ML12320A544

DC Cook CDBI Response to Question 2012-CDBI-298

ML12320A544
Person / Time
Site:	Cook
Issue date:	11/15/2012
From:	Hodge W - No Known Affiliation
To:	Caroline Tilton Division of Policy and Rulemaking, - No Known Affiliation
Cruz H
References
2012-CDBI-298
Download: ML12320A544 (59)

Text

Mrs. C. Tilton W. Hodge 2443 Warrenville Road 500 Circle Dr.

Suite 210 Buchanan, MI 49107 Lisle, Illinois 60532-4352 Re: DC Cook CDBI response to question 2012-CDBI-298

Dear Mrs. Tilton,

Attached is the white paper supporting the DC Cook licensing basis position on Steam Generator Tube Rupture. This white paper is intended to address the following potential violations discussed in the NRC technical exit on August 23, 2012.

• Potential violation of T.S. 5.4.1 for emergency response with loss of control air during SGTR. The NRC contends that steps in procedures should have accounted for the time required to put nitrogen in service to provide motive force to the SG PORVs, as well as contending we cannot credit the CAC. If we truly needed Nitrogen, via the procedure it would not have been lined up in time to support the safety analysis.

• Potential violation for non-conservative T.S 3.7.4 for Control Air Compressor out of service. The NRC has a concern that we may have potentially exceeded our allowed outage time on SG PORVs (assuming CAC out of service would make the SG PORVs inoperable) or not having adequate compensatory actions for equipment inoperable.

Sincerely, W. Hodge

DC Cook Steam Generator Tube Rupture Margin to Overfill Licensing Basis Position

1. Background

During the DC Cook 2012 CDBI inspection the NRC inspectors questioned the design and licensing basis for Steam Generator Tube Rupture (SGTR) Margin to Overfill (MTO). Specifically the design of the compressed air system as a motive force for the Steam Generator Power Operated Relief Valves, with regard to reliance on non-safety grade equipment to mitigate an accident, and the ability to supply compressed air with equipment out of service, and a concurrent loss of offsite power in the affected unit.

2. DC Cook Licensing History Discussion DC Cooks original FSAR made the assumption that S/G overfill would not occur because of the expectation that the primary-secondary pressure differential could be eliminated within 30 minutes. As a result, the original SGTR only examined the dose consequences from the accident, assuming a loss of condenser due to a loss of offsite power or loss of condensate system. The loss of condenser forced use of the S/G PORVs to cool down the plant. No further examination of the LOOP or its consequences to other equipment, other than the reliance on the SG PORVs, was considered. The assumption stated in the early FSAR, e.g., in Amendment 75 of the Unit 2 section of 14.2.4 of April 1977, is that Assuming normal operation of the various plant control systems, the following sequence of events is initiated by a tube rupture This supports the position that the LOOP was not used in the original accident analysis, other than to force discharge of the steam from the affected S/G to the environment instead of the condenser.

This is further supported by a note in Section 15.1 of the original DC Cook SER that indicates SGTR was only viewed from the prospect of radiological releases to the environment.

In 2000, Westinghouse completed a detailed SGTR analysis for each unit to determine if the assumption that the steam generator did not overfill remained valid and to verify that the offsite release mass remained bounding. Other than the more sophisticated analysis tool (the LOFTTR2 computer code) that was employed, after receiving NRC approval for its use, no changes were made to the Cook Plant SGTR licensing basis.

Following the approval of the SER for the supplemental SGTR MTO methodology in October of 2001 (Attachment 1), the methodology detailed in the License Amendment Request documented in C1000-11 (Attachment 2) and RAI responses documented in C0601-21 (Attachment 3), was added to the DC Cook UFSAR in November of 2001. The SER approving SGTR MTO for DC Cook, explicitly states that no single failure is considered.

The Unit 1 and Unit 2 MUR license amendments further support the acceptance by the Staff on the positions stated above. Cook Plants response to NRC Question No. 4 in AEP:NRC:2900-01 and the NRCs SER for Unit 1 MUR on December 20, 2002 (see Section 3.2.2.3.3 of the SER) demonstrate that NRC accepts our use of nominal conditions (i.e. the unit is operating with equipment in normal alignment, and all equipment is available) in the analyses.

This position conforms with the majority of nuclear stations licensed in the 1960s and 1970s. The two DC Cook units received their operating licenses in 1974 and 1977. Our research undertaken to understand the requirement for a LOOP/SGTR and single failure showed that NUREG-0800 was updated in the 1996 timeframe and added an additional design basis feature to include the most limiting single failure to the LOOP/SGTR analysis. D C Cook did not receive a backfit order to adopt the new position contained in the 1996 SRP NUREG-0800.

3. Licensing Basis Discussion The current DC Cook licensing basis SGTR MTO calculation is a best-estimate analysis performed using the LOFTTR2 code, and assumes a loss of offsite power, resulting in the loss of the condenser, but does not assume a single failure.

As called out in Letter C0601-21, control air appurtenances along with the SG PORVs are non-safety related and relied upon to mitigate a SGTR. Section 4 of this paper describes in further detail from the UFSAR all the components which make up the control air system, which includes the normal source of compressed air (the two Plant Air Compressors), the backup source of compressed air (the Control Air Compressor), as well as the associated piping, valves, etc. Note that the Nitrogen system is not included as part of the described control air system, it can be used to provide motive force to the SG PORVs but is only included as part of a defense in depth design. Since the normal and backup sources of compressed air are included as part of control air appurtenances these components are assumed to be available to mitigate a SGTR.

The SGTR SER approves mitigation of the SGTR event without the consideration of a single failure. Since the Plant Air Compressors and Control Air Compressor are assumed to be available, and no single failure is required to be considered; these components are allowed to be used in the mitigation of an SGTR. The LOFTTR2 code which was used to analyze the SGTR transient does not model the control air system explicitly, the control air system is assumed to be available in the model to provide motive force to the Steam Generator PORVs, and as documented in the SGTR SER:

NRC staff concludes that the licensee can incorporate the LOFTTR2 code into its licensing bases for CNP and can use the LOFTTR2 code, with the current licensing basis assumptions as inputs for the overfill analysis of steam generator tube rupture accidents.

AEP letter C0601-21 clearly states that the control air to the SG PORVs is non-safety grade. The SGTR SER states that the NRC reviewed the UFSAR and concluded that the licensing basis SGTR does credit limited use of non-safety grade equipment for mitigating the SGTR. The NRC acceptance of the use of non-safety grade control air to mitigate an SGTR would seem to imply a lack of expectation that the control air system be provided with emergency onsite power in the event of a loss of offsite power.

Therefore the assumption that compressed air would be available to mitigate the SGTR event, and compressed air can be provided from either the normal source of compressed air (Plant Air Compressors) or the backup source of compressed air (Control Air Compressor) is in compliance with the DC Cook licensing basis.

4. Compressed Air System Description Unit 1 is licensed independently of Unit 2, and is considered to be separate with the exception of explicitly identified shared systems defined in the UFSAR. D.C. Cooks UFSAR section 1.3.9.h (Attachment 6) identifies that the compressed air system is a shared system. As described in UFSAR chapter 9.8.2 (Attachment 7) the compressed air system is required to provide a continuous supply of compressed air to vital loads. of this letter contains system overview drawings, which supplement this discussion, showing the arrangement and interconnection of the compressed air system.

As described in UFSAR 9.8.2.3 during normal operation a single Plant Air Compressor (PAC) supplies both units plant and control air headers. In the event of low plant air header pressure the second PAC will automatically start and load. A low control air header pressure in either unit will automatically start the Control Air Compressor (CAC) in that respective unit. The compressed air system is designed such that the CAC for each unit is supplied by an emergency power supply. If the CAC is out of service for any reason during a SGTR event, compressed air would be available from the Plant Air Compressor powered by the unaffected unit.

While not controlled by Technical Specifications DC Cook is sensitive to the importance of the compressed air system. The unavailability of control air system is controlled by the maintenance rule. Specifically, functions CA-02 and MS-05 in Maintenance Rule (10 CFR 50.65) Scoping Documents for the Compressed Air and Main Steam Systems, respectively. Additionally work control procedure PMP-2291-WMP-001 (Attachment 8) requires both PACs to be guarded in the event a CAC is out of service; or to guard the opposite unit PAC, both CACs, and the Backup Air Compressor if a PAC is taken out of service.

5. Electrical Power Description The scenario postulated by the inspectors involves the loss of offsite power to the affected unit. Since the compressed air system is shared between units and the normal

supply of control air may be supplied from either unit, it is important to consider the sources of power to the air compressors.

The following is a detailed discussion addressing specifically how AC power is available to the maintained plant air system. The information below is supplemented by system overview drawings contained in Attachment 5.

Normally, auxiliary power is supplied via the Unit Aux Transformers 1AB(2AB) and 1CD(2CD) powered via the associated units Main Generator. A loss of offsite power to the affected units Plant Air Compressor is likely to result in a loss of the Technical Specification related source of offsite power to the unaffected units Plant Air Compressor. The loss of Technical Specification source of offsite power to the unaffected unit does not result in a loss of power to the unaffected units Plant Air Compressor. The unaffected unit will remain in operation with power supplied to the Plant Air Compressor and its Aux Oil Pump via the Unit Aux Transformers.

6. Licensing Implications of the Postulated Scenario DC Cook provided the list of equipment required to mitigate a SGTR to the NRC in the RAI response documented in C0601-21. Included in this list is non-safety-related control air appurtenances, which includes the normal and backup supplies of control air. Since the normal and backup sources of control air are the Plant Air Compressors and the Control Air Compressor respectively, and the NRC implicitly approved the use of this equipment to mitigate a SGTR without the consideration of a single failure. Both the normal and backup supplies of air are considered valid sources of compressed air to mitigate a SGTR and coincident loss of offsite power. The normal supply of control air is shared between units, and based on the discussion in Section 5 a loss of offsite power in Unit 1 would not result in a loss of the Plant Air Compressor in Unit 2, and vice versa.

In the postulated scenario where a Control Air Compressor is out of service, and that unit experiences a SGTR with a concurrent loss of offsite power; per the DC Cook design and licensing basis the unaffected unit Plant Air Compressor is a valid supply of compressed air for the mitigation of the SGTR event. Because no single failure is considered in the DC Cook licensing basis, the unaffected unit Plant Air Compressor is assumed to be available and functional. If the postulated scenario precludes the use of compressed air supplied from the unaffected unit Plant Air Compressor, relative to the DC Cook licensing basis that would be considered a single failure, and considered beyond the DC Cook design basis.

7. Conclusion DC Cook Units 1 and 2 were licensed and have as a design basis the ability to address the SGTR coincident with a Loss of Offsite Power. Inclusion of another single failure is a

beyond design basis event for D C Cook. As the plant air system is described in the UFSAR as a shared system and assumed to be available in the SGTR with LOOP analysis, failure to credit the air system would constitute another single failure. The postulated scenario of a SGTR with dual unit LOOP and the Control Air Compressor out of service, posed by the NRC inspectors is believed to be beyond design and licensing basis, and therefore not subject to evaluation via the inspection or licensing process at this time.

The DC Cook design and licensing basis allows the use of non-safety related control air appurtenances, which include the normal and backup supplies of compressed air. As described in the UFSAR, DC Cook is designed with compressed air as a shared system.

