NRC 2010-0136, License Amendment Request 261 Extended Response to Request for Additional Information

License Amendment Request 261 Extended Response to Request for Additional Information

ML102520325
Person / Time
Site:	Point Beach
Issue date:	09/08/2010
From:	Meyer L Point Beach
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
NRC 2010-0136
Download: ML102520325 (103)

Text

POINT BEACH THIS LETTER CONTAINS PROPRIETARY INFORMATION IN ACCORDANCE WITH 10 CFR 2.390 September 8, 2010 NRC 2010-0136 10 CFR 50.90 U.S. Nuclear Regulatory Commission AlTN: Document Control Desk Washington, DC 20555 Point Beach Nuclear Plant, Units 1 and 2 Dockets 50-266 and 50-301 Renewed License Nos. DPR-24 and DPR-27 License Amendment Request 261 Extended Power Uprate Response to Request for Additional lnformation

References:

( 1 FPL Energy Point Beach, LLC letter to NRC, dated April 7, 2009, License Amendment Request 261, Extended Power Uprate (ML091250564)

(2) NRC electronic mail to NextEra Energy Point Beach, LLC, dated August 26, 2010, Point Beach Nuclear Plant, Units Iand 2 - Requests for Additional Additional Associated with Extended Power Uprate (TAC Nos. ME1044 and ME1045) (MLI 02440095)

NextEra Energy Point Beach, LLC (NextEra) submitted License Amendment Request (LAR) 261 (Reference I ) to the NRC pursuant to 10 CFR 50.90. The proposed amendment would increase each unit's licensed thermal power level from 1540 megawatts thermal (MWt) to 1800 MWt, and revise the Technical Specifications to support operation at the increased thermal power level.

Via Reference (2), the NRC staff determined that additional information is required to enable the staff's continued review of the request. Enclosure Iprovides the NextEra proprietary response to the NRC staff's request based on input from the Point Beach Nuclear Plant (PBNP) nuclear steam supply system (NSSS) vendor. Upon the removal of Enclosure I, the balance of this letter may be considered non-proprietary. Enclosure 2 provides the NextEra non-proprietary versions of the Enclosure 1 response. Enclosure 3 provides Westinghouse authorization letter CAW-I 0-2922 with accompanying affidavit, Proprietary lnformation notice and Copyright notice that supports Enclosure I.Enclosure 4 provides the remaining NextEra responses to the NRC staff's request.

NextEra Energy Point Beach, LLC, 6610 Nuclear Road, Two Rivers, W 54241

Document Control Desk Page 2 The affidavit sets forth the basis on which the information may be withheld from public disclosure by the Commission and addresses with specificity the considerations listed in Paragraph (b)(4) of 10 CFR 2.390.

NextEra requests that the information which is proprietary to Westinghouse be withheld from public disclosure in accordance with 10 CFR 2.390. Correspondence with respect to the copyright or proprietary aspects of the items listed above or the supporting Westinghouse affidavit should reference CAW-10-2922 and should be addressed to J. A. Gresham, Manager, Regulatory Compliance and Plant Licensing, Westinghouse Electric Company, LLC, P.O.

Box 355, Pittsburgh, Pennsylvania 15230-0355.

This letter contains no new Regulatory Commitments and no revisions to existing Regulatory Commitments.

The information contained in this letter does not alter the no significant hazards consideration contained in Reference (1) and continues to satisfy the criteria of 10 CFR 51.22 for categorical exclusion from the requirements of an environmental assessment.

In accordance with 10 CFR 50.91, a copy of this letter is being provided to the designated Wisconsin Official.

I declare under penalty of perjury that the foregoing is true and correct.

Executed on September 8,201 0.

Very truly yours, NextEra Energy Point Beach, LLC fL-----\

Larry Meyer Site Vice President Enclosure cc: Administrator, Region Ill, USNRC Project Manager, Point Beach Nuclear Plant, USNRC Resident Inspector, Point Beach Nuclear Plant, USNRC PSCW

ENCLOSURE 2 NEXTERA ENERGY POINT BEACH, LLC POINT BEACH NUCLEAR PLANT, UNITS 1 AND 2 LICENSE AMENDMENT REQUEST 261 EXTENDED POWER UPRATE NON-PROPRIETARY RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION The NRC staff determined that additional information was required (Reference 1) to enable the Mechanical and Civil Engineering Branch to complete its review of License Amendment Request (LAR) 261, Extended Power Uprate (EPU) (Reference 2). The following information is provided by NextEra Energy Point Beach, LLC (NextEra) in response to the NRC staff's request.

Introduction By letter to the Nuclear Regulatory Commission (NRC) dated April 2, 2009 (Agencywide Document and Management System Accession No. ML091250564), the licensee of the Point Beach Nuclear Plant (PBNP), Units 1 and 2, NextEra Energy Point Beach, LLC, submitted a license amendment request (LAR), pursuant to the requirements of Title 10 of the Code of Federal Regulations Section 50.90, "Application for Amendment of License or Construction Permit." The LAR proposes to increase the power level of the current Renewed Operating License (OL) to 1,800 megawatts thermal (MWt), approximately 17% above the current licensed thermal power (CLTP) of 1,540 MWt and approximately 18.5% above the Original Licensed Thermal Power (OLTP) of 1,518.5 MWt.

The Mechanical & Civil Engineering Branch staff has reviewed the LAR licensing report (LR) for power uprate. The staff has identified that additional information is needed to complete the review, The staff's request for additional information (RAI) is attached. This request does not include items related to safety-related valves and pumps since review of these components is performed by the Component Integrity, Performance and Testing Branch. Please note that EMCB RAls related to LR Section 2.2. I , "Pipe Rupture Locations and Associated Dynamic Effects" and Section 2.2.5, "Seismic and Dynamic Qualification of Mechanical and Electrical Equipment", if required, will be submitted via a separate memorandum.

Page 1 of 12

Requests for Additional Information EMCB RAI 14 For the vessel support, LR Table 2.2.2.3-3 shows fatigue CUF of 0.995 for CLTP to 60 year plant renewed life and 10.8421for post-EPU.

a) Clarify whether the EPU CUF value of 0.842 is applicable for the 60 year plant renewed life?

Note 2 of Table 2.2.2.3-3 states that: "Number 0.842 was calculated using a stress concentration factor (SCF) of 1.5 applied to thermal stresses, as determined from a finite element analysis. The pre-EPU cumulative fatigue usage factor 0.995 applied on overly conservative SCF of 3.27 to the thermal stresses."

b) Please provide a description which clearly shows how these stress concentration factors have been developed and the geometry that they apply to.

NextEra Response a) The EPU CUF value of 0.842 for the external support brackets is applicable for the 60 year plant renewed life.

Note 2 of Table 2.2.2.3-3 states that: "Number 0.842 was calculated using a stress concentration factor (SCF) of [ ] applied to thermal stresses, as determined from a finite element analysis. The pre-EPU cumulative fatigue usage factor 0.995 applied an overly conservative SCF of [ ] to the thermal stresses."

b) The original stress report (OSR) used SCFs from Figure A.7-1 of U.S. Department of Commerce, Office of Technical Services report PB-I 51-987, "Tentative Structural Design Basis for Reactor Pressure Vessels and Directly Associated Components." This document was a pre-cursor to the American Society of Mechanical Engineers (ASME)

Code. The [ ] SCF was taken directly from the figure and pertains to fillets on a stepped bar subject to tensile loading.

In the OSR, the [ ] a" SCF was used to calculate peak stresses at the 1.I25 inch fillet juncture at the bottom of the external support bracket and the vessel shell. It was also used to calculate the peak stresses at the compound fillet lower corner junctures of the external support bracket and the vessel shell. The compound fillet lower corner junctures resulted from blending the 1.I25 inch fillet and the 2 inch fillet between the sides of the external support bracket bottom plate and the vessel shell. The limiting location for fatigue in the OSR was at one of the compound fillet lower corner junctures.

Therefore, the new SCF developed, as described below, was applicable to the same limiting compound fillet lower corner juncture.

Page 2 of 12

The SCF was calculated by applying linear scaling between the thermal peak stresses from a 3-D finite element model versus the reported thermal peak stresses in the OSR.

Linear scaling was possible given the method used to calculate the thermal peak stresses (opeak)in the OSR. The method used was as follows:

where Q is the secondary membrane plus bending stress through the vessel thickness in the region of the limiting compound fillet lower corner juncture. The finite element model geometry and thermal boundary conditions were made to be the same as those considered in the OSR.

A heatup transient and 100% steady-state load case was analyzed using the same thermal boundary conditions and material properties as listed in the OSR. Therefore, the FEA and OSR secondary membrane plus bending stress through the vessel thickness in the region of the limiting compound fillet lower corner juncture will be essentially equivalent. Peak thermal stress in the axial, hoop, and radial directions was recorded and compared to the peak thermal stress (hoop and axial) provided in the OSR. The maximum thermal peak stress ratio was calculated for each time point in the heatup transient and the 100% steady-state load case.

Case Peak Stress Peak Stress Peak Stress SCF (FEA) (OSR) Ratio (FEAIOSR) (FEN (ksi) (ksi)

E I""a,c [ ] "1'

[ I""a,c [ I a'c a,c a , ~

Heatup [ [ [

[ I "'" [ I "lC [ I a'c [ I""

100% Steady-State [ ] [ 1 [ la" [ la" The SCF was calculated using the following equation:

SCF = Peak Stress Ratio x [ ] ""

A maximum SCF of [ ] a.C was calculated. The average of all the SCFs in the above table was calculated to be 1.46, but a slightly higher value of [ ] ""was used in the evaluation. The thermal peak stresses in the OSR were first divided by [ ] "." and then multiplied by the new [ ] SCF. The [ ] SCF was left on the pressure and external load stresses because the total stress was dominated by the thermal stress.

Also, the [ 1 SCF calculated was only applicable for thermal loadings, not mechanical loadings. The pressure, thermal and external load stresses were all combined and new total stresses calculated for all transient times. The new total stresses were then evaluated for EPU conditions and the cumulative fatigue usage recalculated producing a final cumulative fatigue usage of 0.842.

Page 3 of 12

EMCB RAI 18 PBNP EPU LAR Section 2.2.2.5.7 predicts a pre-uprate and post-uprate tube wear values for the PBNP Unit 2 SG tubes for 40 years design life and states that: "This amount of wear will not significantly affect tube integrity and is judged to be acceptable. " Please indicate the amount of tube wear beyond which the tube structural integrity is considered to be affected and your technical basis for this judgment. In addition, provide the EPU evaluated tube wear for the PBNP Unit I SG tubes and the method of evaluation.

NextEra Response For Unit 2, the post-uprate wear is calculated to be [ ] for the life of the plant. This represents [ ] a*C through-wall wear. Therefore, it is viewed to be acceptable since it is well below the Technical Specification limit of 40% through-wall, and the calculated structural limit is

[ ] through-wall. The calculation for the structural limit is contained in LAR 261, , Section 2.1.9, Steam Generator Tube Inservice Inspection.

While wear rates were not specifically calculated for Unit 1, a review of similar steam generator models to the Model 44F steam generators in Unit 1 show that the Unit 2 wear rate results are typical for similar steam generators.

Based on eddy current testing, neither unit shows many tubes (less than 1%) that have demonstrated wear. Using a conservative uprate factor that modified the calculated wear rate for tubes left in service, it is demonstrated that tube integrity will still be maintained in both units until the next scheduled steam generator tube inspection. While the EPU can result in additional tubes exhibiting wear, the number is expected to be acceptable based on the current behavior of the steam generators.

EMCB RA124 Please clarify whether the ratio values in Tables 2.2.2.7-2 and 2.2.2.7-3 are for EPU or CLTP and update these tables to show calculated and allowable values from both CLTP and EPU.

Note I of Table 2.2.2.7-2 indicates that the pressurizer spray nozzle has failed to meet the ASME Section 111 NB-3222.2 primary plus secondary stress intensity requirement of 3Sm and has been qualified by the alternate rules of the simplified elastic-plastic analysis of sub-paragraph NB-3228.3, If this condition is for stress intensity calculated at EPU conditions, please provide a quantitative summary of the evaluation which shows that the special rules for exceeding 3Sm, as provided by (a) through (0 of sub-paragraph NB-3228.3 have been met. In the requested summary, please show calculated and allowable values and not just ratios, as currently included in the above-mentioned tables.

Page 4 of 12

NextEra Response The ratio values in Table 2.2.2.7-2 are for current licensed thermal power (CLTP). The EPU did not change the maximum ranges of stress intensity for the pressurizer components.

Table 2.2.2.7-2 is replaced with the following:

Component Calculated Stress Allowable Stress Intensity Range Intensity Range (ksi) (ksi)

Spray Nozzle [ c,e (1) 39.60 Upper Head [ 1 "'" 90.00 Surge Nozzle [ 1 "c,e

' 57.90 Safety and Relief Nozzle [ 39.54 Support Skirt and Flange [ 1 "c,e

' 69.30 Lower Head [ 58.20 Heater Well [ 1 "'c,e 69.90 Manway [ 57.84 Instrument Nozzle [ 1 "'" 57.84 Immersion Heater [ 1 "'" 49.20 NOTE:

(1) Quantity shown is the stress intensity range with thermal bending removed. The range of primary plus secondary stress intensity exceeded the 3S, limit, but this is permitted, provided the rules of NB-3228.3 of the ASME Code are met. Those requirements have been satisfied for this component.

The spray nozzle exceeded the 3Sm limit in the original evaluation. This was not changed by the EPU. The NB-3228.3 requirements were satisfied in the original stress report.

For Table 2.2.2.7-3, the values in the table are for CLTP. They did not change for EPU and are applicable for EPU.

The stress allowable for the pressurizer support anchor bolts is 4.5 ksi and the calculated stress value is [ ] b8C ksi.

Page 5 of 12

EMCB RAI 26 For the RPV internals, as shown in LR Table 2.2.3-3, that exceed the NB-3222.2 primary plus secondary stress intensity requirement of 3Sm at EPU conditions, please provide a quantitative summary of the evaluation which shows that the 3Sm code limit is met when excluding thermal bending stresses and that the remainder of NB-3228.3 requirements (b) through (0 have also been satisfied.

NextEra Response The components that exceed the NG-3222.2 primary plus secondary stress intensity requirement of 3Sm at EPU conditions from LAR 261, Attachment 5, Table 2.2.3-3 are:

- Upper Core Plate Alignment Pins

- Core Barrel Assembly Upper Girth Weld (UGW)

- Core Barrel Assembly Lower Girth Weld (LGW)

- Lower Radial Restraints - Key Weld A quantitative summary of these component evaluations are discussed below.

I Upper Core Plate Alignment Pins Maximum Stress Intensity (psi)

I Transient I Stress Ranae SQ, I s12 s23 s31 OBE a,c a,c a,c

[ [ [

(UU2+UD2)Range [ la" a,c

[

[

I a,c

[ I a,ca,c (NU1+NDl)Range [

(Note that the maximum range for mechanical plus thermal stresses c 3Sm; therefore, no elastic-plastic fatigue analysis is required)

Following the maximum transient combinations, the fatigue usage factors are calculated below.

Because these welds are not full-penetration, inspectable welds, a weld quality factor of 4.0 is used per ASME Code.

1. OBE + UU2 + UD2 The corresponding allowable cycles from ASME Code fatigue curve 1-9.2-1 are n=[ la" cycles, and the applied number of cycles N = 400. Thus, Page 6 of 12

The corresponding allowable cycles from ASME Code fatigue curve 1-9.2-1 are n=[ 1"" cycles, and the applied number of cycles N = 280. Thus, The corresponding allowable cycles from ASME Code fatigue curve 1-9.2-1 are n=[ ] a.C cycles, and the applied number of cycles N = 20,700. Thus, Total fatigue usage factor becomes U = C Ui = [ " ] a.C < I .O

2. Core Barrel Assembly Upper Girth Weld The summary of peak stress at the outer surface of the UGW is:

Load Condition or (psi) csz (psi) oy (psi) Classification Deadweight --- --- [

a,c Pm Core Barrel --- --- [ 1 "'" Qb Deflection Pressure [ la" [ la'" [ I "I" Pm Differential FIV --- --- [ 1 a,c "lC Pm OBE --- --- Pb Thermal --- [ la" [ 1 a,c Q As the shear stress is zero, the radial, circumferential, and axial stress components are the principal stresses. Then, The principal stresses from the above table are as follows:

Page 7 of 12

The stress differences are as follows:

Stress Intensity SI = [ ] a*c > 3Sm = 49,200 psi Since the 3Sm limit is not satisfied, a simplified elastic-plastic analysis for fatigue must be performed in accordance with Subsection NG-3228.3 of the ASME Code, provided that the requirements of (a) through (f) below are met:

(c) The stress differences are as follows (without thermal):

Stress Intensity SI = [ la"< 3Sm = 49,200 psi (without thermal)

(d) The value of Sa are multiplied by the factor Ke Ke = 1.0 + ( I -n)/n(m-I ) ((Sn13Sm) -1 ), for 3Sm < Sn < 3*m*Sm For austenitic steel:

n=[ la,";

m = [ lakc; 3Sm = 49,200 psi; with Sn = [ 1 a,C Therefore, Then, the alternating stress, with a weld quality factor of 1.0 according to ASME Code, is as follows:

Salt = [ Ia,c (Sij)

Salt = [ Ia*c

From Figure 1-9.2.1 of the ASME Code, the number of allowable cycles corresponding to:

Salt = [ Ia,c N=[ ] cycles Consider only 400 OBE cycles, -+U l = [ lave Without seismic, the maximum stress range or stress intensity becomes:

Then, Salt = [

(c) Stays the same and the procedure of NG-3227.6 is not required.

(d) Meets the thermal ratcheting requirement of NG-3222.5 since the maximum allowable range of thermal stress (y') calculated on the elastic basis is greater than the calculated value of [ ] psi:

Then, (e) Satisfied since the temperature does not exceed 700°F.

(f) Satisfied since SyISu = [ ] < 0.8 Page 9 of 12

3. Core Barrel Assembly Lower Girth Weld Summary of peak stress at the outer surface of the LGW (2) is as follows:

Load Condition or (psi) tsz (psi) oy (psi) Classification Deadweight --- --- 1 a,c Pm Core Barrel --- --- [ 1 "I" Qb Deflection Pressure [ ] "I" [ ] a*C [ 1"'" Pm Differential FIV --- --- [ la," Pm OBE --- --- [

a," Pb Thermal --- [ I "'" [ 1"," Q As the shear stress is zero, the radial, circumferential, and axial stress components are the principal stresses. Then, Following the above procedure, principal stresses from the above table are:

The stress differences are as follows:

S31 = [ ] > 3Sm = 49,200 psi Since the 3Sm limit is not satisfied, a simplified elastic-plastic analysis for fatigue must be performed in accordance with Subsection NG-3228.3 of the ASME Code provided that the requirements of (a) through (f) below are met:

(c) The stress differences are as follows (without thermal):

The principal stresses from the above table are as follows:

Page 10 of 12

The stress differences are as follows:

S31 = [ ] as c 3Sm = 49,200 psi (d) The Sa value is multiplied by factor Ke Then, the alternating stress, Salt = 1/2 x 1.32 x Max I(Sij)l Salt = [ 1 From Figure 1.9-2 of the ASME Code, the number of allowable cycles corresponding to:

Salt = [ Iarc N=[ ] a*c cycles Consider the umbrella (U) cycles for Normal + Upset is 21,380 cycles, (c) Stays the same and the procedure of NG-3227.6 is not required.

(d) Meets the thermal ratcheting requirement of NG-3222.5, since the maximum allowable range of thermal stress (y') calculated on the elastic basis is greater than the calculated value of [ ] a.C psi:

Y' = (0)tensile-thermalI(0)yield ; and x = PmI(0)yield Then, (0) tensile-thermal '[ ] "'" > [

(e) Satisfied since the temperature does not exceed 700°F (f) Satisfied since Sy ISu = [ la"< 0.8 Page 11 of 12

4. -

Lower Radial Restraints Key Weld For the Lower Radial Restraints - Key weld, a revision to the stress calculations was performed for EPU conditions subsequent to submittal of LAR 261. The calculation revision indicates that the "After EPU" stress intensity no longer exceeds the 3Sm allowable with a 0.7 weld quality factor for primary-plus-secondarystress intensity, as required by NB-3222.2. By copy of this request for additional information (RAI) response, the values for the Lower Radial Restraints - Key Weld "After EPU" and allowable stress intensities presented in Table 2.2.3-3 of to LAR 261 are replaced with the following:

After EPU Stress Intensity (Pm + Pb + Q) = [ ] a'C ksi Allowable Stress Intensity (3Sm)*(0.7) = 35.6 ksi Conclusion Based on the quantitative information provided above, these components are within the allowable limits of Subsection NG of the 1998 Edition of the ASME Code Section Ill, Division I, including 2000 Addenda and, therefore, are acceptable.

