ML13037A204

Response to Second Request for Additional Information to Support NRC Reactor Systems Branch (Srxb) Technical Review of the CR-3 Extended Power Uprate LAR

ML13037A204
Person / Time
Site:	Crystal River
Issue date:	01/31/2013
From:	Franke J Duke Energy Corp, Florida Power Corp
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
3F0113-08, TAC ME6527
Download: ML13037A204 (19)

Text

PDuke E Energy Crystal River Nuclear Plant Docket No. 50-302 Operating License No. DPR-72 January 31, 2013 3F01 13-08 U.S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, DC 20555-0001

Subject:

Crystal River Unit 3 - Response to Second Request for Additional Information to Support NRC Reactor Systems Branch (SRXB) Technical Review of the CR-3 Extended Power Uprate LAR (TAC No. ME6527)

References:

1. FPC to NRC letter dated June 15, 2011, "Crystal River Unit 3 - License Amendment Request #309, Revision 0, Extended Power Uprate" (ADAMS Accession No. ML112070659)

2. Email from S. Lingam (NRC) to D. Westcott (FPC) dated November 13, 2012, "CR-3 EPU LAR - SRXB Draft RAls (ME6527)"

3. NRC to FPC letter dated December 19, 2012, "Crystal River Unit 3 Nuclear Generating Plant - Request for Additional Information for Extended Power Uprate License Amendment Request (TAC No. ME6527)" (ADAMS Accession No. ML12333A089)

Dear Sir:

By letter dated June 15, 2011, Florida Power Corporation (FPC) requested a license amendment to increase the rated thermal power level of Crystal River Unit 3 (CR-3) from 2609 megawatts (MWt) to 3014 MWt (Reference 1). On November 13, 2012, via electronic mail, the NRC staff provided a draft request for additional information (RAI) to support the SRXB technical review of the CR-3 Extended Power Uprate (EPU) License Amendment Request (LAR) (Reference 2).

By teleconference on December 12, 2012, CR-3 discussed the draft RAI with the NRC staff to confirm an understanding of the information being requested. On December 19, 2012, the NRC staff provided a formal RAI needed to complete its evaluation of the CR-3 EPU LAR (Reference 3). The letter identified that response to five of the RAls should be provided within 90 days and the remaining thirty one should be provided within 45 days from the date of RAI request. By agreement between Mr. Dan Westcott of FPC and Siva Lingam of the NRC on January 29, 2013, the response to RAI 2.8.5.4.5.3 will be changed from the 45 day response and will be provided as part of the 90 day response.

Attachment A to this correspondence, "FPC Response to Second Request for Additional Information - Reactor Systems Branch Technical Review of the CR-3 EPU LAR," provides the formal response to eight of the RAIs.

AI Crystal River Nuclear Plant

• 15760 W. Powerline Street Crystal River, FL 34428

U.S. Nuclear Regulatory Commission Page 2 of 3 3F01 13-08 Attachment B, "ANP-3195(P), Revision 0, Responses for Crystal River Unit 3 EPU Licensing Amendment Report NRC Reactor Systems Branch Requests for Additional Information (Proprietary)," provides the formal AREVA response to twenty two of the RAIs.

Attachment C contains an Affidavit executed by AREVA for withholding of proprietary information.

Attachment D, "ANP-3195(NP), Revision 0, Responses for Crystal River Unit 3 EPU Licensing Amendment Report NRC Reactor Systems Branch Requests for Additional Information (Non-Proprietary)," provides the formal redacted AREVA response to twenty two of the RAIs.

Attachment E contains a table listing the location of each response by the Attachment where it is located.

This correspondence contains no new regulatory commitments.

If you have any questions regarding this submittal, please contact Mr. Dan Westcott, CR-3 Regulatory Affairs Manager at (352) 563-4796.

Sincerely, J ;A. Franke

,vice President Crystal River Nuclear Plant JAF/scp Attachments:

A. FPC Response to Second Request for Additional Information - Reactor Systems Branch Technical Review of the CR-3 EPU LAR B. ANP-3195(P), Revision 0, Responses for Crystal River Unit 3 EPU Licensing Amendment Report NRC Reactor Systems Branch Requests for Additional Information (Proprietary)

C. AREVA Request for Withholding of Proprietary Infoirmation D. ANP-3195(NP), Revision 0, Responses for Crystal River Unit 3 EPU Licensing Amendment Report NRC Reactor Systems Branch Requests for Additional Information (Non-Proprietary)

E. Location of Reactor Systems RAI Responses xc: NRR Project Manager Regional Administrator, Region It Senior Resident Inspector State Contact

U.S. Nuclear Regulatory Commission Page 3 of 3 3F0113-08 STATE OF FLORIDA COUNTY OF CITRUS Jon A. Franke states that he is the Vice President, Crystal River Nuclear Plant for Florida Power Corporation; that he is authorized on the part of said company to sign and file with the Nuclear Regulatory Commission the information attached hereto; and that all such statements made and matters set forth therein are true and correct to the best of his knowledge, information, and belief.

