life is calculated by comparing the inspection results to the acceptance criteria. The results of this analysis are compared to the procedural acceptance criteria to determine:

"* if a follow-up inspection is required and when it should be scheduled,

"* if inspections at additional locations are needed in the current outage, and

"* if the component requires repair or replacement - either immediately or during a future outage.

" The operating pressure, temperature, and flowrate are inputs to the CHECWORKS model, which is used to predict the FAC wear rate in the susceptible components. The MUR power uprate will result in changes to these operational values. The values will be revised in the CHECWORKS model to predict future wear rates. These changes will be minimal, and the system operating parameters will remain within the design limits.

" The EPRI CHECWORKS software is used by CNP's FAC Program to model the piping systems. The source of the input parameters is actual cycle-specific values, and the FAC Program directs these values to be changed and maintained in the software if the values change in the field.

to AEP:NRC:2902 Page 12 A review of heat balances that reflect the effect of the MUR power uprate on FAC-related parameters indicates that no additional systems, piping, or other components need to be added to the FAC Program as a result of the MUR power uprate. The FAC Program will direct changes to the CHECWORKS input parameters for changes to system flowrates, temperatures, and pressures. A revised plant heat balance calculation indicates that the changes are minimal and the MUR uprate is not expected to significantly affect the current wear predictions of the CHECWORKS software.

NRC Question 12 Provide the details of how the power uprate will effect the steam dump system capabilities.

Response to Question 12 Westinghouse sizing criterion recommends that the steam dump system (valves and pipe) be capable of discharging 40 percent of the rated steam load at full-load steam pressure to permit the NSSS to withstand an external load reduction of up to 50 percent of plant rated electrical load without a reactor trip. The current design requirement stated in the UFSAR is for the steam dumps, or turbine by-pass system, to have a capacity of approximately 40 percent of full-load steam flow. The 1.66 percent power uprate affects the steam dump capability in several ways.

First, the full-load steam flow value increases with the uprate, so for a fixed steam flow through the steam dump valves, the capacity in terms of full-load steam flow is reduced. Secondly, the full-power steam pressure is reduced for increased steam flow conditions, given other parameters remain constant (e.g., Tavg and RCS flow rate). The net effect of the 1.66 percent power uprate is a slight reduction in the available steam dump capability, for a given set of RCS parameters.

As indicated in Section VI.2.1 of Reference 1, a final steam dump valve flow capacity analysis is in progress to determine the appropriate steam dump travel stop position. Based upon a Westinghouse evaluation, a capability of approximately 45 percent of full-load steam flow can be achieved with the travel stops removed, even if a conservatively low steam pressure of 618 psia is assumed. The uprated steam pressure will remain above 679 psia, as discussed in Section IV.5.2 of Reference 1, and further clarified in I&M's response to Question 6, above. To satisfy the commitment made by I&M in Reference 1, the steam dump travel stop position will be adjusted to the proper position prior to implementing the 1.66 percent power uprate.

NRC Question 13 Provide the details of how the power upratewill affect airand hydraulic operatedvalves.

to AEP:NRC:2902 Page 13 Response to Question 13 A review of heat balances that reflect the effect of the 1.66 percent power uprate on system design function parameters indicates that there is no impact on the ability of air and hydraulic-operated valves (AHOVs) to perform their design function in the systems affected by the MUR power uprate. No additional AHOVs were identified as being impacted by the MUR Uprate Program. As a result, no changes will be required to the AHOV Program due to the MUR power uprate.

NRC Question 14 In the application, the pressure temperature curves on Figure 3.4-2 of the technical specifications (TS) have been changed to reflect the effects from the power uprate. By letter dated May 3, 2002, you stated the pressure temperature curves in the TS did not reflect the most limiting material. Pleaseprovide calculations and revised TS pages that reflect both the power uprateand the most limiting material.

Response to Question 14 In an August 13, 2002, telephone conference with the NRC Staff, I&M committed to revise the pressure-temperature (P-T) limit curves applicability limits proposed by Reference 2 to include the effects of the new limiting reactor vessel beltline material, as well as the increased neutron fluence associated with the 1.66 percent power uprate. A supplement to Reference 2 that will revise the proposed P-T curves applicability limits will be provided under separate cover. The revised applicability limits in the license amendment request supplement will reflect the results of a recent computation based on the uprated power level and considering the new limiting reactor vessel beltline material. The license amendment request supplement will also withdraw the proposed change to the reactor vessel surveillance schedule, as implementation of this change is not required for the MUR power uprate.

NRC Question 15 In response to item I.1.D of RIS 2002-03, Attachment 1, Submittal Attachment 3, cites WCAP-8567for a descriptionof "Improved Thermal Design Procedure" (ITDP) and states that NRC has approved the use of ITDP at Cook Nuclear Plant Unit 1. The reference citedfor this approval does not include NRC review and acceptance of thisprocedurefor general use. Please clarify. Please describe the applicationof ITDPfor the requestedpower uprate.

