ML092660617

Attachment 3 - Corrected Pages for WCAP-17092-NP (Non-Proprietary)

ML092660617
Person / Time
Site:	Surry
Issue date:	06/30/2009
From:	Westinghouse
To:	Office of Nuclear Reactor Regulation
References
09-455A WCAP-17092-NP, Rev 0
Download: ML092660617 (29)

Text

1-5 Attachment 3 Corrceted Pages for WCAP-17092-NP (Non-Proprietary)

June 2009 WCAP- 17092-NP WCAP-17092-NP June 2009 Revision 0

1-5 Prior calculations assumed that contact pressure from the tube would expand the tubesheet bore uniformly without considering the restoring forces from adjacent pressurized tubesheet bores. In the structural model, a tubesheet radius dependent stiffness effect is applied by modifying the representative collar thickness (see Section 6.2.4) of the tubesheet material surrounding a tube based on the position of the tube in the bundle. The basis for the radius dependent tubesheet stiffness effect is similar to the previously mentioned "beta factor" approach. The "beta factor" was a coefficient applied to reduce the crevice pressure to reflect the expected crevice pressure during normal operating conditions in some prior H*

calculations and is no longer used in the structural analysis of the tube-to-tubesheet joint. The current structural analysis consistently includes a radius dependent stiffness calculation described in detail in Section 6.2.4. The application of the radius dependent stiffness factor has only a small effect on the ultimate value of H* but rationalizes the sensitivity of H* to uncertainties throughout the tubesheet.

The contact pressure analysis methodology has not changed since 2007 (Reference 1-9). However, the inputs to the contact pressure analysis and how H* is calculated have changed in that period of time. The details describing the inputs to the contact pressure analysis are discussed in Section 6.0.

The calculation for H* includes the summation of axial pull out resistance due to local interactions between the tube bore and the tube. Although tube bending is a direct effect of tubesheet displacement, the calculation for H* conservatively ignores any additional pull out resistance due to tube bending within the tubesheet or Poisson expansion effects acting on the severed tube end. In previous submittals, the force resisting pull out acting on a length of a tube between any two elevations h, and h2 was defined in Equation (1-1):

F, = (h 2 - hl)FHE+ rd P Adh (1-1) where:

FHE = Resistance per length to pull out due to the installation hydraulic expansion, d = Expanded tube outer diameter, P = Contact pressure acting over the incremental length segment dh, and, I = Coefficient of friction between the tube and tubesheet, conservatively assumed to be 0.2 for the pull out analysis to determine H*.

The current H* analysis generally uses the following equation to determine the axial pull out resistance of a tube between any two elevations h, and h2: a,c,e K 1 Where the other parameters in Equation (1-2) are the same as in Equation (1-1) and (1-2)

]ac.e A detailed explanation of the WCAP- 17092-NP June 2009 Revision 0

1-6 revised axial pull out equation are included in Section 6.0 of this report. However, the reference basis for the H* analysis is the assumption that residual contact pressure contributes zero additional resistance to tube pull out. Therefore, the equation to calculate the pull out resistance in the H* analysis is:

h2 J,= ,w' rdPdh h, (1-3) 1.3.2 Leakage Integrity Analysis Prior submittals of the technical justification of H* (Reference 1-9) argued that K was a function of the contact pressure, P,, and, therefore, that resistance was a function of the location within the tubesheet.

The total resistance was found as the average value of the quantity ulK, the resistance per unit length, multiplied by L, or by integrating the incremental resistance, dR = /K dL over the length L, i.e.,

R=pK(L 2 - LI)=P= f KdL (1-4)

Interpretation of the results from multiple leak rate testing programs suggested that the logarithm of the loss coefficient was a linear function of the contact pressure, i.e.,

InK = ao +aPc, (1-5) where the coefficients, ao and a, of the linear relation were based on a regression analysis of the test data,;

both coefficients are greater than zero. Simply put, the loss coefficient was determined to be greater than zero at the point where the contact pressure is zero and it was determined that the loss coefficient increases with increasing contact pressure. Thus, (1-6) and the loss coefficient was an exponential function of the contact pressure.

The B* distance (LB) was defined as the depth at which the resistance to leak during SLB was the same as that during normal operating conditions (NOP) (using Equation 1-4, the B* distance was calculated setting RSLB = RNOp and solving for LB). Therefore, when calculating the ratio of the leak rate during the design basis accident condition to the leak rate during normal operating conditions, the change in magnitude of leakage was solely a function of the ratio of the pressure differential between the design basis accident and normal operating plant conditions.