Jon . Franke e President rystal River Nuclear Plant The foregoing document was acknowledged before me this ____ day of j J ,2013, by Jon A. Franke.

Signature of Notary Public State o Plrubi e4OL"q ~UIUA Awl[Wil PON%9 .': 4 ~

O7MM I £GL6 GO #uOlsIMSWW0 NNWVJ*IOd '3NA1'OIV" (Print, type, or stamp Commissioned Name of Notary Public)

Personally Produced Known / -OR- Identification

FLORIDA POWER CORPORATION CRYSTAL RIVER UNIT 3 DOCKET NUMBER 50-302 / LICENSE NUMBER DPR-72 ATTACHMENT A FPC RESPONSE TO SECOND REQUEST FOR ADDITIONAL INFORMATION - REACTOR SYSTEMS BRANCH TECHNICAL REVIEW OF THE CR-3 EPU LAR

U. S. Nuclear Regulatory Commission Attachment A 3F0113-08 Page 1 of 11 FPC RESPONSE TO SECOND REQUEST FOR ADDITIONAL INFORMATION - REACTOR SYSTEMS BRANCH TECHNICAL REVIEW OF THE CR-3 EPU LAR By letter dated June 15, 2011, Florida Power Corporation (FPC) requested a license amendment to increase the rated thermal power level of Crystal River Unit 3 (CR-3) from 2609 megawatts (MWt) to 3014 MWt (Reference 1). On November 13, :2012, via electronic mail, the NRC staff provided a draft request for additional information (RAI) to support the Reactor Systems Branch (SRXB) technical review of the CR-3 Extended Power Uprate (EPU) License Amendment Request (LAR). By teleconference on December 12, 2012, CR-3 discussed the draft RAI with the NRC staff to confirm an understanding of the information being requested. On December 19, 2012, the NRC staff provided a formal RAI needed to complete its evaluation of the CR-3 EPU LAR.

This Attachment contains eight responses prepared by FPC.

SRXB REQUEST FOR ADDITIONAL INFORMATION 2.8.4.3 Overpressure Protection During Low Temperature Operation 2.8.4.3.1 Please address the reduced exposure over which current low-temperature overpressure protection (LTOP) and pressure/temperature limits are valid by confirming that the Technical Specification (TS) is not limited by effective full-power year, or by revising the applicability period contained in TS 3.4.11.

Response

As indicated in Section 2.8.4.3 of the CR-3 EPU Technical Report (TR) (Reference 1, Attachments 5 and 7), the current pressure-temperature (P-T) limits continue to be acceptable for EPU operation with a Reactor Coolant System (RCS) radiation embrittlement accumulation of up to 27.5 effective full power years (EFPY). The change to the P-T limits applicability from 32 EFPY to 27.5 EFPY for EPU operation is identified in the markup of Improved Technical Specification (ITS) Bases B 3.4.11, "Low Temperature Overpressure Protection (LTOP)

System," which was included in the CR-3 EPU LAR (Reference 1, Attachment 4).

As noted in Section 2.8.4.3 of the EPU TR, a vessel fluency of 50.3 EFPY at EPU conditions was analyzed and it was determined that the current P-T limits and LTOP requirements may not support operation at EPU conditions beyond 27.5 EFPY. Additional correspondence regarding the evaluations of the current CR-3 P-T limits at EPU conditions were provided to the NRC Reactor Vessels and Internals Branch in FPC to NRC letters dated September 27, 2012 (Reference 2) and December 18, 2012 (Reference 3).

P-T Limits CR-3 Limiting Condition for Operation (LCO) 3.4.3, "RCS Pressure and Temperature (P/T)

Limits," requires the P-T limits to be maintained within the limits specified in the RCS Pressure and Temperature Limits Report (PTLR). As required by ITS 5.6.2.19, "Reactor Coolant System (RCS) PRESSURE AND TEMPERATURE LIMITS REPORT (PTLR)," the P-T limits are developed in accordance with the requirements of 10 CFR 50 Appendix G utilizing the analytical methods specified in Babcock and Wilcox (B&W) Topical Report BAW-10046A, "Methods of

U. S. Nuclear Regulatory Commission Attachment A 3F01 13-08 Page 2 oflI Compliance with Fracture Toughness and Operational Requirements of 10 CFR 50, Appendix G," (Reference 4). The applicability of the current P-T limits was adjusted from 32 EFPY to 27.5 EFPY based on changes in reactor pressure vessel (RPV) fast neutron fluence (neutron E >

1.0 MeV) as a result of operation at EPU conditions. As of the end of CR-3 operating Cycle 16, the currently calculated EFPYs is 22.8 (Reference 2). Therefore, the CR-3 ITS requirements associated with P-T limits are not required to be specifically modified as a result of limiting the current P-T limits to 27.5 EFPY at EPU conditions at this time.

As required by 10 CFR 50.59 and 10 CFR 50.90, FPC will, when required, obtain a license amendment to change the ITS prior to EPU operation beyond 27.5 EFPY to address any revised CR-3 P-T limits.