In the event of a SGTR with concurrent loss of offsite power in one unit, the unaffected unit can provide power to its Plant Air Compressor. In the event that a Control Air Compressor is out of service and that unit experiences a SGTR with a loss of offsite power, the source of control air would be the unaffected unit Plant Air Compressor.

Exclusion of the alternate unit Plant Air Compressor as a valid source of compressed air to mitigate the SGTR event would be considered a single failure, and beyond the current DC Cook design and licensing basis.

Attachment 1 SER Approving the SGTR MTO methodology for DC Cook

October 24, 2001 Mr. Robert P. Powers, Senior Vice President Indiana Michigan Power Company Nuclear Generation Group 500 Circle Drive Buchanan, MI 49107

SUBJECT:

DONALD C. COOK NUCLEAR PLANT, UNITS 1 AND 2 - ISSUANCE OF AMENDMENTS (TAC NOS. MB0739 AND MB0740)

Dear Mr. Powers:

The U.S. Nuclear Regulatory Commission has issued the enclosed Amendment No. 256 to Facility Operating License No. DPR-58 and Amendment No. 239 to Facility Operating License No. DPR-74 for the Donald C. Cook Nuclear Plant, Units 1 and 2. The amendments are in response to your application dated October 24, 2000, as supplemented June 29, 2001, approve changes to the updated final safety analysis report (UFSAR).

The amendments would approve changes to the UFSAR to incorporate a supplemental methodology for the analysis of steam generator overfill following a steam generator tube rupture.

A copy of our related safety evaluation is also enclosed. A Notice of Issuance will be included in the Commission's next biweekly Federal Register notice.

Sincerely,

/RA/

John F. Stang, Senior Project Manager, Section 1 Project Directorate III Division of Licensing Project Management Office of Nuclear Reactor Regulation Docket Nos. 50-315 and 50-316

Enclosures:

1. Amendment No. 256 to DPR-58

2. Amendment No. 239 to DPR-74

3. Safety Evaluation cc w/encls: See next page

October 24, 2001 Mr. Robert P. Powers, Senior Vice President Indiana Michigan Power Company Nuclear Generation Group 500 Circle Drive Buchanan, MI 49107

SUBJECT:

DONALD C. COOK NUCLEAR PLANT, UNITS 1 AND 2 - ISSUANCE OF AMENDMENTS (TAC NOS. MB0739 AND MB0740)

Dear Mr. Powers:

The U.S. Nuclear Regulatory Commission has issued the enclosed Amendment No. 256 to Facility Operating License No. DPR-58 and Amendment No. 239 to Facility Operating License No. DPR-74 for the Donald C. Cook Nuclear Plant, Units 1 and 2. The amendments are in response to your application dated October 24, 2000, as supplemented June 29, 2001, approve changes to the updated final safety analysis report (UFSAR).

The amendments would approve changes to the UFSAR to incorporate a supplemental methodology for the analysis of steam generator overfill following a steam generator tube rupture.

A copy of our related safety evaluation is also enclosed. A Notice of Issuance will be included in the Commission's next biweekly Federal Register notice.

Sincerely,

/RA/

John F. Stang, Senior Project Manager, Section 1 Project Directorate III Division of Licensing Project Management Office of Nuclear Reactor Regulation Docket Nos. 50-315 and 50-316

Enclosures:

1. Amendment No. 256 to DPR-58

2. Amendment No. 239 to DPR-74

3. Safety Evaluation cc w/encls: See next page DISTRIBUTION PUBLIC GHill(4) WReckley PD 3-1Reading OGC THarris AVegel, RIII ACRS WBeckner SPeters JStang Accession No. ML012690136 *SE Input Provided OFFICE PDIII-1/PM PDIII-1/LA SRXB OGC PDIII-1/(A)SC NAME JStang THarris FAkstulewicz* AFernandez WReckley DATE 10/2/01 9/28/01 8/17/2001 10/19/01 10/23/01 OFFICIAL RECORD COPY

Donald C. Cook Nuclear Plant, Units 1 and 2 cc:

Regional Administrator, Region III Drinking Water and Radiological U.S. Nuclear Regulatory Commission Protection Division 801 Warrenville Road Michigan Department of Lisle, IL 60532-4351 Environmental Quality 3423 N. Martin Luther King Jr Blvd Attorney General P.O. Box 30630, CPH Mailroom Department of Attorney General Lansing, MI 48909-8130 525 West Ottawa Street Lansing, MI 48913 Ronald Gaston Director, Regulatory Affairs Township Supervisor Indiana Michigan Power Company Lake Township Hall Nuclear Generation Group P.O. Box 818 One Cook Place Bridgman, MI 49106 Bridgman, MI 49106 U.S. Nuclear Regulatory Commission David A. Lochbaum Resident Inspector's Office Union of Concerned Scientists 7700 Red Arrow Highway 1616 P Street NW, Suite 310 Stevensville, MI 49127 Washington, DC 20036-1495 David W. Jenkins, Esquire A. Christopher Bakken, Site Vice President Indiana Michigan Power Company Indiana Michigan Power Company Nuclear Generation Group Nuclear Generation Group One Cook Place One Cook Place Bridgman, MI 49106 Bridgman, MI 49106 Mayor, City of Bridgman Michael W. Rencheck P.O. Box 366 Vice President, Nuclear Engineering Bridgman, MI 49106 Indiana Michigan Power Company Nuclear Generation Group Special Assistant to the Governor 500 Circle Drive Room 1 - State Capitol Buchanan, MI 49107 Lansing, MI 48909

INDIANA MICHIGAN POWER COMPANY DOCKET NO. 50-315 DONALD C. COOK NUCLEAR PLANT, UNIT 1 AMENDMENT TO FACILITY OPERATING LICENSE Amendment No. 256 License No. DPR-58

1. The U.S. Nuclear Regulatory Commission (the Commission) has found that:

A. The application for amendment by Indiana Michigan Power Company (the licensee) dated October 24, 2000, as supplemented June 29, 2001, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations set forth in 10 CFR Chapter I; B. The facility will operate in conformity with the application, the provisions of the Act, and the rules and regulations of the Commission; C. There is reasonable assurance (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commission's regulations; D. The issuance of this amendment will not be inimical to the common defense and security or to the health and safety of the public; and E. The issuance of this amendment is in accordance with 10 CFR Part 51 of the Commission's regulations and all applicable requirements have been satisfied.

2. Accordingly, by Amendment No. 256, Facility Operating License No. DPR-58 is hereby amended to authorize a change to the methodology used in the evaluation of a steam generator (SG) overfill following a SG tube rupture referenced in the updated final safety analysis report (UFSAR), as set forth in the license amendment application dated October 24, 2000, as supplemented June 29, 2001, and evaluated in the associated safety evaluation by the Commissions Office of Nuclear Reactor Regulation. The licensee shall update the UFSAR by adding a description of this change, as authorized by this amendment, and in accordance with 10 CFR 50.71(e).

3. This license amendment is effective as of its date of issuance and shall be implemented within 30 days.

FOR THE NUCLEAR REGULATORY COMMISSION

/RA/

William D. Reckley, Acting Chief, Section 1 Project Directorate III Division of Licensing Project Management Office of Nuclear Reactor Regulation Date of Issuance: October 24, 2001

INDIANA MICHIGAN POWER COMPANY DOCKET NO. 50-316 DONALD C. COOK NUCLEAR PLANT, UNIT 2 AMENDMENT TO FACILITY OPERATING LICENSE Amendment No. 239 License No. DPR-74

1. The U.S. Nuclear Regulatory Commission (the Commission) has found that:

A. The application for amendment by Indiana Michigan Power Company (the licensee) dated October 24, 2000, as supplemented June 29, 2001, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations set forth in 10 CFR Chapter I; B. The facility will operate in conformity with the application, the provisions of the Act, and the rules and regulations of the Commission; C. There is reasonable assurance (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commission's regulations; D. The issuance of this amendment will not be inimical to the common defense and security or to the health and safety of the public; and E. The issuance of this amendment is in accordance with 10 CFR Part 51 of the Commission's regulations and all applicable requirements have been satisfied.

2. Accordingly, by Amendment No. 239, Facility Operating License No. DPR-74 is hereby amended to authorize a change to the methodology used in the evaluation of a steam generator (SG) overfill following a SG tube rupture referenced in the updated final safety analysis report (UFSAR), as set forth in the license amendment application dated October 24, 2000, as supplemented June 29, 2001, and evaluated in the associated safety evaluation by the Commissions Office of Nuclear Reactor Regulation. The licensee shall update the UFSAR by adding a description of this change, as authorized by this amendment, and in accordance with 10 CFR 50.71(e).

3. This license amendment is effective as of its date of issuance and shall be implemented within 30 days.

FOR THE NUCLEAR REGULATORY COMMISSION

/RA/

William D. Reckley, Acting Chief, Section 1 Project Directorate III Division of Licensing Project Management Office of Nuclear Reactor Regulation Date of Issuance: October 24, 2001

SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 256 TO FACILITY OPERATING LICENSE NO. DPR-58 AND AMENDMENT NO. 239 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

1.0 INTRODUCTION

By application dated October 24, 2000, as supplemented June 29, 2001, the Indiana Michigan Power Company (the licensee) requested approval of changes to the updated final safety analysis report (UFSAR). The proposed amendments would approve incorporating a supplemental methodology into the analysis of steam generator (SG) overfill following a steam generator tube rupture (SGTR). The new analysis more realistically models the operator actions and plant response. The results from the calculations would then be used to determine the time available for operator actions to prevent overfill and to revise the plant Emergency Operating Procedures.

The current SGTR analysis for D. C. Cook Nuclear Plant (CNP) Units 1 and 2, calculates an average break flow from the time of the accident until the reactor trips and safety injection (SI) initiates. Following SI initiation, the UFSAR analysis uses an equilibrium break flow that continues at a constant rate for 30 minutes. The resulting break flow mass transfer is then used to calculate the radiological consequences of the SGTR. The UFSAR calculations are considered conservative since the reduction in the break flow rate over the thirty minute period is ignored. Inherent in this evaluation is the assumption that the operator can terminate the break flow in 30 minutes, and that the termination will prevent the SG from overfilling. The 30 minute time to termination is the current licensing basis referenced in the UFSAR.

During an expanded system readiness review, the licensee conducted SGTR simulator exercises, and the operators demonstrated that the time to terminate the tube rupture break flow exceeded the 30 minute assumption. Should operators significantly exceed the 30 minute termination criteria, the SG could overfill, assuming the break flow documented in the UFSAR occurred. Upon SG overfill, water enters the steam lines. The steam lines at D. C. Cook are not qualified to contain water, and the pressure operated relief valves (PORVS) are not qualified to relieve water. This event could have radiological consequences beyond the design basis of the D. C. Cook Nuclear Plants.

The licensee proposes to incorporate a supplemental methodology into the analysis of steam generator overfill following a SGTR. The licensee plans to use the results from the analysis to

determine the time available for operator actions to prevent overfill and to revise the plant Emergency Operating Procedures.

The licensee s June 29, 2001, letter, provided additional information only in response to the Nuclear Regulatory Commission (NRC) staff's request for additional information dated May 7, 2001. The letter provided clarifying information within the scope of the original application and did not change the initial proposed no significant hazards consideration determination.