The NRC Staff raised several concerns relative to the credibility of the existence of the loss coefficient versus contact pressure relationship used in support of the development of the B* criterion:

WCAP- 17092-NP June 2009 Revision 0

1-13 Table 1-1 List of Conservatisms in the H* Structural and Leakage Analysis (Continued)

Assumption/Approach Why Conservative?

A [ This is conservative because it reduces the stiffness of the solid and perforated regions of the tubesheet to the lowest level for each operating condition (see Section 6.2.2.2.2).

ac,e Pressure is not applied to the Applying pressure to the ace (see Section 6.2.2.2.4).

a~c,e The radius dependent stiffness Including these structures in the analysis would reduce the tubesheet displacement and limit the local deformation of the analysis ignores the presence of tubesheet hole ID (see Section 6.2.4.4).

the [

a~c,e The tubesheet bore dilation [ Thermal expansions under operating loads were

]ace (see Section 6.2.5).

a2c,e 2250 (NOP conditions).

WCAP-17092-NP June 2009 Revision 0

5-3 5.3 CALCULATION OF APPLIED END CAP LOADS The tube pull out loads' (also called end cap loads) to be resisted during normal operating (NOP) and faulted conditions for Surry Units 1 and 2 for the hot leg are shown below. End cap load is calculated by multiplying the required factor of safety times the cross-sectional area of the tubesheet bore hole times the primary side to secondary side pressure difference across the tube for each plant condition.

AP (psi) Area Load Factor of H* Design End Operating Condition (Ppri-Psec) (See Note 1) (lbs.) Safety Cap Load (lbs.)

Normal Op. (maximum) ac,e Faulted (SLB)

(See Note 2)

Faulted (Locked Rotor)

(See Note 2)

Faulted (Control Rod Ejection) (See Note 2)

Notes:

1. Tubesheet Bore Cross-Sectional Area = [ ac,e

2. The source of the pressure differentials is Reference 9-21 The above calculation of end cap loads is consistent with the calculations of end cap loads in prior H*

justifications and in accordance with the applicable industry guidelines (Reference 5-3). This approach results in conservatively high end cap loads to be resisted during NOP and faulted conditions because a cross-sectional area larger than that defined by the tubesheet bore mean diameter is assumed.

The end cap loads noted above include a safety factor of 3 applied to the normal operating end cap load and a safety factor of 1.4 applied to the faulted condition end cap loads to meet the associated structural performance criteria consistent with NEI 97-06, Rev. 2 (Reference 5-3).

Seismic loads have also been considered, but they are not significant in the tube joint region of the tubes (Reference 5-1 ).

H* values are not calculated for the locked rotor and control rod ejection transients because the pressure differential across the tubesheet is bounded by the SLB transient for the 3-loop Model 51F plant. In support of the leakage analysis provided in Section 9.0, the parameters included in Tables 5-1 through 5-5 are used to compare contact pressures during normal operating plant conditions and all design basis accident conditions for all radial locations throughout the thickness of the tubesheet.

The values for end cap loads in this subsection of the report are calculated using an outside diameter of the tube equal to the mean diameter of the tubesheet bore plus 2 standard deviations.

WCAP- 17092-NP June 2009 Revision 0

5-5 Table 5-1 Operating Conditions - Model 51F Plants Parameter and Units Surry Units 1 and 2(1)

Power - NSSS MWt 2609 Primary Pressure psia 2250 Secondary Pressure psia F- a_,e Reactor Vessel Outlet 'F (Low Tavg/

Temperature High Tavg)

SG Primary-to-Secondary psid (Low Tavg/

'Pressure Differential (psid) High Tavg)

(1) PCWG-2662, Rev. 1, "Surry Units 1 & 2 (VPA/VIR): Revision to Category IIIP (for Limited Scope Contract) Approval of PCWG parameters to Support a 2% Uprate Program Incorporating a Tav, Coastdown," November 7, 2001.

WCAP- 17092-NP June 2009 Revision 0

5-6 Table 5-2 Steam Line Break Conditions Parameters and Units Surry Units 1 and 2 Primary-Secondary Pressure (psia) a,c,e Primary Fluid Temperature ('F) (HL and CL)

Secondary Fluid Temperature (°F) (HL and CL)

WCAP-17092-NP June 2009 Revision 0

5-7 Table 5-3 Locked Rotor Event Conditions Parameters and Units Surry Units 1 and 2 Peak Primary-Secondary Pressure (psi) a....