LTOP Requirements As stated in the applicable safety analysis section of the CR-3 ITS Bases B 3.4.11, the LTOP applicability is based on a limiting reactor vessel temperature of 263°F at the 1/4T wall depth and the LTOP enable temperature of 264°F includes correction for instrument uncertainty. This LTOP enabling temperature remains conservative and RCS LTOP is maintained during operation at EPU conditions up to 27.5 EFPY. Therefore, the LCO 3.4.11 applicability is not required to be modified for operation at EPU conditions.

As required by 10 CFR 50.59 and 10 CFR 50.90, FPC will, when required, obtain a license amendment to change the applicability of LCO 3.4.11 prior to EPU operation beyond 27.5 EFPY to address any revised CR-3 P-T limits.

2.8.4.4 Residual Heat Removal System 2.8.4.4.1 Page 2.8.4.4-3 of the TR indicates that there are improved actions that could require that the plant be in cold shutdown within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. Please provide citations to the specific requirements for added clarity, and explain how these requirements "could require" cold shutdown in 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />, as stated in the TR.

Response

Not all CR-3 ITS actions require shutdown to Mode 5 as the end state, but when they do, the standard time allowed to achieve Mode 5 (i.e., cold shutdown conditions) is 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. For example: If RCS operational leakage exceeds the limits of LCO 3.4.12, "RCS Operational LEAKAGE," the ITS actions allow 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> to restore the operational leakage to within limits. If the operational leakage is not restored to within the limits in 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, the plant must be placed in Mode 3 (i.e., hot shutdown conditions) within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and Mode 5 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. Thus, if specific ITS actions cannot be performed within the required completion time, ITS may require a plant shutdown to cold conditions and the time to achieve cold conditions is typically 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.

This time to achieve Mode 5 is consistent with NUREG-1430, "Standard Technical Specifications - Babcock and Wilcox Plants." Other examples include ITS 3.4.3, "RCS Pressure and Temperature (P/T) Limits", ITS 3.5.4, "Borated Water Storage Tank (BWST)", and ITS 3.6.3, "Containment Isolation Valves."

As described in Section 2.8.4.4 of the EPU TR, a calculation was performed considering EPU conditions to demonstrate that the Decay Heat (DH) Removal System would continue to be

U. S. Nuclear Regulatory Commission Attachment A 3F0113-08 Page 3 of Il capable of achieving Mode 5 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> from the EPU power level to support compliance with the ITS cold shutdown requirements.

2.8.4.4.2 In CR-3 Updated Final Safety Analysis Report Section 9.4 (Page 20), the following information is provided:

a. Decay Heat Removal Pumps Two 100% capacity pumps are arranged in parallel. Each is capable of continuous operation during the decay heat removal mode and during refueling operations. Both pumps are available for emergency operation. The design flow is that required to cool the RC [reactor coolant] system from 280 IF to 140 °F in 14 hours1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br />, assuming a Nuclear Service and Decay Heat Sea Water (RW) system temperature of 85 IF. The steam generators are used to cool the RC system

[RCS] from operating temperature to the 280 IF temperature.

b. Decay Heat Removal Heat Exchangers During a routine shutdown one heat exchanger is capable of removing decay heat from the circulated reactor coolant. Both heat exchangers are operated to cool the circulated reactor coolant from 280 IF to 140 IF in 14 hours1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br />, assuming a RW system temperature of 85 °F. As RW system temperature rised (to a maximum of 95 IF) cooldown time will extend beyond 14 hours1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br />, but this increase in time is inconsequential. With a single heat exchanger in service, cooldown to 140 IF will require 7 days.

c. Borated Water Storage Tank The Borated Water Storage Tank (BWST) is located outside the Reactor building and the Auxiliary Building. It contains a minimum of 2,270 ppm [parts per million] boron in solution and is used both for emergency core injection and filling the fuel transfer canal during refueling. The BWST also supplies borated water for emergency cooling to the Reactor Building Spray (BS) system, the DH

[decay heat] system, and the MU [make-up] system.

In light of the above, please compare the Final Safety Analysis Report (FSAR) discussion to the evaluations discussed in this section of the TR. Explain whether these functional specifications remain applicable, whether this information is historical, or whether this information will be updated. If it will be updated, please provide the revised FSAR text.

Response

The information related to the CR-3 DH Removal System functional capabilities provided in Section 2.8.4.4 of the EPU TR is based on the assumptions and results in the decay heat removal cooldown calculations performed considering EPU conditions and does not directly align with the DH Removal System functional capabilities provided in Section 9.4, "Decay Heat Removal System," of the CR-3 FSAR. FPC will update the CR-3 FSAR, as required, in accordance with the requirements of 10 CFR 50.71(e) to reflect the revised DH Removal System functional capabilities at EPU conditions rendering the currently cited information historical. The FSAR will also be revised to identify the new minimum BWST boron concentration of 2600 ppm.