Response to Question 15 The use of Westinghouse WCAP-8567, "Improved Thermal Design Procedure," was initially approved for CNP Unit 1 in the NRC's Safety Evaluation Report (SER) for Unit I License to AEP:NRC:2902 Page 14 Amendment 74, dated September 20, 1983 (Reference 11). Reference 11 should be used in place of Unit 1 License Amendment 126 (Reference 1.6 of the Unit 1 MUR Uprate Program License Amendment Request, Reference 2), which approved a more recent use of the ITDP methodology at CNP Unit 1.

I&M applied the ITDP methodology for the requested 1.66 percent power uprate by identifying the individual contributors to the accuracy of the thermal power calorimetric. The error components (sensitivities) are combined statistically using the square root of the sum of the squares (SRSS) methodology to calculate the total reactor thermal power accuracy. Typically, error components that are dependent are combined arithmetically into independent groups, which are then statistically combined.

NRC Question 16 The "Sensitivity % Rated Thermal Power (RTP)""column of the submitted table appears to be mislabeled, and appears to represent the product of RTP sensitivity and the uncertainty in the various parametermeasurements. The reference in that same table to "Root Mean Squared (RMS) " is interpretedto have been intended to mean "Square Root Sum of the Squares (SRSS)."

Response to Question 16 The "Uncertainty" and the "Sensitivity" columns of Table I-1 are directly related. The "%RTP" is intended to indicate that the units of the "Sensitivity" column are in percent of rated thermal power and not in the process units associated with the "Parameter" column. Total uncertainty was determined by varying each process parameter about a base value and determining the corresponding sensitivity of percent rated thermal power (%RTP). As an example, at the current 100 percent RTP, the feedwater pressure is 725.10 pounds per square inch - gauge (psig). The uncertainty of the feedwater pressure input to the plant process computer (PPC) calorimetric program is determined to be +/-15 psig. Thus, if the actual feedwater pressure is 725.10 psig, and an error as large as +/-15 psig is possible at the point that the feedwater pressure signal is input to the PPC, the corresponding error in the calculated %RTP could be as large as +/-0.00 1753 %RTP.

Thus, Table I-1 shows that the sensitivity of %RTP to a change in feedwater pressure of +/-15 psig is +/-0.001753 %RTP.

As noted, the reference in this same table to root mean squared (RMS) should have been referenced to SRSS.

Attachment 4 to AEP:NRC:2902 Page 15 NRC Question 17 In your Submittal Attachment, 3 Section I.1.G/H, bullet 5 you state that failure of one plane of leading edge flow meter (LEFM) transducers would not affect power measurement, and cites Caldon Topical Report ER-157P and the associated Safety Evaluation Report (SER) as justificationfor this claim. The report and the associatedSER do not support this claim. Loss of an entire detection plane in an LEFM CheckPlus system would render it functionally similar to an LEFM Check system. Such a reduced system would not be optimized for single-plane use, and so performance would likely fall short of a properly configured LEFM Check system.

ER-15 7P clearly indicates a significant difference in accuracy between the Check and CheckPlus flowmeters. The topical report and SER indicate that continued operation without reduction in power with one LEFM CheckPlus component out of service might bejustifiable, but leaves it up to the applicantto provide the justification. Pleaseclarify.

Response to Question 17 Reference 2, Attachment 3, Section 1.1.G/H, Bullet 5, is deleted from this license amendment request by the following discussion. Implementation of the MUR Uprate Program will develop administrative controls that will ensure that loss of a single plane of transducers in the LEFM CheckPlus system is considered an LEFM out-of-service condition. This will eliminate the concern pertaining to the accuracy of the LEFM with the loss of a single plane of transducers.

Attachment 4, "Commitments," of Reference 2 included a commitment to install the new LEFM CheckPlus system at CNP Unit 1. As noted in the commitment, the design change for the installation includes development of system out-of-service administrative requirements. Because the development of out-of-service administrative requirements is already being tracked by this commitment, no new regulatory commitments will be initiated to track this activity.

NRC Question 18 The applicationrefers to a serial link between the LEFM and the PPC(PlantProcess Computer) and states that the venturi-basedinstrument will always be calibratedin accordancewith the last "good" valuefrom the LEFM. However, there is no discussion of the timing or operation of this link or of the calibration adjustment. Please provide a discussion of: a) the nature and operation of the serial link, b) the schedule by which the venturi-basedflowmeter calibration is adjusted, c) the method for adjusting the venturiflowmeter calibration, and d) the means for distinguishing "good"from "bad" LEFM datafor the purpose of calibrationadjustment of the venturi meter.

to AEP:NRC:2902 Page 16 Response to Question 18

a. Nature and Operation of the Serial Link The serial data link consists of the hardware and software used by the PPC to acquire data and status information from the Caldon LEFM CheckPlus system output and to store this information within the PPC for use by other applications.