References (1) NRC electronic mail to NextEra Energy Point Beach, LLC, dated August 26, 2010, Point Beach Nuclear Plant, Units 1 and 2 - Requests for Additional Additional Associated with Extended Power Uprate (TAC Nos. ME1044 and ME1045) (MLI 02440095)

(2) FPL Energy Point Beach, LLC letter to NRC, dated April 7, 2009, License Amendment Request 261, Extended Power Uprate (ML091250564)

Page 12 of 12

ENCLOSURE 3 NEXTERA ENERGY POINT BEACH, LLC POINT BEACH NUCLEAR PLANT, UNITS I AND 2 LICENSE AMENDMENT REQUEST 261 EXTENDED POWER UPRATE WESTINGHOUSE AUTHORIZATION LETTER, ACCOMPANYING AFFIDAVIT, PROPRIETARY INFORMATION NOTICE, AND COPYRIGHT NOTICE CAW-I 0-2922 7 pages follow

Westinghouse Electric Company Nuclear Services P.O. Box 355 Pittsburgh, Pennsylvania 15230-0355 USA U.S. Nuclear Regulatory Commission Direct tel: (412) 374-4643 Document Control Desk Direct fax: (412) 374-3846 Washington, DC 20555-000 1 e-mail: greshaja@westinghouse.com Proj letter: WEP- 10-93 CAW- 10-2922 September 3,2010 APPLICATION FOR WITHHOLDING PROPRIETARY INFORMATION FROM PUBLIC DISCLOSURE

Subject:

WEP-10-93 P-Attachment, "Point Beach Nuclear Plant Units 1 and 2 - Response to the Request for Additional Information from Civil and Mechanical Engineering Branch Related to License Amendment Request No. 261 Extended Power Uprate (EPU) (TAC Nos. ME 1044 and ME 1045)" (Proprietary)

The proprietary information for which withholding is being requested in the above-referenced report is further identified in Affidavit CAW-10-2922 signed by the owner ofthe proprietary information, Westinghouse Electric Company LLC. The affidavit, which accompanies this letter, sets forth the basis on which the information may be withheld from public disclosure by the Commission and addresses with specificity the considerations listed in paragraph (b)(4) of I0 CFR Section 2.390 of the Commission's regulations.

Accordingly, this letter authorizes the utilization of the accompanying affidavit by NextEra Energy Point Beach LLC.

Correspondence with respect to the proprietary aspects of the application for withholding or the

. Westinghouse affidavit should reference this lettei, CAW-10-2922, and should be addressed to J. A. Gresham, Manager, Regulatory Compliance and Plant Licensing, Westinghouse Electric Company LLC, P.O. Box 355, Pittsburgh, Pennsylvania 15230-0355.

Very truly ysurs,

/J. A. Gresham, Manager Regulatory Compliance and Plant Licensing Enclosures

AFFIDAVIT COMMONWEALTH OF PENNSYLVANIA:

COUNTY OF ALLEGHENY:

Before me, the undersigned authority, personally appeared J. A. Gresham, who, being by me duly sworn according to law, deposes and says that he is authorized to execute this Affidavit on behalf of Westinghouse Electric Company LLC (Westinghouse), and that the averments offact set forth in this Affidavit are true and correct to the best of his knowledge, information, and belief:

" J. A. Gresham, Manager Regulatory Compliance & Plant Licensing Sworn to and subscribed before me this 3rd day of September 2010 COMMONWEALTH OI' RNNIYLVANIA NotartrlSeal Cynthia Olesky, Notary PuMk

(

I Haor Mm, WeabnOlOland Cwntv MY Commkslon upires ~ u t y16,20i4 I Member. Pennsvlvanla Association of Nobiles

(1) I am Manager, Regulatory Compliance & Plant Licensing, in Nuclear Services, Westinghouse Electric Company LLC (Westinghouse), and as such, I have been specifically delegated the hnction of reviewing the proprietary information sought to be withheld from public disclosure in connection with nuclear power plant licensing and rule making proceedings, and am authorized to apply for its withholding on behalf of Westinghouse.

(2) I am making this Aff~davitin conformance with the provisions of 10 CFR Section 2.390 of the Commission's regulations and in conjunction with the Westinghouse Application for Withholding Proprietary Information from Public Disclosure accompanying this Afidavit.

(3) I have personal knowledge of the criteria and procedures utilized by Westinghouse in designating information as a trade secret, privileged or as confidential commercial or financial information.

(4) Pursuant to the provisions of paragraph (b)(4) of Section 2.390 of the Commission's regulations, the following is furnished for consideration by the Commission in determining whether the infomztion sought to be withheld from public disclosure should be withheld.

(i) The information sought to be withheld from public disclosure is owned and has been held in confidence by Westinghouse.

(ii) The information is of a type customarily held in confidence by Westinghouse and not customarily disclosed to the public. Westinghouse has a rational basis for determining the types of information customarily held in confidence by it and, in that connection, utiIizes a system to determine when and whether to hold certain types of information in confidence. The application of that system and the substance of that system constitutes Westinghouse policy and provides the rational basis required.

Under that system, information is held in confidence if it falls in one or more of several types, the release of which might result in the loss of an existing or potential competitive advantage, as follows:

(a) The information reveals the distinguishing aspects of a process (or component, structure, tool, method, etc.) where prevention of its use by any of Westinghouse's competitors without license from Westinghouse constitutes a competitive economic advantage over other companies.

(b) It consists of supporting data, including test data, relative to a process (or component, structure, tool, method, etc.), the application of which data secures a competitive economic advantage, e.g., by optimization or improved marketability.

(c) Its use by a competitor would reduce his expenditure of resources or improve his competitive position in the design, manufacture, shipment, installation, assurance of quality, or licensing a similar product.

(d) It reveals cost or price information, production capacities, budget levels, or commercial strategies of Westinghouse, its customers or suppliers.

(e) It reveals aspects of past, present, or future Westinghouse or customer hnded development plans and programs of potential commercial value to Westinghouse.

(f) It contains patentable ideas, for which patent protection may be desirable.

There are sound policy reasons behind the Westinghouse system which include the following:

(a) The use of such information by Westinghouse gives Westinghouse a competitive advantage over its competitors. It is, therefore, withheld from disclosure to protect the Westinghouse competitive position.

(b) It is information that is marketable in many ways. The extent to which such information is available to competitors diminishes the Westinghouse ability to sell products and services involving the use of the information.

(c) Use by our competitor would put Westinghouse at a competitive disadvantage by reducing his expenditure of resources at our expense.

(d) Each component of proprietary information pertinent to a particular competitive advantage is potentially as valuable as the total competitive advantage. If competitors acquire components of proprietary information, any one component

4 CAW- 10-2922 may be the l e y to the entire puzzle, thereby depriving Westinghouse of a competitive advantage.

(e) Unrestricted disclosure would jeopardize the position of prominence of Westinghouse in the world market, and thereby give a market advantage to the competition of those countries.

(f) The Westinghouse capacity to invest corporate assets in research and development depends upon the success in obtaining and maintaining a competitive advantage.

(iii) The infonnation is being transmitted to the Commission in confidence and, under the provisions of 10 CFR Section 2.390, it is to be received in confidence by the Co~mnission.

(iv) The information sought to be protected is not available in public sources or available infonnation has not been previously employed in the same original manner or method to the best of our knowledge and belief.

(v) The proprietary information sought to be withheld in this submittal is that which is appropriately marked in WEP-10-93 P-Attachment, "Point Beach Nuclear Plant Units 1 and 2 -Response to the Request for Additional Infonnation from Civil and Mechanical Engineering Branch Related to License Amendment Request No. 261 Extended Power Uprate (EPU) (TAC Nos. ME 1044 and ME 1045)," (Proprietary) dated September 2010, for submittal'to the Comnission, being transmitted by NextEra Energy Point Beach LLC letter and Application for Withholding Proprietary Infonnation from Public Disclosure, to the Document Control Desk. The proprietary information as submitted for use by Westinghouse for Point Beach Units I and 2 is expected to be applicable for other licensee submittals in response to certain NRC requirements for Extended Power Uprate submittals.

This information is part of that which will enable Westinghouse to:

(a) Provide input to the Nuclear Regulatory Commission for review of the Point Beach EPU submittals.

CAW- 10-2922 (b) Provide results of customer specific calculations.

(c) Provide licensing support for customer submittals.

Further this information has substantial commercial value as follows:

(a) Westinghouse plans to sell the use of similar information to its customers for purposes of meeting NRC requirements for licensing documentation associated with EPU submittals.

(b) Westinghouse can sell support and defense of the technology to its customer in the licensing process.

(c) The information requested to be withheld reveals the distinguishing aspects of a methodology which was developed by Westinghouse.

Public disclosure of this proprietary information is likely to cause substantial harm to the competitive position of Westinghouse because it would enhance the ability of competitors to provide similar information and Iicensing defense services for commercial power reactors without commensurate expenses. Also, public disclosure of the information would enable others to use the information to meet NRC requirements for licensing documentation without purchasing the right to use the information.

The development of the technology described in part by the information is the result of applying the results of many years of experience in an intensive Westinghouse effort and the expenditure of a considerable sum of money.

In order for competitors of Westinghouse to duplicate this information, similar technical programs would have to be performed and a significant manpower effort, having the requisite talent and experience, would have to be expended.

Further the deponent sayeth not.

PROPRIETARY INFORMATION NOTICE Transmitted herewith are proprietary and/or non-proprietary versions of documents furnished to the NRC in connection with requests for generic andlor plant-specific review and approval.

In order to conform to the requirements of 10 CFR 2.390 of the Commission's regulations concerning the protection of proprietary information so submitted to the NRC, the information which is proprietary in the proprietary versions is contained within brackets, and where the proprietary information has been deleted in the non-proprietary versions, only the brackets remain (the information that was contained within the brackkts in the proprietary versions having been deleted). The justification for claiming the information so designated as proprietary is indicated in both versions by means of lower case letters (a) through (f) located as a superscript immediately following the brackets enclosing each item of information being identified as proprietary or in the margin opposite such information. These lower case letters refer to the types of information Westinghouse customarily holds in confidence identified in Sections (4)(ii)(a) through (4)(ii)(f) of the afXdavit accompanying this transmittal pursuant to 10 CFR 2.390(b)(l).

COPYRIGHT NOTICE The reports transmitted herewith each bear a Westinghouse copyright notice. The NRC is permitted to make the number of copies of the information contained in these reports which are necessary for its internal use in connection with generic and plant-specific reviews and approvals as well as the issuance, denial, amendment, transfer, renewal, modification, suspension, revocation, or violation of a license, permit, order, or regulation subject to the requirements of 10 CFR 2.390 regarding restrictions on public disclosure to the extent such information has been identified as proprietary by Westinghouse, copyright protection notwithstanding. With respect to the non-proprietary versions of these reports, the NRC is permitted to make the number of copies beyond those necessary for its internal use which are necessary in order to have one copy available for public viewing in the appropriate docket files in the public document room in Washington, DC and in local public document rooms as may be required by NRC regulations if the number of copies submitted is insufficient for this purpose. Copies made by the NRC must include ,

the copyright notice in all instances and the proprietary notice if the original was identified as proprietary.

ENCLOSURE 4 NEXTERA ENERGY POINT BEACH, LLC POINT BEACH NUCLEAR PLANT, UNITS I AND 2 LICENSE AMENDMENT REQUEST 261 EXTENDED POWER UPRATE RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION The NRC staff determined that additional information was required (Reference 1 ) to enable the Mechanical and Civil Engineering Branch to complete its review of License Amendment Request (LAR) 261, Extended Power Uprate (EPU) (Reference 2). The following information is provided by NextEra Energy Point Beach, LLC (NextEra) in response to the NRC staff's request.

Introduction By letter to the Nuclear Regulatory Commission (NRC) dated April 2, 2009 (Agencywide Document and Management System Accession No. ML091250564), the licensee of the Point Beach Nuclear Plant (PBNP), Units I and 2, NextEra Energy Point Beach, LLC, submitted a license amendment request (LAR), pursuant to the requirements of Title 10 of the Code of Federal Regulations Section 50.90, "Application for Amendment of License or Construction Permit." The LAR proposes to increase the power level of the current Renewed Operating License (OL) to 1,800 megawatts thermal (MWt), approximately 17% above the current licensed thermal power (CLTP) of 1,540 MWt and approximately 18.5% above the Original Licensed Thermal Power (OLTP) of 1,518.5 MWt.

The Mechanical & Civil Engineering Branch staff has reviewed the LAR licensing report (LR) for power uprate. The staff has identified that additional information is needed to complete the review. The staff's request for additional information (RAI) is attached. This request does not include items related to safety-related valves and pumps since review of these components is performed by the Component Integrity, Performance and Testing Branch. Please note that EMCB RAls related to LR Section 2.2. I, "Pipe Rupture Locations and Associated Dynamic Effects" and Section 2.2.5, "Seismic and Dynamic Qualification of Mechanical and Electrical Equipment': if required, will be submitted via a separate memorandum.

Page 1 of 41

Requests for Additional Information EMCB RAI I It is noted that the PBNP EPU licensing report (LR) specifies that the plant design basis code of record for BOP piping analysis is the USAS B31.I Power Piping Code, 1967 Edition. Please verify and/or identify the code utilized in qualifying nuclear steam supply systems (NSSS) and balance of plant (BOP) piping and pipe supports for EPU conditions. I f different from the plant design basis code of record, providejustification and confirm that the calculated values for piping and supports utilized the original code of construction allowable values.

NextEra Response Balance of Plant (BOP) Piping and Supports The EPU evaluations for balance of plant (BOP) piping systems were evaluated to the USA Standard (USAS) B31.IPower Piping Code, 1967 Edition, which is the original code of record for BOP piping systems.

The original code of record for the evaluation of BOP pipe supports is American Institute of Steel Construction (AISC), Manual of Steel Construction, Sixth Edition. Updated revisions to this code can be used provided the requirements and intent stipulated in the original codes of record have been satisfied. The EPU evaluations for BOP pipe supports were evaluated using the AISC code, Sixth Edition, including updated revisions through the Ninth Edition. In the above cases, the requirements and intent stipulated in the alter codes of record have been satisfied.

NSSS (RCS) Piping and Surqe Line Thermal Stratification For the NSSS piping (reactor coolant system (RCS) piping), the Point Beach Nuclear Plant (PBNP) Final Safety Analysis Report (FSAR) Table 4.1-9 states that the code requirement is the USAS B31.IPower Piping Code and that the version of the Code which was in effect at the time the original component was ordered is applicable. Other sections of the PBNP FSAR (e.g.,

Section 4.2, page 4.2-14) state that the piping and fittings are designed to the B31.1, 1955 Edition. Based on the review of the existing plant design basis analysis of record (AOR) evaluations and qualifications performed for the steam generator replacement program and fuel upgrade program, NextEra concluded that the American National Standards lnstitute (ANSI)

Code for Pressure Piping, B31.I, 1973 Edition was utilized as the code of record. This is considered acceptable because the equations presented in the I955 version of the code are identical to the equations presented in the 1973 version of the code. Also, per the note in ANSl B31.I, 1973 Edition, the B31.I, 1967 Edition through 831.I, 1972 Edition, have been revised and consolidated into one publication and re-designated B31.I, 1973 Edition. The PBNP NSSS piping evaluations and qualifications for EPU conditions also utilized the ANSl Code for Pressure Piping B31.I, 1973 Edition, as was used in the existing plant design basis AOR.

Therefore, the code of record allowable values used in the existing plant design basis AOR are used for the EPU evaluation.

For the pressurizer surge line, considering only the effects of thermal stratification, the American Society of Mechanical Engineers (ASME) Code, 1986 Edition used is in compliance with NRC Bulletin No. 88-11 (Reference 3) and as documented in LAR 261, Attachment 5, Section 2.2.2.1.2, Input Parameters, Assumptions, and Acceptance Criteria. Reference (3)

Page 2 of 41

fatigue analysis should be performed in accordance with the latest ASME Code, Section Ill requirements incorporating high cycle fatigue. The original code of record for the pressurizer surge line thermal stratification is the ASME Code, Section Ill, 1986 Edition. For the current licensing basis at PBNP and for EPU conditions, the evaluation of the pressurizer surge line, considering only the effects of thermal stratification, was performed and found to be in compliance with both the NRC Bulletin 88-11 and the original code of record.

RCS Supports (Except Reactor Vessel Supports)

The original code of construction for RCS supports (steam generator (SG), reactor coolant pump (RCP) and pressurizer) was AISC, Sixth Edition. Updated revisions to this code can be used provided the requirements and intent stipulated in the later codes of record have been satisfied.

The existing plant design basis AOR evaluation for PBNP, NSSS supports (SG, RCP and pressurizer) performed during the 1995 and 2001 timeframe (including the RSG program) utilized the AISC, Eighth Edition and ASME Code, Section Ill, Subsection NF, 1974 Edition as the code of record. The allowable values for AISC, Sixth Edition and the allowable values for AISC, Eighth Edition are comparable. Also, the allowable values for AISC, Eighth Edition and the ASME Code, Section Ill, Subsection NF, 1974 Edition are comparable. Therefore, the current code of record used in the existing plant design basis AOR is used for the EPU evaluations. In the above cases, the requirements and intent stipulated in the later codes of record have been satisfied.

EMCB RAI 2 Confirm that the reactor coolant system (RCS) piping and supports, componentsJprimary equipment nozzles and supporfs, associatedreactor coolant loop (RCL) branch piping and supports, did not experience an increase in stresses due to the EPU because the existing analysis contains loads which envelop the loads at EPU conditions.

NextEra Response While the existing analyses remained bounding for some discrete components and supports, several components and supports required re-analyses due to increased or previously unanalyzed loads. The following response discuses each of the groupings of piping, supports, components, and primary equipment, to describe which remained bounded, and those that required new analyses.

For the determination of stresses, the inputs to be considered are loads due to primary system operating pressure, seismic excitation, deadweight, plant operating temperatures and loss of coolant accident (LOCA) forces. Primary system operating pressure does not change, and seismic and deadweight loads are not expected to change under EPU conditions.

However, the PBNP reactor vessel support stiffness was modified which changed the seismic loads. Please refer to the NextEra response to EMCB RAI 16 for further discussion of the revised reactor vessel support modeling. The revised seismic loads were included as part of the various component EPU evaluations as noted in the component responses below.

Plant operating temperatures changed for the EPU (lower Tcold,higher That), resulting in a change to the thermal inputs to the component, piping and support evaluations. The plant Page 3 of 41

operating temperature changes also revised the loadings associated with the design transients listed in LAR 261, Attachment 5, Table 2.2.6-1. These revised loadings are included in the component EPU evaluations and noted below. Plant operating temperature changes affected the LOCA forces, and the corresponding component and piping LOCA loads and motions for the EPU. The impacts of these changes are discussed below.

NSSS (RCS) Pipinq The RCS piping pressure loads, deadweight loads, and seismic excitation did not change from the existing design basis AOR.

The following affected loads were re-evaluated:

e Thermal loads due to changed plant operating temperatures (lower Tc0ldand higher That) e RCS piping LOCA forces due to changed operating temperatures e Reactor pressure vessel (RPV) LOCA forces due to changed operating temperatures 0 RPV LOCA displacement due to corrected support structure stiffness The PBNP design transients (LAR 261, Attachment 5, Table 2.2.6-1) pertain to fatigue design.

The RCS piping is designed to USAS B31.I, which does not require fatigue analysis and is therefore unaffected by the changes in design transients.

The revised RCS loop piping analyses demonstrated that the stresses will remain enveloped by the previous analyses results as indicated in the note to Table 2.2.2.1-1 of LAR 261, .

Pressurizer Surge Line (Including Thermal Stratification)

The pressure loads, deadweight loads, and seismic excitation inputs from the design basis AOR were unaffected.

The operating thermal and thermal stratification loadings will change under EPU due to operating temperature and design transient inputs. These changes required an evaluation of the surge line stresses.

The evaluation of the surge line demonstrated that the stresses will remain enveloped by the previous analyses results and will remain within the acceptance criteria used in the previous analyses under EPU conditions.

RCS Branch Pipinq Reactor coolant loop (RCL) branch piping evaluations which reconciled revised RCL displacements for EPU conditions concluded that existing design basis RCL branch piping analyses remain acceptable for EPU conditions (i.e., no change to stresses due to EPU).

Reactor Vessel For the EPU, revised plant operating temperatures, design transients and interface loads with the reactor vessel were evaluated. Changes to the plant operating temperatures and design transients affected the transient thermal and pressure loadings on the various reactor vessel Page 4 of 41

components. Transient thermal and pressure loading changes affect the reactor vessel component primary plus secondary stress intensity ranges and cumulative fatigue usage factors. The EPU transient thermal and pressure loading changes were evaluated for each reactor vessel component and the resulting primary plus secondary stress intensity ranges and cumulative fatigue usage factors were shown to be acceptable as listed in LAR 261, , Table 2.2.2.3-3.

The interface loads evaluated were those associated with the reactor internals, reactor coolant loop piping, vessel supports and safety injection system piping.

B Reactor internals interface loads consist of seismic and LOCA loads which both changed for the EPU as explained in the overall introductory paragraph to this RAI response. As shown in LAR 261, Attachment 5, Table 2.2.2.3-4, the EPU reactor internals interface loads with the reactor vessel were bounded by the allowable loads evaluated in the existing AOR.

a RCL piping interface loads consist of deadweight, thermal, seismic and LOCA loads acting on the reactor vessel inlet and outlet nozzles. Only the RCL piping thermal and LOCA interface loads changed for the EPU conditions. The thermal and LOCA interface loads were shown to be bounded by those evaluated in the AOR. Even though RCL piping seismic interface loads did not change for EPU conditions, an existing outlet nozzle safe shutdown earthquake (SSE) axial load was found to be larger than that qualified in the AOR. The increased stress due to this load was considered in the outlet nozzle faulted primary stress evaluation and shown to be acceptable.

e Vessel support interface loads, similar to the reactor internals interface loads, consist of seismic and LOCA loads which also changed for the EPU as explained in the overall introductory paragraph to this RAI response. The EPU operating basis and design basis earthquake vertical loads on the external support brackets were larger than those qualified in the AOR. However, the increased loads were factored into all external support bracket primary, primary plus secondary and fatigue EPU evaluations and shown to be acceptable.

e Safety injection system piping interface loads, similar to the RCL piping interface loads, consist of deadweight, thermal, seismic and LOCA loads acting on the safety injection nozzles. These loads were not previously evaluated in the AOR and only the LOCA loads changed for EPU conditions. All the loads were incorporated into the safety injection nozzle primary, primary plus secondary stress intensity range and cumulative fatigue usage factor evaluations and shown to be acceptable.