U. S. Nuclear Regulatory Commission Attachment A 3F0113-08 Page 4 of 11 2.8.5.2.3 Loss of Normal Feedwater Flow 2.8.5.2.3.1 The TR states that the loss of feedwater AOO is the limiting transient in terms of establishing the minimum emergency feedwater (EFW) flow requirements. Please discuss this statement in the context of Title 10 of the Code of Federal Regulations, Part 50, Section 50.36 requirements. For example, cite the applicable TS requirements that pertain to EFW, discuss what changes are necessary. If this information is contained in material that has already been submitted, a reference to this material is acceptable.

Response

CR-3 ITS 3.7.5, "Emergency Feedwater (EFW) System," provides the LCO and remedial action requirements in accordance with 10 CFR 50.36(c)(2)(i) to ensure the EFW System establishes the minimum EFW flow requirements during a loss of feedwater AOO. Surveillance Requirement (SR) 3.7.5.2 continues to require a verification that each EFW pump develops the required discharge head in accordance with the Inservice Testing Program and SR 3.7.5.3 continues to require a verification that each EFW pump starts automatically on an actual or simulated actuation signal every 24 months.

In addition, new SR 3.7.5.7 is proposed to perform a Channel Calibration of the required EFW pump flow instrumentation every 24 months. A description of the new SR and the basis for the new SR are described in Attachment 1, "Description of Proposed Change, Background, Justification for the Request, Determination of No Significant Hazards Considerations," of the CR-3 EPU LAR. As stated in Table 1, "CR-3 Operating License and Technical Specification Technical Changes," in Attachment 1 of the EPU LAR, the current EFW flow requirement for loss of feedwater AOO is 275 gpm per steam generator. At EPU conditions, the EFW flow requirement increases to 330 gpm per steam generator. In order to increase the flow sufficiently, the EFW pump low flow instrumentation will be modified to automatically isolate recirculation flow when the EFW pumps are automatically actuated and flow reaches an appropriate range.

The new SR 3.7.5.7 and the associated Bases are provided in Attachment 2, "Operating License and Improved Technical Specification Changes (Markup)," Attachment 3, "Operating License and Improved Technical Specification Changes (Revision Bar Format)," and Attachment 4, "Improved Technical Specification Bases Changes (Markup)" of the CR-3 EPU LAR (Reference 1). SR 3.7.5.7 is added to ensure the EFW pump minimum flow instruments open the associated EFW pump recirculation line isolation valves to provide pump low flow protection and close the associated EFW pump recirculation line isolation valves in time to ensure adequate EFW discharge flow to the steam generators as assumed in the safety analysis.

The EFW System actuation delay time assumption in the pre-EPU safety analyses is 60 seconds.

The EFW System actuation delay time assumption in the EPU safety analyses has been reduced to 40 seconds capturing some EFW actuation delay margin. FPC has confirmed that the actual EFW System actuation delay time has been historically < 40 seconds and is not being revised as a result of EPU. Thus, there are no associated setpoint modifications, calculations, or design changes to the Emergency Feedwater Initiation and Control System actuation instrumentation due to this reduced timing in the safety analyses. Also, actuation delay margin continues to exist such that any additional delay, as a result of the stroke timing of the new EFW pump recirculation valves, will not impact the ability of the EFW System to deliver the minimum required flow within 40 seconds as assumed in the EPU safety analyses (Reference 5).

U. S. Nuclear Regulatory Commission Attachment A 3F01 13-08 Page 5 oflI 2.8.5.2.3.6 The TR discusses a separate analysis, performed in a nominal condition, which is used to confirm the TS value for the pressurizer water level upper limit. Please provide additional information explaining how this analysis accomplishes that purpose.

Response

As stated in the Bases of ITS 3.4.8, "Pressurizer," the basis for the pressurizer upper level limit of 290 inches is to prevent water relief through the pressurizer safety valves, which preserves the steam space for RCS pressure control and ensures the capability to establish and maintain pressure control for steady state operation and to minimize the consequences of potential overpressure transients. However, prevention of water relief through the pressurizer safety valves is an operational goal for abnormal operational transients and is not a specific acceptance criterion for the CR-3 RCS overpressure safety analyses. As indicated in "Condition A - The Safety analysis RCS overpressure and pressurizer overfill events," in Section 2.8.5.2.3 of the EPU TR, the loss of feedwater analysis performed for EPU conditions assumed an initial nominal pressurizer level of 240 inches. This pressurizer level is automatically controlled, alarmed, and monitored by the operators.

Also, to ensure the current pressurizer upper level limit of 290 inches specified in ITS 3.4.8 continued to meet the operational goal of prevention of water relief through the pressurizer safety valves at EPU conditions, an additional loss of feedwater analysis was performed using an initial pressurizer level of 290 inches and nominal parameters as described in, "Condition B - The nominal RCS overpressure and pressurizer overfill event," in Section 2.8.5.2.3 of the EPU TR.

The additional loss of feedwater analysis demonstrated that the pressurizer upper level limit of 290 inches specified in ITS 3.4.8 will continue to prevent water relief through the pressurizer safety valves during abnormal operational transients at EPU conditions.

At CR-3, neither the Reactor Protection System, nor the Engineered Safeguards Actuation System includes a high pressurizer level actuation.