A serial interface device is used to interface the PPC with the LEFM equipment via serial links.

The device is connected to the ethernet local area network (LAN). A separate port on the serial device is connected to each LEFM link via an RS-232 serial cable. Since there are two links from the LEFM, Port 1 of the serial device is connected to CPU-A of the LEFM, while Port 2 is connected to CPU-B of the LEFM. The Data Link software uses specific operating system service calls to access and read the ports of the serial device. The data link does not provide any automatic update between the venturi and LEFM flowmeters. The process for adjustment between the venturi and LEFM power outputs is manual and is described below.

The venturi calorimetric and the LEFM calorimetric are completely separate and are performed independently by the PPC. Each program performs independent calculations to determine core thermal power.

b & c. Venturi Flowmeter Calibration Following LEFM Loss The venturi instrumentation is not "calibrated" on-line by a linkage to the LEFM. Instead, the venturi calorimetric calculated power is manually adjusted; i.e., calibrated to the last "good" LEFM calorimetric and the corresponding venturi calorimetric at that same time. This is performed by retrieving the last good thermal power computed by the LEFM (PL) and comparing it to the thermal power computed by the venturis (Pv) at that same time. A correction factor (CF) is then calculated by taking the ratio of the last good LEFM calorimetric power value to the venturi power value at that same time (i.e., CF = PL / Pv). For the 48-hour period proposed in Reference 2, during which operation at the uprated power would be allowed as long as steady-state conditions exist, the corrected calorimetric power would be computed as being equal 0 = CF x Pv).

to the current venturi calorimetric power multiplied by the correction factor (PcoR Plant operating procedures will be revised to ensure that should the LEFM out-of-service condition not be corrected, Operations will reduce plant thermal power level such that the plant is operating at or below the pre-uprate power level limit of 3250 MWt at the time that the 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months has elapsed. Attachment 4, "Commitments," of Reference 2 included a commitment to install the new LEFM CheckPlus system at CNP Unit 1. As noted in the commitment, the design change for the installation includes development of operational procedures. Therefore, no new regulatory commitments are required to track this procedure change.

to AEP:NRC:2902 Page 17

d. Distinguishing "Good" from "Bad" LEFM Data The last "good" value of the LEFM power calorimetric will be the last retrievable data point with a status of "good." The method of identifying the status of LEFM data by the electronic unit and the alarms to the operator are described in the Caldon documentation located in the CNP vendor documentation program and the software design descriptions for the data link and the calorimetric program.

NRC Question 19 If the plant computer or the plant computer serial link from the LEFM is not operational, automaticpower calculationswill not be performed. Please show that these conditions, and any other conditions that might interfere with automatic operation,areproperly accountedfor in the procedures and in appropriate limitations associated with the proposed modification. In particular,show that, despite such conditions, the venturi-basedflowmeter calibration will remain sufficiently correlatedwith the LEFM calibrationto support continued operation above the pre-upratepower limit in the event ofLEFMfailure.

Response to Question 19 The adjustment of the power-level calculated by the venturi upon a loss of the LEFM is explained in the response to Question 18. A PPC failure would be treated as a loss of both the LEFM and the ability to obtain a corrected calorimetric power using the venturis. This would result in reducing plant power to the pre-uprated rated thermal power limit of 3250 MWt. The 48-hour time period would not apply in this specific case, as a manual calorimetric would be required. The manual calorimetric only supports operation at plant power levels up to 3250 MWt.

NRC Question 20 Please show that the time limit establishedfor continued operation above the pre-upratepower limit with the LEFM out ofserviceproperly accountsfor:

decay ofventuri-basedflowmeter accuracyfrom the most recent LEFM-based calibrationupdate to the time of LEFMfailure, continued operationfrom the time ofLEFMfailure to the initiationofpower runback, and continued operation during power runback, until the indicatedpower is at or below the pre upratepower limit.

to AEP:NRC:2902 Page 18 Response to Question 20 During past refueling outages, the feedwater venturis were inspected for evidence of fouling.

The results of these venturi inspections have consistently indicated that the Unit I feedwater venturis do not experience fouling. Based on this evidence, feedwater venturi fouling that would result in degradation of the accuracy of these components is not expected. Thus, venturi fouling that would degrade flowmeter accuracy would not be expected over the 48-hour period that the LEFM is not operational.

As discussed in the response to Question 18, upon LEFM failure, the venturi power calorimetric values would be adjusted (i.e., calibrated to the last valid power output of the LEFM prior to the time of LEFM failure). Expectations of instrument drift vary depending upon the manufacturer's specifications. However, values of drift are typically in the range of tenths of a percent of the calibrated span over 18 to 24 months or more. This typical drift value would not result in any significant drift for the instrumentation associated with the calorimetric measurements over a 48-hour period.