2.0 EVALUATION The discrepancy between the simulator exercises and the assumptions in the SGTR analysis, required the licensee to reexamine the SGTR accidents. The licensee proposes implementing WCAP-10698-P-A SGTR Analysis Methodology to Determine the Margin to Steam Generator Overfill, to update the analysis. To implement the WCAP, the licensee used the LOFTTR2 computer code and the plant-specific current licensing basis assumptions. The improvements in the analysis included modeling operator actions, enhancing the SG secondary side model, and improving the tube rupture break flow model.

From the new analysis, the licensee plans to determine the time available for operator actions to prevent steam generator overfill. They will then correct the discrepancy between the UFSAR analysis and the demonstrated plant response with regard to SGTR overfill. Based upon the results of the calculations, the licensee also plans to update the emergency operating procedures to incorporate the enhancements identified by the new analysis.

The licensee's use of WCAP-10698-P-A presented several exceptions from the requirements of the NRC staff's safety evaluation that approved it. These exceptions are presented in more detail below as Items 1 through 5, and are summarized in Table 1. Overall, WCAP-10698-P-A describes a conservative methodology for SGTR overfill calculations. The WCAP applies the LOFTTR1 computer code for modeling the SGTR transient. Input assumptions into the accident analysis model include loss of offsite power, most reactive rod stuck, conservative initial conditions, turbine runback, 120 percent of 1971 ANS (American Nuclear Society) decay heat standard, and the worst single failure, among other assumptions. However, variations in plant designs prevent a single model from adequately representing all Westinghouse plants.

Because of these variations, the NRC required that plant-specific input be provided when utilities reference the WCAP methodology. The required plant-specific input is as follows:

1. Each utility in the SGTR subgroup must confirm that they have in place simulators and training programs which provide the required assurance that the necessary actions and times can be taken consistent with those assumed for the WCAP-10698 design-basis analysis. Demonstration runs should be performed to show that the accident can be mitigated within a period of time compatible with overfill prevention, using design-basis assumptions regarding available equipment, and to demonstrate that the operator action times assumed in the analysis are realistic.

The licensee confirmed that they have simulator and training programs in place that assure the necessary actions and times can be taken to prevent steam generator overfill. The licensee also stated that the operator action times assumed in the analysis are realistic because they were confirmed by simulator demonstrations. They incorporated these action times into their

training programs. However, when establishing the bases for the SGTR transient, the licensee did not assume the same design-basis assumptions as the WCAP-10698 analysis.

2. A site specific SGTR radiation offsite consequence analysis which assumes the most severe failure identified in WCAP-10698, Supplement 1. The analysis should be performed using the methodology in SRP Section 15.6.3, as supplemented by the guidance in Reference (1) - (Note: Reference (1) of the WCAP-10698 Safety Evaluation).

In response to this requirement, the licensee did not submit the offsite consequence analysis.

They, instead, proposed keeping their current licensing basis SGTR calculation for the offsite radiological consequences. The licensee states that this proposal is adequate, since the original licensing basis analysis has a greater primary to secondary side mass transfer than the analysis performed using the WCAP methodology.

3. An evaluation of the structural adequacy of the main steam lines and associated supports under water-filled conditions as a result of SGTR overfill.

Because licensees evaluation determined that the steam generators do not overfill, the licensee did not submit a structural evaluation of the main steam lines and associated supports for the water-filled conditions of a SGTR overfill incident.

4. A list of systems, components and instrumentation which are credited for accident mitigation in the plant-specific SGTR EOP(s). Specify whether each system and component specified is safety grade. For primary and secondary PORVs and control valves, specify the valve motive power and state whether the motive power and valve controls are safety grade. For non-safety grade systems and components, state whether safety grade backups are available which can be expected to function or provide the desired information within a time period compatible with prevention of SGTR overfill or justify that non-safety grade components can be utilized for the design-basis event. Provide a list of all radiation monitors that could be utilized for identification of the accident and the ruptured steam generator and specify the quality and reliability of this instrumentation if possible. If the EOPs specify SG sampling as a means of ruptured SG identification, provide the expected time period for obtaining the sample results and discuss the effects on the duration of the accident.

The licensee provided the required lists of systems, components, and instrumentation that are used for SGTR accident mitigation. They also specified the safety classification of the systems and power sources. However, the licensee listed several systems used for SGTR mitigation that are not safety related and do not have safety related backups. The licensee justified the use of the non-safety related equipment by stating that these systems are credited in the current UFSAR Section 14.2.4 accident analysis. Upon review of UFSAR Section 14.2.4, the staff concludes that the licensing basis SGTR analysis does credit limited use of non-safety grade equipment for mitigating the SGTR.

5. A survey of plant primary and balance-of-plant systems design to determine the compatibility with the bounding plant analysis in WCAP-10698. Major design differences should be noted. The worst single failure should be identified if different from the WCAP-10698 analysis and the effect of the difference on the margin of overfill should be provided.

The licensee did not use the bounding plant analysis of WCAP-10698-P-A, but performed a D. C. Cook plant-specific analysis. Therefore, they did not submit a survey of the plant systems that determined the variance with the WCAP analysis. Also, the licensee did not assume the worst single failure as prescribed by the WCAP-10698-P-A safety analysis, and did not provide its effect on the margin to overfill. The licensee based their decision not to assume the worst single failure on the fact that their current licensing basis does not include a single failure.

Overall, the proposed D. C. Cook plant methodology and the approved WCAP-10698 methodology vary significantly. The differences are listed in Table 1.

Table 1 WCAP-10698-P-A D. C. Cook Uses LOFTTR1 computer model Uses LOFTTR2 computer model Assumes a worst single failure for design Does not assume worst single failure basis Requires offsite radiological consequence Does not provide analysis based on WCAP analysis, assuming worst failure methodology or worst failure Requires structural adequacy analysis of Does not provide structural analysis SGTR overfill Requires comparison of BOP equipment with Does not provide comparison WCAP case Because of the significance of these variations from the WCAP-10698-P-A methodology, the staff cannot endorse the licensees reference to WCAP-10698-P-A in the licensing basis for a SGTR overfill analysis. However, the LOFTTR2 computer code has been previously accepted for licensing basis SGTR analyses. Therefore, we find it acceptable for the licensee to use LOFTTR2 for their licensing basis SGTR overfill analysis as well as the licensing calculation for the design basis SGTR accident.

Finally, the licensee committed to revise the Unit 1 emergency operating procedures to incorporate enhancements from the new analysis. The licensee has updated the Unit 1and 2 emergency operating procedures. The licensee will revise the UFSAR to incorporate the use of the new methodology in the SGTR analyses. Incorporating the information from the new SGTR model is acceptable. However, as stated earlier, citing WCAP-10698-P-A as the licensing basis for the SGTR overfill analysis is not acceptable.

3.0

SUMMARY

The licensees method of implementation of WCAP-10698-P-A does not satisfy the WCAP safety evaluation requirements. Therefore, the incorporation of WCAP-10698-P-A into D. C. Cook 's licensing basis is not acceptable as proposed in the October 24, 2000, application. However, the LOFTTR2 computer code has been previously accepted for use in licensing basis analyses. Therefore, the NRC staff concludes that the licensee can incorporate the LOFTTR2 code into its licensing bases for CNP and can use the LOFTTR2 code, with the current licensing basis assumptions as inputs for the overfill analysis of steam generator tube rupture accidents. This change to the licensing basis does not affect accident initiators or precursors. The change also does not increase the probability of an accident or decrease the ability of the operators to mitigate the consequences of an accident. Therefore, the proposed change to the UFSAR is acceptable.

4.0 STATE CONSULTATION

In accordance with the Commission's regulations, the Michigan State official was notified of the proposed issuance of the amendments. The State official had no comments.

5.0 ENVIRONMENTAL CONSIDERATION

These amendments change the requirements with respect to installation or use of a facility component located within the restricted area as defined in 10 CFR Part 20. The staff has determined that the amendments involve no significant increase in the amounts, and no significant change in the types, of any effluents that may be released offsite, and that there is no significant increase in individual or cumulative occupational radiation exposure. The Commission has previously issued a proposed finding that the amendments involve no significant hazards consideration and there has been no public comment on such finding (66 FR 7682). Accordingly, the amendments meet the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9). Pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the issuance of the amendments.

6.0 CONCLUSION

The staff has concluded, based on the considerations discussed above, that: (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 amendments will not be inimical to the common defense and security or to the health and safety of the public.

Principal Contributor: Sean Peters Date: October 24, 2001

Attachment 2 DC Cook License Amendment Request for SGTR MTO

indiana Michiga*o Power Company 500 uirce DUie Buchanan. M1 49107 1373 INDIANA MICHIGAN POWER October 24, 2000 C1000-1 1 10 CFR 50.90 Docket Nos.: 50-315 50-316 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Mail Stop O-P1-17 Washington, DC 20555-0001 Donald C. Cook Nuclear Plant Units 1 and 2 LICENSE AMENDMENT FOR CHANGES IN STEAM GENERATOR TUBE RUPTURE ANALYSIS METHODOLOGY Pursuant to 10 CFR 50.90, Indiana Michigan Power Company, the Licensee for Donald C. Cook Nuclear Plant (CNP) Units 1 and 2, proposes to amend Facility Operating Licenses DPR-58 and DPR-74 to incorporate a supplemental methodology into its analysis of steam generator (SG) overfill following a steam generator tube rupture (SGTR). The proposed change would use the analysis methodology documented in the Westinghouse Electric Company WCAP-10698-P-A, "SGTR Analysis Methodology to Determine Margin to Steam Generator Overfill," to more accurately calculate the transient response of CNP to a postulated SGTR with respect to CNP SG overfill. The break flow model used in WCAP-10698-P-A has been reviewed and accepted by the Nuclear Regulatory Commission (NRC) in safety evaluation report, "Acceptance for Referencing of Licensing Topical Report WCAP-10698, 'SGTR Analysis Methodology to Determine Margin to Steam Generator Overfill,' December 1984," dated March 30, 1987. Since this methodology is not currently part of the CNP licensing basis, use of this methodology for the supplemental SGTR analysis has been determined to involve an unreviewed safety question.

Therefore, NRC staff review and approval are required for the addition of this methodology to the CNP licensing basis in accordance with 10 CFR 50.90. The Updated Final Safety Analysis Report will be revised to incorporate the use of the new methodology. to this letter provides a detailed description of the proposed changes. Attachment 2 describes the evaluation performed in accordance with 10 CFR 50.92(c), which concludes that no significant hazard is involved.

U. S. Nuclear Regulatory Commission C1000-11 Page 2 provides the environmental assessment and Attachment 4 provides the new commitments made in this letter.

Copies of this letter and its attachments are being transmitted to the Michigan Public Service Commission and Michigan Department of Environmental Quality, in accordance with the requirements of 10 CFR 50.91.

Should you have any questions, please contact Mr. Wayne J. Kropp, Director of Regulatory Affairs, at (616) 697-5056.