2.8.5.2.4 Feedwater System Pipe Breaks Inside and Outside Containment By letter dated July 17, 2012, the licensee provided ANP-3114(P), which discussed sensitivity studies performed on the initialconditions. The sensitivity studies identified a new set of limiting initial conditions. It is this analysis, and the associated initial conditions, that the NRC staff evaluated in support of the proposed EPU.

2.8.5.2.4.4 The TR states that the LONF event is used to establish TS requirements for the EFW system. Explain what role the FWLB event analysis plays in establishing TS requirements.

Response

The CR-3 feedwater line break (FWLB) event is not used to establish the minimum EFW flow requirements for ITS 3.7.5, "EFW System" since the FWLB peak pressure occurs at -13 seconds which is prior to EFW flow initiation at -68 seconds after FWLB event initiation. Therefore, EFW does not contribute to mitigation of the FWLB overpressure event. The loss of feedwater (LONF) event is used to determine the EFW flow required to prevent a liquid-solid pressurizer and subsequent liquid relief through the pressurizer safety valves. This demonstrates that the

U. S. Nuclear Regulatory Commission Attachment A.

3F01 13-08 Page 6 of 11 loss of feedwater accident does not evolve into a worse event, namely a small break loss of coolant accident. Per EPU TR Table 2.8.5.2.3-1, "Sequence of Events for Loss of Feedwater -

Condition A," peak pressurizer (PZR) liquid level occurs at either 311 or 393 seconds, depending upon the specific LONF event (overfill or overpressure).

2.8.5.2.4.5 ANP-3 114(P) indicated that steam generator initial inventory had a significant effect on the results of the FWLB analyses. Please provide additional information concerning the steam generator operating characteristics, both at pre-EPU and post-EPU power levels. Additional information concerning the original once through steam generators would also facilitate further comparison between the current licensing basis results and the EPU results.

Response

Once Through Steam Generators (OTSGs), original (OOTSG) and replacement (ROTSG) contain adjustable internal orifices, which control the feedwater flow resistance between the downcomer region and the tube region. Level control systems for the OTSGs control feedwater flow based upon the sensed level in the downcomer region. During startup and low power operating conditions, the OTSG is controlled at a low level limit setting. Following transition off low level limits, the feedwater control system automatically increases the feedwater flow, and the downcomer water level, in response to the heat being transferred from the Reactor Coolant system.

The water inventory within the tube region, and the secondary side fluid characteristics, are primarily dependent on the power (heat transfer) and relatively independent of the downcomer water level and orifice setting. The orifice setting, therefore, determines the full power operating indicated level and the mass of water in the downcomer, which then determines the total mass of water in the steam generator. In the downcomer region, feedwater is heated by mixing with aspirating steam (from the tube region). The heated feedwater enters the tube region (below the orifice) at near saturated conditions. Within the tube region, the secondary side inventory, and outlet steam conditions (superheat), will change over time in response to tube plugging and tube fouling. In these respects, the replacement and original steam generators perform the same.

The original steam generators had been in operation since initial plant startup and have tubes plugged, whereas the replacement steam generators have not operated since installation and have no plugged tubes. The primary side parameters (RCS Thot and Tcold) are determined based upon RCS flow rate. The ROTSG has slightly less primary side flow resistance thereby causing a slight increase in forced reactor coolant system flow rate. Given the difference in plugging and fouling, direct comparisons between the original and replacement steam generators are only meaningful when stated in terms of comparable power, orifice setting, plugging/fouling and RCS flow rate.

The replacement steam generators were designed to be direct replacement and meet the form, fit, and function of the original steam generators. The replacements were also designed in anticipation of an extended power uprate. There are differences in material and physical characteristics between the replacement and original steam generators that will have minor effects upon operational characteristics during normal operation, and under transient and accident conditions. The most significant differences that influence thermal performance are as shown below in Table 2.8.5.2.4.5-1.

U. S. Nuclear Regulatory Commission Attachment A 3F01 13-08 Page 7 of 11 Table 2.8.5.2.4.5-1 Parameter Original OTSG Replacement OTSG Tube Quantity 15531 15607 Tube Heated Length (in.) 625.375 629 Tube Thermal Conductivity at 10.833 9.854 550°F (BTU/ft-hr-°F)

Tube Heating Surface Area 133000 134391 (ft2)

Downcomer Annulus Width 8.25" nom. 8.75" nom.

(in.)

Net secondary side (cold) 3412 3485 volume (ft3)

Primary side irrecoverable 31.68 30.8 pressure drop (psi) (TDF, 0%

plugging).

For pre-EPU conditions, 2568 MWt core and the 2609 MWt Measurement Uncertainty Recapture (MUR) power uprate, a ROTSG orifice setting was selected to provide a full power operating level between approximately 70% to 72% (indicated, operating range). Under these conditions, the ROTSG would have slightly greater internal liquid and total secondary inventory mass than the original, new OTSG. The ROTSG will have slightly greater primary side forced coolant flow than the unplugged OTSG, and therefore Thot will be slightly colder in the ROTSG, although both will be at a nominal 604'F at RCS Thermal Design Flow Conditions (with Tave controlled at 579°F). The ROTSG will produce superheated steam approximately 2.6°F hotter than the original steam generator (thermal design flow conditions, 0 tube plugging). Within the tube region, the OTSG and ROTSG have comparable boiling tube lengths and superheat regions.