CRDMs The CRDMs do not experience an increase in stresses due to the EPU because the existing analysis contains loads that envelope the loads at EPU conditions.

Steam Generator The dynamic loading on the steam generator is unchanged or is enveloped by the original design basis. However, there are some changes to the component stresses due to thermal and secondary side pressure changes in the steam generators as a result of EPU conditions.

Page 5 of 41

These changes were conservatively evaluated through comparative analyses that will increase the design basis stresses in accordance with pressure and temperature changes resulting from the uprate. These changes were evaluated and compared to the Code allowable and have been shown in Tables 2.2.2.5-1 and 2.2.2.5-2 of LAR 261, Attachment 5 to meet Code allowables in accordance with the original design basis.

RCPs The EPU caused no changes to the stresses in the main flange and main flange bolted joint and the analysis of record remains bounding.

However, existing analysis for the RCP casing does not envelope EPU conditions, Increases for the EPU conditions due to the primary plus secondary pressure and mechanical loads, and the maximum steady-state thermal plus pressure and mechanical stresses, are shown in Table 2.2.2.6-1 of LAR 261, Attachment 5. These stresses were increased by 3.23% due to a difference in the heatup/cooldown temperature range between the design specification and the Model 93 casing stress analysis. The increased stresses remain below allowable limits, per the ASME Code, 1965 Edition.

Pressurizer The revised transients have no effect on the primary stress evaluations performed previously for the pressurizer. The maximum ranges of primary plus secondary stress intensities remain unchanged for the pressurizer components at EPU conditions.

RV lnternals The existing AOR for the reactor internal components contained loads which enveloped or remained the same for some components and were increased in other components due to EPU conditions. In cases where the loads/stresses were increased due to EPU conditions, calculations were performed which reduced conservatisms (i.e., plant-specific NSSS design transients and plant-specific OBE loads instead of generic two-loop enveloped inputs) and to show that those components meet the ASME Code allowable stress limits and corresponding fatigue usage remains less than 1.O.

RCS Supports (Except Reactor Vessel Supports)

The deadweight and seismic loads on the RCS equipment supports (SG, RCP, and pressurizer) will not change due to EPU. The thermal and LOCA loads will change due to the changes in plant operating temperature and reactor vessel support stiffness. The revised support analyses for EPU conditions demonstrate that the RCS supports will remain within established allowable stress limits. The design transients described in LAR 261, Attachment 5, Section 2.2.6, are not a factor in the analysis of RCS component supports.

RPV Supports See the NextEra response to Part a) of EMCB RAI 16.

Page 6 of 41

EMCB RAI 3 Confirm that the current licensing basis at PBNP does not contain any requirements for fatigue evaluation of the above-mentioned systems, structures, and components (SSCs).

NextEra Response For PBNP, the current licensing basis does not contain any requirements for fatigue evaluation for BOP systems.

There are fatigue requirements for reactor coolant system components as discussed below.

Results of the fatigue evaluations for these components as a result of the EPU are provided in the tables from LAR 261, Attachment 5 referenced below.

NSSS (RCS) Piping and Surge Line Thermal Stratification Per Table 4.1-9 of the PBNP FSAR and the existing design basis AOR, the code requirement of the NSSS (RCS) piping is based on the USAS B31.I, 1973 Edition, Code for Pressure Piping, which does not require a fatigue evaluation.

For the pressurizer surge line, considering only the effects of thermal stratification, the current licensing basis at PBNP includes a fatigue evaluation to address NRC Bulletin 88-11 (Reference 3). The code edition used is in compliance with the pressurizer surge line thermal stratification NRC Bulletin Number 88-11 and as documented in LAR 261, Attachment 5, Section 2.2.2.1.2. For the current licensing basis at PBNP and for EPU conditions, the evaluation of the pressurizer surge line, considering only the effects of thermal stratification, are in compliance with NRC Bulletin 88-1 1, and is performed to the 1986 version of the ASME code.

RCS Branch Pipinq PBNP RCS branch piping evaluations are performed in accordance with the ASA B31.ICode for Pressure Piping, 1955 Edition.

This code does not contain any requirements for fatigue evaluation for piping qualification.

Reactor Vessel The current PBNP licensing basis for the Unit 1 and Unit 2 reactor vessels contains the following ASME Code requirements:

Unit 1 - 1965 Edition of ASME Code, Section Ill for the reactor vessel Unit 1 - 1998 Edition through 2000 Addenda of ASME Code, Section Ill for the replacement reactor vessel closure head (RRVCH)

Unit 2 - 1968 Edition through Winter 1968 Addenda of ASME Code, Section Ill for the reactor vessel Unit 2 - 1998 Edition through 2000 Addenda of ASME Code, Section Ill for the RRVCH Page 7 of 41

These ASME code editions contain requirements for fatigue evaluation. For instance, in the 1965 and 1968 Editions of the ASME Code, the fatigue requirements are contained in sub-paragraph N-415.2. In the 1998 Edition of the ASME Code, the fatigue requirements are contained in sub-paragraph NB-3222.4(e). The Unit 1 and Unit 2 reactor vessel fatigue results are listed in LAR 261, Attachment 5, Table 2.2.2.3-3 and are acceptable.

CRDMs The CRDM stress analysis is based on ASME Code Section Ill criteria. The CRDM meets these criteria including requirements for fatigue evaluation. Fatigue evaluations are required for the CRDMs and are shown to be acceptable in Table 2.2.2.4-1 and Table 2.2.2.4-2 of LAR 261, .

Steam Generator Fatigue evaluations are required for the steam generator per the ASME Codes delineated in LAR 261, Attachment 5, Section 2.2.2.5.1. Fatigue evaluations are shown to be acceptable in Table 2.2.2.5-1 for Unit 1 and Table 2.2.2.5-2 for Unit 2 of LAR 261, Attachment 5.

RCPs The reactor coolant pumps are included in the discussion of metal fatigue as it relates to meeting the intent of the ASME Boiler and Pressure Vessel Code, Section Ill, Class I equipment. Original reactor coolant pump analyses for the Model 93 RCPs complied with this requirement by calculating cumulative fatigue usage factors for the casing (including the suction and discharge nozzles), the main flange, and the main flange bolted joint. RCP evaluations performed for the EPU concluded that the fatigue usage factor originally calculated remains valid under EPU conditions, as summarized in Table 2.2.2.6-1 of LAR 261, Attachment 5.

Fatigue crack growth in the RCP motor flywheel was previously evaluated for all operating domestic Westinghouse plants, and determined to be negligible over a 60 year life of the flywheel. Inputs considered in that evaluation envelop EPU conditions. Fatigue crack growth therefore remains negligible for EPU conditions.

Fatigue evaluations are required for the RCPs and are shown to be acceptable in Table 2.2.2.6-1 of LAR 261, Attachment 5.

Pressurizer Fatigue evaluations are required for the pressurizer and are shown to be acceptable in Table 2.2.2.7-1 of LAR 261, Attachment 5.

RV lnternals The original licensing basis for PBNP does not contain requirements for fatigue evaluation of the reactor vessel internals (RVI) components. RVI components were designed and manufactured prior to the availability of ASME Code Section Ill, Subsection NG, "Core Support Structures."

Fatigue evaluations were, therefore, neither required nor performed for all reactor internal components. However, RVI components were evaluated for fatigue, based on the intent of ASME Code Section Ill, Subsection NG. RVI components evaluated for fatigue were shown to be acceptable and are listed in Table 2.2.3-3 of LAR 261, Attachment 5.

Page 8 of 41

RCS Supports (Except Reactor Vessel Supports)

The original code of construction, the AISC Sixth Edition, Appendix B, required a fatigue evaluation at 20,000 stress reversal cycles. The AISC, Eighth Edition, has same requirements as the AISC, Sixth Edition. The design basis RCS supports (SG, RCP and pressurizer) loads do not approach this level of stress reversal cycles. Therefore, RCS supports do not require a fatigue evaluation for the EPU conditions.

RPV Supports The RPV supports are not evaluated for the effects of fatigue. Appendix B of the AISC "Specification for the Design, Fabrication and Erection of Structural Steel for Buildings," dated February 12, 1969, requires a fatigue evaluation at 20,000 stress reversal cycles. The design basis RPV support loads do not approach this level of stress reversal cycles.

EMCB RAI 4 Tables 1-1 and 1-2 provide the RCS operating temperatures and pressures for EPU and current licensed thermal power (CLTP). Table 2.5.5.1-1 provides main steam (MS) operating and design temperature and pressure. Table 2.5.5.4-1 provides feedwater (FW) operating temperature and pressure. For the CLTP and EPU, please provide both the FW and RCS design temperatures and pressures.

NextEra Response The current and EPU feedwater and condensate system design temperatures and pressures are provided below:

System Piping Segment Current Design EPU Design PressITemp PressITemp From Condenser to Condensate 20 psig I100°F 50 psig 1 150°F Pump Suction Condensate Pump Discharge and 400 psig / 348°F (Max) 415 psig 1400°F (Max)

Heater Drain Pump Discharge to Feedwater Pump Suction Feedwater Pump Discharge to 1525 psig / 436°F 1525 psig 1400°F No. 5 Feedwater Heaters No. 5 Feedwater Heaters to 1525 psig I436°F 1525 psig / 480°F Feedwater Regulating Valve Block Valves From Feedwater Regulating Valves 1310 psig I436"F* 1315 psig 1480°F to Feedwater Isolation Valves From Feedwater Isolation Valves 1310 psig 1436°F" 1270 psig / 480°F to Steam Generators

• For current conditions, the feedwater isolation valves do not exist and the current design pressure and temperature listed is from the feedwater regulating valves to the steam generators.

Page 9 of 41

The RCS design temperatures and pressures are provided in FSAR Table 4.1.6 and are shown below. These values do not change for the EPU.

Design PressITemp Reactor Coolant System 2485 psig I 650°F Pressurizer Surge Line 2485 psig I 680°F EMCB RAI 5 Section 2.2.2.2.2.2 states that, The two piping systems of most concern with respect to flow rate increases are main steam and feedwater systems."

a) Identify all piping systems that would experience higher flow rates due to the EPU implementation.

b) Section 2.2.2.2.2.3 also states that "Additionally, the implementation of the EPU will result in higher flow rates for several piping systems. Piping systems experiencing these higher flow rates require review for potential flow induced vibration issues. " Please discuss how these reviews were conducted and provide a summary of their results.

c) Provide a clear description of the planned activities to address flow-induced vibration (FIV) on susceptible systems.

d) Describe the methodology and provide the acceptance criteria for the evaluation of FIV for these piping systems.

NextEra Response a) The implementation of EPU will result in higher flow rates that will impact the levels of flow induced piping vibration in BOP piping systems that comprise the main power cycle.

These piping systems include main steam, feedwater, condensate, extraction steam and heater drains (including heater vents and drains).

b) A plan has been developed for PBNP to address flow induced vibration in piping affected by power uprate. The plan began with the development of a program to address scope, method, evaluation and acceptance criteria. The scope includes the piping with increased flow rates resulting from EPU identified in the NextEra response to EMCB RAI 5, Item a), above.

With respect to piping vibration, the ability to analytically predict potential flow induced piping vibration displacements and resulting stresses due to higher flow rates resulting from EPU is complex. It involves assessing many piping system attributes, such as plant piping configuration, valve alignment and support locations and functions that are being modified as a result of EPU. The more effective method of precluding piping failures due to flow induced vibration due to changes from EPU is the implementation of the Point Beach developed plan to extensively monitor actual piping response to actual plant conditions. This method and plan has been successfully implemented for Extended Power Uprates (EPUs), Stretch Power Uprates (SPUs) and Measurement Uncertainty Recapture (MURs) for several PWR nuclear plants including Beaver Valley Units 1 and 2, Seabrook, Ginna, North Anna Units 1 and 2, Millstone Unit 3 and Page 10 of 41

Comanche Peak Units 1 and 2. This method provides a more proactive and reliable means for addressing potential piping vibration issues.

The piping identified in the NextEra response to EMCB RAI 5, ltem a), above, will be observed by experienced piping testing engineers at several different plant operating power levels to identify areas where piping vibration displacement is occurring. The initial sets of observations (pre-baseline, as defined in the PBNP piping vibration monitoring plan) will be at the pre-EPU full-power level and will establish the baseline pipe vibrations. Several pre-baseline piping vibration walkdowns have already been performed. Walkdowns performed in March 2008, August 2008, September 2008, November 2008 and December 2009 provided specific data on existing piping vibration levels at PBNP Unit 1 and Unit 2. The walkdowns performed in November 2008 and December 2009 included observations of piping vibration following the implementation of the modification for the replacement of the No. 4 and 5 feedwater heaters for Units 1 and 2. The piping vibration levels observed during these five pre-baseline walkdowns were at levels that, based upon extensive engineering experience, result in piping vibration stress levels below stress criteria provided in ASME OM SIG-2003, Part 3. No detailed analyses were required to support this conclusion. NextEra also determined that there was no requirement to implement any piping or support modifications prior to the EPU implementation outage, because there were no potential piping vibration issues identified. An additional pre-baseline walkdown for each unit will be performed prior to entering each EPU outage to identify any potential piping vibration issues that should be addressed during the outage. Observations for EPU will take place at the post-EPU power level test plateaus (from 20% to 100% power) established for power ascension testing. By comparing the observed pipe vibrationsldisplacements at various power levels with those observed at the pre-baseline power level, increased pipe vibrations will be identified and the need for additional evaluations will be determined. As stated above, the acceptance criteria for all piping evaluations will be in accordance with ASME OM SIG 2003, Part 3.

As stated in the NextEra response to EMCB RAI 5, ltem b) above, observed piping vibrations will be evaluated to ensure that damage will not result. For PWRs where the critical EPU-affected piping is accessible, the activities planned to address and assess piping vibrations are to monitor the piping before the EPU outage and during the plant heat-up and power ascension for EPU. The affected piping to be observed includes the lines that are modified by EPU and the EPU-affected lines that were identified through the PBNP corrective action program. The methodology to be used for the monitoring and evaluation of the piping vibration will be in accordance with ASME OM-SIG-2003, Part 3.

d) As described in the NextEra response to EMCB RAI 5, ltem b) above, the methodology is based on performing a series of walkdowns spanning from the current plant condition to the completion of power ascension testing following the implementation of power uprate. Acceptance criteria for all piping evaluations will be in accordance with ASME OM SIG-2003, Part 3.

Page 11 of 41

EMCB RAI 6 This RAI is in reference to EPU-LR Section 2.12.1.2.3.4, Vibration Monitoring.

This section, in part, states that:

A Piping and Equipment Vibration Monitoring Program, including plant walkdowns and monitoring of plant equipment, will be established to ensure that steady state flow induced piping vibrations following EPU implementation are not detrimental to the plant, piping, pipe supports or connected equipment.

a) Has the development of this program been completed? If not, provide the schedule for completion.

In the same section, it is also stated that:

The program scope will also include any lines or equipment within the monitored systems that have been modified or otherwise identified through the PBNP action report system as having already experienced vibration issues.

b) Has this work been performed yet? If not, provide the schedule for completion.

EPU-LR Section 2.12.1.2.3.4 also states that:

Subsequent observations will take place at each EPU Test Plateau, as described in Section 2.12.1.2.3. I above. By comparing the observed pipe vibrations/displacements at various power levels with previously established acceptance Criteria, potentially adverse pipe vibrations will be identified, evaluated and resolved prior to failure.

c) Please list the acceptance criteria and supporting basis to be utilized for evaluating observed pipe vibrations and displacements at various EPU ascension power levels.

d) Have base line data at CLTP been gathered and have they been analyzed and projected to the EPU level to determine that at EPU power the allowable limits will not be exceeded? If yes, provide evaluation summaries which show that established acceptance criteria can be met for EPU conditions. If not, provide a justification why this work has not been performed yet.

NextEra Response a) The development of this program has been completed, and several plant vibration walkdowns in support of this program have been performed. Refer to the NextEra response to EMCB RAI 5, ltem b), for specific details related to this program.

b) Refer to the NextEra responses to EMCB RAI 5, ltems b) and c), and the NextEra response to EMCB RAI 6, ltem d) below, for details.

c) The acceptance criteria used for piping vibration is in accordance with ASME OM SIG-2003, Part 3. Refer to the NextEra response to EMCB RAI 5, ltems b), c) and d), and EMCB RAI 6, ltem d) below, for additional details on the supporting basis.

Page 12 of 41

d) As described in the NextEra response to EMCB RAI 5, ltem b), plant walkdowns have been performed in March 2008, August 2008, September 2008, November 2008 and December 2009 to obtain baseline vibration data at the current license basis power level. The relatively low amplitude piping vibration displacement levels observed during these baseline plant walkdowns were determined by engineering experience to develop stresses in the piping that are within acceptable stress limits as defined in ASME OM SIG-2003, Part 3. These baseline walkdowns were also used to develop a list of the most critical points, which will be specifically observed during the EPU power ascension process in accordance with the piping vibration plan. No additional analysis was required to conclude expected piping vibration stress levels are below stress criteria provided in ASME OM SIG-2003, Part 3, as discussed in the NextEra response to EMCB RAI 5, ltem b).

The ability to analytically predict potential flow induced piping vibration displacements and resulting stresses due to higher flow rates resulting from EPU is complex. It involves assessing many piping system attributes, such as plant piping configuration, valve alignment and support locations and functions which are being modified as a result of EPU. The more effective method of precluding piping failures due to flow induced vibration under EPU conditions is the implementation of the PBNP developed plan to extensively monitor actual piping response to actual plant conditions. This method and plan has been successfully implemented for Extended Power Uprates (EPUs), Stretch Power Uprates (SPUs) and Measurement Uncertainty Recapture (MURs) for several PWR nuclear plants including Beaver Valley Units Iand 2, Seabrook, Ginna, North Anna Units Iand 2, Millstone Unit 3 and Comanche Peak Units Iand 2. This method provides a more proactive and reliable means for addressing potential piping vibration issues.

EMCB RAI 7 Section 2.2.2.2.2 states that, "BOP piping and support systems were evaluated to assess the impact of operating .temperature, pressure and flow rate changes that will result due to the implementation of EPUJJ and contains a list of "BOP piping and support systems that were evaluated for EPU condition^.'^ The list follows this quoted statement. From this list, Table 2.2.2.2-1 of the LR indicates that only portions of the M, FW, condensate, extraction steam and FW heater drains have been evaluated.

a) Identify all systems (inside and outside containment) that experience increase in temperature, increase in pressure and an increase in flow rate.

b) For systems that experience increases in the above parameters, provide the method of your evaluation. Provide a quantitative summary of the maximum stresses and fatigue usage factors (if applicable) for original and EPU conditions with a comparison to the original code of consfruction allowable stress values. Include only maximum stresses and data at critical locations (i.e., nozzles, penetrations, etc). List all piping modifications (for pipe supports see (d) below) required due to EPU and the associated schedule for completion. For affected nozzles and containment penetrations, provide a summary of loads compared to specific allowable values for the nozzles and penetrations (include containment penetrations, steam generator (SG) and FW pump nozzles).

Page 13 of 41

c) For the systems with a thermal change factor greater than 1.00, provide a description of pre-operational measures taken to identilj locations that could potentially be subject to unacceptable thermal expansion interaction resulting in an unanalyzed plant condition that could potentially overstress piping and supports. In addition, confirm that a program will be in place for monitoring thermal expansion at the startup of the EPU. The EPUpower ascension program (see LR page 2.12-4) does not appear to contain such a provision. In addition, page 2.12-14 of the LR states that the "EPU power ascension program will be developed. " Please verify that this program has been developed.

d) For the systems in (b), state the method used for evaluating pipe supports when considering EPU conditions and confirm that the supports on the affected piping systems have been evaluated and shown to remain structurally adequate to perform their intended design function. Provide detail descriptions of all pipe support modifications needed to meet design basis at EPU conditions. In addition, list also type, size, loading (current and EPU) and location of supports that need to be modified and/or added due to the EPU.

e) Provide the schedule for completion of all piping and pipe support modifications and additions.

NextEra Response a) Portions of the following piping systems will experience an increase in temperature, pressure, and/or flow rate resulting from EPU. As such, detailed pipe stress and/or pipe support evaluations are required:

0 Main Steam 0 Condensate 0 Feedwater a Extraction Steam 0 Heater Drains With respect to pipe stress and support issues, no other piping systems contained temperature, pressure and/or flow rate increases that required detailed pipe stress and support evaluations. The auxiliary feedwater piping and supports have been addressed in separate requests for information (References 4 and 5).

b) The NUPIPE-SWPC computer program was used to evaluate piping systems which will experience an increase in temperature, pressure and/or flow rate, as described in LAR 261, Attachment 5, Section 2.2.2.2.2. The NUPIPE-SWPC program performs a linear-elastic analysis of piping systems subjected to thermal, static and dynamic loads and utilizes the finite element method of analysis to accommodate specific requirements in the piping analysis.

A summary of the maximum stress levels for current and EPU conditions, including a comparison to code of record allowable stress levels are provided in Attachment 1. For each piping system listed in this table, the stresses reported are at the most critical location of the piping system, corresponding to the piping location containing the highest stress interaction ratio. The stress interaction ratio is defined as the ratio of EPU stress divided by the allowable stress. These critical stress locations may be at equipment nozzles, containment penetrations, or any in-line piping component (e.g., valve, elbow, Page 14 of 41

reducer, etc.) within the analytical boundaries of the piping stress model. Attachment I does not contain any cumulative usage factors since fatigue evaluations for BOP piping are not required per the current piping code of record USAS B31.IPower Piping Code, 1967 Edition.

A summary of the piping modifications resulting from EPU modifications are provided in response to EMCB RAI 8.

With respect to pipe support modifications, specific details are provided in the NextEra response to EMCB RAI 7, Item d), below.