Sincerely, R. P. Powers Vice President

\dmb Attachments c: J. E. Dyer MDEQ - DW & RPD NRC Resident Inspector R. Whale

U. S. Nuclear Regulatory Commission C1000-1 1 Page 3 AFFIRMATION I, Robert P. Powers, being duly sworn, state that I am 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 R. P. Powers Vice President SWORN TO AND SUBSCRIBED BEFORE ME THŽLS, D y OF 2000 JULIE E. NEWMILLER Notary Public, Berrien County, MI My Commission Expires Aug 22, 2004 (I Notary Public My Commission Expires - /

ATTACHMENT 1 TO C 1000-11 DESCRIPTION AND SAFETY ANALYSIS FOR THE PROPOSED CHANGES A. Summary of Proposed Changes Indiana Michigan Power Company (I&M), the Licensee for Donald C. Cook Nuclear Plant (CNP) Units 1 and 2, proposes to amend Facility Operating Licenses DPR-58 and DPR-74 to incorporate a supplemental methodology into its analysis of steam generator (SG) overfill following a steam generator tube rupture (SGTR). The proposed change would use the analysis methodology documented in the Westinghouse Electric Company (Westinghouse)

WCAP-10698-P-A, "SGTR Analysis Methodology to Determine Margin to Steam Generator Overfill," to more accurately calculate the transient response of CNP to a postulated SGTR with respect to CNP SG overfill. The break flow model used in WCAP- 10698-P-A has been reviewed and accepted by the Nuclear Regulatory Commission (NRC) in safety evaluation report (SER),

"Acceptance for Referencing of Licensing Topical Report WCAP-10698, 'SGTR Analysis Methodology to Determine Margin to Steam Generator Overfill,' December 1984," dated March 30, 1987. The use of this methodology for the supplemental SGTR analysis has been determined to involve an unreviewed safety question (USQ). Therefore, NRC staff review and approval are required for the addition of this methodology to the CNP licensing basis in accordance with 10 CFR 50.90. The Updated Final Safety Analysis Report (UFSAR) will be revised to incorporate the use of the new methodology.

The change in methodology would be applied to supplemental analyses for the determination of the time available for operator actions to prevent overfilling the secondary side of the affected SG in response to an SGTR event. The present methodology would be retained for calculating the radiological consequences of a postulated SGTR since the current CNP licensing basis methodology continues to bound the radiological consequences calculated by the new methodology.

B. Description and Bases for the Current Requirements The CNP licensing basis analysis for SGTR was included in the December 18, 1967, license application. This analysis was retained as part of the Final Safety Analysis Report, Section 14.2.4, "Steam Generator Tube Rupture," as described in the NRC's SER dated September 10, 1973, and remains in Section 14.2.4 of the UFSAR. This analysis calculates an average SGTR break flow for the time period from the postulated accident initiation until reactor trip and safety injection (SI) initiation, which are assumed to occur simultaneously. This analysis assumes an equilibrium break flow following reactor trip and SI initiation that continues at a constant rate for thirty minutes. The resulting break flow mass transfer is then used to calculate the radiological consequences of the postulated accident.

to C 1000-11 Page 2 The calculations performed as part of the SGTR analysis methodology are based on the limited industry experience and calculational capabilities that existed when CNP was licensed. The use of a constant mass flow rate for thirty minutes simplified the analysis calculations and was deemed conservative because the reduction in the break flow rate over the thirty-minute duration is ignored. Inherent in the evaluation is the assumption that an operator can terminate the break flow in thirty minutes, and that a thirty-minute termination time will prevent SG overfill from occurring.

C. Description of the Change and the Need for Revision of the Requirement I&M proposes to adopt as part of the CNP licensing basis a new, NRC-approved analysis method using a different calculational technique that models operator actions to more accurately predict the time to overfill an SG following an SGTR. The current licensing basis analysis for the postulated CNP SGTR accident assumes that the SG experiencing the tube rupture could be isolated within thirty minutes. That estimate was considered reasonable based on what was known when CNP Units 1 and 2 were licensed. Since that time, additional information has been obtained, procedures have been changed, control room protocols have evolved, and better analysis tools have become available for calculating operational transient responses.

Issues related to the SGTR analysis and the time to SG overfill were identified in March 1999, during the CNP expanded system readiness review. To address these issues, I&M personnel conducted SGTR simulator exercises that adhere to the CNP emergency operating procedures (EOPs). These exercises demonstrated that the time for reactor operators to terminate the tube rupture break flow in the affected SG exceeds thirty minutes. Therefore, the analysis assumption that the affected SG is isolated within thirty minutes is invalid.

The methodology used for the analysis of SGTR events cannot be used to determine if the SG overfills since the simplistic modeling does not consider the secondary side liquid volume transient. The methodology uses a mass and energy balance to calculate the primary-to secondary leakage through the ruptured tube and steam release to the atmosphere. At thirty minutes, the event is assumed to end as a result of the assumption that primary-to-secondary break flow has been terminated. No operator actions are explicitly modeled in the analysis, although the operators are required to perform the necessary steps to terminate the break flow.

Thirty minutes is not assumed a criterion for operator action; it is an analysis assumption used to conservatively calculate the total break flow.

Although the thirty-minute timeframe was selected as an analytical assumption, it could result in water entering the main steam line connected to the affected SG. Overfilling of the affected SG is unacceptable because the steam lines are not qualified for water fill and the SG power-operated relief valves are not qualified to relieve water. Overfill during a SGTR may propagate the event into a main steam line break accident coincident with SGTR. The radiological consequences to C 1000-11 Page 3 from such a combination of events have not been analyzed as it is outside of the licensing and design basis for CNP.

I&M determined that a new analysis using a different calculational technique that includes modeling operator actions is needed to more accurately identify the time to overfill. I&M proposes to use the break flow model and associated LOFTRR2 computer code described in WCAP-10698-P-A to quantify SG filling response following a postulated SGTR. The use of this break flow model would supplement the present SGTR analysis that did not specifically address SG overfill.

I&M has performed calculations in accordance with the WCAP-10698-P-A methodology. The new analysis calculation, which accounts for timing of operator actions, indicates that the break flow duration is longer than thirty minutes. The incorporation of a new methodology to more accurately characterize SGTRs and subsequent SG overfill timing into the CNP licensing basis is needed to rectify this non-conformance with the UFSAR description of the CNP response to SGTR events. Incorporation of the new methodology into the CNP licensing basis has been determined to constitute a USQ, requiring review and approval by the NRC.

D. Bases for the Proposed Changes The current SGTR thermal and hydraulic analyses performed for CNP do not incorporate the advantage of the available computer analysis model to determine the dynamic plant behavior following an SGTR accident. Rather, simplified calculations were performed based on the expected SGTR transient response to determine the primary to secondary break flow and the steam release to the atmosphere for use in calculating the offsite radiation exposure due to the event.

Following the R. E. Ginna Nuclear Power Plant SGTR event in January 1982, a new SGTR analysis methodology was developed. The new methodology is based on modeling operator actions for SGTR recovery derived from plant-specific simulator studies, incorporates an improved SG secondary-side model, and includes a more realistic tube rupture break flow model.

The NRC approved the revised SGTR analysis methodology in an SER, "Acceptance for Referencing of Licensing Topical Report WCAP-10698, 'SGTR Analysis Methodology to Determine Margin to Steam Generator Overfill,' December 1984," dated March 30, 1987. As required by the NRC as part of this SER, this methodology has subsequently been adopted by the Westinghouse Owners Group subgroup of plants that received operating licenses in this time frame. I&M has determined that the use of this methodology is applicable to CNP.

The current CNP SGTR analysis does not explicitly address the SG filling response due to an SGTR accident. The new methodology, widely adopted by owners of Westinghouse pressurized water reactor plants, is best suited to analyze the SG secondary-side inventory response following an SGTR as opposed to simplified hand calculations. Thus, approval for use of the to C 1000-11 Page 4 methodology is being requested to supplement the CNP SGTR analysis. This will allow the SGTR analysis to reflect more accurately the time to overfill of the affected SG in the CNP licensing basis.

The use of this WCAP methodology and associated computer code for break flow modeling more accurately calculates the plant response to an SGTR event. The improved accuracy of the new methodology provides valuable information related to the analysis of operator actions and the associated timing of these actions. The more accurate calculations related to the SGTR overfill transient provide valuable insights for enhancement of the EOPs. These types of improvements have been incorporated into the Unit 2 EOPs and are in progress for the EOPs for Unit 1. Revisions to the appropriate Unit 1 EOPs to incorporate enhancements identified due to the new SGTR SG overfill methodology will be completed prior to restart from the current outage.

E. Discussion of Risk The proposed change, to adopt a new analytical method to evaluate the effects of an SGTR, does not affect any accident initiators or precursors. As such, the proposed change does not increase the probability of an accident. The proposed change also does not affect the ability of operators to mitigate the consequences of an accident. The WCAP-10698-P-A methodology calculates more accurately the flow from the reactor coolant system to the SG secondary side following a postulated SGTR. The resulting break flow mass transfer is then used to calculate the radiological consequences of the postulated accident. The current licensing basis methodology for calculating the radiological consequences of a postulated SGTR results in mass transfer values that bound those calculated using the new methodology. As such, the existing licensing basis radiological consequence calculations will be retained. Thus, no additional radiological source terms are generated, and the consequences of an accident previously evaluated in the UFSAR will not be increased. Therefore, the incorporation of the new methodology would not result in an increase in risk for CNP.

ATTACHMENT 2 TO C 1000-11 NO SIGNIFICANT HAZARDS CONSIDERATION EVALUATION Indiana Michigan Power Company (I&M) has evaluated this proposed amendment and determined that it does not involve a significant hazard. According to 10 CFR 50.92(c), a proposed amendment to an operating license does not involve a significant hazard if operation of the facility in accordance with the proposed amendment would not:

1. involve a significant increase in the probability of occurrence or consequences of an accident previously evaluated;

2. create the possibility of a new or different kind of accident from any previously evaluated; or

3. involve a significant reduction in a margin of safety.

I&M proposes to incorporate a supplemental methodology into its analysis of steam generator (SG) overfill following a steam generator tube rupture (SGTR). The proposed change would use the analysis methodology documented in the Westinghouse Electric Company WCAP-10698-P-A, "SGTR Analysis Methodology to Determine Margin to Steam Generator Overfill," to more accurately calculate the transient response of Donald C. Cook Nuclear Plant (CNP) to a postulated SGTR with respect to CNP SG overfill. The break flow model used in WCAP-10698-P-A has been reviewed and accepted by the Nuclear Regulatory Commission (NRC) in safety evaluation report, "Acceptance for Referencing of Licensing Topical Report WCAP-10698, 'SGTR Analysis Methodology to Determine Margin to Steam Generator Overfill,' December 1984," dated March 30, 1987. The use of this methodology for the supplemental SGTR analysis has been determined to involve an unreviewed safety question.

Therefore, NRC staff review and approval are required for the addition of this methodology to the CNP licensing basis in accordance with 10 CFR 50.90. The Updated Final Safety Analysis Report (UFSAR) will be revised to incorporate the use of the new methodology.

The change in methodology would be applied to supplemental analyses for the determination of the time available for operator actions to prevent overfilling the secondary side of the affected SG in response to an SGTR event. The present methodology would be retained for calculating the radiological consequences of a postulated SGTR since the current CNP licensing basis methodology continues to bound the radiological consequences calculated by the new methodology.