Primary Fluid Temperature (OF)* (HL/CL)

Secondary Fluid Temperature (OF)* (HL/CL)

Primary Fluid Temperature (OF)** (HL/CL)

Secondary Fluid Temperature (OF)** (HL/CL)

• Low Tavg

• • High Tavg HL - Hot Leg CL - Cold Leg NA - Not Applicable WCAP-17092-NP June 20090 Revision

5-8 Table 5-4 Control Rod Ejection Event Conditions Parameters and Units Surry Units I and 2 Peak Primary-Secondary Pressure (psi) -c,e Primary Fluid Temperature (F)* (HL/CL)

Secondary Fluid Temperature (OF)* (HL/CL)

Primary Fluid Temperature (OF)** (HL/CL)

Secondary Fluid Temperature (OF)** (HL/CL)

• Low Tavg

• • High Tavg HL - Hot Leg CL - Cold Leg NA - Not Applicable WCAP- 17092-NP June 2009 Revision 0

5-9 Table 5-5 H* Design End Cap Loads for Normal Operating Plant Conditions, Locked Rotor and Control Rod Ejection for Model 51F Plants Low Tavg High Tavg Control Rod Ejection Plant End Cap Load End Cap Load Locked Rotor End Cap Load w/Safety Factor w/Safety Factor End Cap Load (lbf)

(lbf) (Ibf) (lbf Surry Units I & 2 Ic_ aLIe WCAP- 17092-NP June 2009 Revision 0

6-10 Therefore, hnomjnai = [ I"" inch (i.e., [ ]Ice inch and 1 = [ ]c'e when the tubes are not included. From Slot (Reference 6-5) the in-plane mechanical properties for Poisson's ratio of 0.3 are:

Property Value E -p a~c,e V =

E * / Ey G*"/Gy y y =

Elastic modulus of solid material where the subscripts P, d and y refer to the pitch, diagonal and thickness directions, respectively. These values are substituted into the expressions for the anisotropic elasticity coefficients given previously. The coordinate system used in the analysis and derivation of the tubesheet equations is given in Reference 6-4.

Using the equivalent property ratios calculated above in the equations presented at the beginning of this section yields the elasticity coefficients for the equivalent solid plate in the perforated region of the tubesheet for the finite element model.

The three-dimensional structural model is used in two different analyses: 1) a static structural analysis with applied pressure loads at a uniform temperature and 2) a steady-state thermal analysis with applied surface loads. The solid model and mesh is the same in the structural and thermal analyses but the element types are changed to accommodate the required degrees of freedom (e.g., displacement -for structural, temperature for thermal) fcr each analysis. The tubesheet displacements for the perforated region of the tubesheet in each analysis are recorded for further use in post-processing. Figure 6-2 is screen shots of the three-dimensional solid model of the Model 5IF SG. Figure 6-3 shows the entire 3D model mesh.

WCAP- 17092-NP June 2009 Revision 0

6-18 a,c,e K

with the elasticity coefficients calculated as:

I a,c,e I I a,c,e LI J a,c,e a,c,e a,c,e I Zand I j* a,c,e where I and I ] a,c,e The variables in the equation are:

Ep = Effective elastic modulus for in-plane loading in the pitch direction,

= Effective elastic modulus for loading in the thickness direction, vp = Effective Poisson's ratio for in-plane loading in the thickness direction, Up = Effective shear modulus for in-plane loading in the pitchdirection,

= Effective shear modulus for transverse shear loading, Eda = Effective shear modulus for in-plane loading in the diagonal direction, V*d = Effective Poisson's ratio for in-plane loading in the diagonal direction, and, v = Poisson's ratio for the solid material, E = Elastic modulus of solid material, yRz = Transverse shear strain rz = Transverse shear stress,

[D] = Elasticity coefficient matrix required to define the anisotropy of the material.

WCAP- 17092-NP June 2009 Revision 0

6-21 Table 6-6 Summary of H* Surry Unit 1 Analysis Mean Input Properties Plant Name Surry 1 Plant Alpha VPA Plant Analysis Type Hot Leg SG Type 51F Input . Value Uit' Reference Accident and Normal Temperature Inputs NOP Thot ace ' F PCWG-07-49 NOP T10, .. , F:F PCWG-07-49 SLB TS AT _..F_ . F See Reference 9-12 SLB CH AT .F OF___ See Reference 9-12 Shell DT .F OF_.__ See Reference 9-12 SLB Primary AT "F.