In accordance with plant operating procedures, power reduction will occur to ensure that the plant will be at or below the pre-uprate power limit, 3250 MWt, within 48-hours in the event of a loss-of-LEFM condition. In the case of a loss of the PPC, the operating procedures will ensure that the plant transitions to the pre-uprate power level, as needed to support the manual calorimetric measurement using the venturis.

Therefore, operation over the period that the LEFM is out of service is justified using the venturis, as applicable.

NRC Question 21 Please specify the time allowed from initiation of power runback until core power reaches the pre-upratepower limit, in the event of extended LEFMfailure.

Response to Question 21 For the LEFM out-of-service condition, the 48-hour "clock" will start at the time of LEFM failure. Failure will be annunciated in the control room on the PPC screen that displays the calorimetric power level. The LEFM electronic unit and central processing unit (CPU) continuously monitor, test and/or verify the following attributes of the LEFM operation:

"* Acoustical processing units

"* Analog inputs

"* Test paths

"* Signal quality to AEP:NRC:2902 Page 19

"* Path-to-path sound velocity

"* Velocity profiles

"* Watchdog timer

"* Flowrate calculations uncertainty verified against specified System Uncertainty Threshold

"* Meter path operation (i.e., signal quality, sound velocity to specified thresholds)

"* Meter velocity profile (i.e., changes in hydraulic profile, verified against specified thresholds)

The procedures for power reduction will be in accordance with current operating procedures such that the plant will be operating at, or below, the pre-uprate power level limit of 3250 MWt by the time the 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months has elapsed. For the loss-of-PPC case, the 48-hour limit does not apply and power reduction will be in accordance with current operating procedures such that the plant will transition to a power level at, or below, the pre-uprate power level limit of 3250 MWt, as described in response to Questions 18 and 19.

NRC Question 22 RIS 2002-03, Attachment 1,Section I.1.F requests certain information concerning all instrumentation involved in the power calorimetric. The licensee's response to this item addresses only the LEFM. Please provide the requested information for the remaining instrumentation.

Response to Question 22 In addition to the process inputs provided by the LEFM CheckPlus system, the PPC program uses the following process inputs to calculate thermal power:

"* Steam Pressure

"* Blowdown Flow

"* Charging Flow

"* Charging Temperature

"* Charging Pressure

"* Letdown Flow

"* Letdown Temperature

"* Letdown Pressure

"* Pressurizer Pressure

"* RCS Loop 4 Cold Leg Temperature

"* Volume Control Tank (VCT) Temperature Blowdown flow measurement is performed by a Caldon ultrasonic measurement system.

Calibration of this ultrasonic measurement system is maintained using self-checking and self-adjusting methods. The value and status of the blowdown flow measurement are provided to the PPC. If the status of the blowdown flow measurement or the failure of the blowdown flow to AEP:NRC:2902 Page 20 system indicates that the status is "bad", this is reflected in the PPC calorimetric program and results in the status of the LEFM calorimetric values also indicating a "bad" status. Control of the ultrasonic measurement system is maintained by the CNP change control process. Hardware control of the ultrasonic measurement system is provided by the CNP design change control process, which conforms to 10 CFR 50, Appendix B, and control of the system software is provided by CNP's software control process.

The remaining process inputs are obtained from analog instrumentation channels that are maintained and calibrated in accordance with required periodic calibration procedures.

Configuration of the hardware associated with these process inputs is maintained in accordance with the CNP change control process.

Instruments that affect the power calorimetric, including the LEFM inputs, are monitored by CNP's System Engineering personnel in accordance with the requirements of I&M's Corrective Action Program. Equipment problems for plant systems, including the LEFM CheckPlus equipment, fall under the site work control processes. Conditions that are adverse to quality are documented under the Corrective Action Program. Corrective Action procedures, which ensure compliance with the requirements of 10 CFR 50, Appendix B, include instructions for notification of deficiencies and error reporting.

Calibration and maintenance are performed by CNP Instrumentation and Controls (I&C)-Maintenance Department personnel using site procedures. Site procedures are developed using the vendor technical manuals for the applicable equipment. All work is performed in accordance with site work control procedures. Routine preventive maintenance procedures include physical inspections, power supply checks, back-up battery replacements, and internal oscillator frequency verification. Corrective actions involving maintenance will be performed by I&C-Maintenance Department personnel, qualified in accordance with I&M's I&C Training Program.

Plant procedures ensure compliance with the requirements of 10 CFR Part 21.

NRC Question 23 Please confirm that the installation of the new flowmeter will not adversely affect the performance of the existingflow instrumentation.