The determination that the criteria set forth in 10 CFR 50.92 are met for this amendment request is indicated below.

to C 1000- 11 Page 2

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

The proposed change, to adopt a new analytical method to evaluate the effects of an SGTR, does not affect any accident initiators or precursors. As such, the proposed change does not increase the probability of an accident. The proposed change also does not affect the ability of operators to mitigate the consequences of an accident. The proposed change does not impact the design of the affected plant systems such that previously analyzed systems, structures, and components (SSCs) would now be more likely to fail. The changes will not modify plant systems to reduce their design capability during normal operating and accident conditions. The use of the WCAP-10698-P-A methodology to more accurately calculate the flow from the reactor coolant system (RCS) to the SG secondary side following a postulated SGTR does not affect the probability of any analyzed events. The use of the WCAP-10698-P-A methodology does not affect SGTR initiators or precursors. Therefore, incorporating the new methodology does not affect equipment malfunction probability, nor does it affect or create new accident initiators or precursors. Thus, there will be no reduction in the capability of those SSCs in limiting the consequences of previously evaluated accidents.

Additionally, the present methodology for calculating the radiological consequences of a postulated SGTR is conservative when compared with results from the new methodology. As such, the existing licensing basis radiological consequence calculations will be retained. Thus, no additional radiological source terms are generated, and the consequences of an accident previously evaluated in the UFSAR will not be increased. The use of this WCAP methodology and associated computer code for break flow modeling more accurately calculates the plant response to an SGTR event. The improved accuracy of the new methodology provides valuable information related to the analysis of operator actions and the associated timing. Such accurate transient response information enables enhancements to be made to the emergency operating procedures (EOPs).

Therefore, the proposed changes cannot increase the consequences or probability of occurrence of an accident previously evaluated.

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

The proposed change does not impact the design of affected plant systems, involve a physical alteration to the systems, or change to the way in which systems are currently operated, such that previously unanalyzed SGTRs would now occur. The change to incorporate the WCAP-10698-P-A methodology does not introduce any new malfunctions; it calculates more accurately the flow from the RCS to the SG secondary side following a postulated SGTR to determine the time available for operator actions to prevent overfilling the affected SG.

to C 1000-11 Page 3 Thus, use of the WCAP-10698-P-A methodology does not affect or create new accident initiators or precursors or create the possibility of a new or different kind of accident.

Therefore, the proposed changes do not increase the possibility of a new or different kind of accident than previously evaluated.

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

The approval of the license amendment will not result in any modifications to affected plant systems that would reduce their design capabilities during normal operating and accident conditions. By using the WCAP-10698-P-A methodology, a more accurate SGTR response is calculated. The improved understanding of the transient response enables enhancements to the EOPs, which provide further assurance that SSCs required for accident mitigation are protected.

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

In summary, based upon the above evaluation, I&M has concluded that these changes involve no significant hazards consideration.

ATTACHMENT 3 TO C 1000- 11 ENVIRONMENTAL ASSESSMENT Indiana Michigan Power Company (I&M) has evaluated this license amendment request (LAR) 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 LAR 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 Attachment 2, this proposed amendment does not involve 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 change in methodology would be applied to supplemental analyses for the determination of the time available for operator actions to prevent overfilling the secondary side of the affected steam generator in response to a steam generator tube rupture (SGTR) event. The present methodology would be retained for calculating the radiological consequences of a postulated SGTR since the current Donald C. Cook Nuclear Plant licensing basis methodology continues to bound the radiological consequences calculated by the new methodology. Therefore, there is no significant change in the types or significant increase in the amounts of any effluents released offsite.

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

The proposed change will not result in significant changes in the operation or configuration of the facility. There will be no change in the level of controls or methodology used for processing of radioactive effluents or handling of solid radioactive waste, nor will the proposal result in any change in the normal radiation levels within the plant. Therefore, there will be no significant increase in individual or cumulative occupational radiation exposure resulting from this change.

ATTACHMENT 4 TO C1000-11 COMMITMENTS The following table identifies those actions committed to by Indiana Michigan Power Company (I&M) in this submittal. Other actions discussed in the 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 Revisions to the appropriate Unit 1 emergency operating Prior to initial entry into Mode 2 procedures to incorporate enhancements identified due to from the current Unit 1 outage.

the new steam generator tube rupture overfill methodology will be completed prior to restart from the current outage.

After NRC approval of the amendment request, the Updated To be included in the next Final Safety Analysis Report (UFSAR) will be revised to 10 CFR 50.71(e) UFSAR update incorporate the use of the new methodology in steam submittal.

generator tube rupture analyses.

Attachment 3 DC Cook response to Request for Additional Information Response

Indiana Michigan Power Company 500 Circle Drive Buchanan, MI 49107 1373 INDIANA MICHIGAN POWER June 29, 2001 C0601-21 10 CFR 50.90 Docket Nos.: 50-315 50-316 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Mail Stop O-P 1-17 Washington, DC 20555-0001 Donald C. Cook Nuclear Plant Units 1 and 2 RESPONSE TO NUCLEAR REGULATORY COMMISSION REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT FOR "CHANGES IN STEAMI GENERATOR TUBE RUPTURE ANALYSIS METHODOLOGY" (TAC NOS. MB0739 AND MB0740)

References:

1) Letter from R. P. Powers (I&M) to Nuclear Regulatory Commission (NRC) Document Control Desk, "License Amendment for Changes in Steam Generator Tube Rupture Analysis Methodology," C 1000-11, dated October 24, 2000.

2) Letter from J. F. Stang (NRC) to R. P. Powers (I&M),

"Donald C. Cook Nuclear Plant, Units 1 and 2 - Request for Additional Information Regarding License Amendment Request," dated May 7, 2001, (TAC Nos. MB0739 and MB0740).

3) Letter from S. A. Greenlee (I&M) to NRC Document Control Desk, "Notification of a Due Date Extension for Response to a Request for Additional Information," C0501-18, dated May 31, 2001, (TAC NOS. MB0739 AND MB0740).

In Reference 1, Indiana Michigan Power Company (I&M), the Licensee for Donald C. Cook Nuclear Plant (CNP) Unit 1 and Unit 2, proposed to amend

ý Do I

U. S. Nuclear Regulatory Commission C0601-21 Page 2 Facility Operating Licenses DPR-58 and DPR-74 to change the CNP licensing basis as described in the Updated Final Safety Analysis Report. I&M proposed to incorporate a supplemental methodology into its analysis of steam generator (SG) overfill following a postulated steam generator tube rupture (SGTR). The proposed change would use the analysis methodology documented in the Westinghouse Electric Company WCAP-10698-P-A, "SGTR Analysis Methodology to Determine Margin to Steam Generator Overfill," to more accurately calculate the transient response of CNP to a postulated SGTR with respect to SG overfill.

In Reference 2, the NRC informed I&M that additional information was needed to enable the NRC staff to adequately evaluate the proposed amendment. In Reference 3, I&M informed the NRC that the response to the requested information would be provided by June 30, 2001. The attachment to this letter provides the information requested in Reference 2.

There are no new commitments made in this submittal.

Should you have any questions, please contact Mr. Ronald W. Gaston, Manager of Regulatory Affairs, at (616) 697-5020.

Sincerely, W . Rencheck Vice President Nuclear Engineering

/bj b Attachment c: J. E. Dyer MDEQ - DW & RPD NRC Resident Inspector R. Whale

ATTACHMENT TO C0601-21 RESPONSE TO NUCLEAR REGULATORY COMMISSION STAFF REQUEST FOR ADDITIONAL INFORMATION REGARDING LICENSE AMENDMENT FOR CHANGES IN STEAM GENERATOR TUBE RUPTURE ANALYSIS METHODOLOGY By letter dated October 24, 2000, from R. P. Powers, Indiana Michigan Power (I&M), to the Nuclear Regulatory Commission (NRC) Document Control Desk, I&M submitted a license amendment request to incorporate a supplemental methodology into its analysis of steam generator (SG) overfill following a postulated steam generator tube rupture (SGTR). The NRC, by letter dated May 7, 2001, from J. F. Stang (NRC) to R. P. Powers (I&M), requested additional information regarding the October 24, 2000, submittal. The information provided below responds to the NRC's request for additional information.

NRC Question "Section D, 'Plant Specific Submittal Requirement,' of Enclosure 1 of the safety evaluation for WCAP- 10698-P-A, states that certain plant-specific input shall be provided when referencing the WCAP for licensing actions. Please provide the required information."

I&M Response I&M is proposing to utilize limited aspects of the WCAP-10698-P-A methodology and associated computer codes to supplement Donald C. Cook Nuclear Plant's (CNP's) current licensing basis SGTR analysis to directly address postulated steam generator overfill. The proposed change in methodology would be applied only to supplemental analyses for the determination of the time available for operator actions to prevent overfilling the secondary side of the affected SG in response to a SGTR event. This change in analysis technique is being proposed because it provides a more accurate representation of SG fill than CNP's current licensing basis. CNP's present methodology would be retained for calculating the radiological consequences of the postulated SGTR since the current CNP licensing basis methodology continues to bound the radiological consequences calculated by the new methodology. Since not all aspects of the WCAP-10698-P-A methodology are being adopted by I&M, not all five plant specific input requirements, as described in Section D of the NRC safety evaluation report (SER) for WCAP-10698-P-A, are applicable to CNP.

The five items described in Section D of the SER for WCAP-10698-P-A are provided below with I&M's response following each item.

(1) Each utility in the SGTR subgroup must confirm that they have in place simulators and training programs which provide the required assurance that the necessary actions and times can be taken consistent with those assumed for the WCAP-10698 design basis analysis. Demonstration runs should be performed to show that the

Attachment to C0601-21 Page 2 accident can be mitigated within a period of time compatible with overfill prevention, using design basis assumptions regarding available equipment, and to demonstrate that the operator action times assumed in the analysis are realistic.

The required operator action times used in the CNP-specific SGTR margin to overfill analysis were verified via simulator demonstration runs to assure the operators could mitigate the accident within a period of time compatible with overfill prevention. The bounding design basis analysis documented in WCAP-10698 is not being used by CNP, as discussed further in item (5), since the margin to SG overfill following a SGTR has been addressed by CNP-specific analyses.

The required operator action times used in the CNP-specific analysis have been incorporated into CNP's Operator Training program to assure continued adequate performance and continued justification for the use of the assumed times. SGTR scenarios were also included in the simulator validation of CNP's Emergency Operating Procedure (EOP) program. Validation includes, for example, verification that the EOP is compatible with plant design and can be performed within acceptable time limits.

(2) A site-specific SGTR radiation offsite consequence analysis which assumes the most severe failure identified in WCAP-10698, Supplement 1. The analysis should be performed using the methodology in SRP Section 15.6.3, as supplemented by the guidance in Reference (1).

As stated in I&M's October 24, 2000, submittal, CNP's current licensing basis calculation for offsite radiological consequences of a postulated SGTR remains bounding. Specifically, the mass transfer values used in the current licensing basis analysis for offsite dose consequences bound those calculated using the new WCAP methodology. Therefore, CNP's present methodology is being retained for calculating the offsite radiological consequences of a postulated SGTR.

(3) An evaluation of the structural adequacy of the main steam lines and associated supports under water-filled conditions as a result of SGTR overfill.

An evaluation of the structural adequacy of CNP's main steam lines under water filled conditions is not necessary. The margin to SG overfill analysis following a SGTR determined that an overfilled condition would not occur. This conclusion is supported by CNP operator action timing and plant simulator runs, which have also been validated as discussed in item (1) above.