Given the additional tubes in the ROTSG, the ROTSG will have slightly greater primary to secondary heat transfer under natural circulation conditions (compared to the OTSG at the same level and plugging conditions).

Thermal performance predictions were not performed for the OOTSG at EPU power. However, the original generators can be discussed qualitatively in comparison to the replacements, based upon the physical differences in the generators. At EPU full power conditions, both the OOTSG and the ROTSG inventory (tube region) will be greater than at lower power, due to increased boiling length, and the steam superheat will be decreased in comparison to pre-EPU conditions.

With lower superheat and greater boiling length, tube inventory increases since the average density of the tube region fluid increases. For EPU, the turbine throttle pressure is increased from 900 to 930 psia, and the RCS Tave control setting is increased from 579 to 582°F. Because of the increase in tube region inventory and an increase in downcomer inventory (at comparable indicated operating levels), the analytical assumptions for initial inventory for a main steam line break (MSLB) have been increased. The selected orifice setting for EPU operation will maintain the steam generator inventory below that assumed in the new EPU MSLB analysis, and also

U. S. Nuclear Regulatory Commission Attachment A 3F01 13-08 Page 8 of 11 below the level that would degrade the aspirating steam's ability to preheat the feedwater in the downcomer region (or flood the aspirating port) at full EPU conditions.

With specific regard to secondary side inventory, the values in Table 2.8.5.2.4.5-2 below are predicted conditions from the ROTSG manufacturer's THEDA 2 three-dimensional thermal-hydraulic computer code developed specifically for Once-Through Steam Generators. It is noted that transient code secondary inventory values (RELAP) vary slightly from THEDA-2.

Performance information is for each of the two ROTSG planned operating conditions, without plugging or significant fouling, at pre-EPU and EPU power level conditions and best estimate RCS flow conditions (approximately 110% of Thermal Design Flow). The values at EPU require, and reflect, a greater opening area for the internal orifice when compared to pre-EPU conditions.

Table 2.8.5.2.4.5-2 2609 MWt (core power) 3014 MWt (core power)

Downcomer Operating Range 72.2% 80% (Note 1)

Level Tube region, liquid, lbm 14200 21100 Total Liquid Inventory, lbm 41020 50646 Total inventory, lbm 46103 55602 Turbine control pressure 900 psia 930 psia RCS Tave 579 0 F 582 0 F Steam Flow rate 5.509 E+6 6.428 E+06 ROTSG outlet nozzle steam 920.1 957.7 pressure (static, psia)

Steam temp. at SG nozzle 594.13°F 590.4°F RCS Thot 602.25°F 608.5 0 F Range of plugging considered 0 to 20% 0 to 5%

Note 1- Values are presented for a nominal 80% full EPU power operating range level (determined by orifice opening). A reduction in orifice resistance resulting in a 70% operating level would reduce EPU downcomer inventory (and total inventory) by approximately 3000 lbm.

At EPU conditions, a smaller range of plugging conditions (less than 5%) has been used in safety analysis and thermal performance analysis, in comparison to the pre-EPU conditions. This reduces the analytical complexity when considering the range of operating conditions that must be enveloped within the safety analysis. Both the original and replacement OTSGs would experience lowered outlet steam superheat at significant plugging levels. A smaller range of allowable plugging for the replacement OTSG does not reflect any inherent differences or limitations of the ROTSG compared to the original OTSG.

U. S. Nuclear Regulatory Commission Attachment A 3F0113-08 Page 9 of 11 Table 2.8.5.2.4.5-3 below shows RCS and steam temperatures at nominal full-power operating conditions in order to demonstrate the changes in these parameters between the original OTSGs and the ROTSGs at pre and post-EPU power levels.

The original OTSGs were not evaluated at the EPU power level. However, since the ROTSGs were designed to be functionally identical to the original components, the ROTSG results should be close to what would be expected for the OTSGs. The following 4 cases are useful for comparison:

1) Core power 2568 MWt, original OTSGs, 0% tube plugging

2) Core power 2609 MWt (MUR), original OTSGs, Cycle 15 tube plugging (SG A 2.4%, SG B 5.7%)

3) Core power 2609 MWt (MUR), ROTSGs, 0% tube plugging

4) Core power 3014 MWt (EPU), ROTSGs, 0% tube plugging Comparing Case 1 to Case 2 shows a decrease of 10 F in steam temperature and superheat, due to the combined effects of SG tube plugging and the MUR core power increase.

Comparing Case 2 to Case 3 shows an increase of about 2.5°F in steam temperature and superheat, due to the clean, unplugged ROTSGs replacing the original partially-plugged OTSGs.

Comparing Case I to Case 3 therefore shows an increase of about 1.5°F in steam temperature and superheat. This represents a clean, unplugged OTSG at original core power and the ROTSGs at MUR power.