A summary of EPU loads and allowable values for steam generator and feedwater pump nozzles and containment penetrations that were affected by EPU are as follows:

Feedwater P u m ~ s See Attachment 2 for feedwater pump nozzle load summaries.

Steam Generators See Attachment 3 for steam generator main steam nozzle load summaries.

See Attachment 4 for steam generator feedwater nozzle load summaries.

Containment Penetrations See Attachment 5 for containment penetration main steam load summaries, See Attachment 6 for containment penetration feedwater load summaries.

The stress values and load data provided in this response and referenced tables may change as result of final design and as-built conditions. The final results will remain within code allowable values and acceptance criteria.

c) During baseline walkdowns being performed for piping vibration, piping systems that will be subjected to a temperature increase associated with EPU (i.e., main steam, condensate, feedwater, extraction steam, and heater drains) will be inspected to identify locations where there is a potential for unacceptable thermal expansion interaction. The increases in thermal expansion displacements associated with EPU are expected to be less than 1/16 inch, and therefore, these increased displacements should not be a significant concern. However, during startup of the EPU, piping systems subjected to a temperature increase will be observed to identify any unacceptable conditions.

The planlprogram for monitoring thermal expansion during power ascension following the implementation of EPU will be included in the Power Ascension Program which is being developed as part of the EPU implementation modification that implements the EPU and Power Ascension Program.

d) The pipe supports were evaluated for increased loads due to EPU by performing manual calculations and/or detailed computer analyses, using the PC-PREPS and ANSYS computer programs, as described in LAR 261, Attachment 5, Section 2.2.2.2.2. The PC-PREPS computer program performs a complete structural analysis, including an AlSC code check, weld qualification and baseplatelanchor bolt qualifications. The Page 15 of 41

ANSYS computer program uses finite element analysis methods to perform detailed welded attachment analyses. The support evaluations have demonstrated that affected pipe supports, including new and modified supports, are acceptable for EPU conditions in accordance with current plant design basis.

Detailed data related to pipe supports requiring modification due to EPU are provided in Attachment 7 (Unit I ) and Attachment 8 (Unit 2). The subject tables provide the support number, piping system, pipe size, location, EPU load, and description of modification.

Many of the support modifications involve new supports, or relocated supports, or supports where existing detailed analyses were not available, such that there is no existing load data available, or a comparison of current to existing loads would not be an accurate representation of a load increase due to EPU. Based on this observation, no current loads were provided in the tables.

The pipe support load data provided in this response and referenced tables may change as result of final design and as-built conditions. The final results will remain within code allowable values and acceptance criteria.

e) The final EPU modifications for Unit 1 will be installed during the Fall 2011 outage. The final EPU modifications for Unit 2 will be installed during the Spring 201Ioutage. The implementation plan has been provided in Reference (6).

EMCB RAI 8 Section 2.2.2.2.2 states that "... main steam and feedwater pipe support modifications are required to mitigate the larger flow induced fluid transient loads that resulted due to EPU conditions." Please identify all piping systems that require modifications for EPU. Provide a detailed description of piping and pipe support modifications (including new supports) that are required for EPU. Include pipe line name, size, type and identification name of pipe support and the reason for the revision/addition.

NextEra Response The following piping systems required modifications for EPU.

a Main Steam (pipe supports only) a Feedwater

@ Condensate 0 Extraction Steam a Heater Drains (including heater relief valve piping)

There were no main steam or feedwater "piping" modifications required to address fluid transient loads resulting from EPU. The main steam and feedwater modifications required to address fluid transient loads resulting from EPU were limited to "pipe support" modifications.

Page 16 of 41

A summary of the piping modifications resulting from EPU modifications are as follows:

Feedwater and Condensate Svstem e Replacement of feedwater pumps require suction and discharge piping changes to match new nozzle locations and revised pump and motor arrangement Q Replacement of feedwater pump minimum recirculation lines and valves require larger diameter piping and valves Q Replacement of the feedwater heaters require piping changes to match new nozzle sizes and locations Q Installation of new feedwater isolation valves require piping changes to install new valves Heater Drain Svstem

@a Modification of the heater drain pump minimum flow recirculation lines require piping changes to install automatic valve to open/close to maintain minimum pump flow a Replacement of heater drain control valves require piping changes due to increase in valve size e Replacement of the feedwater heaters require piping changes to match new nozzle sizes and locations e Modification of the feedwater heater level controls require piping changes to facilitate new level transmitters and switches Extraction Steam Svstem e Replacement of the feedwater heaters require piping changes to match new nozzle sizes and locations Heater Relief Valve Piping a Replacement of the No. 4 and 5 feedwater heater relief valves require discharge piping changes to accommodate larger relief capacity In addition, minor small bore piping changes in the condensate, heater vents and drains, and service water systems associated with EPU modifications are being made.

For detailed summary of required pipe support modifications resulting from EPU, refer to the response for EMCB RAI 7, ltem d). The pipe line name, size, type, and identification name of the pipe support, along with the reason for the revisionladdition are included in the NextEra response to EMCB RAI 7, ltem d).

Page 17 of 41

EMCB RAI 9 EMCB RAI 9 refers to pipe stress summaries of the EPU LR Table 2.2.2.2-1.

a) Confirm whether stress summaries of Table 2.2.2.2- 1 include stresses due to fluid transient loads associated with the EPU; such as turbine stop valve (TSV), main steam isolation valve (MSIV) and main feedwater isolation valve (MFIV) closure transients. If not, provide stress summaries of the feedwater and main steam piping evaluations that contain stresses due to EPU higher fluid transient loads. In addition, for main steam and feedwater nozzles and containment penetrations, provide a summary of loads compared to specific allowable values for the nozzles and penetrations.

b) The stress summaries of Table 2.2.2.2-1 are not based on the current plant piping configurations. Please update this table to show pipe stress summaries of EPU piping configuration and conditions.

c) Table 2.2.2.2- 1 does not contain stress summaries for the sustained loads equation. Veriw that pressure in piping systems (BOP and inside containmenf) is not affected by the proposed EPU.

NextEra Response a) The stresses provided in LAR 261, Attachment 5, Table 2.2.2.2-1 included stresses due to fluid transient loads associated with EPU. The updated stress data provided in the NextEra response to EMCB RAI 9, ltem b) below also includes stresses due to fluid transients, as applicable.

The main steam and feedwater nozzle loads and containment penetration loads, including their respective allowable values, are provided in the response for EMCB RAI 7, ltem b).

b) The updated stress summaries reflecting EPU piping configurations and conditions are provided in the response for EMCB RAI 7, ltem b). The pipe stress values provided in the NextEra response to EMCB RAI 7, ltem b) and referenced tables may change as a result of final design and as-built conditions. The final results will remain within code allowable values and acceptance criteria.

c) The pipe stress sustained loads equation has been included in the updated stress summaries provided in the response for EMCB RAI 7, ltem b). The updated sustained stress data has evaluated pressure changes andlor piping and support system configuration changes resulting from EPU that would potentially impact the sustained stress equation. The sustained stress levels for piping systems (BOP and inside containment) under EPU conditions remain within the current design basis allowable limits.

Page 18 of 41

EMCB RAI 10 At the time of the EPU LAR submittal, some EPUrequired piping and pipe support analyses had not been performed or completed. On page 2.2.2-18 of the EPU LR, states that "...the piping and support evaluations will be performed as part of the overall design change package.. ." This is not acceptable to the staff. Please provide assurance that all piping and pipe support evaluations, including new and modified supports, have been completed and the evaluations have found that these SSCs are capable of maintaining their designed structural integrity for EPU conditions in accordance with the current plant design basis. Also, please provide the schedule for the required installations.

NextEra Response The evaluations for all piping and pipe supports (including new and modified supports) for EPU conditions have been completed. These evaluations have demonstrated that piping and related pipe supports, including new and modified supports, are acceptable for EPU conditions in accordance with current plant design basis. Refer to the NextEra responses to EMCB RAI 7, EMCB RAI 8 and EMCB RAI 9 for evaluation results. The pipe stress values and pipe support loads provided in the NextEra responses to EMCB RAI 7, EMCB RAI 8 and EMCB RAI 9, may change as result of final design and as-built conditions. The final results will remain within code allowable values and acceptance criteria.

The final EPU modifications for Unit 1 will be installed during the Fall 201 1 outage. The final EPU modifications for Unit 2 will be installed during the Spring 2011 outage. The implementation plan has been provided via Reference (6).

EMCB RAI I 1 Please explain why the reactor pressure vessel (RPV) stress summary does not contain primary plus secondary stress intensity values compared to 3S, for the RPV inlet and outlet nozzle support pads. I f these values were not calculated for EPU, provide a justification.

NextEra Response The original stress reports did not evaluate the primary plus secondary stress intensity ranges for the RPV inlet and outlet nozzle support pads. No explanation was given in the reports as to why the primary plus secondary stress intensity ranges were not evaluated; however, the ranges would be under the 3S, limit based on the following discussion.

Page 19 of 41

The RPV inlet and outlet nozzle support pads are seated in support shoes that make up part of the RPV support system. The average operating temperature of the support shoes is approximately 400°F. The largest temperature gradient in the nozzle support pads would be from the inside diameter of the outlet nozzle to the bottom of the support pad given that the outlet nozzle is exposed to higher reactor coolant temperatures than the inlet nozzle. Assuming a very conservative outlet nozzle inside diameter temperature of 650°F, the temperature gradient through the support pad would be 250°F through a metal thickness of approximately 12 inches. The linear thermal gradient hoop and axial stress is approximated using the following equation:

E ~ T where: E = 26.05 x lo6 psi C T ~= ox= $. a = 7.33 x 10-6in/in/"F 2(1- v) AT = 250°F v = 0.3 The maximum linear thermal gradient stress would be approximately +34 ksi. Note that material properties for SA-508 Class I1at 650°F are used.

The original stress reports did provide pressure, thermal and external load stresses during each transient at the inside diameter and the bottom of the support pad for each respective RPV nozzle. These stresses were combined to form total stress intensities which were then used to calculate cumulative fatigue usage factors at the two locations.

The largest total stress range in the original stress reports occurs on the inside diameter of the outlet nozzle. The maximum total stress range is created from the steam pipe break and no-loss-of-function seismic events. The +34 ksi linear thermal gradient stress calculated above is substituted for the peak thermal stress in the two transients that make up the largest total stress range. One transient has 34 ksi linear thermal gradient stress while the other transient has -34 ksi linear thermal gradient stress. Recombining the given pressure, linear thermal gradient and external load stresses results in a primary plus secondary stress intensity range of approximately 67 ksi which is well under the 80.1 ksi 3S, limit.

For EPU conditions, the conservative 250°F temperature gradient would still be applicable, so the 34 ksi maximum linear thermal gradient stress would also apply for EPU conditions. The steam pipe break transient is not affected by EPU conditions. Any changes to the no-loss-of-function seismic event compressive stresses in the nozzle support pads would minimally impact the primary plus secondary stress intensity range since the thermal stress dominates this quantity. Therefore, the 67 ksi primary plus secondary stress intensity range would also be applicable for EPU conditions.

EMCB RAI 12 Please clarify whether the fatigue derived cumulative usage factors (CUFs) shown in tables of EPU LR Section 2.2, "Mechanical and Civil Engineering': are for the 60 year renewed plant life.

NextEra Response The cumulative usage factors in the tables of EPU LR Section 2.2 are for the 60 year renewed plant life.

Page 20 of 41

EMCB RAI 13 Were the stress analyses rerun or were scaling factors used with the CLTP or the original stress reports to determine EPU stress intensities and fatigue CUFs shown in LR Table 2.2.2.3-3?

Provide your methodology which shows how the scaling factors were derived and how they were used to determine EPU stress intensities and fatigue CUFs from baseline stress reports.

Also explain the "standard engineering approachesJ'usedto evaluate changes in the thermal and pressure stresses, due to adverse changes in temperature and/or pressure variations from the baseline transients. Provide an example which shows the methodology used.

NextEra Response The only reactor vessel component stress and fatigue analysis that was rerun for the EPU was the RRVCH flange evaluation. The original RRVCH flange evaluation was performed using the Westinghouse WESTEMSTMsoftware. The original WESTEMS database was updated for EPU conditions and rerun to provide updated RRVCH flange stress and fatigue results. Scaling factors were applied to all other reactor vessel component EPU evaluations.

Listed in LAR 261, Attachment 5, Table 2.2.2.3-1 are the baseline stress reports supporting the CLTP. Collectively, these baseline stress reports constitute the AOR for the PBNP Unit 1 and Unit 2 reactor vessels. The original stress reports provided the initial reactor vessel component stress and fatigue results which have been modified by the RSGIuprating and RRVCH programs.

As mentioned previously, all reactor vessel component EPU evaluations (except the RRVCH flange) scaled the stresses derived in the RSGIuprating and RRVCH evaluations. For instances where the RSGIuprating did not affect the original stress report stresses while the EPU did, the original stress report stresses were scaled. The RRVCH evaluations completely replaced any analogous component evaluations in either the RSGIuprating or original stress reports.

The scaling factor method began by comparing the new EPU transients to those previously qualified in the AOR. To identify the EPU transients that were not bounded by AOR transients, the EPU and AOR transient data were expressed in terms of temperature variation (AT) for Thot and Tcold,rate of temperature variation (ATIsec) for Thotand Tcoldand pressure variation (AP).

EPU transients (That and Tcold)whose temperature variation, rate of temperature variation andlor pressure variation exceeded those for the AOR transients required further consideration in the RV component evaluations. LAR 261, Attachment 5, Table 2.2.2.3-2 lists the EPU transients that were not bounded by the AOR transients. Also listed in the table are the EPU transient parameters that were not bounded. When the Thotor Tcoldparameters are listed, it refers to the maximum factor calculated based on either the temperature variation or rate of temperature variation.

The transient temperature scale factors (That andlor Tcold)were determined by dividing the EPU temperature variations by the AOR temperature variations as well as the EPU rate of temperature variations by the AOR rate of temperature variations. The maximum ratio calculated conservatively became the thermal scale factor for that transient. A similar approach was used for the EPU versus AOR pressure variations to develop the pressure scale factor for that transient. The methodology described so far constitutes the "standard engineering approaches" cited in LAR 261, Attachment 5, Section 2.2.2.3.

Page 21 of 41

The EPU transient thermal and pressure scale factors developed were applied to the applicable RSGIuprating or original stress report transient primary plus secondary thermal and pressure stresses. The incremental thermal and pressure stress changes were then used to calculate new transient primary plus secondary stress intensities, which were then used to evaluate any changes to the maximum ranges of stress intensity for the reactor vessel 'component.

The EPU transient thermal and pressure scale factors were also conservatively applied to the applicable RSGIuprating or original stress report transient thermal and pressure stresses used to calculate transient total stresses for use in the reactor vessel component fatigue evaluations.

The new transient total stresses were then evaluated for the impact on the reactor vessel component cumulative fatigue usage.

For the RRVCH component evaluations, except for the RRVCH flange, the scale factors were very conservatively applied directly to the transient primary plus secondary stress intensities and the fatigue pair alternating stress intensities. This approach was used due to the absence of the detailed transient thermal and pressure stresses in the existing RRVCH computer output.

The following provides a brief example of the methodology:

AT ATIsec AP AOR transient (a) 40 1.25 50 EPU transient (a) 45 1.50 75 Scale factor 1.125 I.20 I.5 Thermal scale factor = I.20 (maximum of 1.I 25 and 1.20)

Pressure scale factor = 1.5 The AOR transient (a) primary plus secondary stresses (assuming external load stress is zero) is provided below:

Pressure Stress Thermal Stress Stress Axial Hoop Radial Axial Hoop Radial Intensity AOR Transient (a) 50 100 I0 120 120 40 170 Scale Factors 75 150 15 I44 144 48 23 1 Applied Other AOR transients affected by scale factors were scaled similarly and new stress intensities calculated. A check was then made for any changes to the maximum primary plus secondary stress intensity range. When a new maximum primary plus secondary stress intensity range was created, the new value was reported for the reactor vessel component for EPU conditions.

A similar approach was employed for the fatigue analysis of the reactor vessel component except that new total stress intensities were calculated and the fatigue evaluation was updated.

Page 22 of 41

EMCB RAI 15 Please verify whether or not the fatigue CUF values shown on Table 2.2.2.3-3 reflect effects from environmentally assisted fatigue? If not provide a justification.

NextEra Response NextEra determined that the environmental effects on the fatigue CUF values shown on LAR 261, Attachment 5, Table 2.2.2.3-3, were negligible. The dissolved oxygen content in the RCS was found to be below the minimum threshold value for the tensile stress producing transients. Therefore, it was not necessary to include the effects from environmentally assisted fatigue into the CUF values shown on LAR 261, Attachment 5, Table 2.2.2.3-3.

EMCB RAI 16 LR Table 2.2.2.3-6 contains the EPU revised "RPV support loads (per Support)."

a) Please explain whether these RPV loads were applied to each shoe of its support structure and discuss why the CLTP RPV support loads would change for EPU?

b) Please also provide the corresponding allowable loads for the EPU revised RPV supporf loads, as shown in Table 2.2.2.3-6.

NextEra Response a) In the support structure analytical model the maximum individual RPV support load combinations (Normal, Upset, Faulted-I, and Faulted-2) were applied to each of the six support shoe locations simultaneously.

During a detailed review of the RPV system model for EPU it was discovered that the vessel support stiffness used in horizontal and vertical directions did not consider the complete flexibility of the reactor vessel support system. A corrective action was initiated by Westinghouse and the potential discrepancy was addressed for the current PBNP operation as well as for the proposed EPU conditions. The RPV system analyses were performed for both seismic and LOCA conditions using the revised vessel support stiffness values in horizontal and vertical directions. This revised analysis using a more flexible reactor vessel support system produced results that were higher than the previously analyzed loads as used in the current analysis of record. Since the RPV system analysis results feed into various other analyses, including the reactor vessel supports, the new loads were shown to be higher than previously analyzed loads and were reconciled for both the current operation as well as EPU conditions. The downstream analyses were confirmed to be acceptable and within allowable limits as part of the corrective action resolution.

b) There are four critical RPV support structural components; the support shoe, the leveling screw, the support structure pipe column and box beam. The results of the structural evaluation of these components for revised loadings under EPU conditions, in the form of stress interaction ratios, are provided in LAR 261, Table 2.2.2.3-5.

Page 23 of 41

The requested allowable loads along with the corresponding actual load from LAR 261, Table 2.2.2.3-6 and the resultant stress interaction ratios, LAR 261, Table 2.2.2.3-5, for the support shoe and leveling screw are provided in Tables 16-1 and 16-2 below.

Table 16-1 RPV Support Shoe Actual vs. Allowable Load Comparison Load Support shoe' Combination Actual Load Allowable Load IR (400%)

Normal 0.3 kips 627.8 kips 0.05%

I Upset 1 89.3 kips 1 627.8 kips 1 14.22% 1 I Faulted-I 1 177.3 kips 1 1,255.6 kips 1 14.12% 1 Faulted-2 1 228.3 kips 1 1,255.6 kips I 18.18%

Note 1: The support shoe is subject to horizontal loads (V) only; see LR Table 2.2.2.3-6.

Table 16-2 RPV Support Leveling Screw Actual vs. Allowable Load Comparison Load Leveling Screw (2 Screws)

Combination I Actual ~ o a d ' Allowable Load I IR (<I 00%)

I Normal 1 142.3 kips 1 782.5 kips 1 18.19% 1 Upset 231.3 kips 782.5 kips 29.56%

Faulted-I 319.3 kips 1,056.4 kips 30.23%

I Faulted-2 1 370.3 kips 1 1,056.4 kips I 35.05%

Note 1: Includes additional shear load due to friction (i.e., 142 kips)

The requested allowable loads for the pipe column and box beam are not directly available as are the support shoe and leveling screw since the stress interaction ratios are based on a structural analysis of the combined support frame. The support frame analytical model is shown in Figure 16-1. The structural analysis produced critical member loads for the pipe column cross sections and the box beam cross sections.

Critical or controlling member loads in the form of axial forces (tension and compression), biaxial shear forces, torsional moments, and biaxial bending moments were created. Actual member stresses were computed from the critical member loads and the corresponding cross section properties. Allowable stresses for tension, compression, shear, and biaxial bending were computed in accordance with the PBNP primary equipment support design basis requirements taken from Table A.5-3 of the FSAR. Stress interaction ratios were then computed with the axial tension and compression with biaxial bending combination equations shown in Figure 16-2 below.

Shear stress interaction ratios were also computed with combined direct shear and shear due to torsion. The controlling stress ratios for the pipe column and the box beam cross sections are summarized in LAR 261, Table 2.2.2.3-5.

In summary, the structural qualification of the pipe column and the box beam for EPU conditions is demonstrated by showing that all combined actual stresses are less than the corresponding allowable stresses.

Page 24 of 41

rt. &:%E E Y i B U I ~ YtFff~mrs L ~ +rrkir.?is - ::oiid Fq3rez~,t.%trir~

Figure 16-1 RPV Support Structure Analytical Model Figure 16-2 Combined Stress Interaction Equations Page 25 of 41

EMCB RAI 17 PBNP EPU LR Section 2.2.2.5.7 discusses the evaluation performed to address the effects of flow induced vibration (FIV) on the SG tubes due to the increased EPU flow. Please discuss the bases for your assumptions, acceptance criteria and the methodology used for calculating tube wear, vibration forces and stresses.