(4) A list of systems, components and instruments which are credited for accident mitigation in the plant specific SGTR EOP(s). Specify whether each system and component specified is safety grade. For primary and secondary PORVs and control valves specify the valve motive power and state whether the motive power and valve controls are safety grade. For non-safety grade systems and components

Attachment to C0601-21 Page 3 state whether safety grade backups are available which can be expected to function or provide the desired information within a time period compatible with prevention of SGTR overfill or justify that non-safety grade components can be utilized for the design basis event. Provide a list of all radiation monitors that could be utilized for identification of the accident and the ruptured steam generator and specify the quality and reliability of this instrumentation if possible. If the EOPs specify steam generator sampling as a means of ruptured SG identification, provide the effect on the duration of the accident.

As indicated in CNP's response to item (1), the license amendment request is intended to apply a more accurate analysis to demonstrate that CNP's current licensing basis of precluding SG overfill is maintained. A list of the systems, components and instruments credited in CNP's current SGTR analysis is provided in the table below.

The actions prescribed in CNP's EOPs for SGTR accident mitigation focus on four key aspects:

"* isolating the ruptured SG,

"* cooling the reactor coolant system (RCS),

"* depressurizing the RCS, and

"* terminating operation of the emergency core cooling system (ECCS).

The EOPs for a reactor trip or safety injection, and a steam generator tube rupture direct the operators to use specific equipment. The most challenging SGTR scenario with respect to SG fill includes a coincident loss of offsite power, which results in some of the equipment allowed to be used in the EOPs (consistent with the Westinghouse Emergency Response Guidelines) to be unavailable. Thus, the EOP-prescribed equipment presented in the tables and discussions below are based on offsite power not being available.

If Non-Safety Grade, is Equipment/ ID No. Safety Safety Grade Function Remarks Component Name Grade Backup (Y or N) Available?

(Y or N)

SG Water Level - BLP-lxO, -lxl, -1x2; Y N/A Ruptured SG Narrow Range where x corresponds Identification to SG's I through 4 AFW Discharge FMO-211 & -212, - Y N/A Ruptured SG Valve 221 & -222, -231 & - Isolation 232, or -241 & -242 Main Feed Pump Unit 1: 1-OME N N Feedwater Notes I Trip LPSVE, -LPSVW, - Isolation and 6 HPSVE, -HPSVW Unit 2: 2-OME-84 SCVE, -SCVW __

Attachment to C0601-21 Page 4 Main Feed Pump FMO-251 and -252 N N Feedwater Notes 1 Discharge Valves Isolation and 6 Feedwater FRV-210, -220, -230, N N Feedwater Notes 1 Regulating Valves -240 Isolation and 6 Feedwater Isolation FMO-201, -202, - N N Feedwater Notes 1 Valves 203, -204 Isolation and 6 Steam Supply Valve MCM-22 1, or -231 Y N/A Ruptured SG to TDAFP Isolation SG Blowdown DCR-310, -320, -330, N N Ruptured SG Note 6 Isolation Valve or -340 Isolation SG Blowdown DCR-301, -302, -303, N N Ruptured SG Note 6 Sample Valve or -304 Isolation SG Stop Valve MRV-210, -220, - Y N/A Ruptured SG Note 2 230, or -240 Isolation SG PORVs MRV-213, -223, - N N Ruptured SG Notes 3, (air-operated) 233, -243 Isolation and 4, and 6 RCS Cooldown via Non Ruptured SGs Core Exit Y N/A Monitor RCS Thermocouples NTR-I through -65 Cooldown Pressurizer PORVs NRV- 151, -152, and N N RCS Notes 4 (air-operated) -153 Depressurization and 6 Pressurizer Water NLI-151, NLP-151, - Y N/A ECCS Note 5 Level 152, -153 Termination Criteria Notes:

1. The isolation of main feedwater is provided post-reactor trip via a feed pump trip, closure of the feed pump discharge valves (FMO-251 & -252), feed regulating valves (FRV-210, -220, 230, and -240), and the feedwater isolation valves (FMO-201, -202,

-203, and -204).

2. The SG stop valves drain valve (DRV-407) and steam line warming valves (MS-144 and -143) are also closed, or check closed. These lines are not a significant secondary vent path, and thus timely closure is not critical.

3. The SGTR EOP directs the operators to increase the setpoint of the SG PORV on the ruptured SG from the nominal setpoint of 1025 psig to 1040 psig.

4. The SG PORVs form part of the main steam system pressure boundary upstream of the SG stop valves, and thus are safety-grade. However, the electrical and control air appurtenances for the SG PORVs are non-safety grade. Similarly, the pressurizer PORVs provide part of the safety grade RCS pressure boundary, but the control functions to manipulate these valves are classified as non-safety grade. Two of the

Attachment to C0601-21 Page 5 three pressurizer PORVs (NRV-152 and -153) have a continuous back-up source of air in the form of air bottles inside containment. As such, no operator action is required to align the back-up air bottles.

5. During the RCS depressurization, pressurizer level is restored to satisfy, in part, the ECCS termination criteria. Upon satisfying the ECCS termination criteria, the safety injection pumps are secured, all but one centrifugal charging pump (CCP) is stopped, and the boron injection tank is isolated. The remaining CCP is used to establish charging and letdown.

6. The Unit 1 and Unit 2 CNP licensing basis SGTR analysis described in Section 14.2.4 of the UFSAR credits non-safety grade equipment to mitigate the consequences of a SGTR accident. Thus, the use of the non-safety grade equipment, (e.g., SG and pressurizer PORVs) for accident mitigation following a SGTR in the margin to SG overfill analyses is consistent with CNP's licensing bases for both units.

The following radiation monitors could be used for identification of a SGTR accident.

• SG blowdown line,

• SG power-operated relief valve (PORV) line,

• gland steam condenser vent, and

• steam jet air ejector vent.

All four of the radiation monitor instruments listed above are non-safety grade, and are specifically listed in the EOPs as indications that can be used for identification of a SGTR event. These instruments are maintained and tested in accordance with CNP Technical Specifications and Offsite Dose Calculation Manual requirements. In accordance with 10 CFR 50.65, these instruments are also monitored within the scope of CNP's maintenance rule program. These monitors have not exceeded their maintenance reliability criteria.

The SGTR EOP allows identification of the ruptured SG by any of following indications:

a) directing chemistry personnel to sample all SGs for an activity analysis and perform a one-minute beta analysis, and b) identifying the ruptured SG by one or more of the three indications:

"* an unexpected rise in SG narrow range level, or

"* high radiation from any SG sample, or

"* high radiation from any SG PORV.

The most limiting accident scenario with respect to SG tube overfill is the complete severance of one SG U-tube. The high primary to secondary flows that result from this

Attachment to C0601-21 Page 6 design basis accident allow the ruptured SG to be promptly identified by the operators due to the unexpected rise in SG narrow range level. Thus, the most timely indication of the design basis SGTR is provided by the narrow range SG water level.

The chemistry sample provides a longer-term confirmatory indication of the ruptured SG for large break scenarios. The chemistry sample is only one of three methods specified in the SGTR EOP for the identification of the affected SG. The operator can use any one of the three methods for identifying a ruptured SG. The EOP actions focus primarily on the other two methods; checking the readings from the four radiation monitors discussed previously to see if the SG tubes are intact, and checking SG levels. The reactor trip EOP does include directions to sample the SGs in the event that the ruptured SG event was not identified by checking the radiation monitors. Thus, the chemistry sample of a ruptured SG provides confirmation, not primary indication, in the case of a design basis break.

In summary, the high primary to secondary flow rate due to a design basis break results in SG water level behavior and radiation monitor alarms that provide relatively quick indication of a ruptured SG. Therefore, the SG chemistry sample analysis time is not a critical aspect of the accident mitigating actions for scenarios that would be challenging with respect to SG fill.

(5) A survey of plant primary and "balance-of-plant" system design to determine the compatibility with the bounding plant analysis in WCAP-10698. Major design differences should be noted. The worst single failure should be identified if different from the WCAP-10698 analysis and the effect of the difference on the margin of overfill should be provided.

This item is not applicable to CNP. CNP is not using the bounding plant analysis as described in WCAP-10698. As stated in Reference 1, CNP proposes to apply limited use of the WCAP-10698 methodology (and associated computer code) to supplement the CNP SGTR analysis with a CNP-specific margin to SG overfill analysis. The supplemental margin to SG overfill analysis used plant-specific analysis input values.

Since the supplemental analysis is CNP-specific, the WCAP-10698 bounding plant analysis was not used, or needed. Therefore, there is no need to differentiate the CNP design from the generic plant design. Regarding worst single failure assumptions, CNP's current licensing basis SGTR analysis does not include a single failure. Thus, there is no need for CNP to consider a single failure in the SGTR margin to overfill analysis.

Comparison to No Significant Hazards Evaluation CNP's response to the NRC's request for additional information does not affect the original evaluation performed in accordance with 10 CFR 59.92. The information provided in this response is considered supporting information and does not change the intent of CNP's original submittal.

Attachment 4 Compressed Air and Control Air System Overview Drawings

EQUIPMENT OPERABILITY REQUIREMENTS AIR SYSTEM SETPOINTS 125 psig Air receiver safety valves open PPI Units 1 and 2:

106 psig CAS wet receiver pressure CAC unloads 1 Control air compressor, plant air compressor, east and west dryer 100 psig CAS wet receiver pressure CAC loads strings, containment control air headers #1 and #2, the turbine and PPA 98 psig at PPS-11(21) Plant air header un-isolates auxiliary building 20 psi, 50 psi, and 85 psi control air headers 1 97 psig Turbine Building air header Alarm PAC failure / low pressure 95 psig at XPA-100 (100# header) Control air pressure low alarm Common:

PTA 95 psig at PPS-10 or 20 Stand-by PAC starts Inlet Filter Common plant air compressor (standby compressor on roof)

Silencer 1 90 psig CAS wet receiver pressure Associated CAC auto-starts PA-112 85 psig at PPS-11(21) Plant air header isolates PDI Applicability:

PDI SV-75 80 psig Control Air Pressure Manual Reactor Trip 1 Modes 1, 2, 3, 4, 5, and 6 1

PA-104 NESW NESW 5 psid in .3 sec PAC surge protection-unloader opens PPX PTI PTA 3 2 2 PPI 2

PRV-1 PA-105 PA-111 SYSTEM PURPOSE Separator Plant Air After Cooler The Plant Air System provides compressed air Plant Air Moisture Receiver PFR Hose Connections for general plant services, instrumentation and Reservoir 200 cu ft 1 PPI Screen House control (the Plant Air System normally supplies PRV-2 4 PPA Hose Connection the Control Air System), containment XTA 20 Turbine Lagging integrated leak rate testing, containment 23 Drain Generator Purge penetration pressurization, and respiratory use.