Response to Question 23 For Unit 1, the Caldon LEFM flow-measuring device is installed at least 124 feet upstream of the venturi and other feedwater flow instrumentation. The path between these instruments also includes at least six 90-degree elbows or tees, three flow valves, and three different pipe diameters. This is a sufficient equivalent length of pipe, in terms of the number of pipe to AEP:NRC:2902 Page 21 diameters and flow resistance elements, to prevent hydraulic interference between these instruments. Therefore, there is no hydraulic communication between these instruments that would cause interference due to the installation of the new Caldon LEFM flow-measuring device.

NRC Question 24 Please clarify item I.1.G/H of Attachment 3 of your application to Reference 1 to address operationat any power level in excess of the pre-uprate limit notjust exactly at the new limit.

Response to Question 24 I&M concurs with the NRC staff's interpretation that Item I.1.G/H of Attachment 3 to Reference 2 should be interpreted to refer to plant operation at any power level in excess of the pre-uprate limit, up to the new limit.

NRC Question 25 Please provide a copy of the calculation that establishes the thermal power measurement uncertainty, as requestedin Item L .E of Attachment 1, and reiteratedand explained in Items 1.2, 1.6, and 1.7 of Attachment 2, to RIS 2002-003. Item G.6 of RIS Attachment 2 also requests detailed information.

Response to Question 25 Calculation 1-2-01-03 CALC 2, Revision 1 "Power Calorimetric Accuracy using the Caldon Check Plus Feedwater Flow Measurement System and a modified PPC CALM Program," which establishes the thermal power measurement uncertainty for the proposed 1.66 percent power uprate, will be provided under separate cover.

References from Unit 1 RAI Response (from Attachment 1 to AEP:NRC:2900-01)

1. Letter from J. F. Stang (NRC) to A. C. Bakken III, I&M, "Donald C. Cook Nuclear Plant, Unit 1 - Request for Additional Information Regarding License Amendment Request, 'Power Uprate Measurement Uncertainty Recapture,' dated June 28, 2002 (TAC No. MB5498)," dated October 2, 2002

2. Letter from J. E. Pollock (I&M) to NRC Document Control Desk, "License Amendment Request for Appendix K Measurement Uncertainty Recapture - Power Uprate Request," AEP:NRC:2900, dated June 28, 2002 to AEP:NRC:2902 Page 22

3. Letter from R. P. Powers, I&M, to NRC Document Control Desk, "Donald C. Cook Nuclear Plant Units 1 and 2, Technical Specification Change Request Containment Recirculation Sump Water Inventory," C 1099-08, dated October 1, 1999

4. Letter from J. F. Stang, NRC, to R. P. Powers, I&M, "Issuance of Amendments Donald C. Cook Nuclear Plant, Units 1 and 2 (TAC Nos. MA6766 and MA6767),"

dated December 13, 1999

5. Letter from R. P. Powers, I&M, to NRC Document Control Desk, "Donald C. Cook Nuclear Plant Units 1 and 2, License Amendment Request for Credit of Rod Cluster Control Assemblies for Cold Leg Large Break Loss-of-Coolant Accident Subcriticality," C0999-1 1, dated September 17, 1999

6. Letter from J. F. Stang, NRC, to R. P. Powers, I&M, "Issuance of Amendments Donald C. Cook Nuclear Plant, Units 1 and 2 (TAC Nos. MA6473 and MA6474),"

dated December 23, 1999

7. Letter from J. F. Stang, NRC, to R. P. Powers, I&M, "Donald C. Cook Nuclear Plant, Units 1 and 2 - Issuance of Amendments (TAC Nos. MB0739 and MB 0740)," dated October 24, 2001

8. Pettigrew, M. J, Taylor, C. E. and Subash, N. "Flow Induced Vibration Specifications For Steam Generators and Liquid Heat Exchangers", AECL-11401, Chalk River Laboratories, Chalk River, Ontario, November 1995

9. EPRI TR-107569-V1R5, "EPRI PWR Steam Generator Examination Guidelines,"

September 1997

10. NEI 97-06, "Steam Generator Program Guideline"

11. Letter from D. L. Wigginton, NRC, to J. Dolan, I&M, issuing CNP Unit 1 License Amendment 74, dated September 20, 1983 to AEP:NRC:2902 Page 23 Applicability of RAI Questions/Reponses to Unit 2 MUR Uprate and Location of Discussion Applicability of Question 1 to Unit 2 MUR Uprate I&M has reviewed the subject NSALs for impact on the Unit 2 Westinghouse-designed steam generators. The results of this review indicate that the current analyses remain conservative, and the Unit 2 MUR power uprate is supported by the evaluations summarized in Attachment 3 of this letter. As the guidance provided in Regulatory Issue Summary 2002-03, "Guidance on the Content of Measurement Uncertainty Recapture Power Uprate Applications," did not specify a requirement to review vendor-generated advisory letters, this review is not addressed in to this letter. The evaluation of the three potential concerns identified by the subject NSALs are discussed in the paragraphs that follow.