NextEra Response Bases for Assumptions:

Fluidelastic Instability Fluidelastic instability is a function of various parameters as indicated in the design basis analysis. Changes in operating conditions will modify some of these parameters and result in changes to the previously calculated values. The principle values that will change as a result of the uprate will be the secondary side fluid velocity (V) and the density (p). The fluidelastic stability ratio is related to the fluid velocity and density through the following relationship:

Stability ratio "c p" x V Turbulence Turbulent displacements are a function of various parameters including density (p) and velocity (V) of the form p(V (3's) 0.5, where S (a turbulence constant) can range from 0.304 to 2.34. This means that displacements can be a function of pVawhere "a" can range from 1.65, [(3+0.304)*0.5] to 2.67, [(3+2.34)*0.5] or -pv2. For conservatism, the displacements are scaled using the conservative relationship:

Wear Potential The tube wear parameter is essentially a function of displacement. Therefore, any changes to this parameter would be proportional to displacements associated with turbulence. Therefore, wear can be modified using the same methods used for turbulence.

Page 26 of 41

Acceptance Criteria:

The acceptance criteria are as follows:

1. Fluidelastic stability ratios < I.O.

2. Amplitude of tube vibration due to turbulence no greater than half (112) of the gap between tubes. This considers the worst case scenario that the adjacent tubes are moving 180" out of phase.

Unit I: 112 * (1.2344 - 0.875) = 0.1797 inch Unit 2: 112 * (1-234- 0.875) = 0.1 795 inch

3. Demonstrate that unacceptably large rates of tube wear will not occur after the uprate.

Note that 40% wear depth for the Model 44F and Delta-47 steam generators would be 0.4 x 50 mils = 20 mils.

Methodology:

Based on factors derived above, the original flow induced vibration (FIV) results are modified to address the effects of the EPU. These values for fluidelastic instability, turbulence, and tube wear were compared to the design basis allowable values and showed continued acceptability following the EPU.

Fatigue usage associated with general FIV resulting from the most limiting uprated operating condition has been calculated. In the original analysis, the limiting tube had a maximum FIV induced tube bend,ing stress of ~ 3 0 psi 0 for Unit 1 and 410 psi for Unit 2. Conservative EPU calculations indicate that when these tubes are in operation at the uprated condition, the corresponding maximum stress levels would be 479 psi for Unit 1 and 655 psi for Unit 2. This level of stress is still well below the endurance limit of approximately 20 ksi at 1E l Icycles, and will not result in any fatigue usage factor increase.

EMCB RAI 19 SG tubes have been known to fail and rupture due to high cycle fatigue caused by vibration due to fluid-elastic instability. Discuss the applicability of the NRC Bulletin 88-02, "Rapidly Propagating Fatigue Cracks in Steam Generator Tubes, " to the PBNP SGs.

NextEra Response NRC Bulletin 88-02 (Reference 7) is not applicable to PBNP Units 1 and 2 replacement steam generators (RSG) because the tube support plates (TSPs) are fabricated of stainless steel.

One of the prerequisites for high cycle U-bend fatigue is the formation of a dented tube support condition at the upper plate. This support condition is a result of a build-up of corrosion products associated with drilled holes in carbon steel TSPs. Since the broached stainless steel support plate in the RSG is designed to inhibit the introduction of corrosion products, the support condition necessary for the development of high cycle fatigue cannot occur. As a result, high cycle fatigue associated with unsupported inner row tubes cannot occur in the PBNP Units Iand 2 steam generators.

Page 27 of 41

EMCB RAI 20 PBNP EPU LR Tables 2.5.5.1-1 and 2.5.5.4-1 show that, at EPU power levels main steam and FW flow rates will increase by over 20%, while velocities in the main steam from SGs to TCSVs could increase by approximately 27% and condensate and feedwater system flow velocities are expected to increase by approximately 25% at EPU power level.

a) Please provide for both units analysis summaries for the steam dryer, dryer supports, flow-reflectors (if applicable) and for other SG internals due to flow-induced loadings associated with fluid-elastic instability, vortex shedding or acoustic type loadings due to the EPU higher FW and steam flow. If these types of analyses for the SG internals have not been performed or flow-induced loads are not thought to be a concern for these components, provide a justification which supports your position.

b) Discuss whether any acoustic resonance could be generated at EPU flow or during power ascension to EPU power in the feedwater and main steam lines and describe how the acoustics-driven dynamic pressure loading acting on the components inside the steam generator under EPU conditions will be estimated. The discussion of the results presented in EPU LR Section 2.2.2.5 of the comparative assessment between geometries of B WR and PWR steam dryers does not demonstrate and is inconclusive as to why an acoustic type pressure wave cannot be generated and create a pressure loading on the dryer and its components.

c) Discuss procedures in place for preparation, response and preventive actions designed to detect and remove loose parts that could potentially occur due to component degradation as a result of the EPU increased main steam and FW flow. Also, please discuss the potential for damage that these loose parts could have to the safety-related SSCs.

NextEra Response a) EPU Flow loadings, including those associated with fluid-elastic instability, vortex shedding or acoustic type loadings are considered to be insignificant in the analysis of the SG dryer and dryer supports and other PBNP SG internals. There are no existing conditions identified in the piping systems connected to the SG that are potential sources for flow-induced acoustic resonances or system vibration that would adversely impact SG internals at EPU. Further, there is no history of vibration problems in these lines at PBNP. Many units with similar SG upper internal configurations have been visually inspected periodically in this region of the SGs and found not to have any indication of FIV degradation of the steam dryers or related supports. Furthermore, in-service experience has revealed no such phenomenon related to domestic PWR NSSSs.

As an additional consideration for EPU, the guidance provided in Regulatory Guide 1.20 (RG 1.20) (Reference 8) as it relates to PWR SGs has been followed. By taking into account industry operating experience, comparative evaluations and analysis have been completed to develop the overall conclusion that there are no predicted vibrational issues identified for the SG steam dryer assemblies and supports at EPU conditions.

LAR 261, Attachment 5, Section 2.2.2.5.12 presents the steam dryer and dryer support evaluation summary in alignment with the RG 1.20 guidance on evaluation to flow-induced loadings on SG internals. This section indicates that the potential for FIV induced loadings have been carefully considered using the guidelines provided in Page 28 of 41

RG 1.20 and has concluded that FIV of the secondary moisture separators is not significant under EPU conditions.

In addition, the effect of increased flow at EPU conditions will be monitored through existing plant loose part monitoring system procedures and in-service inspections, including periodic SG eddy current testing, foreign object search and retrieval (FOSAR) and an SG upper internals inspection during each of the two scheduled outages following EPU. The two Westinghouse SG models operating at PBNP Units 1 and 2 do not use steam flow reflectors by design, and as a result, steam flow reflector FIV is not a plausible condition.

b) A search of the Institute of Nuclear Power Operations (INPO) database of operating experience (OE) reveals that operating BWR plants have reported FIV-related issues in the steam dryer region and PWR SGs lack similar experiences. Flow characteristics through a BWR steam dome are significantly different from those of a typical PWR SG, such as those operating at PBNP Units 1 and 2. In a BWR vessel, localized regions near the steam outlet nozzles may be continually exposed to steam flows in excess of 100 ft/s largely due to flow redirection. Steam flows of this nature may generate a concern for FIV related degradation issues, with a potential for significant stresses in the steam dryers and support structures.

The steam velocities and densities through the dryer region of the PBNP Units Iand 2 SGs show relatively low FIV potential, with a maximum of approximately 5.4 ft/s and I.7lbm/ft3,respectively, under the EPU conditions. Also, clearances between the dryer and SG steam exit nozzle are in excess of 35 inches with no major components near the steam exit and a direct steam flow path existing to the SG steam outlet nozzle. These low steam velocities and densities combined with considerable dryer clearances indicate a low potential for FIV concerns and cyclic acoustic-type pressure loads occurring at the SG dryers in the PBNP Units Iand 2 SGs. Additionally, there has been no potential source identified for flow induced acoustic resonances or system vibration that would adversely impact RCS components such as SG internals. Therefore, acoustic resonance type loadings are considered to be insignificant in the analysis of the SG dryer and dryer supports and other SG internals.

Although there is no evidence of acoustical pressure load generation in the PBNP SGs and PWRs in general, analysis has also been performed to address the effects of BWR type acoustical loadings on the PBNP SG dryers for the EPU. This analysis assumed that acoustical energy of the same general magnitude seen in the BWR industry experiences is present at the SG steam outlet nozzle. A natural frequency, mode shape and corresponding stress analysis has been performed for the steam dryers of the PBNP Unit 1 and 2 SGs. The results of analysis concluded that the range of natural frequencies for the limiting dryer bank component is approximately 65 Hz to 250 Hz for the first twenty mode shapes. Upon determination of the structure natural frequencies and resulting mode shapes, classical deformation and stress analysis equations have been applied to calculate the maximum displacements and resulting stresses at the point of maximum postulated steam dryer structure deflection. The static and cyclical stresses resulting from the potential vibration are found to be below the ASME Code allowable and fatigue strength endurance limit of the dryer material. Therefore, should acoustical loadings of the magnitude observed in BWR industry experiences actually develop, the PBNP Unit Iand 2 SG steam dryer and support structures are found to not be Page 29 of 41

susceptible to vibrational fatigue failure and loose part generation as a result of EPU operating conditions.

Industry experience of PWRs at roughly 28 domestic plants operating 92 SGs with the same or similar types of dryer and support structures as those in service at PBNP Units 1 and 2 have no reported operational issues or failures related to FIV. This strong performance database of operating plant history is aligned with the RG 1.20 evaluation conclusions provided in LAR 261, Attachment 5, Section 2.2.2.5 and the Westinghouse determination that acoustic type FIV loadings in the SG steam dryer region is not a concern within the operational bounds of the EPU at PBNP Units 1 and 2.

c) The PBNP Loose Parts Monitoring System is an array of acoustic monitors whose primary function is protection of the steam generator tubesheet and the fuel against contact with debris. System sensor locations include the bottom of the reactor vessel (2), on the steam generator tubesheet, on the primary side of the SG tubesheet, and on the secondary side of the SG tube sheet. The sensor outputs are monitored automatically, and an alarm is initiated if the sound energy level exceeds a preset threshold. An alarm prompts further investigation and evaluation of the potential risk to the fuel cladding or primary system pressure boundary.

Loose Parts Originating in the Feedwater Svstem Loose parts originating in the feedwater system downstream of the No. 5 feedwater heater may pass into the SGs, and if so, could be detected by the loose parts monitoring system and actions to assess the condition would be initiated.

Continuous monitoring of SG integrity is provided by steam jet air ejector, blowdown, and steam line activity monitors, and periodically by primary-to-secondary leak rate calculations. Debris detected directly or indirectly in the SG secondary side would be evaluated, and appropriate corrective action to safeguard the continued integrity of the SGs taken via the corrective action process.

Flow generated loose parts that originate upstream of the No. 5 feedwater heaters, unless smaller than the diameter of the No. 5 feedwater heater tubes, would be caught and retained on the tube sheet of the heaters.

Practical operating experience suggests that large debris in the heaters is readily detected by audible indications because the debris continually circulates and impacts the heat exchanger end-bell and tube sheet. Such indications would prompt an assessment of the situation via the corrective action process.

Loose Parts Originating in the Steam Generators or Main Steam System Similarly, transportable debris released from the steam system would either travel to the strainers at the inlet of the turbine control valves, or lodge in system components or dead-legs. If passed to the strainers, they would have no adverse effects on safety equipment and would remain there until detected and retrieved during routine outage maintenance.

It is possible that small debris released in the steam drum might drop down into the steam generator tube bundle. Such debris would be monitored for and detected by the Page 30 of 41

loose parts monitoring system in the same way as debris arriving in the tube bundle from the feedwater system.

Particularly large transportable debris released into the steam system would be apparent by a decrease in steam flow in the partially obstructed line. This would be evidenced by one or more of the following indications:

0 A change in turbine governor valve position(s),

a A change in the affected SG pressure and flow as compared to the other steam generator, and/or a A change in plant efficiency.

Such indications would prompt further investigation and assessment via the corrective action process.

High density debris originating in the steam drum between the primary separators and the secondary separators would not be transportable due to the relatively low steam velocity between the separator stages. If sufficiently light with a larger drag cross section, debris might be transportable downstream of the secondary separators where flow velocity is higher. However, larger transportable debris would be caught on the flow limiting inserts installed in the SG outlet neck. This would be indicated by a change in SG pressure and flow as compared to the other SG as described in the above paragraph.

If debris were small enough to pass through the flow limiters, it would also be small enough to pass all the way downstream to the turbine control valve inlet strainers. It is not credible that such smaller debris would lodge in the steam flow venturies, though such obstructions would be immediately apparent by an abnormal steam flow indication.

Indications of abnormal operation would prompt further investigation, assessment, and corrective action as appropriate.

The potential effects of released debris are limited to obstruction of safety related valves that interfere with their design function(s). In the case of the feedwater system, the valves of concern are the feedwater regulation valves (FRVs) due to their relatively small flow passages. These valves have caged plugs with relatively small flow passages, and are backed up by the redundant feedwater isolation valves that have a larger flow cross section than an FRV, and therefore would not be affected by debris that passes through an FRV. As such, the safety effect of debris that might interfere with the function of the FRVs is judged to be minimal.

The safety-related valves in the main steam system with active safety functions are the main steam safety valves (MSSVs), the atmospheric dump valves, the main steam isolation valves (MSIVs), the main steam non-return check valves, and the turbine stop valves.

The MSSVs and atmospheric dump valves are located on top of a stagnant, large diameter relief valve header that has no steam flow under normal operating conditions.

Therefore, it is not considered credible for debris released in the MS system to reach these valves during normal operation. Conversely, when needed to function in response to abnormal transients, the system steam flows are either substantially lower (less than CLTP full flow) or of very brief duration until the transient is terminated. Consequently, Page 31 of 41

the likelihood of transport of loose parts originating in the main steam system to these valves is considered very low.

Debris transported into the large diameter relief valve header would most likely fall to the bottom of the header and remain there. However, if it were sufficiently small to be carried by steam flow to the top surface of the header, debris should also be sufficiently small to only affect one of the valves supplied from the header (either the atmospheric dump, or one of the three MSSVs) supplied by the header. In any case, each steam generator is served by separate relief headers providing another degree of redundant protection against the effects of any single piece of debris.

The MSIVs, main steam non-return check valves, and turbine stop valves have large, unobstructed flow areas that are substantially larger than the throat of the steam generator flow limiting devices. Therefore, postulated debris being carried with main steam flow is not expected to lodge or remain in these valves and interfere with their function. Should such an unlikely event occur, the valves are redundant and serve to back up one another so that no single piece of debris could defeat the safety isolation function of the valves.

EMCB RAI 21 EPU LR Section 2.2.2.5 states that: "With the increased flow conditions within the steam drum expected from EPU conditions, material loss in the carbon steel steam drum components may be initiated or accelerated. Periodic steam generator inspections will detect degradation that may occur." Please provide the frequency of the scheduled inspections for the steam drum components and the supporting basis that drives these inspections.

NextEra Response An engineering assessment of the potential impact of the planned EPU operating conditions on the steam drum components was completed. During the assessment, a review of steam generator industry history and the impact of erosion-corrosion degradation at uprated conditions was conducted. The engineering assessment concluded that material loss in the carbon steel steam drum components due to erosion-corrosion may be initiated or accelerated due to operation of the steam generator at EPU conditions.

An initial sample inspection of PBNP steam generators from each unit during refueling outages U1R30 (Spring 2007) and U2R29 (Spring 2008) was conducted, and the results of the inspections showed that there was no significant erosion-corrosion damage or material degradation of the steam generator upper internals.

An additional evaluation of the steam drum upper internal components was completed for potential material loss following EPU. The evaluation utilized conservatively high wear rates compared to industry inspection findings on similar generators with similar flow velocities for the steam drum components. The most limiting components were evaluated for material loss for two operating cycles at EPU conditions. The resulting conservatively high material loss would not affect the components structural integrity. Utilizing a conservative inspection frequency of one operating cycle for the initial inspection following uprate will ensure the structural integrity of the Steam Drum components is maintained.

Page 32 of 41

The recommendations from the assessment and evaluation noted above included that after every plant operating cycle for both units, inspections of the steam drum components be performed to determine if the increased flow rates have initiated or accelerated the erosion-corrosion process. The frequency of this inspection interval may be alteredlextended after initial inspections are completed. Note that LAR 261, Commitment #I 7 stated, "A formal monitoring program for the steam generator steam drum components will be implemented prior to operation of each unit at EPU conditions. The monitoring will be conducted over two operating cycles to confirm components are performing adequately at EPU operating conditions. See LR Section 2.2.2.5, Steam Generators and Supports."

Consistent with the commitment noted above, inspections of the steam generator upper internals will be performed after installation of the modifications associated with the moisture separator assemblies. These inspections will provide a baseline assessment of the steam generator upper internals prior to operating at EPU conditions. Inspections of the upper internals will be performed during the first two refueling outages following the EPU uprate on each unit to determine if the increased flow rates have initiated or accelerated the erosion-corrosion process. The frequency of the inspections may be adjusted following these inspections. In addition, aging management reviews will continue to be performed on the steam generator feedwater rings, J-nozzles, and feedwater ring supports using the Water Chemistry Control Program and the Steam Generator Integrity Program.

EMCB RAI 22 EPU LR Section 2.2.2.5, with respect to the structural adequacy of the steam drum components states that: "flow-induced vibration of these components during uprated conditions is considered to be enveloped by the original design basis evaluations due to the limited change in flow parameters within the steam drum under EPU conditions. " Please describe the original design basis evaluations and provide references of these evaluations which have been performed for the steam drum components that include flow-induced loads. Also, please describe how the flow parameters in the original design basis evaluations envelop the EPU increased flow conditions.

NextEra Response Detailed stress analyses of the steam drum components were performed for the significant loadings that could potentially occur on steam drum components. Assessments of the flow induced vibration (FIV) potentjal of the steam drum components were made during the design of the PBNP steam generators, and it was recognizing that cyclic FIV loadings were not significant for the reasons discussed below. As a result, a detailed FIV analysis was not required for either the original design structural analysis or the structural analysis that addressed the EPU.

It has been Westinghouse's experience that fluid loadings of steam drum components has not resulted in any degradation or repair of these components that could be attributed to FIV. Other degradation mechanisms have been observed in this region and have been primarily limited to flow accelerated corrosion (FAC). Industry experience for PWR steam generators indicate that unacceptable FIV is not occurring in this region of the steam generator.

FIV is a function of various parameters including fluid density (p) and fluid velocity (V). In the steam drum region, the fluid is primarily composed of steam which has lower values of density versus the density for liquid water. As a result, the dynamic pressure (pv2) in this region is also low and would result in only small FIV loadings. The individual modular primary moisture Page 33 of 41

separators in the PBNP steam generators are physically smaller than moisture separators in other model steam generators. The PBNP moisture separators are well supported and as a result, the structures would be expected to have high natural frequencies. FIV potential is also a function of natural frequency, and components having lower natural frequencies tend to have a larger potential for an unacceptable FIV response. Since the PBNP separators would tend to have larger natural frequencies than other designs, the potential for an unacceptable FIV response would be even further reduced.

Design basis analysis of the PBNP Unit Iand Unit 2 steam generator steam drum components considered load conditions that could potentially result in a significant stress or displacement of any structure in the steam drum. The analysis focused on conditions that produced primary stresses in the components. For Unit I,the potential effects of cyclic loading were considered and were addressed in a component specific fatigue analysis. In this region of the steam generator, the limiting component with respect to cycle loadings was determined to be the riser barrel/lower deck plate fillet weld. The analysis performed for this weld determined that the fatigue usage was acceptable for the applied cyclic loadings. FIV could potentially result in fatigue usage accumulation in some steam generator components, however, these loads were not considered to be significant in this region due to past Westinghouse and industry experience, the low magnitude of the loads and the general robustness of the associated structures. In addition, the PBNP Unit 2 stress report clearly states, "At the elevation of the upper internals, thermal and pressure loads due to steam temperature changes during operating transients are negligible. Therefore, it is concluded that fatigue usage in this area is not a concern and only primary stresses will be evaluated." Recognizing that cyclic FIV loadings are not significant for the reasons discussed above, a detailed FIV analysis was not required for either the original design basis structural analysis or the structural analysis that addressed the EPU.

EMCB RAI 23 Please confirm that EPU LR Section 2.2.2. I indicates that for the NSSS piping and supports the current analyses on record contain load and transient input data that bound those of the EPU conditions.

NextEra Response NSSS Piping and Surge Line Thermal Stratification See the NextEra response provided for EMCB RAI 2.

NSSS Supports (SG and RCP)

See the NextEra response provided for EMCB RAI 2.

Page 34 of 41

EMCB RAI 25 a) For EPU LR Section 2.2, "Mechanical and Civil Engineering,"please verify that, where a different code or code edition than the original code of construction has been utilized, a documented code reconciliation exists that allows such use and that the allowable values from the original code of construction have been utilized with the reconciled (later) year code. As an example, LR Section 2.2.2.7 concludes that: "flhe] pressurizer components meet the stress intensity/fatigue requirements of the ASME Code Section 111, 1965 Edition with Addenda through Summer 1966 for all proposed EPU operation." However, the same section indicates that the stress and fatigue evaluations have been performed in accordance with a later ASME Code edition. The code edition year is not mentioned.

b) For sub-sections in LR Section 2.2 where the acceptance criteria and evaluation does not mention either the code, code section and/or code year, please provide that information.

For instance, in the case of the reactor coolant pumps and supports, Section 2.2.2.6 indicates that the acceptance criteria at EPU conditions for stress limits and fatigue usage requirements are in accordance with the American Society of Mechanical Engineers (ASME)

Code, Section 111. However, it does not mention the code year.

NextEra Response NSSS (RCS) Piping and Surge Line Thermal Stratification a) See the NextEra response to EMCB RAI I.

b) See the NextEra response to EMCB RAI 1.

RCS Branch Pipinq a) See the NextEra responses to EMCB RAI 1 and EMCB RAI 3.

b) See the NextEra responses to EMCB RAI 1 and EMCB RAI 3.