Comparing Case 3 to Case 4 shows a decrease of 4°F in steam temperature, and a decrease of 8.5°F in steam superheat, due to the EPU. The reason for the decrease is the combined effects of increased secondary side mass flow and higher turbine throttle pressure setpoint, and is partially offset by the increase in RCS average temperature and resulting increase in hot leg temperature.

Table 2.8.5.2.4.5-3 Parameter Case 1 Case 2 Case 3 Case 4 Core Thermal Power (MWt) 2568 2609 2609 3014 SG Type OTSG OTSG ROTSG ROTSG SG A/B Tube Plugging % 0%/0% 2.4%/5.7% 0%/0% 0%/0%

Thot (°F) 601.7 602.2 602.1 608.5 T 0old (°F) 556.2 555.8 555.9 555.6 Tawe (OF) 579 579 579 582 Turbine Throttle Pressure (psia) 900 900 900 930 Full-Power Steam Temp (OF) 593.7 592.6 595.3 591.4 Full-Power Steam Superheat (°F) 57.6 56.6 59.0 50.6 Superheat Region (% of tube 50% 48% 43% 28%

length)

U. S. Nuclear Regulatory Commission Attachment A 3F01 13-08 Page 10 of 11 2.8.5.6 Decrease in Reactor Coolant Inventory 2.8.5.6.1 Inadvertent Opening of Pressurizer Pressure Relief Valve 2.8.5.6.1.1 Recent NRC staff review experience has indicated that a spurious PORV opening can cause an engineered safety features actuation, associated with the depressurization. This actuation can challenge the RCS by overfilling the pressurizer. Please provide information to address this concern.

Response

Inadvertent Pilot Operated Relief Valve (PORV) Opening Standard Review Plan requirements were demonstrated to be met. Refer to Reference 6, FPC letter dated October 11, 2011, , AREVA 86-9167251-001, "Summary of CR3 EPU Inadvertent Pressurizer Relief Valve Opening." A spurious PORV opening may cause an engineered safety features actuation associated with RCS depressurization. An engineered safety features actuation should not challenge the RCS integrity during restoration by the operating crew.

The CR-3 PZR is equipped with the PORV and a motor operated PORV Isolation Valve used to prevent a pressurizer steam blowdown in the event that the PORV fails to reclose after being actuated and also to isolate a leaking PORV. The isolation valve closes in 13.9 seconds. The PORV actuation setpoint is 2450 psig. The pressurizer is also equipped with two code safety valves both with set pressure of 2500 psig. The PORV and code safety valves are equipped with discharge tailpipe accelerometers to indicate flow and provide an annunciator alarm.

Four simulator runs were performed to provide insights on this question and demonstrate that no new safety concerns exist with an inadvertent opening of the PORV and possible engineered safety features actuation. In the simulator runs described here, the same initial conditions were established for each. Those conditions were:

• 100.08% EPU power (3017 MWt)

• Pressurizer level 220 inches

• RCS Pressure 2155 psig

• Tave 582°F The first case was for an inadvertent high pressure injection (HPI) actuation. The results were benchmarked against the AREVA analysis 86-9168766-001, "CR-3 EPU Inadvertent Engineered Safeguards Actuation (IESA) Analysis Summary" submitted as Enclosure 3 in Reference 6 and parameter trends were determined to be similar. Also the simulator time for PZR fill was longer than the AREVA analysis due to some simulator normal operating parameters.

The second case evaluated response to an inadvertent PORV opening. In this case, operator response is based on the operator taking established "prompt and prudent action." Operator response is based on indication of the PORV being open from the annunciator alarm, and verification of lowering RCS pressure and PORV tailpipe accelerometer indications available in close proximity to the PORV block valve controls. Based on these conditions the operator must isolate the PORV in less than 1 minute to avoid a reactor trip. A reactor trip would lead to either the third or fourth case.

U. S. Nuclear Regulatory Commission Attachment A 3F0113-08 Page 11 oflI The third case fails the PORV open and no operator actions are taken. Following a reactor trip, the RCS continues to depressurize and HPI actuates. When HPI actuates, the PORV is failed closed to maximize RCS inventory addition. The time for PZR fill was determined to be greater than the time for the first case due to loss of RCS inventory while the PORV was open.

The fourth case simulates the operating crew not recognizing the PORV has failed open and methodically working through Emergency Operating Procedures (EOPs). After completing the immediate actions of the reactor trip procedure, EOP-02, "Vital System Status Verification," the crew would transition to EOP-03, "Inadequate Subcooling Margin." The first priority focuses on ensuring adequate core cooling and then provides guidance to isolate potential RCS leaks. Step 3.20 of EOP-03 directs closure of the PORV isolation valve, RCV- 11 which terminates the leak.

When adequate Subcooling margin is regained, the EOPs and EOP rules provide guidance to control HPI, control PZR level, establish letdown and re-establish a PZR bubble. During this event, the PZR safety valves were not challenged.