The Westinghouse NSALs that identified steam generator level concerns (i.e., NSAL 02-3, including Revision 1, NSAL 02-4, and NSAL 02-5) were entered into the CNP Plant Operating Experience database, and have been evaluated in accordance with the CNP Corrective Action Program.

NSAL-02-3 identified a potential concern regarding the impact on steam generator water level low-low setpoint margin due to additionally recognized differential pressure within the steam generator which could affect the pressures measured across the upper and lower narrow range span instrumentation. The additional differential pressure was identified across the steam generator mid-deck plate at the top of the primary separator assembly. The CNP Unit 2 steam generators were identified to be impacted, and the full-load mid-deck pressures differential was reported by Westinghouse to be 0.17 psid. I&M's evaluation of this condition determined that adequate margin is available in the steam generator water level low-low trip setpoint calculation to accommodate the effects of a differential pressure across the steam generator mid-deck plate.

Thus, the existing steam generator water level low-low trip setpoint remains unaffected, and there is no effect on the setpoint values used in the analyses of record for the loss-of-coolant accident (LOCA), non-LOCA transients, and the Anticipated Transient Without Scram (ATWS) event. Therefore, the current analyses remain conservative, and the Unit 2 MUR power uprate is supported by the evaluations presented elsewhere in this submittal.

NSAL-02-4 identified a potential indication accuracy concern with the steam generator water level high-high trip setpoint for water levels above the steam generator mid-deck plate. The source of the inaccuracy is due to void content in the two-phase mixture above the steam generator mid-deck plate. The evaluation of this condition determined that the CNP Unit 2 trip setpoint would be reached before the steam generator water level would reach the mid-deck plate level. Thus, the indication accuracy concern for water levels above the mid-deck plate is not of concern for CNP Unit 2, and the existing steam generator water level high-high trip setpoint remains acceptable. Therefore, there is no effect on the setpoint values used in the analyses of to AEP:NRC:2902 Page 24 record, and the current analyses remain conservative. Consequently, the Unit 2 MUR power uprate is supported by the evaluations presented elsewhere in this submittal.

NSAL-02-5 also involved the potential effects of the pressure differential across the steam generator mid-deck plate, but the focus was on the potential impact to the initial steam generator water level modeled in the accident analyses due to increased water level uncertainty. The specific accident analyses of interest were: Loss of Normal Feedwater / Loss of All AC Power to the Station Auxiliaries, Feedwater Malfunction, Feedline Break, Steamline Break Mass and Energy Release calculations, and LOCA mass and energy release calculations. I&M performed an evaluation of this condition, with the assistance of Westinghouse who has performed the potentially affected analyses of record. The evaluation determined, in all cases, that the conclusions of the current analyses remain applicable and bounding due to existing available margin in one or more of the following areas: the initial steam generator water mass that has been assumed in the applicable analysis; conservative power level values used in the analyses of record and the corresponding decay heat load; simplified analysis models that conservatively ignore heat sinks available by thick metal mass; and margin between the calculated results and the applicable acceptance criteria. Thus, the current analyses of record for the events cited above continue to remain bounding. Therefore, the current analyses remain conservative and the Unit 2 MUR power uprate is supported by the evaluations presented elsewhere in this submittal.

Applicability of Question 2 to Unit 2 MUR Uprate The post-LOCA analysis issues that were the presented in response to Question 2 apply to both Units 1 and 2. This information is provided in Section 11.1.3, "Post-Loss of Coolant Accident Analyses," of Attachment 3 to this letter.

Applicability of Question 3 to Unit 2 MUR Uprate and Location of Discussion The total power measurement uncertainty calculation that was submitted to the NRC by Reference 4 is applicable to both CNP Units 1 and 2. Reference to this correspondence is is provided in Section 1.1.E of Attachment 3 to this letter.

Applicability of Question 4 to Unit 2 MUR Uprate As noted in Section 11.1.4 of Attachment 3 to this letter, the NRC-approved Unit 2 supplemental SGTR margin to steam generator overfill analysis assumed a nominal nuclear steam supply system (NSSS) power level of 3600 MWt (i.e., 3588 MWt core power level). Therefore, the power level assumed for the current SGTR margin-to-overfill analysis bounds the proposed increase in the CNP Unit 2 core power to 3468 MWt.

to AEP:NRC:2902 Page 25 Applicability of Question 5 to Unit 2 MUR Uprate A summary of the evaluation of mechanical repair hardware for the Unit 2 steam generators is provided in Section IV.5.3 of Attachment 3 to this letter.

Applicability of Question 6 to Unit 2 MUR Uprate The design controls that will be implemented to ensure the full-power steam pressure limitation is maintained are addressed in Section IV.5.2 of Attachment 3 to this letter.