Reactor Vessel a) For the EPU, one set of reactor vessel component evaluations was performed and shown to be applicable to Unit Iand Unit 2. However, the results were evaluated against each unit's code of construction according to the following:

For Unit I, the reactor vessel component results (except the RRVCH and its components) were evaluated to the original code of construction, the 1965 Edition of the ASME Code, Section Ill.

For Unit 2, the reactor vessel component results (except the RRVCH and its components) were evaluated to the original code of construction, the 1968 Edition through Winter 1968 Addenda of the ASME Code, Section Ill.

For both Unit 1 and Unit 2, the RRVCH and its components were evaluated to the 1998 Edition through 2000 Addenda of the ASME Code, Section Ill. Documented code reconciliations to the Unit Iand Unit 2 codes of construction were performed in the Unit Iand Unit 2 RRVCH design reports.

Page 35 of 41

b) The Acceptance Criteria in LAR 261, Attachment 5, Section 2.2.2.3 lists the applicable codes of construction for the Unit 1 and Unit 2 reactor vessels, and they are re-iterated in the above response to ltem a).

CRDMs a) The CRDM AOR for EPU conditions are completed in accordance with the ASME Code, Section 111, 1998 Edition with Addenda through 2000. The AOR includes reconciliation of the ASME Code requirements for the ASME Code edition used in the AOR to those used for the original construction Code, ASME Section 111 1965 Edition, through Summer 1966 Addenda for Unit Iand Summer 1967 Addenda for Unit 2.

b) Please see the response provided for ltem a).

Steam Generator a) The Code year and Addenda used in the qualification of the Unit IModel 44F and Unit 2 Model Delta-47 replacement steam generators for the EPU analyses is unchanged from the original RSG. Therefore, no Code reconciliation was required to be performed. The RSG design basis for steam generators is as noted in LAR 261, Attachment 5, Section 2.2.2.5.1.

Where the original construction code, ASME Code, Section 111 1965 Edition, through Summer 1966 Addenda, did not contain the specific material used for steam generator hardware items, a later ASME Code was used for the material properties, and the Code year is provided in LAR 261, Attachment 5, Section 2.2.2.5.9. The allowable values were based on original construction ASME Code year of the 1965 Edition, through Summer 1966.

b) The design basis for the installed steam generators is provided in LAR 261, Attachment 5, Section 2.2.2.5.1. The applicable ASME Code year for each steam generator hardware item is provided in LAR 261, Attachment 5, Section 2.2.2.5.9.

RCPs a) This question is not applicable to the RCPs. No code reconciliation was performed because the PBNP RCPs were not certified to an original code year of construction.

b) LAR 261, Attachment 5, Section 2.2.2.6 does not indicate the code year for the acceptance criteria for the stress limits and fatigue usage requirements for the reactor coolant pumps at EPU conditions because the Model 93 RCPs were not required to be N-stamped to a particular code year. The age of the RCPs predates specific code requirements for pumps. Rather than being certified to a particular code year and addenda, the RCPs were analyzed to the intent of the ASME Code available at that time.

Stress analyses for the PBNP RCPs consists of a series of generic Model 93 stress reports for the casing, main flange, and main flange bolted joint, which utilized design criteria from the ASME Code, Section 111, 1965 Edition.

Page 36 of 41

Pressurizer a) The ASME Code, Section 111, 1986 Edition, is discussed in LAR 261, Attachment 5, Section 2.2.2.7.1. NRC Bulletin 88-11 (Reference 3) required a later edition of the ASME Code for pressurizer surge nozzle high cycle fatigue calculations. No later Code edition was mentioned in LAR 261, Attachment 5, Section 2.2.2.7.

b) ASME Code editions used in the evaluations were cited in LAR 261, Attachment 5, Section 2.2.2.7. The pressurizer evaluation used ASME Code, Section 111, 1965 Edition with Addenda through Summer 1966.

RV lnternals a) PBNP Units 1 and 2 were built before the implementation of Subsection NG of the ASME Code; therefore, no specific ASME Code year is applicable for Section 2.2.3 of LAR 261, Attachment 5. The ASME Boiler and Pressure Vessel Code, Section Ill, Division I,1998 Edition with 2000 Addenda, "Code Section NG-3222 and NG-3228.3,"

was chosen to meet the intent of the ASME Code. The original analyses for the PBNP reactor internals adopted the allowable stress criteria of Article 4 of the ASME Boiler and Pressure Vessel Code Section Ill, Section I,1968 Edition with Addenda through Winter 1968.

Comparison of the allowable stress and fatigue criteria presented in Subsection NG of the 1998 Edition of the ASME Code Section Ill, Division I, including 2000 Addenda with Article 4 of the 1968 Edition with Addenda through Winter 1968, demonstrates that the criteria used in this analysis are reconciled with the requirements and the allowable stress limits. Also, the fatigue usage criteria in the 1968 Edition with Addenda through Winter 1968 are identical to those in the 1998 Edition including 2000 Addenda of the ASME Code.

b) See the NextEra response provided above for Item a).

RCS Supports (Except Reactor Vessel Supports) a) See the NextEra response provided for EMCB RAI I.

b) See the NextEra response provided for EMCB RAI 1 RPV Supports a) For the RPV supports, the original design basis design requirements were used for the EPU project. The design basis requirements for the RPV supports design are contained in Table A.5-3 of the PBNP FSAR. This table provides the Normal, Upset and Faulted allowable stress limits for a couple of the materials used in the RPV support construction. Although not specifically mentioned, these stress limits are identical to the "working stress" requirements of the AlSC "Specification for the Design, Fabrication and Erection of Structural Steel for Buildings," dated February 12, 1969. For the Faulted loading combination the allowable stress limits are 90% of yield for direct tension stress and tension stress due to bending and 54% of tensile yield for shear stresses.

Page 37 of 41

Compressive stresses are not specifically addressed in the PBNP Table A.5-3.

However, for EPU, the AlSC Part 1 allowable compressive stress was used for the Normal and Upset loading conditions and 90% of the AlSC critical buckling stress was used for the Faulted loading condition.

b) See the NextEra response provided above for Item a).

EMCB RAI 27 For LR Table 2.2.3-3, please provide an explanation which demonstrates why, at EPU conditions, the primary plus secondary stress intensity range of some vessel internal components has been greatly reduced. Also, please explain, quantitatively, how the baffle-former bolts have been evaluated and qualified since the table does not contain a stress and fatigue usage summary for these components.

NextEra Response The components listed in Table 2.2.3-3 that were evaluated and shown to have reduced component primary plus secondary stress intensity range due to EPU conditions include:

- Upper Core Plate Alignment Pins

- Lower Support Columns

- Core Barrel Assembly Outlet Nozzle

- Lower Core Support Plate The current analysis of record is based on Westinghouse two-loop generic plant assessments and envelops most of the Westinghouse two-loop plants. As part of the PBNP EPU analyses, some of this conservatism in the generic analysis was removed using plant-specific inputs to obtain additional margin and demonstrate acceptability of the PBNP reactor internal components structural integrity. In general, stresses due to mechanical loads, such as OBE and vibrations, are not impacted for EPU conditions. The thermal analysis contained other limiting thermal transients, such as excessive feedwater and reactor coolant system (RCS) depressurization, that were used in generic two-loop design report and are not applicable to PBNP. These conservatisms were removed, and new thermal stresses were calculated. In addition, there are some geometrical differences in generic two-loop design compared to PBNP, which is the main reason for the reduction in primary plus secondary stress intensity range for some vessel internal components.

The test program for which the baffle former bolts were evaluated was performed in such a manner that the primary plus secondary stress check required by Subsection NG of the ASME Code is satisfied. In lieu of the cyclic stress requirements of Article NG-3222.4(e) of Subsection NG of the ASME Code, the test program was performed within the requirements of Article 11-1500 of ASME Code, Section Ill, Division I,Appendix II. This is permitted per Article NG-3222.4(a) of Section Ill, Subsection NG of the ASME Code. The basis for baffle-former bolt qualification is based on these test results rather than stress and fatigue qualification.

Page 38 of 41

The methodology used for baffle bolt fatigue is summarized as follows:

(I) The baffle plate temperature difference is generated using Westinghouse computer code TEMFOR.

(2) From the temperature difference, the baffle bolt displacements due to normal and upset conditions are calculated.

(3) The allowable cycles are determined based on displacement and cyclic data methodology developed for Westinghouse design plants for both normal and upset temperature differences.

(4) The cumulative baffle bolt fatigue usage is determined for all normal and upset transients except the loading and unloading normal transient.

(5) The allowable number of normal loading and unloading transient cycles is determined based on a maximum allowable bolt fatigue usage of 0.9999.

Based on the temperature difference and the average bolt displacement calculations, a bolt displacement of 0.016275 inch was obtained, and the limiting bolt location was above the pin displacement of Plate 3 at a temperature difference of 48.4"F. From this data, a limiting number of 8,240 upset transients were obtained for a cumulative fatigue usage of 0.9999.

The normal and upset transients calculated in this analysis gave a baffle bolt fatigue usage of 0.5825. The cumulative baffle bolt fatigue usage factor was set at a maximum of 0.9999. The remaining baffle bolt fatigue usage for loading and unloading transients is the difference of 0.9999 and 0.5825. NextEra determined that the maximum allowable transients for the loading and unloading transient cycles was 3,545 cycles, corresponding to a fatigue usage factor of 0.9999.

The results of this analysis confirmed that the baffle bolts remain acceptable as long as the number of loading and unloading transient cycles is limited to 3,545. This limitation is contained in LAR 261, Attachment 5, Table 2.2.6-1, Note 1.

EMCB RAI 28 Table 2.2.3-2 of the LR for the guide tubes provides a value of 266.0~10" in/in strain from measured strain data as an acceptable (or allowable) mean strain and 65.0xl0-~in/n for alternating dynamic strain. Please explain where the data that established these values originated from and why these values are applicable to the PBNP guide tubes.

NextEra Response The acceptable guide tube mean (static) and dynamic strain value of 266.0~10-~ inlin and 65.0x10-~inlin, respectively, were obtained using the stress and the fatigue allowable stress limits of the ASME Code Section Ill, Division 1, 1998 Edition with 2000 Addenda by converting it to the corresponding strain values.

Evaluations were performed to predict PBNP responses by using the in-plant prototype measurement from R.E. Ginna (Ginna). The scaling of structural response due to flow-induced vibration (FIV) was performed according to analytical and experimental formulations relating to such parameters as flow rates and temperature changes, which may affect the amplitude of the response, and consequently the maximum stress (strain) range. The scaling law is an approximation of the FIV forces independent of what the fluid dynamic source may be (i.e., laminar, flow-induced, cross-flow, turbulent, vortex shedding, steady-state, transient). The Page 39 of 41

scaling law was used to obtain corresponding guide tube responses due to FIV for PBNP and are provided in LAR 261, Attachment 5, Table 2.2.3-2. Since the guide tube design of PBNP Units 1 and 2 are identical to the Ginna guide tubes, the measured mean and dynamic strains obtained from Ginna are applicable to PBNP.

EMCB RAI 29 In Tables 2.2.3-1 and 2.2.3-2 of the LR, the current analyses of record (AOR) values originated from Ginna. Please explain where the "After EPU" column values originate from. Also, please provide an explanation of why, from all of the vessel internals components, only the guide tubes and the thermal shield top suppon' bolts and flexures have been evaluated for flow induced vibration.

NextEra Response The "After EPU" values for PBNP were calculated as part of the EPU project. These evaluations involved use of fully instrumented test data from a two-loop prototype plant (Ginna).

This data is representative of all two-loop plants, and from this data, the response of the PBNP reactor internals were scaled for the EPU operating conditions. The scaling of structural response due to FIV was performed according to analytical and experimental formulations relating to such parameters as flow rates and temperature changes, which may affect the amplitude of the response, and consequently, the maximum stress (strain) range. The scaling law is an approximation of the FIV forces independent of what the fluid dynamic source may be (i.e., laminar, flow-induced, cross-flow, turbulent, vortex shedding, steady-state, or transient).

Based on the analysis performed for PBNP, the reactor internals response due to FIV is small and well within the allowable based on the high-cycle fatigue endurance limit for the material.

Specific FIV evaluations are performed only for the guide tubes and the thermal shield top support bolts and flexures. The guide tubes are selected to ensure control rod insertion.

Therefore, it is necessary to show that the response due to FIV remains within acceptable limits.

The thermal shield top support block bolts and flexures are selected based on the thermal shield bolt failure in one of the three-loop plants that was observed in the past.

Strain gauge measurements on other key upper and lower internals, such as, lower support plate, lower support columns, lower radial support keys, upper core plate and upper core plate alignment pins were not taken during in-plant testing of Ginna. However, it has been shown in similar circumstances that the maximum stress due to FIV at the lower support columns and lower support plate for a Westinghouse three-loop plant were only 65 psi and 225 psi, respectively. Consequently, the stresses at these components due to FIV for PBNP would also be negligible for the EPU conditions.

Based on the above discussion, the guide tubes and the thermal shield top support bolts and flexures evaluated for PBNP Units 1 and 2 are reasonable. The evaluation results demonstrate that these components remain functional and structural integrity is maintained at EPU conditions in regards to FIV response of the reactor internal components.

Page 40 of 41

References NRC electronic mail to NextEra Energy Point Beach, LLC, dated August 26, 2010, Point Beach Nuclear Plant, Units 1 and 2 - Requests for Additional Additional Associated with Extended Power Uprate (TAC Nos. ME1044 and ME1045) (MLI 02440095)

FPL Energy Point Beach, LLC letter to NRC, dated April 7, 2009, License Amendment Request 261, Extended Power Uprate (ML091250564)

U.S. Nuclear Regulatory Commission, "Pressurizer Surge Line Thermal Stratification,"

NRC Bulletin No. 88-11, dated December 20, 1988 (ML031220290)

NextEra Energy Point Beach, LLC letter to NRC, dated October 9, 2009, License Amendment Request 261, Extended Power Uprate, Response to Acceptance Review Questions (ML092860098)

NextEra Energy Point Beach, LLC letter to NRC, dated January 8, 2010, License Amendment Request 261, Extended Power Uprate, Auxiliary Feedwater System Pipe Stress Analysis Information (MLI 00110037)

NextEra Energy Point Beach, LLC letter to NRC, dated February 11, 2010, License Amendment Request 261, Extended Power Uprate, Withdrawal of Expedited Review Request (MLI 00470786)

U.S. Nuclear Regulatory Commission, "Rapidly Propagating Fatigue Cracks in Steam Generator Tubes," NRC Bulletin No. 88-02, dated February 5, 1988 (ML031220043)

U.S. Nuclear Regulatory Commission, "Comprehensive Vibration Assessment Program for Reactor lnternals during Preoperational and Initial Startup Testing,"

Regulatory Guide 1.20, Revision 3, dated March 2007 (ML070260376)

Page 41 of 41

ENCLOSURE 4 ATTACHMENT I NEXTERA ENERGY POINT BEACH, LLC POINT BEACH NUCLEAR PLANT, UNITS I AND 2 LICENSE AMENDMENT REQUEST 261 EXTENDED POWER UPRATE PIPE STRESS

SUMMARY

AT EPU CONDITIONS 14 pages follow

Piping Analysis Loading Existing EPU Allowable Stress Description Condition Stress Stress Stress Interaction (psi) (psi) (psi) Ratio (Note 2) (Note 4) (Note 1 & 3)

Unit 1, Main Steam Inside Equation 8 11,112 11,112 17,500 0.64 Containment Loop A (Sustained)

Steam Generator I-HX-1A Equation 9B 17,849 19,107 21,000 0.91 to Penetration P-I (Occasional)

Equation 9C 19,107 21,405 31,500 0.68 (Occasional)

Unit IMain Steam Inside Equation 8 10,786 10,786 17,500 0.62 Containment Loop B (Sustained)

Steam Generator 1-HX-I B Equation 9~ 12,371 12,676 21,000 0.60 to Penetration P-2 (Occasional)

Equation 9C 13,506 13,546 31,500 0.43 (Occasional)

Unit 1 Main Steam Equation 8 12,130 10,552 17,500 0.60 Outside Containment (Sustained)

Equation 9B 19,107 20,930 21,000 0.997 (Occasional)

Equation 9C 23,608 25,081 31,500 0.80 (Occasional)

Unit 2 Main Steam Inside Equation 8 10,800 11,057 17,500 0.63 Containment Loop A (Sustained)

Steam Generator 2-HX-I/\,

to Penetration P-I Equation 9B 19,297 20,706 21,000 0.99 (Occasional)

Equation 9C 29,046 29,984 31,500 0.95 (Occasional)

Unit 2 Main Steam Inside Equation 8 11,100 10,885 17,500 0.62 Containment-Loop B (Sustained)

Steam Generator 2-HX-1b Equation 9~ 12,517 12,320 21,000 0.59 to Penetration P-2 (Occasional)

Equation 9C 14,186 13,929 31,500 0.44 (Occasional)

Page 1 of 14

Piping Analysis Loading Existing EPU Allowable Stress Description Condition Stress Stress Stress Interaction (psi) (psi) (psi) Ratio (Note 2) (Note 4) (Note 1 & 3)

Unit 2 Main Steam Equation 8 14,849 14,698 15,000 0.98 Outside Containment (Sustained)

Equation 9B 19,107 20,827 21,000 0.99 (Occasional)

Equation 9C 26,241 27,206 31,500 0.86 (Occasional)

Unit IFeedwater Inside Equation 8 7,450 9,311 15,000 0.62 Containment Loop A (Sustained)

Equation 9B 14,780 15,119 18,000 0.84 (Occasional)

Equation 9C 20,643 20,812 27,000 0.77 (Occasional)

Equation II 17,692 18,277 37,500 0.49 (Sustained +

Thermal)

Unit 1 Feedwater Inside Equation 8 NIA 9,257 15,000 0.62 Containment Loop B (Sustained)

Equation 9B 11,I 63 11,293 18,000 0.63 (Occasional)

Equation 9C 12,630 12,706 27,000 0.47 (Occasional)

Equation 11 22,220 23,009 37,500 0.61 (Sustained +

Thermal)

Unit 1 Feedwater Outside Equation 5,975 13,761 15,000 0.92 Containment (Sustained)

Equation 9B 17,098 17,970 18,000 0.998 (Occasional)

Equation 9C 26,556 26,114 27,000 0.97 (Occasional)

Equation 11 17,858 19,254 37,500 0.51 (Sustained +

Thermal)

Page 2 of 14

Piping Analysis Loading Existing EPU Allowable Stress Description Condition Stress Stress Stress Interaction (psi) (psi) (psi) Ratio (Note 2) (Note 4) (Note 1 8 3)

Unit 2 Feedwater Inside Equation 8 7,920 9,660 15,000 0.64 Containment Loop A (Sustained)

Equation 9B 14,027 14,588 18,000 0.81 (Occasional)

Equation 9C 16,310 16,691 27,000 0.62 (Occasional)

Equation 11 17,351 17,708 37,500 0.47 (Sustained +

Thermal)

Unit 2 Feedwater Inside Equation 8 8,070 8,780 15,000 0.59 Containment Loop B (Sustained)

Equation 9B 12,324 12,625 18,000 0.70 (Occasional)

Equation 9C 15,960 16,133 27,000 0.60 (Occasional)

Equation 11 14,508 14,785 37,500 0.39 (Sustained +

Thermal)

Unit 2 Feedwater Outside Equation 8 6,920 14,008 15,000 0.93 Containment (Sustained)

Equation 96 17,528 17,561 18,000 0.98 (Occasional)

Equation 9C 26,444 25,306 27,000 0.94 (Occasional)

Equation II 20,960 23,675 37,500 0.63 (Sustained +

Thermal)

Unit ICondensate Inlet NIA 5,121 15,000 0.34 and Outlet to FWH-20A & (Sustained) 206 Equation 10 NIA 4,335 22,500 0.19 (Thermal)

Page 3 of 14

Piping Analysis Loading Existing EPU Allowable Stress Description Condition Stress Stress Stress Interaction (psi) (psi) (psi) Ratio (Note 2) (Note 4) (Note 1 & 3)

Unit IExtraction Steam Equation 8 N/A 3,335 15,130 0.22 lnlet to FWH-20A & 20B (Sustained)

Equation 11 32,700 34,546 42,350 0.82 (Sustained +

Thermal)

Unit 1 Heater Drains Equation 8 NIA 4,286 15,000 0.29 Outlet from FWH-20A & (Sustained) 20B to HD Tank Equation 10 N/A 6,827 22,500 0.30 (Thermal)

Unit IHeater Drains Equation 8 N/A 6,399 15,000 0.43 Outlet from FWH-21A to (Sustained)

FWH-20A Equation 10 7,497 8,852 22,500 0.39 (Thermal)

Unit 1 FWH-20A & 208 Equation 8 NIA 2,390 15,000 0.16 Vent Piping from Drain (Sustained)

Tank Equation 10 NlA 4,718 22,500 0.21 (Thermal)

Unit IExtraction Steam Equation 8 NIA 7,423 14,690 0.51 Inlet to FWH-21A & 21B (Sustained)

Equation 10 7,842 10,702 27,110 0.39 (Thermal)

Unit 1 FWH-20A & B and Equation 8 NIA 2,161 15,000 0.14 FWH-2lA&B RV (Sustained)

Discharge Equation 10 15,900 16,751 22,500 0.74 (Thermal)

Unit 1 Heater Drains Equation 8 N/A 14,362 15,000 0.96 Outlet from FWH-21B to (Sustained)

FWH-20B Equation 10 NlA 9,296 22,500 0.41 (Thermal)

Page 4 of 14

Piping Analysis Loading Existing EPU Allowable Stress Description Condition Stress Stress Stress Interaction (psi) (psi) (psi) Ratio (Note 2) (Note 4) (Note 1 & 3)

Unit 1 Heater Drains Inlet Equation 8 NIA 11,165 15,000 0.74 FWH-21A & 21B (Thermal)

Equation 10 17,682 17,346 22,500 0.77 (Thermal)

Unit 1 MSR to Heater Equation 10 11,799 12,256 22,500 0.54 Drain Tank (Thermal)

Unit 1 Loop A Main Equation 10 7,990 10,387 22,500 0.46 Steam to lnlet of AFW (Thermal)

Pump Turbine Unit ILoop B Main Equation 10 6,600 8,580 22,500 0.38 Steam to lnlet of AFW (Thermal)

Pump Turbine Unit 2 Loop A Main Equation 10 6,540 8,502 22,500 0.38 Steam to lnlet of AFW (Thermal)

Pump Turbine Unit 2 Loop B Main Equation 10 6,510 8,463 22,500 0.38 Steam to lnlet of AFW (Thermal)

Pump Turbine Units 1 & 2 MS Inlet Equation 10 2,657 2,904 22,500 0.13 Piping MSR A, B, C & D (Thermal)

Extraction Steam from Equation 8 N/A 4,668 15,130 0.31 Crossunder Piping (Sustained)

(H.P. Turbine Nozzles to 27,220 0.26 Equation ,0 NIA 7,117 Preseparator)

(Thermal)

Unit 2, 4thPoint Heaters A Equation 8 NIA 3,654 15,000 0.24

& B Drain Outlet Piping (Sustained)

Equation 10 NlA 6,543 22,500 0.29 (Thermal)

Page 5 of 14

Piping Analysis Loading Existing EPU Allowable Stress Description Condition Stress Stress Stress Interaction (psi) (psi) (psi) Ratio (Note 2) (Note 4) (Note 1 & 3)

Unit 2, 5thPoint Heater B Equation 8 NIA 5,344 15,000 0.36 Drain Outlet to 4thpoint (Sustained)

Heater B N/A Equation 10 9,204 22,500 0.41 (Thermal) point Heater A Unit 2, !jth Equation 8 NIA 6,791 15,000 0.45 Drain Outlet to 4'h point (Sustained)

Heater A NlA Equation 10 8,513 22,500 0.38 (Thermal)

Unit 2, 4thand 5thPoint Equation 8 NIA 2,511 15,000 0.17 Heaters A and B Noz. N6 (Sustained) to Atmospheric Blowoff Equation 9 NIA 6,746 27,000 0.25 Tank (Occasional)

Equation II NlA 18,112 37,500 0.48 (Sustained +

Thermal)

Unit 2, I"Point Heaters Equation 8 NIA 9,915 15,000 0.66 A & B Inlet and 3" Point (Sustained)

Heaters A & B Outlet Equation 26,570 37,500 0.71 Piping.