OF.__ See Reference 9-12 SLB Secondary AT . _ . OF.. See Reference 9-12 Secondary Shell AT Hi .F OF___ PCWG-07-49 Secondary Shell AT Low 7 F OF_ PCWG-07-49 Cold Leg AT .F OF_ PCWG-07-49 Hot Standby Temperature .1 PCWG-07-49 Operating Pressure Input Faulted SLB Primary Pressure asc-.:e si See Reference 9-12 Normal Primary Pressure 2235.0 psig Other Cold Leg AP psg9 PCWG-07-49 Low Secondary Pressure -

NOP L

_______*i*]*:::,  : ______ ig

___lpsg___i PCWG-07-49 PCWG-07-49__________

NOP Secondary Pressure - Hi .. !.[______ psig PCWG-07-49 L

Faulted Faul SLB Le Secondary...,

condary " 'I . : ,] :psig:.: See Reference 9-12 Pressure-June 2009 17092-NP WCAP- 17092-NP June 2009 Revision 0

6-22 Table 6-7 List of SG Models and H* Plants With Tubesheet Support Ring Structures TS Support General Plant Alpha SG Model Ring? Arrangement B a,c,e Drawing Braidwood - 2 CDE D5 ] 1103 J99 Sub 3 Byron - 2 CBE D5 1103J99 Sub 3 SAP - Use Callaway (SCP)

Wolf Creek - 2 SG Drawings F 1104J54 Sub 2 PSE - Use Seabrook -2 (NCH) SG Salem - 1 Drawings F 11 04J86 Sub 9 Surry - 1 VPA*** 51F 1105J29 Sub 3 Surry - 2 VIR*** 51F 1105J29 Sub 3 Turkey Point- 4 FLA** 44F 1105J45 Sub 3 Millstone - 3 NEU F 11 82J08 Sub 8 Comanche Peak - 2 TCX D5 1182J16 Sub' 1 Vandellos - 2 EAS F 11 82J34 Sub I Seabrook - 1 NAH F 1182J39 Sub 3 Turkey Point- 3 FPL** 44F 1183J01 Sub 2 Catawba - 2 DDP D5 1183J88 Sub 2 Vogtle - 1 GAE F 1184J31 Sub 13 Vogtle - 2 GBE F 1 184J32 Subl Point Beach - 1 WEP** 44F 1184J32 Sub 1 Robinson - 2 CPL** 44F 6129E52 Sub 3 Indian Point - 2 IPG 44F 6136E16 Sub 2

• • Model 44 F - These original SGs have been replaced.

• • • Model 51F- These original SGs have been replaced.

June 2009 WCAP- 17092-NP WCAP-17092-NP June 2009 Revision 0

6-29 Table 6-8 Conservative Generic NOP Pressures and Temperatures for 4-Loop Model F (These values do not exist in operating SG and are produced by examining worst-case comparisons.)

Normal Operating, Bounding Secondary Surface Temperature t c,e Primary Surface Temperature Cold Leg Hot Leg Primary Pressure Cold Leg Hot Leg Secondary Pressure End Cap Pressure Structural Thermal Condition_

Reference Temperature Table 6-9 Generic NOP Low T.vg Pressures and Temperatures for 4-Loop Model F Normal Operating, Low Tave ____

Secondary Surface Temperature Fce Primary Surface Temperature Cold Leg Hot Leg Primary Pressure Cold Leg Hot Leg Secondary Pressure End Cap Pressure Structural Thermal Condition Reference Temperature Table 6-10 Generic NOP High T.v, Pressures and Temperatures for 4-Loop Model F Normal Operating, High Tavg Secondary Surface Temperature -

Primary Surface Temperature Cold Leg Hot Leg Primary Pressure Cold Leg Hot Leg Secondary Pressure End Cap Pressure Structural Thermal Condition Reference Temperature L WCAP- 17092-NP June 2009 Revision 0

6-30 Table 6-11 Generic SLB Pressures and Temperatures for 4-Loop Model F Main Steam Line Break ace Secondary Surface Temperature Primary Surface Temperature Cold Leg Hot Leg Primary Pressure Cold Leg Hot Leg Secondary Pressure End Cap Pressure Structural Thermal Condition Reference Temperature Table 6-12 Generic FLB Pressures and Temperatures for 4-Loop Model F Feedwater Line Break Secondary Surface Temperature Primary Surface Temperature Cold Leg Hot Leg Primary Pressure Cold Leg Hot Leg Secondary Pressure End Cap Pressure Structural Thermal Condition Reference Temperature Table 6-13 Conservative Generic SLB Pressures and Temperatures for 4-Loop Model F (These values do not exist in operating SG and are produced by examining worst-case comparisons.)