Applicability of Question 7 to Unit 2 MUR Uprate An evaluation of the CNP Unit 2 RSGs indicates that significant levels of tube vibration will not occur from either the fluidelastic, vortex shedding or turbulent mechanisms as a result of the MUR Uprate Program. The projected level of tube wear as a result of vibration is expected to remain small. This information is provided in Section IV.5.4 of Attachment 3 to this letter.

Applicability of Question 8 to Unit 2 MUR Uprate An evaluation was performed which demonstrated that the results of the RG 1.121 analysis are acceptable for the 1.66 percent power uprate. The resultant tube structural (minimum wall) limits are summarized in Table IV-1 and Section IV.5.5 of Attachment 3 to this letter.

Applicability of Question 9 to Unit 2 MUR Uprate Effects of the 1.66 percent MUR on other potential modes of steam generator tube degradation (e.g., axial and/or circumferential cracking, etc) were considered for Unit 2. This information is provided in Section IV.5.4 of Attachment 3 to this letter.

Applicability of Question 10 to Unit 2 MUR Uprate The impact of the Unit 2 MUR power uprate is addressed in a sub-section of Section IV.5.4, "Steam Generator Tube Integrity," of Attachment 3 to this letter. As discussed in Section IV.5.4, the required frequency of inspection is not affected significantly by the proposed Unit 2 MUR power uprate.

Applicability of Question II to Unit 2 MUR Uprate The activities, elements, and philosophy of CNP's FAC Monitoring Program are common to both Units 1 and 2. The review of heat balances that reflect the effect of the Unit 2 MUR uprate on FAC-related parameters also indicates that no additional systems or piping need to be added to AEP:NRC:2902 Page 26 to the FAC Program as a result of the Unit 2 MUR uprate. This information is provided in Section VII.6.4 of Attachment 3 to this letter.

Applicability of Question 12 to Unit 2 MUR Uprate Section VI.2.1 of Attachment 3 to this letter provides the details of how the power uprate will effect the steam dump system capabilities.

Applicability of Question 13 to Unit 2 MUR Uprate The methodology for evaluating AHOVs for Unit 2 is the same as that discussed for Unit 1.

Similarly, no AHOVs were identified as impacted and no changes will be required to the AHOV Program as a result of the MUR Uprate Program. This information is provided in Section VII.6.3 of Attachment 3 to this letter.

Applicability of Question 14 to Unit 2 MUR Uprate Reference 1 requested a change to the applicability date of the Unit 1 RCS Pressure-Temperature Heatup and Cooldown (P-T) Limit Curves to reflect the increased fluence rates associated with the 1.66 percent power uprate. A corresponding change is not requested in this Unit 2 MUR power uprate license amendment request, because the revised Unit 2 P-T limit curves that were submitted for NRC review in July 2002 (Reference 5) are based on a power level that bounds the 3468 megawatts thermal (MWt) requested by this license amendment request. This information is provided in Section IV.1.1, "Reactor Vessel Integrity - Neutron Irradiation," of Attachment 3 to this letter.

Applicability of Question 15 to Unit 2 MUR Uprate As noted in response to Criterion 3 of Section 1.1.D, the methodology used for evaluating reactor thermal power uncertainty for CNP Unit 2 is consistent with the accepted setpoint methodology of WCAP-1 1397-P-A, "Revised Thermal Design." The cited reference for the revised thermal design procedure (RTDP) methodology, as well as the NRC safety evaluation report that approved the RTDP for use at CNP Unit 2, were verified to be correct. Since the ITDP methodology is not used for the Unit 2, this question is not directly applicable to the Unit 2 MUR license amendment request.

Applicability of Question 16 to Unit 2 MUR Uprate The clarification provided in response to Question 16 has been incorporated into Section I.1.E of Attachment 3 to this letter. Additionally, the reference to Root Mean Squared (RMS) in Table I-1 has been changed to Square Root Sum of the Squares.

to AEP:NRC:2902 Page 27 Applicability of Question 17 to Unit 2 MUR Uprate The proposed allowed outage time for the Unit 2 LEFM CheckPlus system and the technical basis for the time selected reflect the information provided in response to Question 17 for Unit 1, above. Section 1.1.G/H of Attachment 3 to this letter indicates that administrative controls will be developed to specify that loss of a single plane of transducers in the LEFM CheckPlus system will be considered an LEFM out-of-service condition.

Applicability of Question 18 to Unit 2 MIUR Uprate The description of the serial data link is provided in Section 1.1 of Attachment 3 to this letter.

The method of distinguishing "good" data points, and the basis for the 48-hour allowed outage time (i.e., venturi fouling and instrument drift discussions) are provided in Section 1.1.G. The venturi flowmeter calibration methodology is presented in Section 1.1..H under the heading, "Venturi Flowmeter Calibration Following LEFM Loss."

Applicability of Question 19 to Unit 2 MUR Uprate The actions to be taken following a PPC failure will be the same for both Units 1 and 2 (although the de-rate power levels differ). These actions are discussed in Attachment 3,Section I.1.GiH, under the heading, "Power Level Adjustment Following a Plant Process Computer Failure."