PA-113 PPI PA-120 Diesel Generator Rooms PA-114 XRV-5 PA-247 20 PPS AUTO FEATURES 20 PRV-21 To Drain

• Compressor auto starts at 95 psig in the plant Compressor PRV-20 Controls air ring header by PPS-10(20)

PA-115 PPI

• Plant air ring header auto isolation by PPS-PPA PA-116 11(21) 2 3 Normal air supply To PPS

• Compressor unloader valve PRV-2 maintains to air compressor control Unit 2 Aux Building, XRV-2 XRV-3 from 100 psig control air Refueling area, 21 constant discharge pressure with changing header Containment loads 2-PA-128 demand Seal air to plant Unit 2

• Compressor unloader valve fully opens for air compressor Control Air System Unit 2 Plant Air surge protection

• Auxiliary oil pump auto start on PAC Start and Compressor SHuddown PPI (Cross Connect) 1 PAC AUTO TRIPS PPA 1

• Load Shed (Train B)

Inlet Filter 1-PA-128

• Load Conservation (Train B)

Silencer PTA Unit 1 PDI 1 Control Air System

• Low Oil Pressure 1

PA-104

• High Oil Temperature PA-112 PDI PA-129 SV-75 PPS

• High 1st Interstage Air Temperature 1 11 Backup Air NESW NESW PPX PTI PTA Compressor

• High 2nd Interstage Air Temperature PRV-1 3 2 2 PPI

• Loss of Control Inverter 2

• Microprocessor Fault PRV-10 PA-105 PA-111 Unit 1 and Unit 2

• Motor Current Transducer Failure Containment Plant Air After Cooler Separator Pressurization

• Transmitter Failures PRV-2 Plant Air Testing PPS Moisture Receiver PFR 200 cu ft 10 Reservoir 1 PPI XTA 4 PPA 10 PAC MANUAL TRIPS 23 Drain

• Control Room Switch PPI PA-113 PA-120

• DCCS- Select STOP PA-114 XRV-5 PA-247 10 PRV-11 Service Building, Diesel Generator Rooms, Chemistry Lab,

• Manual Emergency Trip PB Plant Heating Boiler, Hose Connections - Turbine Lagging, Generator Purge, Makeup Plant, Hose Connections - Screen House Chemical Cleaning Tank To Drain Compressor Controls SOD-06401-002 PPA PPI PA-115 PLANT AIR SYSTEM 2 3 PA-116 Sheet #: 1 Rev. 5 Date: 09/28/10 Normal air supply To Unit 1 Aux Building, to air compressor control Refueling area, FOR TRAINING USE ONLY from 100 psig control air Containment loads XRV-2 XRV-3 Unit 1 Plant Air header To Turbine Room Sump Compressor Seal air to plant air compressor

EQUIPMENT OPERABILITY REQUIREMENTS AUTO FEATURES CA-108 Set at 125 psi CA-369

• Compressor auto start at 90 psig in the wet-air receiver (PPS-3)

Exhaust NESW NESW SV-39 Units 1 and 2:

• Compressor loads at 100 psig and unloads at 106 psig in the wet-air XTA XPX XTX XTA XTI XTX Control air compressor, plant air compressor, east and west dryer receiver (PPS-2) 1 1 1 2 1 2 strings, containment control air headers #1 and #2, the turbine and auxiliary building 20 psi, 50 psi, and 85 psi control air headers

• Compressor trips on low oil pressure or low NESW pressure XPI To Cylinder Unloaders 1 CA-102 CA-107 Common:

NESW XSO-53 After Common plant air compressor (standby compressor on roof)

Control Air Cooler Wet Control SYSTEM PURPOSE Compressor Air Receiver Applicability:

PPS The control air system provides a reliable source of filtered and dried air XPA Modes 1, 2, 3, 4, 5 and 6 1 3 at three different regulated pressures for plant instrumentation and Drain 500 cu ft controls.

CA-112 PPS Electric PA-128 2

Heater Drain Purge Outside Inside Blower Containment Containment

• typical of 2 Relief Valves SV-43N XTC 27 XDI

• 55psig From plant air 12 CA-113 supply ring To 50 psig XPI SV-206-4 XPA XRV-151 supply ring CA-114 25 104 CA-127NE CA-128NE 90psig 55psig CA-115NW CA-115NE XPX XPI To 85 psig East 17 13 XFI-100 supply ring CA-123 Air North Rotameter XCR-100 XCR-101 XRV-186 CA-130N CA-132N XPX XPX Dryers North 500 cu ft To 100 psig 13 11 After XFR

• header XSO-58 55psig Filters 13 XTA To 50 psig North XPI 13 NC NC 11 Drain XPA supply ring Pre-Filters SV-206-3 XTI 101 XRV-150 Drain 90psig Exhaust 28 XDI CA-133N CA-134N CA-119N CA-120 CA-121E To 85 psig 14 supply ring Drain Drain CA-853 XCR-102 XCR-103 XRV-185 CA-116NE XRV-11 NO CA-124 XPI CA-127NW CA-128NW XSO-57 XPS XPI To NESW valves CA-116NW 26 Exhaust 100 100

• Air Filters XPA XPI for containment 55psig cooling CA-131 Dry Control 50 50 Note: Unit 1 component configuration is shown.

For Unit 2 the flow path is: Electric Air Receivers QR-12-1 Heater CA-143 XRV-50 CA-791 CA-149 CA-155 CA-161 North Pre-Filter West air Dryer North After Filter Drain CA-168 To control South Pre-Filter East air Dryer South After Filter

• 55psig air system QR-12-2 CA-167 50 psig header Purge XTC Drain CA-144 XRV-51 CA-792 CA-150 CA-156 CA-162 Blower SV-43S 17 XPA XPI XDI

• 25psig 20 20 22 CA-113 QR-12-3 CA-142 XPI SV-206-2 CA-145 XRV-20 CA-793 CA-151 CA-157 CA-163 To control CA-114 15

• air system CA-127SE CA-128SE 25psig CA-115SE 20 psig header CA-115SW XPX XPI QR-12-4 CA-123 West South 27 23 CA-146 XRV-21 CA-794 CA-152 CA-158 CA-164 XPX XPX Air After CA-130S CA-132S South XPI XPI 23 21 Dryers Filters 500 cu ft

• 90psig 84 19 XPA XPI XFR 85 85 XSO-56 XTA 23 South XPI 23 QR-12-5 21 Drain CA-147 XRV-85 CA-795 CA-153 CA-159 CA-165 To control Pre-Filters air system SV-206-1 XTI Drain

• 90psig Exhaust 18 XDI CA-133S CA-134S 85 psig header CA-119S CA-120 CA-121W QR-12-6 24 Drain Drain CA-148 XRV-86 CA-796 CA-154 CA-160 CA-166 CA-116SE XRV-10 CA-124

• typical of 2 Relief Valves XPI CA-127SW CA-128SW SOD-06401-001 XSO-55 CA-116SW 16 Exhaust Normal Supply to To Containment Weld Channel Pressurization CONTROL AIR SYSTEM Compressor Control System Sheet #: 1 Rev. 4 Date:09/28/10 CA-148 CA-148 CA-134S (Abandoned in Place)

FOR TRAINING USE ONLY Drain Drain

Attachment 5 Electrical System Overview Drawings

LEGEND PURPOSE Derby Bridgman AB The BOP Electrical System has no 765 KV Capacitor Bank Safety Related functions, and no credit is 345 KV 12 TR-7 taken for the offsite power sources for 69 KV 69 KV 12 KV Safe Shutdown due to Appendix R Fire or Station Blackout. Non-Safety Related 34.5 KV Containment Temp Power Functions are:

Training Access Fab Shop Transformers 26 KV Construction Emerg Warehouse

• Connect the main generator Trans Simulator Building Containment 12 KV Feed TR Sewage Fire output to the AEP System grid.

12 EP-2 52 G1 Facility Site Access Cooling 12 EP-1 Office Treatment Pump House G1 Control Building System

• Supply power to all plant 4 KV 2250KW Building & (Future)

M NC NO Addition S electrical buses including the 600 V Maint. Outage Dry Cask Condensate Facility Storage Polisher Reactor Coolant Pump (RCP) 52 G2 52 (Future) System buses, 600 VAC Buses BMC and G2 Palisades Palisades T1 EP Response to SBO Fish Deterrent (Future) CMC, and smaller MCCs served Bus No. 2 Bus No. 1 Twin Branch 2 Voltage Supplemental 1. Wait 150sec for Grid response by BMC and CMC. The BOP VR System Regulator Diesel 2. Motorized Disconnect Switch Opens System uses an offsite power Generators 3. Start Supplemental Diesels source when the plant is off-line.

N2 N N1 4. 1st Diesel Generator up to speed and

• Supply power for support Dumont Line 2EP Voltage closes in to dead bus Livingston Road 12KV Circuit buildings and functions.

Olive 1EP

5. 2nd Diesel Generator Auto Sync to 1st diesel Plant Guard Street B2 generator M2 M M1 Visitors Security Center House Lighting 765 KV 6. Tie Breaker Closes to energize EP bus.

System 4 KV 7. Operator Manually energizes T-Buses 345 KV A2 A1 L2 L L1 Reserve Reserve Feed Feed Hiple TR5 TR4 To Unit 1 To Unit 2 Twin Safety Buses Safety Buses Branch 1 BE NC BC NC K2 K K1 NO BD RCP BUS FAST TRANSFER Main/GSU TR 12 12 Fast Transfer is the automatic re-AB 34.5 KV CD alignment of power supplied to the RCP buses from the UATs, to the RATs as follows:

• Trip the generator output U1 U2 Main switchyard circuit breakers.

Main Gen 34.5 KV 34.5 KV Gen 34.5 KV 34.5 KV

• Trip the UAT supply breakers to the Unit Reserve Unit Reserve Unit Aux Reserve Unit Reserve Main/GSU RCP buses.

Aux TR Aux TR Aux TR Aux TR TR Aux TR Aux TR Aux TR TR

• Close the RAT supply breakers to 1AB 101AB 1CD 101CD 2AB 201AB 2CD 201CD the RCP buses.

These actions initiate simultaneously resulting in 30 milliseconds dead time on the RCP buses. Fast transfer is 7 5 7 5 6 4 5 3 7 5 7 5 6 4 5 3 designed to maintain power to the RCP motors.

1A 4 KV 1B 1C 4 KV 1D 2A 4 KV 2B 2C 4 KV 2D For lockout relay activated generator RCP Bus RCP Bus RCP Bus RCP Bus trips, the RCP buses immediately fast T11C transfer. For reactor / turbine trips, there T11A 1B6 T11B 1B4 1C3 1C5 T11D T21A 2B6 T21B 2B8 2C3 T21C 2C5 T21D is a 30 second delay while the generator 4 KV 4 KV 4 KV 4 KV Vital Bus 4 KV Vital Bus 4 KV Vital Bus 4 KV 4 KV Vital Bus remains connected to the electrical Vital Bus Vital Bus Vital Bus TR11BMC TR11CMC TR21BMC Vital Bus system, then fast transfer initiates.

TR11BLC TR11CLC TR11BLC TR11CLC TR21CMC 11BLC1B 11CLC5B 21BLC1B 21CLC5B 600V Non Vital 600V Non Vital 11BLC 11CLC 21BLC 21CLC 11BCLC 21BCLC Various Various 11BMC1 Unit 1 Turbine 11CMC11 21BMC1 Unit 2 Turbine 21CMC11 Hydraulic System Loads Hydraulic System Loads 600V Non Vital 11BMC 11CMC 600V Non Vital 600V Non Vital 21BMC 21CMC 600V Non Vital 11BCMC 21BCMC SOD-08200-001 2 4 6 8 10 12 14 12 10 8 6 4 2 2 4 6 8 10 12 14 13 9 7 5 3 1 BALANCE OF PLANT ELECTRICAL SYSTEM 3 5 7 9 11 13 13 9 7 5 3 1 3 5 7 9 11 13 12 10 8 6 4 2 Sheet #: 1 Rev. 8 Date: 08/14/09 FOR TRAINING USE ONLY Various MCCs Various MCCs Various MCCs Various MCCs

LOAD SHED A load shed signal is developed in response to an undervoltage (80% of nominal) sensed on any 2 of 3 phases of any safety related 4 kV bus for a period of 2 seconds. 12EP1 From Supplemental Actions that occur upon receipt of a load shed signal: Diesel 4 kV

1. Trips open and blocks closure of the feed breakers which supply power to the bus, thereby ensuring the bus is completely de-energized in preparation for becoming energized by the EDG. Generators

2. Trips open and blocks closure of breakers that supply power to the large motor loads to prevent the EDG from overloading when it connects to the bus.