All simulator runs demonstrated that spurious PORV opening may cause an engineered safety features actuation, associated with the RCS depressurization. This actuation should not challenge the RCS integrity during restoration by the operating crew.

References

1. FPC to NRC letter dated June 15, 2011, "Crystal River Unit 3- License Amendment Request #309, Revision 0, Extended Power Uprate." (ADAMS Accession No.

ML112070659)

2. FPC to NRC letter dated September 27, 2012, "Crystal River Unit 3- Response to Second Request for Additional Information to Support NRC Vessels and Internals Integrity Branch (EIVB) Technical Review of the CR-3 Extended Power Uprate LAR (TAC No. ME6527)."

(ADAMS Accession No. ML12272A344)

3. FPC to NRC letter dated December 18, 2012, "Crystal River Unit 3 - Response to Third Request for Additional Information to Support NRC Vessels and Internals Integrity Branch (EVIB) Technical Review of the CR-3 Extended Power Uprate LAR (TAC No. ME6527)."

(ADAMS Accession No. ML12361A010)

4. B&W Topical Report BAW-10046A, "Methods of Compliance with Fracture Toughness and Operational Requirements of 10 CFR 50, Appendix G," Revision 2, dated June 1986.

5. FPC to NRC letter dated March 19, 2012, "Crystal River Unit 3 - Response to Second Request for Additional Information to Support NRC Instrumentation and Controls Branch (EICB) Technical Review of the CR-3 Extended Power Uprate LAR (TAC No. ME6527)"

(ADAMS Accession No. ML12081A293)

6. FPC to NRC letter dated October 11, 2011, "Crystal River Unit 3 - Response to Request for Additional Information to Support NRC Reactor Systems Branch Acceptance Review of the CR 3 Extended Power Uprate LAR (TAC No. ME6527)" (ADAMS Accession No.

ML11286A092)

FLORIDA POWER CORPORATION CRYSTAL RIVER UNIT 3 DOCKET NUMBER 50-302 / LICENSE NUMBER DPR-72 ATTACHMENT C AREVA REQUEST FOR WITHHOLDING OF PROPRIETARY INFORMATION

AFFIDAVIT COMMONWEALTH OF VIRGINIA )

) ss.

COUNTY OF CAMPBELL )

1. My name is Gayle F. Elliott. I am Manager, Product Licensing, for AREVA NP Inc. (AREVA NP) and as such I am authorized to execute this Affidavit.

2. I am familiar with the criteria applied by AREVA NP to determine whether certain AREVA NP information is proprietary. I am familiar with the policies established by AREVA NP to ensure the proper application of these criteria.

3. I am familiar with the AREVA NP information contained in the document ANP3195(P) Revision 0, entitled "Responses for Crystal River Unit 3 EPU Licensing Amendment Report NRC Reactor Systems Branch Requests for Additional Information," dated January 2013 and referred to herein as "Document." Information contained in this Document has been classified by AREVA NP as proprietary in accordance with the policies established by AREVA NP for the control and protection of proprietary and confidential information.

4. This Document contains information of a proprietary and confidential nature and is of the type customarily held in confidence by AREVA NP and not made available to the public. Based on my experience, I am aware that other companies regard information of the kind contained in this Document as proprietary and confidential.

5. This Document has been made available to the U.S. Nuclear Regulatory Commission in confidence with the request that the information contained in this Document be withheld from public disclosure. The request for withholding of proprietary information is made in accordance with 10 CFR 2.390. The information for which withholding from disclosure is

requested qualifies under 10 CFR 2.390(a)(4) "Trade secrets and commercial or financial information":

6. The following criteria are customarily applied by AREVA NP to determine whether information should be classified as proprietary:

(a) The information reveals details of AREVA NP's research and development plans and programs or their results.

(b) Use of the information by a competitor would permit the competitor to significantly reduce its expenditures, in time or resources, to design, produce, or market a similar product or service.

(c) The information includes test data or analytical techniques concerning a process, methodology, or component, the application of which results in a competitive advantage for AREVA NP.

(d) The information reveals certain distinguishing aspects of a process, methodology, or component, the exclusive use of which provides a competitive advantage for AREVA NP in product optimization or marketability.

(e) The information is vital to a competitive advantage held by AREVA NP, would be helpful to competitors to AREVA NP, and would likely cause substantial harm to the competitive position of AREVA NP.

The information in the Document is considered proprietary for the reasons set forth in paragraphs 6(b) and 6(c) above.

7. In accordance with AREVA NP's policies governing the protection and control of information, proprietary information contained in this Document has been made available, on a limited basis, to others outside AREVA NP only as required and under suitable agreement providing for nondisclosure and limited use of the information.

8. AREVA NP policy requires that proprietary information be kept in a secured file or area and distributed on a need-to-know basis.

9. The foregoing statements are true and correct to the best of my knowledge, information, and belief.

SUBSCRIBED before me this _.._____

day of _T9ra 2013.

Ella Carr-Payne NOTARY PUBLIC, COMMONWEALTH OF VIRGINIA MY COMMISSION EXPIRES: 8/31/2013 Reg. #309873