(Sustained +

Thermal)

Unit 2, I"Point Heaters Equation 8 NIA 1,265 15,000 0.08 A & B Steam Inlet Piping, (Sustained)

(Nozzle N3A) N/A 0.07 Equation 1I 2,469 37,500 (Sustained +

Thermal)

Unit 2, IS' Point Heaters Equation 8 NIA 1,832 15,000 0.12 A & B Steam Inlet Piping, (Sustained)

(Nozzle N3B) NlA Equation 1I 4,186 37,500 0.1 1 (Sustained +

Thermal)

Page 6 of 14

Piping Analysis Loading Existing EPU Allowable Stress Description Condition Stress Stress Stress Interaction (psi) (psi) (psi) Ratio (Note 2) (Note 4) (Note I & 3)

Unit 2, lSt Point Heaters Equation 8 N/A 1,099 15,000 0.07 A & B Steam lnlet Piping, (Sustained)

(Nozzle N3C) N/A 3,598 37,500 0.10 Equation 11 (Sustained +

Thermal)

Unit 2, I"Point Heaters Equation 8 NIA 1,843 15,000 0.12 A & B Steam lnlet Piping, (Sustained)

(Nozzle N3D) N/A 6,460 37,500 0.17 Equation II (Sustained +

Thermal)

Unit 2, lSt Point Heaters Equation 8 NIA 1,676 15,000 0.11 A & B Operating Air (Sustained)

Outlet Piping (Nozzle N8) N/A 2,517 22,500 0.11 Equation (Thermal)

Unit 2, 2" Point Heaters Equation 8 N/A 4,005 15,000 0.27 A & B (FW Outlet) to 3rd (Sustained)

Point Heaters A & B (FW Equation 10 NIA 8,196 22,500 0.36 Inlet Piping) (Thermal)

Unit 2, 2ndPoint Heaters Equation 8 NIA 2,059 15,000 0.14 A & B,Extraction Steam (Sustained)

Inlet (Nozzle N23A) Equation 10 NIA 1,178 22,500 0.05 (Thermal)

Unit 2, 2ndPoint Heaters Equation 8 NIA 3,527 15,000 0.24 A & B,Extraction Steam (Sustained)

Inlet (Nozzle N23B) Equation 10 N/A 4,152 22,500 0.18 (Thermal)

Unit 2, 2ndPoint Heaters Equation 8 NIA 3,343 15,000 0.22 A & B, Operating Air (Sustained)

Outlet Piping (Nozzle Equation 10 N/A 1,380 22,500 0.06 N28) (Thermal)

Unit 2, 3rd Point Heaters Equation 8 NIA 10,546 15,000 0.7 A & B, Steam lnlet Piping (Sustained)

(Nozzle N3) Equation 10 N/A 7,693 22,500 0.34 (Thermal)

Page 7 of 14

Piping Analysis Loading Existing EPU Allowable Stress Description Condition Stress Stress Stress Interaction (psi) (psi) (psi) Ratio (Note 2) (Note 4) (Note I& 3)

Unit I, FW Pump Suction Equation 8 NIA 9,437 15,000 0.63 Piping (Sustained)

Equation 10 N/A 21,511 22,500 0.96 (Thermal)

Unit 2, lst Point Heaters Equation 8 NIA 1,053 15,000 0.07 A & B, Drain Outlet Piping (Sustained)

Equation 10 NlA 1,086 22,500 0.05 (Thermal)

Unit 2, znd Point Heaters Equation 8 NIA 1,207 15,000 0.08 A & B, Drain Outlet Piping (Sustained)

Equation 10 NlA 5,047 22,500 0.22 (Thermal)

Unit 2, 3rd Point Heaters Equation 8 NIA 7,182 15,000 0.48 A & B, Drain Outlet Piping (Sustained)

Equation 10 2,452 22,500 0.1 1 (Thermal)

Unit 2, 1 Point Heaters Equation 8 NIA 5,844 7 5,000 0.39 A & B, Emergency Drain (Sustained)

Cooler Bypass Piping Equation 10 7,618 22,500 0.34 (Thermal)

Unit 2, 2" Point Heaters Equation 8 N/A 4,614 15,000 0.31 A & 3, Emergency Drain (Sustained)

Cooler Bypass Piping Equation 10 NlA 10,696 22,500 0.48 (Thermal)

Unit 2, 3rd Point Heaters Equation 8 NIA 4,746 15,000 0.32 A & B, Emergency Drain (Sustained)

Outlet Piping Equation 10 NIA 10,085 22,500 0.45 (Thermal)

Unit 1, 4thPoint Heater A, Equation 8 NIA 10,558 15,000 0.71 Liquid Level Control (Sustained)

Connection Tree Equation 10 N/AIF-^^^ 22,500 0.53 (Thermal)

Page 8 of 14

Piping Analysis Loading Existing EPU Allowable Stress Description Condition Stress Stress Stress Interaction (psi) (psi) (psi) Ratio (Note 2) (Note 4) (Note 1 & 3)

Unit 1, 4thPoint Heater B, Equation 8 NIA 10,659 15,000 0.71 Liquid Level Control (Sustained)

Connection Tree Equation 10 N/A 13,610 22,500 0.60 (Thermal)

Unit 1, 5thPoint Heaters Equation 8 NIA 13,492 15,000 0.90 A & B, Level Tree Piping (Sustained)

Equation 10 NIA 6,371 22,500 0.28 (Thermal)

Unit 1, Feedwater Equation 8 NlA 6,609 16,275 0.41 Pump A, Recirculation (Sustained)

Piping Equation 9 NlA 8,519 29,295 0.29 (Occasional)

Equation II NIA 21,315 43,719 0.49 (Sustained +

Thermal)

Unit I,Feedwater Equation 8 NIA 7,052 16,275 0.43 Pump B, Recirculation (Sustained)

Piping Equation 9 N/A 8,491 29,295 0.29 (Occasional)

Equation 11 NIA 16,901 43,719 0.39 (Sustained +

Thermal)

Unit 1, Heater Drain Tank Equation 8 NIA 4,116 15,000 0.27 Pump Recirculation (Sustained)

Replacement Piping Equation 10 NlA 12,176 22,500 0.54 (Thermal)

Unit I,Heater Drain Tank Equation 8 NIA 6,364 15,000 0.42 Pump Discharge (Sustained)

Replacement Piping Equation10 N/A 13,185 22,500 0.59 (Thermal)

Unit 1, Heater Drain Tank Equation 8 NlA 5,224 15,000 0.35 Dump to Condenser (Sustained)

Piping Equation 10 NIA 6,841 22,500 0.30 (Thermal) 1 Page 9 of 14

Piping Analysis Loading Existing EPU Allowable Stress Description Condition Stress Stress Stress Interaction (psi) (psi) (psi) Ratio (Note 2) (Note 4) (Note 1 & 3)

Unit 1, lStPoint Heaters Equation 8 NIA 6,824 15,000 0.45 A & B lnlet and 3rdPoint (Sustained)

Heaters A & B Outlet Equation II N/A 27,465 37,500 0.73 Piping (Sustained +

Thermal)

Unit 1, lStPoint Heaters Equation 8 NIA 1,843 15,000 0.12 A & B Steam lnlet Piping (Sustained)

(Max. stress of all Parts Equation 10 NIA 4896 22,500 0.22 analysed) (Thermal)

Unit 1, lStPoint Heaters Equation 8 NIA 1,631 15,000 0.1 1 A & B Operating Air (Sustained)

Outlet Piping Equation 10 N/A 2,506 22,500 0.1 1 (Thermal)

Unit 1, 2ndPoint Heaters Equation 8 NIA 4,147 15,000 0.28 A & B Feedwater Outlet (Sustained)

Piping Equation 10 N/A 8,210 22,500 0.36 (Thermal)

Unit 1, 2ndPoint Heaters Equation 8 NIA 4,586 15,000 0.31 A & B Extraction Steam (Sustained)

Inlet Nozzle (Max. stress Equation 10 NIA 4,178 22,500 0.19 of Part 8 & Part 9) (Thermal)

Unit 1, 2ndPoint Heaters Equation 8 NIA 4,366 15,000 0.29 A & B Operating Air (Sustained)

Outlet Piping Equation 10 NIA 1,380 22,500 0.06 (Thermal)

Unit 1, 3rdPoint Heaters Equation 8 N/A 10,546 15,000 0.70 A & B, Steam lnlet Piping (Sustained)

Equation 10 NlA 7,693 22,500 0.34 (Thermal)

Unit 1, I Point Heaters Equation 8 NIA 1,507 15,000 0.10 A & B, Drain Outlet Piping (Sustained)

Equation 10 N/A 1,045 22,500 0.05 (Thermal)

Unit 1, 2" Point Heaters Equation 8 NIA 3,520 15,000 0.24 A & B, Drain Outlet Piping (Sustained)

Equation 10 NIA 4,338 22,500 0.19 (Thermal)

Page 10 of 14

Piping Analysis Loading Existing EPU Allowable Stress Description Condition Stress Stress Stress Interaction (psi) (psi) (psi) Ratio (Note 2) (Note 4) (Note 1 & 3)

Unit I, 3rd Point Heaters Equation 8 NIA 5,126 15,000 0.34 A & B, Drain Outlet Piping (Sustained)

Equation 10 N/A 1,998 22,500 0.09 (Thermal)

Unit 1, 1 Point Heaters Equation 8 NIA 6,449 15,000 0.43 A & B, Emergency Drain (Sustained)

Cooler Bypass Piping Equation 10 NIA 8,474 22,500 0.38 (Thermal)

Unit 1, 2ndPoint Heaters Equation 8 NIA 4,395 15,000 0.29 A & B, Emergency Drain (Sustained)

Cooler Bypass Piping Equation 10 NIA 11,116 22,500 0.49 (Thermal)

Unit 1, 3rd Point Heaters Equation 8 NIA 4,611 15,000 0.31 A & B, Emergency Drain (Sustained)

Outlet Piping Equation 10 NIA 9,635 22,500 0.43 (Thermal)

Unit I,Heater Relief Line Equation 8 NIA 1,995 15,000 0.13 Piping from Nozzle 6 of (Sustained) the 4th& 5thPoint Heaters Equation 9 NIA 6,000 10,000 0.33 to Atmospheric Blowoff (Occasional)

Tank .

Equation 1I 21,752 37,500 0.58 (Sustained +

Thermal)

Unit 1, Heater Drain Tank Equation 8 NIA 13,993 15,000 0.93 Level Tree Replacement (Sustained)

Piping Equation 10 NIA 10,065 22,500 0.45 (Thermal)

Unit 2, Generator Bus Equation 8 NlA 4,284 15,000 0.29 Cooler Replacement (Sustained)

Piping Equation 10 NIA 14,735 22,500 0.65 (Thermal)

Unit 1, Condensate Pump Equation 8 NIA 2,543 15,000 0.17 Motor Cooler (Sustained)

Replacement Piping Equation 10 NlA 21,673 22,500 0.96 (Supply & Return) (Thermal)

Page 11 of 14

Piping Analysis Loading Existing EPU Allowable Stress Description Condition Stress Stress Stress Interaction (psi) (psi) (psi) Ratio (Note 2) (Note 4) (Note 1 & 3)

Unit I,FW Heaters 1-3 Equation 8 NIA 12,775 15,000 0.85 Level Tree Replacement (Sustained)

Piping Equation 10 NlA 20,254 22,500 0.90 (Thermal)

Unit 1, Generator Bus Equation 8 NIA 6,295 15,000 0.42 Cooler Replacement (Sustained)

Piping Equation 10 NIA 18,183 22,500 0.81 (Thermal)

Unit 2, Condensate Pump Equation 8 NIA 2,777 15,000 0.19 Motor Cooler (Sustained)

Replacement Piping NIA Equation 10 12,110 22,500 0.54 (Supply & Return)

(Thermal)

Unit 2, FW Heaters 1-3 Equation 8 NIA 12,781 15,000 0.85 Level Tree Replacement (Sustained)

Piping Equation 10 NlA 20,253 22,500 0.90 (Thermal)

Unit 1, SGFP Seal Water Equation 8 NIA 10,270 15,000 0.68

& Lube Oil Cooling Water (Sustained)

Replacement Piping Equation 10 NIA 4,601 22,500 0.20 (Thermal)

Unit 1, Feedwater Pumps Equation 8 NIA 8,089 15,000 0.54 1P-28A & 1P-28B Warm- (Sustained)

Up Replacement Piping Equation 10 NIA 8,671 22,500 0.39 (Thermal)

Unit 2, Heater Drain Tank Equation 8 NIA 4,172 15,000 0.28 Pump Recirculation (Sustained)

Replacement Piping Equation 10 NIA 14,143 22,500 0.63 (Thermal)

Unit 2, Heater Drain Tank Equation 8 NIA 9,345 15,000 0.62 Pump discharge (Sustained)

Replacement Piping Equation 10 NIA 13,504 22,500 0.60 (Thermal)

Page 12 of 14

Piping Analysis Loading Existing EPU Allowable Stress Description Condition Stress Stress Stress Interaction (psi) (psi) (psi) Ratio (Note 2) (Note 4) (Note 1 & 3)

Unit 2, Heater Drain Tank Equation 8 NIA 4,330 15,000 0.29 Dump to Condenser (Sustained)

Piping Equation 10 NlA 6,596 22,500 0.29 (Thermal)

Unit 2, Qualification of Equation 8 NIA 5,599 18,700 0.30 MSR D Reheater Line 2"- (Sustained)

ED-2 Piping & Pipe supports for Vibration NAI Equation 16,644 26,375 0.63 associated with EPU (Thermal) conditions Unit 2, Heater Drain Tank Equation 8 NIA 12,629 15,000 0.84 Level Tree Replacement (Sustained)

Piping Equation 10 N/A 11,249 22,500 0.50 (Thermal)

Unit 2, Feedwater Equation 8 7,179 16,275 0.44 Pump A, Recirculation (Sustained)

Piping Equation 9 NlA 20,504 29,295 0.70 (Occasional)

Equation II NlA 36,496 43,719 0.83 (Sustained +

Thermal)

Unit 2, Feedwater Equation 8 NlA 6,425 16,275 0.39 Pump B, Recirculation (Sustained)

Piping Equation 9 NlA 14,295 29,295 0.49 (Occasional)

Equation II NlA 21,154 43,719 0.48 (Sustained +

Thermal)

Unit 2, Feedwater Pump Equation 8 NlA 7,826 15,000 0.52 Suction Replacement (Sustained)

Piping Equation 1I NlA 34,052 37,500 0.91 (Sustained +

Thermal)

Page 13 of 14

Piping Analysis Loading Existing EPU Allowable Stress Description Condition Stress Stress Stress Interaction (psi) (psi) (psi) Ratio (Note 2) (Note 4) (Note 1 8 3)

Unit 2, SGFP Seal Water Equation 8 NIA 10,073 15,000 0.67

& Lube Oil cooling Water (Sustained)

Replacement Piping Equation 10 NIA 7,767 22,500 0.35 (Thermal)

Unit 2, Feedwater Pumps Equation 8 NlA 10,555 15,000 0.70 2P-28A & 2p-28B Warm- (Sustained)

Up Replacement Piping Equation 10 NIA 13,577 22,500 0.60 (Thermal)

Unit 2, Feedwater Equation 8 NIA 3,876 6,000 0.65 Isolation Valve Air & (Sustained)

Nitrogen Supply Piping Equation 9B N/* 7,115 7,200 0.99 (Occasional)

Equation 9C N/A 9,950 10,800 0.92 (Occasional)

Equation II NIA I1,967 15,000 0.80 (Sustained +

Thermal)

NOTES:

( I ) The Design Margin is based on the ratio of EPU stress divided by the Allowable stress.

(2) The Equation Numbers shown correspond to ASME Section Ill, NCIND-3650 equation numbers.

(3) With respect to piping analyses containing stress interaction ratio greater than 0.90 for EPU conditions, it should be noted that the existing stress interaction ratio (for the same loading condition) for all these piping analyses, with the single exception of U l Main Steam Piping Inside Containment Loop A, are currently greater than 0.90. For example, the U2 Main Steam Piping Inside Containment Loop A, Equation 9C, has a reported stress interaction ratio of 0.95 based on the ratio of 29,984 (EPU stress) divided by 31,500 (allowable stress). The existing stress interaction ratio for this piping is 0.92 based on the ratio of 29,046 (current stress) divided by 31,500 (allowable stress). Hence, for this piping system, the actual stress increase resulting from EPU is insignificant. Additionally, all stress levels resulting in stress interaction ratio less than or equal to 1.0 are acceptable limits in accordance with USAS B31.Icode of record. The allowable stress levels for the USAS B31.Icode are stress levels that are well below material ultimate stress limits.

(4) Where information is not provided, the information was not available.

Page 14 of 14

ENCLOSURE 4 ATTACHMENT 2 NEXTERA ENERGY POINT BEACH, LLC POINT BEACH NUCLEAR PLANT, UNITS I AND 2 LICENSE AMENDMENT REQUEST 261 EXTENDED POWER UPRATE MAIN FEEDWATER PUMP NOZZLE LOAD

SUMMARY

5 pages follow

Table 7-8.1 Equipment: Pump I-P28A (Discharge)

Absolute Max. Thermal Cases I , 2, 4 Ref. 129187-P-0015 (Node 5)

Reactions in Local Coordinates (Ib, ft-lb)

Load Type Fx FY Fz Mx MY Mz Equipment: Pump I-P28A (Discharge)

Absolute Max. from All Thermal Cases Ref. 129187-P-0015 (Node 5)

Reactions in Local Coordinates (Ib, ft-lb)

Load Type Fx FY Fz Mx MY Mz Weight+Thermal+OCC-I 1851 2715 2151 2046 6937 9479 Weight-tTherrna1-1-OCC-2 1359 2537 1810 1826 5240 8494 MAX 1851 2715 2151 2046 6937 9479 Vendor Allowable 4040 4540 5476 27073 16844 11287 I.Ratio (TRANSIENT ONLY) 0.46 0.60 0.39 0.08 0.41 0.84 Page 1 of 5

• It should be noted that the Interaction ratio value of 0.7'9 for all loading directions is due to the fact that the calculated loads were increased by the same percentage (approximately 26%) due to the pump qualification performed by the vendor.

Page 2 of 5

Absolute Max. Thermal Case 7 Ref. 129187-P-0018 (Node 3180)

Reactions in Local Coordinates (Ib, ft-lb)

Load Type Fx FY Fz Mx MY Mz ABSdWeight + Thermal) 3223 365 I974 1450 4404 385 Vendor Allowable 4077 502 2497 1834 5571 574 I.Ratio (STATIC ONLY) 0.79 0.73 0.79 0.79 0.79 0.67 +

• It should be noted that the Interaction ratio value of 0.79 for all loading directions is due to the fact that the calculated loads were increased by the same percentage (approximately 26%) due to the pump qualification performed by the vendor.

Table 7-8.10, Note 1:

It should be noted that the maximum "weight + thermal" Fx load for Thermal Cases 3 and 5 is I307 Ibs, which is greater than the indicated Fx allowable of 806 Ibs.