3. Trips open and locks out selected small loads to prevent overloading the EDG as ESF equipment sequences on to the bus.

4. Starts the EDG. 1EP 2EP From RCP From RCP From RCP From RCP From RCP From RCP From RCP From RCP Bus 1A Bus 1B Bus 1C Bus 1D Bus 2A Bus 2B Bus 2C Bus 2D TECHNICAL SPECIFICATIONS 3.3.5 Loss of Power (LOP) Diesel Generator (DG) 4 kV 4 kV Start Instrumentation 3.8.1 AC Sources - Operating 3.8.2 AC Sources - Shutdown A9 1AB Diesel B1 C1 1CD Diesel D12 A9 2AB Diesel B1 C1 2CD Diesel D12 3.8.9 Distribution Systems - Operating 3.8.10 Distribution Systems - Shutdown A12 B2 C2 D1 A12 B2 C2 D1 BREAKER INTERLOCKS A11 B4 C3 D8 A11 B4 C3 D8 69 kV emergency feeder breakers to 4 kV vital buses T11A T11B T11C T11D T21A T21B T21C T21D h Emergency feeder breakers will not close if either 4 kV 4 kV 4 kV EDG or RCP bus tie breaker is closed h EDG & RCP bus tie breakers will not close if 69 kV 6 10 2 9 6 10 2 9 Breaker is closed Purpose - Prevent paralleling emergency feeder with reserve & auxiliary power supplies (emergency busses 30° out of phase with offsite) 11 1 11 1 11 1 11 1 RCP bus tie breakers h Cannot close RCP bus tie breakers (A9, D12, etc.) 480V 600V 600V 480V 480V 600V 600V 480V 11PHA 11A 11AC 11C 11B 11BD 11D 11PHC 21PHA 21A 21AC 21C 21B 21BD 21D 21PHC unless either reserve or auxiliary feeder breakers to the RCP bus is closed Purpose - Prevent powering RCPs from EDGs LOAD CONSERVATION 11A5 11C10 11B1 11D5 21C10 21B1 21D5 11B & 11D bus tie breaker (same for 11A & C tie) h Bus tie breaker cannot be closed unless feeder The load conservation circuit strips non-essential loads from the breaker for either 11B or 11D is open safeguards buses in the event of a LOOP concurrent with a SI MCC MCC MCC MCC MCC MCC MCC Example: Cant close 11BD unless either 11B11 or or CTS signal. 1-ABD-A 1-ABD-C 1-ABD-B 1-ABD-D 2-ABD-C 2-ABD-B 2-ABD-D 11D1 is open Purpose -Prevent inadvert paralleling of EDGs or Conditions that cause load conservation:

opposite electric trains which could cause overcurrent condition. 1. LOOP followed by a SI - EDG up to speed, output Note - These breakers are Red Tagged open. breakers closed to T11A/21A or D, and SI occurs. CVT CVT

2. SI followed by a load shed - Standing SI signal, EDG 11PHA & C feed to variable control group PZR up to speed but not connected to the bus, and a bus heaters undervoltage condition occurs.

h Only one at a time can be closed 120 V ELSCX 120 V AFW 120 V ELSC 120 V AFWX 120 V AFW 120 V AFWX

3. LOOP followed by a CTS signal - EDG up to speed, 120 V ELSC 120 V ELSCX Purpose - Prevent paralleling EDGs on blackout output breakers closed to T11A/21A or D, and a CTS Normal at power all RCP buses from our main generator output signal occurs. DEGRADED BUS VOLTAGE

4. CTS followed by a load shed - Standing CTS signal, EDG up to speed, and a bus undervoltage condition Degraded Bus Voltage Sensed occurs. (2/3 Phase on T11A(T21A) or T11D(T21D) at 113V Indicated) BUS T11A BUS T11D 1S SI 1N SI LEGEND Actions that occur upon receipt of load conservation signal: Without SG Lo-Lo Level OR SI Signal AND on West AFW Pump East AFW Train A UAT's 1W CS Pump 1E CS Pump

1. Trips and locks out selected non-essential vital bus 4 After 90 seconds the train sensing the DBV will 1W RH Pump 1E RH Pump Train B loads. 1W ESW Pump 1E ESW RCP bus tie breaker transfer to the RAT.

2. Prevents restarting any stripped loads until either the 1W CCW 1E CCW 75 second load conservation timer times out or SI is 4 The RAT will load change to try to address the low 1W Charging Pump 1E Charging Pump Emergency feeder breaker reset after the 60 second SI timer times out. voltage condition. EDG feeder breaker

3. Trips non-essential service water pump. 4 IF the low voltage condition persists for 21 seconds, the train RCP Tie Breakers Open. SOD-08201-001 EMERGENCY FEED If another SI signal is generated after the SI is reset with the 4 Note: 9 seconds to sense + 90 second wait for swap ENGINEERED SAFETY EDG breakers closed, load conservation reinitiates. TRANSFORMER to RAT + 21 seconds to correct = 120 seconds.

(12 EPI) SYSTEMS ELECTRICAL With SG Lo-Lo Level OR SI Signal Sheet #: 1 Rev. 4 Date: 03/09/09 Used only if 4 After 9 seconds, RCP Tie Breakers open. - Normal power lost & FOR TRAINING USE ONLY

- Reserve power lost &

4 Loss of voltage relays Start the EDGs - One or both DGs lost

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Attachment 8 Applicable Pages of DC Cook Procedure PMP-2291-WMP-001

Doc No.: PMP-2291-WMP-001 Rev No.: 020

Title:

WORK MANAGEMENT PROCESS FLOWCHART Alteration Cat.: Minor Revision CDI/50.59: N/A PORC Mtg. No.: N/A CARB Mtg. No.: 675 Admin Hold AR No.: N/A Superceding Proc(s): N/A Temp Proc Exp Date: N/A Temp Change Exp Date: N/A Temp Proc/Change End: N/A Effective Date: 8/24/2012 12:00:00 AM Approvals Name Review/Approval Type/Capacity Date Wendzel, Regan 7 Approval Authority 08/15/2012 12:30 Maret, Bruce 5 Management Review 08/14/2012 10:31 Hicks, Roger 3 Technical Review 08/08/2012 13:41 Carlson, Guss E 1 Validation Review 08/08/2012 13:25 Lain, Thomas 3 Technical Review 07/20/2012 10:19 Keppeler, Randall 1 Cross-Discipline Review 07/20/2012 08:49 Lain, Thomas 1 Cross-Discipline Review 07/09/2012 12:04 Williams, Alisa 1 Cross-Discipline Review 07/06/2012 11:33 Carlson, Guss E 1 Validation Review 07/03/2012 11:56 Swanson, Scott 1 Cross-Discipline Review 06/29/2012 09:25 Gressley, Scott 1 Cross-Discipline Review 06/28/2012 22:17 Gressley, Scott 1 Cross-Discipline Review 06/18/2012 13:36 Signature Comments Approved per Plant Manager Q. Shane Lies.

Approved at CARB 675 Will perform final review of BOM reviews with PM upon his return from vacation. Until then, this is approved as written.

Comments provided via e-mail

Information PMP-2291-WMP-001 Rev. 20 Page 292 of 305 Work Management Process Flowchart Figure 9 Guarded Equipment Listing Pages: 291 - 298 Inoperable or Equipment Unavailable Posting requirements Basis Guarded Item Rope across access to pump cubicle, sign with flasher on Protection of Charging Pump Operable CCP pump and sign on rope. Sign operable Tech Spec (CCP) on breaker and tag in Control equipment Room at 101 switch.

Protection of operable Tech Spec Signs with flasher on pump.

Component equipment. Loss of Operable CCW Sign on 4kV breaker and tag Cooling Water all CCW requires Pump in Control Room at 101 (CCW) Pumps reactor trip and trip switch.*

of all RCPs within 2 minutes.

Redundant Both available equipment and Condensate Signs with flashers on pumps.

equipment to Condensate Booster Pumps Sign on 4kV breakers and tags mitigate loss of Booster Pump AND in Control Room at each 101 additional Running Heater switch.*

Condensate Booster Drain Pumps Pump Signs with flashers on control Redundant Redundant panels for the individual Containment equipment and Containment Containment Cooling Chiller Cooling Chiller potential impact on Cooling Chiller Package. Signs on breakers.

Package Containment Cooling Package Sign on the integrated control capability.

console.

Sign with flasher on pump room gate and on stairs Protection of Containment Operable CTS leading to heat exchanger, tag operable Tech Spec Spray Train at 101 switch and sign on equipment pump breaker.

Control Air Sign with flasher on PAC.

Redundant Compressor Both PACs Sign on breaker and tag in equipment (CAC) Control Room at 101 switch.*

Sign with flasher on Control Air Redundant component. Sign on breaker Redundant Dryer/Filter/

equipment and control switches when equipment Regulator applicable.

Information PMP-2291-WMP-001 Rev. 20 Page 295 of 305 Work Management Process Flowchart Figure 9 Guarded Equipment Listing Pages: 291 - 298 Inoperable or Equipment Unavailable Posting requirements Basis Guarded Item MDAFW Pump - sign with flasher on door to East pump or sign with flasher on gate to West pump. Sign on 4kV Protection of Motor Driven breaker for applicable pump operable Tech Spec Other MDAFP Auxiliary and tag in Control Room at equipment.

AND Feedwater Pump applicable 101 switch.

TDAFP (MDAFP) Redundant TDAFW Pump - sign with equipment flasher on door to pump room and tag in Control Room at 101 switch.

Signs on breakers for Flow Protection of Motor Driven Other MDAFP Control Valves. Signs with operable Tech Spec Auxiliary AND flashers on the Flow Control equipment.

Feedwater Pump TDAFP Valves. Tags in Control (MDAFP) Flow Flow Control Room at applicable 101 Redundant Control Valves Valves switches. equipment Non-Essential Signs with flasher on pump.

Available Redundant Service Water Sign on breaker and tag in NESW Pump equipment (NESW) Pump Control Room at 101 switch.*

Opposite Unit Signs with flasher on PAC, PAC both CACs and Backup Air Plant Air AND Compressor. Sign on breaker Redundant Compressor Both CACs and tag in Control Room at equipment (PAC) AND 101 switch (except for Backup Backup Air Air Compressor).*

Compressor Plant Air Remaining Header Ring PRVs Sign on PRV and tag in Protection of plant Isolation Valve, AND Control Room at 101 switch.

air ring header.

PRV-10, 11, 20, both Units Signs with flasher on PAC.

or 21 PACs Note: Notify FWTDC the EP Yard (69 Switchyards are guarded.

kV) Protection of Reserve Feed AND Sign with flasher at EP yard redundant power Both Units Gate and sign with flasher on supplies EDGs EDG doors. Tag in Control Room at 101 switch.