Applicability of Question 20 to Unit 2 MUR Uprate The basis for determining that venturi fouling and instrument drift support the proposed 48-hour allowed outage time is provided in Section 1.1.G of Attachment 3 to this letter. The discussion of actions to be taken following an LEFM or PPC failure is provided in Section 1.1.H of to this letter.

Applicability of Question 21 to Unit 2 MUR Uprate This information is provided in Section 1.1.H of Attachment 3 to this letter.

Anplicability of Question 22 to Unit 2 MUR Uprate This information is provided in Section I.1.F of Attachment 3 to this letter.

to AEP:NRC:2902 Page 28 Applicability of Question 23 to Unit 2 MUR Uprate The location of the LEFM spool piece is discussed in Section 1.1, "Feedwater Flow Measurement Technique and Power Measurement Uncertainty," of Attachment 3 to this letter. There will be no hydraulic communication between the LEFM flow-measuring device and the existing flow instrumentation that would affect the performance of the existing flow instrumentation.

Applicability of Question 24 to Unit 2 MUR Uprate The response provided to Question 24 for the Unit 1 MUR power uprate request is also applicable to this Unit 2 MUR power uprate request.Section I.1.G of Attachment 3 to this letter provides the technical basis for allowed outage time for the LEFM CheckPlus system with the plant operating at any power level in excess of the current rated thermal power level of 3411 megawatts thermal (MWt).

Applicability of Question 25 to Unit 2 MUR Uprate The total power measurement uncertainty calculation that was submitted to the NRC by Reference 4 is applicable to both CNP Units 1 and 2. Reference to this correspondence is is provided in Section .1.E of Attachment 3 to this letter.

References The references in this list apply to the introduction to this Attachment and the Unit 2 applicability discussions only.

1. Letter from J. E. Pollock (I&M) to Nuclear Regulatory Commission (NRC) Document Control Desk, "License Amendment Request for Appendix K Measurement Uncertainty Recapture - Power Uprate Request," AEP:NRC:2900, dated June 28, 2002

2. Letter J. F. Stang (NRC) to A. C. Bakken III, I&M, "Donald C. Cook Nuclear Plant, Unit 1 - Request for Additional Information Regarding License Amendment Request,

'Power Uprate Measurement Uncertainty Recapture,' dated June 28, 2002 (TAC Nos.

MB5498)," dated October 2, 2002

3. Letter from J. E. Pollock (I&M) to NRC Document Control Desk, "Response to Nuclear Regulatory Commission Request for Additional Information Regarding License Amendment Request for Appendix K Measurement Uncertainty Recapture - Power Uprate Request (TAC No. MB5498)," AEP:NRC:2900-01, dated October 15, 2002 to AEP:NRC:2902 Page 29

4. Letter from J. E. Pollock, I&M, to NRC Document Control Desk, "Submittal of Power Measurement Uncertainty Calculation in Support of License Amendment Request for Appendix K Measurement Uncertainty Recapture - Power Uprate Request (TAC No.

MB 5498)," AEP:NRC:2900-03, dated October 17, 2002

5. Letter from J. E. Pollock, I&M, to NRC Document Control Desk, "Donald C. Cook Nuclear Plant, Unit 2 Docket No. 50-316 License Amendment Request for Unit 2 Reactor Coolant System Pressure-Temperature Curves, and Request for Exemption from Requirements in 10 CFR 50.60(a) and 10 CFR 50, Appendix G," AEP:NRC:2349-01, dated July 23, 2002

Attachment 5 to AEP:NRC:2902 Page I REGULATORY COMMITMENTS The following table identifies those actions committed to by Indiana Michigan Power Company (I&M) in this document. Any other actions discussed in this submittal represent intended or planned actions by I&M. They are described to the Nuclear Regulatory Commission (NRC) for the NRC's information and are not regulatory commitments.

Commitment Date I&M is installing an LEFM CheckPlus system at CNP Unit 2 in Prior to implementing this anticipation of approval of this proposed amendment. Installation of license amendment and this system will be completed prior to implementation of the prior to raising power requested license amendment. The design change for the installation above 3411 MWt will include instrumentation rescaling, UFSAR revision, maintenance and operational procedure impacts, training, monitoring iso-phase bus duct temperature, and implementation of the LEFM CheckPlus system out-of-service administrative technical requirements.

Prior to implementing this uprate, a reload safety evaluation will be Prior to implementing this performed to ensure that the core design bounds the uprated license amendment and condition. prior to raising power above 3411 MWt Perform an analysis of the steam dump valve flow capacity at the Prior to implementing this uprated power level and implement changes/adjustments as required license amendment and to ensure the valves have sufficient capacity prior to implementing prior to raising power the 1.66 percent power uprate. above 3411 MWt

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