However, the corresponding "weight + thermal" Case 3 and 5 Fy and Fz loads, and Mx, My and Mz moments are significantly less than the indicated allowables. Also, the My and Mz loads are the governing loads with respect to the static evaluations for determining coupling misalignment acceptability. As such, these two thermal Fx loading conditions (i.e., Thermal Cases 3 and 5) are acceptable.

Page 3 of 5

Page 4 of 5 Table 7-8.15 Equipment: Pump 2-P28B (Discharge)

Absolute Max. from Thermal Case 7 Ref. 129187-P-0018 (Node 3180)

Reactions in Local Coordinates (Ib, ft-lb)

Load Type Fx FY Fz Mx MY Mz Weight+Thermal+OCC-1 5087 1135 3350 5228 9357 1972 Weight+Thermal+OCC-2 5084 780 2936 4136 7965 1310 MAX 5087 1135 3350 5228 9357 1972 Vendor Allowable 6435 1436 4238 6614 11837 2494 I.Ratio (TRANSIENT ONLY) 0.79 0.79 0.79 0.79 0.79 0.791

• Table 7-8.16 Equipment: Pump 2-P28A (Suction)

I Absolute Max. of All Thermal Cases I Ref. 129187-P-0093 (Node 1270)

Reactions in Local Coordinates (Ib, ft-lb)

Load Type Fx FY Fz Mx MY Mz ABSw (Weight + Thermal) 278 145 1091 666 2817 2577 API Allowable 3800 3000 4600 10800 5400 8000

• It should be noted that the Interaction ratio value of 0.79 for all loading directions is due to the fact that the calculated loads were 'increased by the same percentage (approximately 26%) due to the pump qualification performed by the vendor.

Page 5 of 5

ENCLOSURE 4 ATTACHMENT 3 NEXTERA ENERGY POINT BEACH, LLC POINT BEACH NUCLEAR PLANT, UNITS 1 AND 2 LICENSE AMENDMENT REQUEST 261 EXTENDED POWER UPRATE STEAM GENERATOR MAIN STEAM NOZZLE LOAD

SUMMARY

1 page follows

Main Steam (Unit I)

Nozzle: (Steam Generator IHX-1A)

Description Forces (Kips) Moments (in-Kips)

Axial (Fa) Shear (Fv) Bending (Mb) Torsion (Mt)

Total Loads =(DW + - 46.2 143 7,090.2 9,124 SSE + TT + TH)

WNES Allowable 320 368 18,562 10,550 Nozzle: (Steam Generator 1HX-I B)

Description Forces (Kips) Moments (in-Kips)

Axial (Fa) Shear (Fv) Bending (Mb) Torsion (Mt)

Total Loads =(DW + 32.0 110.6 6,138.2 9,349.6 SSE + TT + TH)

WNES Allowable 320 368 18,562 10,550 Main Steam (Unit 2)

Nozzle: (Steam Generator 2HX-1A)

Description Forces (Kips) Moments (in-Kips)

Axial (Fa) Shear (Fv) Bending (Mb) Torsion (Mt)

Total Loads =(DW + 49.7 193.3 9,344.6 10,348.1 SSE + TT + TH)

WNES Allowable 320 368 18,562 10,550 Nozzle: (Steam Generator 2HX-I B)

Description Forces (Kips) Moments (in-Kips)

Axial (Fa) Shear (Fv) Bending (Mb) Torsion (Mt)

Total Loads =(DW + 30.6 96.4 5,153.2 11,515

• SSE + TT + TH)

WNES Allowable 320 368 18,562 11,515

• Notes:

DW = Dead Weight, SSE = Safe Shutdown Earthquake, TT = Turbine Trip, TH = Thermal.

WNES = Westinghouse Nuclear Energy Systems

• Total loads approved by vendor Page Iof I

ENCLOSURE 4 ATTACHMENT 4 NEXTERA ENERGY POINT BEACH, LLC POINT BEACH NUCLEAR PLANT, UNITS I AND 2 LICENSE AMENDMENT REQUEST 261 EXTENDED POWER UPRATE STEAM GENERATOR FEEDWATER NOZZLE LOAD

SUMMARY

Ipage follows

Feedwater (Unit I)

Nozzle: (Steam Generator 1HX-IA)

Description Forces (Lbs) Moments (ft-lbs)

Axial (Fa) Shear (Fv) Bending (Mb) Torsion (Mt)

Total Loads =(DW + 5,332 11,951 104,501 91,335 SSE + OCCU + TH)

WNES Allowable 220,000 353,624 648,181 312,500 Nozzle: (Steam Generator IHX-16) (All loads in Local coordinates)

Description Forces (Lbs) Moments (ft-lbs)

Axial (Fa) Shear (Fv) Bending (Mb) Torsion (Mt)

Total Loads =(DW + 10,173 16,733 116,467 104,664 SSE + OCCU + TH)

WNES Allowable 220,000 353,624 648,181 312,500 Feedwater (Unit 2)

Nozzle: (Steam Generator 2HX-1A)

Description Forces (Lbs) Moments (ft-lbs)

Axial (Fa) Shear (Fv) Bending (Mb) Torsion (Mt)

Total Loads =(DW + 9,043 12,914 149,057 98,698 SSE + OCCU + TH)

WNES Allowable 220,000 353,624 648,181 312,500 Nozzle: (Steam Generator 2HX-1 B)

Description Forces (Lbs) Moments (ft-lbs)

Axial (Fa) Shear (Fv) Bending (Mb) Torsion (Mt)

Total Loads =(DW + 6,327 12,178 Ill,369 55,246 SSE + OCCU + TH)

WNES Allowable 220,000 353,624 648,181 312,500 Notes:

DW = Dead Weight, SSE = Safe Shutdown Earthquake, OCCU = Occasional, TH = Thermal.

WNES = Westinghouse Nuclear Energy Systems Page 1 of 1

ENCLOSURE 4 ATTACHMENT 5 NEXTERA ENERGY POINT BEACH, LLC POINT BEACH NUCLEAR PLANT, UNITS I AND 2 LICENSE AMENDMENT REQUEST 261 EXTENDED POWER UPRATE CONTAINMENT PENETRATION MAIN STEAM LOAD

SUMMARY

1 page follows

Unit I Penetration: (P-I ) (EB-1-MS-69-A2)

Description Forces (Kips) Moments (ft-Kips)

Axial (Fa) Shear (Fv) Bending (Mb) Torsion (Mt)

Total Loads (Calculated) 73.727 93.723 626.712 302.066

• Allowable 353.0 353.0 975.0 302.066

• Penetration: (P-2) (EB-I -MS-65-Al )

• Total load qualified by stress evaluation Unit 2 Penetration: (P-I ) (EB-2-MS-69-A2)

Description Forces (Kips) Moments (ft-Kips)

Axial (Fa) Shear (Fv) Bending (Mb) Torsion (Mt)

Total Loads (Calculated) 100.568 109.166 806.713 317.425 *

' ~llowable 353.0 353.0 975.0 317.425

• Penetration: (P-2) (EB-2-MS-65-A1)

Description Forces (Kips) Moments (ft-Kips)

Axial (Fa) Shear (Fv) Bending (Mb) Torsion (Mt)

Total Loads (Calculated) 61.855 24.975 225.778 78.362 Allowable 353.0 353.0 975.0 136

• Total load qualified by stress evaluation Page 1 of 1

ENCLOSURE 4 ATTACHMENT 6 NEXTERA ENERGY POINT BEACH, LLC POINT BEACH NUCLEAR PLANT, UNITS i AND 2 LICENSE AMENDMENT REQUEST 261 EXTENDED POWER UPRATE CONTAINMENT PENETRATION FEEDWATER LOAD

SUMMARY

1 page follows

Unit 1 Penetration: (P-3)

Description Forces (Lbs) Moments (ft-lbs)

Axial (Fa) Shear (Fv) Bending (Mb) Torsion (Mt)

Total Loads (Calculated) 24,998 20,246 123,752 87,253 Allowable 192,000 185,000 870,000 1,125,000 Penetration: (P-4)

Description Forces (Lbs) Moments (ft-lbs)

Axial (Fa) Shear (Fv) Bending (Mb) Torsion (Mt)

Total Loads (Calculated) 25,723 24,572 114,540 26,999 Allowable 192,000 185,000 870,000 1,125,000 Unit 2 Penetration: (P-3)

Description Forces (Lbs) Moments (ft-lbs)

Axial (Fa) Shear (F;) Bending (Mb) Torsion (Mt)

Total Loads (Calculated)

P 20,208 18,858 121,188 125,824 Allowable 192,000 185,000 870,000 1,125,000 Penetration: (P-4)

Description Forces (Lbs) Moments (ft-lbs)

Axial (Fa) Shear (Fv) Bending (Mb) Torsion (Mt)

Total Loads (Calculated) 32,728 10,575 103,989 12,412 Allowable 192,000 185,000 870,000 I,125,000 Page 1 of 1

ENCLOSURE 4 ATTACHMENT 7 NEXTERA ENERGY POINT BEACH, LLC POINT BEACH NUCLEAR PLANT, UNITS I AND 2 LICENSE AMENDMENT REQUEST 261 EXTENDED POWER UPRATE

SUMMARY

OF UNIT I PIPE SUPPORTS REQUIRING MODIFICATION 5 pages follow

1 ITEM 1 SUPPORT I SYSTEM / PIPE I BUILDING / EPU LOAD 1 DESCRIPTION 1 TYPE Page 1 of 5

Page 2 of 5 Page 3 of 5 Page 4 of 5 ITEM SUPPORT SYSTEM PIPE BUILDING EPU LOAD DESCRIPTIONI TYPE SIZE LOCATION (Ibs) 154 HB-11-12 HD 6 T 800 Verify weld pattern & size 155 HB-11-13 HD 6 T 500 Verify weld pattern & size 156 HB-11-101 HD 6 T 2500 New lateral sway strut 157 HB-11-102 HD 6 T 500 New spring hanger System Description Buildina Location Description MS - Main Steam A -Auxiliary Bldg RN Feedwater -

C Containment Bldg EXTR ExtractionSteam -

F Fa~adeStructure COND Condensate -

T Turbine Bldg HD Heater Drains & Vents Page 5 of 5

ENCLOSURE 4 ATTACHMENT 8 NEXTERA ENERGY POINT BEACH, LLC POINT BEACH NUCLEAR PLANT, UNITS I AND 2 LICENSE AMENDMENT REQUEST 261 EXTENDED POWER UPRATE

SUMMARY

OF UNIT 2 PIPE SUPPORTS REQUIRING MODIFICATION 4 pages follow

ITEM SUPPORT SYSTEM PIPE BUILDING EPU LOAD DESCRIPTION I TYPE SIZE LOCATION (Ibs) 1 EB-1-MS-PHI MS 30 C 15760 Change Cold Setting 2 EB-1-MS-2H7 MS 30 C 8000 Change Cold Setting 3 EB-1-2HB MS 30 F 22884 Adjust to achieve gaps 4 EB-1-2HC MS 30 F 51928 Adjust to achieve gaps 5 EB-1-2H5 MS 30 A 26000 Replace Size 3 strut with Size 4 Strut

- 6 7

EB-1-2H6 EB-1-2H7 MS MS 30" 30" A

A 34852 19170

-Verify gaps and modify as required Verify gaps and modify as required 8 EB-1-2H9 MS 30" F 62000 Replace rod hanger with Size 7 Strut 9 EB-1-2H9A MS 30 F 50000 Replace rod hanger 10 EB-1-2H15 MS 30 A 65000 Verify and add welds, as required 11 EB-1-2H19 MS 30 F 32000 Add weld as indicated 12 EB-1-2H20 MS 30 F 62000 Replace rod hanger with Size 7 Strut 13 EB-1-2H20A MS 30 F 50000 Replace rod hanger 14 EB-1-R250 MS 30 A 24805 Verify gaps and modify as required 15 EB-?-I3251 MS 30 A 66066 Verify gaps and modify as required 16 EB-2-EA6 MS 24" T 6989 Verify gaps, modify as directed 17 EB-2-2H1 MS 24" T 7000 Reset spring to cold settings 18 EB-2-2H3 MS 24" T 26000 Add Size 4 strut and new welds 19 EB-2-2H4 MS 18" T 9147 Rotate and re-weld strut end bracket 20 EB-2-2H5 MS 16" T 6133 Verify strut end paddle not bound; rotate bracket if needed 21 EB-2-2Hll MS 6 T 2575 Modify elbow lug attachment 22 1 EB-2-2H13 -

MS 6 T 2400

-Modify elbow lug attachment T 18600 Replace existing strut with Size 4 Strut

- 23 24 EB-2-2H15 EB-2-2H17

- MS MS

-16 16 T

- 6977 Replacehanger with S E l S G t 25 EB-2-2H200 MS 16" T 8500 Remove shim, verify gap, & add weld 26 HB-12-2H5 MS 10 x 6 T 2654 Add weld to pipe lug 27 HB-12-2H7 MS 10x6" T 2698 Add weld to pipe lug 28 PSDF-01-001 Fw 16" T 8000 New axial & moment restraint 29 PS DF-01-002 Fw 16" T 11500 New spring hanger 30 PS DF-01-003 Fw 16" T 6000 New snubber 31 PS DF-01-004 Fw 16" T 6500 New spring hanger 32 PS DF-01-005 Fw 16 T 7500 New spring hanger 33 PS DF-01-006 Fw 16" T 8000 New axial & moment restraint 34 PS DF-01-007 Fw 16" T 8000 New spring hanger 35 PS DF-01-008 Fw 16 T 7000 New snubber 36 PS DB-01-2H8 Fw 20 T 15000 Replace 1 114" rod with 1 314" rod 37 PS DB-01-2H11 Fw 20 T 23000 Replace rod hanger 38 PS DB-01-2H12 Fw 20 T 16000 Replace pipe saddle & increase rod size 39 PS DB-01-2H17 Fw 16 T 12500 Increase rod size Page 1 of 4

ITEM SUPPORT SYSTEM PIPE BUILDING EPU LOAD DESCRIPTION I TYPE SIZE LOCATION (Ibs) 40 PS DB-01-DET3 FW 6 T 3500 Replace 2-way restraint 41 PS EB-09-2H1 FW 16 T 16000 Add hold-down frame & lubrite plate 42 PS EB-09-2H4 FW 6 T 3000 Add hold-down frame & lubrite plate 43 PS EB-09-2H6 FW 16 T 6000 Replace existing rod with Anvil Fig 211 Size IStrut 44 PS EB-09-H200 FW 16 F 10000 Add section of tube steel 45 PS EB-09-H201 FW 16" F 30000 Replace strut with larger size Anvil Fig 640 Size 5 46 PS EB-09-S922A FW 16" F 28000 Remove collars and install new trunnions 47 PS DB-01-HS-01U FW 6" T 4000 Add new snubber 48 GD-1-2H101 EXTR 12" T 1100 Relocate spring hanger & shorten rod 49 GD-1-2H102 EXTR 12" T 1500 Relocate spring hanger & shorten rod 50 DB-1-2H18 FW 16 T 7000 Replace trunnion type support 51 DB-1-2H19 FW 16 T 6500 Replace trunnion type support 52 GB-4-2H31 COND 14" T 8853 Replace trunnion type support 53 GB-4-2H32 COND 14" T 2406 Replace trunnion type support 54 HB-4-2H101 HD 6 T 1200 Relocate & replace spring support 55 HB-4-2H102 HD 6 T 1500 Relocate & replace spring support 56 GB-4-2H36 COND 12" T 4800 Shorten rod & replace elbow lug with trunnion 57 GB-4-2H37 COND 12" T 12460 Replace rod hanger 58 DB-1-2H9 FW 16 T 25000 Replace riser clamp with 2 trunnions 59 DB-?-PHI0 FW 16 T 15000 Replace riser clamp with 2 trunnions 60 GB-2-2H101 HD 10" T 631 Shorten rod 61 GB-2-2H102 HD 10" T 631 Shorten rod 62 GB-2-2H103 HD 12" T 1800 Relocate & replace rigid support with spring 63 GB-2-2H104 HD 12" T 1900 Relocate & replace rigid support with spring 64 GB-2-2H105 HD 8" T 1500 Shorten rod 65 HB-I I-2H31 HD 6 T 500 Relocate & replace spring support 66 HB-11-2H32 HD 6 T 1000 Replace rigid vertical support 67 HB-I I-2H33 HD 6" T 1000 ~ e p l z clamp e & shorten rod 68 HB-11-2H34 HD 6 T 1000 Replace clamp & shorten rod 69 HB-I I-2H35 HD 6 T 1000 Replace clamp & shorten rod 70 HB-11-2H36 HD 6 T 700 Relocate support; replace clamp & shorten rod 71 ~B-l-2H37 HD 6 T 1000 Replace rod hanger with strut 72 HB-11-2H38 HD 6 T 500 Replace rigid support with spring; replace clamp & shorten rod 73 HE-I I-2H39 HD 6 T 700 Replace clamp & shorten rod

- 74 75 HB-I I-2H40 HB-11-2H41 HD HD 6

6 T

T 1800 800 New axial restraint New spring hanger 76 GB-4-2H21 COND 12" T 5000 Relocate & replace spring hanger 77 GB-4-2H24 COND 12" T 5000 Relocate & replace spring hanger 78 GB-4-RH33 COND 16" T 4500 Relocate riser clamp & install longer rods Page 2 of 4

ITEM SUPPORT SYSTEM PIPE BUILDING EPU LOAD DESCRIPTION ITYPE SIZE LOCATION (Ibs) 79 GB-4-2H20A COND 12" T 3500 Replace rod hanger 80 W-2A-2H101 EXTR 20 T 3387 Relocate & replace trunnion type support 81 W-2B-2H101 EXTR 20 T 3387 Relocate & replace trunnion type support 82 W-4A-2H101 EXTR 20" T 3370 Relocate & replace trunnion type support 83 W-4B-2H101 EXTR 20 T 3370 Relocate & replace trunnion type support 84 W-7A-2H101 EXTR 18 T 27573 Relocate & replace trunnion type support 85 W-78-2H101 EXTR 18 T 27573 Relocate & replace trunnion type support 86 HB-6A5 HD 4" T 500 Replace rod hanger 87 HB-685 HD 4" T 500 Replace rod hanger 88 HB-6A6 HD 2 112" T 500 Replace rod hanger 89 HB-6B6 HD 2 112" T 500 Replace rod hanger 90 HB-6-2H1 HD 10 T 1800 Replace spring hanger 91 HB-6-2H2 HD 10" T 1800 Replace spring hanger 92 HB-6-2H3 HD 10 T 3232 Replace spring support 93 HB-6-2H4 HD 10" T 3232 Replace spring support 94 10-HF-6A2 HD 10 T 3200 Replace spring hanger 95 10-HF-6B2 HD 10" T 3200 Replace spring hanger T Replace spring hanger

_ _ _ _ _ _ _ _ _ _HD_

96 160-A _ _ _ _8 _ _ _ _ _ _ _ _ _1500 Replace spring hanger 97 160-B HD 8 T 1500 98 105-A HD 6" T 1000 Replace spring hanger 99 1054 HD 6 T 1000 Replace spring hanger 6 T 2500 Replace spring hanger

- 100

- HB-6A3

- - - HD T 2500 Replace spring hanger 101 HB-6B3 HD 6" 102 HB-6A4 HD 8 T 4000 Replace spring support 103 HB-6B4 HD 8 T 4000 Replace spring support 104 HB-5-2H7 HD 6 T 1000 Replace spring support 105 HB-5-2H8 HD 6 T 700 Replace spring support 106 HB-5-2H9 HD 6 T 1000 Replace spring support 107 HB-5-2H10 HD 6 T 700 Replace spring support 108 02-GF-3-11 HD 4" T 800 Replace trunnion support 109 02-GF-3-12 HD 4" T 1100 Replace trunnion support 110 02-GB-3-101 HD 3" T 475 Replace spring support 111 02-GF-3-103 HD 4" T 500 Replace rod hanger with spring hanger 112 02-GF-3-104 HD 3" T 450 New spring support 113 PS GB-3-2H3 HD 12" T 5300 Replace trunnion support 114 PS GB-03-2H101 HD 8 T 2700 New spring hanger 115 HB-18-2H3 HD 12 T 4500 Replace trunnion support with sway strut 116 PS DD-02-001 FW 8" T 2200 New sway strut 117 PS DD-02-002 FW 8 T 2200 New rod hanger Page 3 of 4

ITEM SUPPORT SYSTEM PIPE BUILDING EPU LOAD DESCRIPTION I TYPE SIZE LOCATION (Ibd 118 PS DD-02-003 Fw 8 T 3200 New rod hanger 119 PS DD-02-004 Fw 8 T 8400 New sway strut 120 PS DD-02-005 Fw 8 T 8000 New trunnion support 121 PS DD-02-006 Fw 8" T 2000 New spring hanger 122 PS OD-02-007 Fw 8 T 3663 New 4-way restraint 123 PS DD-02-008 FW 8 T 5500 New trunnion support 124 PS GB-04-2H47 COND 18 T 6000 Replace pipe clamp 125 PS GB-07-001 COND 18 T 4500 New rod hanger 126 PS GF-07-001 COND 18 T 5000 New rod hanger 127 PS GF-07-002 COND 18 T 4000 New spring hanger 128 PS GF-07-003 COND 18 T 4000 New sway strut 129 PS- GF-07-004 - COND - 1 8- T 4000 New spring hanger T 3000 New sway strut 130 PS GF-07-005 COND 18 Svstem Description Buildina Location Description MS Main Steam A - Auxiliary Bldg NV - Feedwater C - Containment Bldg EXTR Extraction Steam F - Fapde Structure COND Condensate T - Turbine Bldg HD - Heater Drains & Vents Page 4 of 4