Main Steam Line Break, High Temp Secondary Surface Temperature Face Primary Surface Temperature Cold Leg Hot Leg Primary Pressure Cold Leg Hot Leg Secondary Pressure End Cap Pressure Structural Thermal Condition Reference Temperature WCAP- 17092-NP June 2009 Revision 0

9-22 Table 9-1 Reactor Coolant System Temperature Increase Above Normal Operating Temperature Associated With Design Basis Accidents (References 9-12 and 9-13)

Steam Line/Feedwater Locked Rotor Locked Rotor Control Rod Ejection (Dead Loop) (Active Loop)

SG Type Line Break SG Hot SG Cold SG Hot SG Cold SG Hot SG Cold SG Hot Leg ('F) Leg (OF) Leg (OF) Leg (OF) Leg (OF) Leg (OF) Leg (OF)

Model F -- c,e Model D5 Model 44F Model 51F

• Best estimate values for temperature during FLB/SLB are used as discussed in Section 9.2.3.1.

WCAP- 17092-NP June 2009 Revision 0

9-23 Table 9-2 Reactor Coolant Systems Peak Pressures During Design Basis Accidents (References 9-12 and 9-13)

Steam Line Feedwater Line Locked Rotor Control Rod Ejection SG Type Break (psia) Break (psia) (psia) (psia)

Model D5 ac,e Model F Model 44F Model 51F WCAP- 17092-NP June 2009 Revision 0

9-24 Table 9-3 Model F Room Temperature Leak Rate Test Data Test No. EP-331080 EP-30860 I EP-30860 EP-29799 I EP-3 1330 EP-31320 EP-3 1300 Collar Bore E *~

Dia. (in.)

Test Pressure Leak Rate (drops per minute - dpm)

Differential (psi)

-__ac,_

1000 1910 2650 3110 AP Ratio Leak Rate Ratio (normalized to initial AP) Average LR Ratio

-- a,c,e 1

1.91 2.65 3.11 WCAP-17092-NP June 2009 Revision 0

WESTINGHOUSE PROPRIETARY CLASS 2 9-25 9-25 Table 9-4 Model F Elevated Temperature Leak Rate Test Data C F I

0> CD cý C C 00 00 ICD 0 C

0) 10 C> 00 C) 00 oý 0> N ¢N 00 Cxl Test No. cq Cl Collar Bore Dia. (in.) L a,c,e Test Pressure Differential (psi) Leak Rate (drops per minute -dpm) a,c,e 1910 2650 3110 AP Ratio Leak Rate Ratio (normalized to initial AP) Average LR Ratio ac,e 1.39 1.63 WCAP- 17092-NP June 2009 Revision 0

9-26 WESTINGHOUSE PROPRIETARY CLASS 2 9-26 WESTINGHOUSE PROPRIETARY CLASS 2 Table 9-5 H* Plants Operating Conditions Summary (1)

Pressure Pressure Differential Differential Across Number Temperature Temperature Temperature Temperature Across the the Tubesheet Plant Name SG Type of Hot Leg (F) Cold Leg (F) Hot Leg (F) Cold Leg (F) Tubesheet (psi)

Loops High Tavg High Tavg Low Tavg Low Tavg (psi) Low Tavg High Tavg a,c,e Byron Unit 2 and D5 4 Braidwood Unit 2 Salem Unit 1 F 4 Robinson Unit 2 44F 3 Vogtle Unit 1 and 2 F 4 Millstone Unit 3 F 4 Catawba Unit 2 D5 4 Comanche Peak Unit 2 Vandellos Unit 2 F 3 Seabrook Unit 1 F 4 Turkey Point Units 44F 3 3 and 4 Wolf Creek F 4 Surry Units 1 and 2 51F 3 Indian Point Unit 2 44F 4 Point Beach Unit 1 44F 2 (1) The source of all temperatures and pressure differentials is Ref~ience 9-21.

WCAP-1 7092-NP June 2009 Revision 0

WESTINGHOUSE PROPRIETARY CLASS 2 9-27 2

Table 9-6 H* Plant Maximum Pressure Differentials During Transients that Model Primary-to-Secondary Leakage Plant Name FLB 3/SLB Pressure Locked Rotor Pressure Control Rod Ejection Normal Operating Pressure Differential (psi) Differential (psi) Pressure Differential (psi) Differential High Tavg (psi) a,ce Byron Unit 2 and Braidwood Unit 2 Salem Unit 1 Robinson Unit 2 Vogtle Unit 1 and 2 Millstone Unit 3 Catawba Unit 2 Comanche Peak Unit 2 Vandellos Unit 2 Seabrook Unit I Turkey Point Units 3 and 4 Wolf Creek Surry Units I and 2 Indian Point Unit 2 Point Beach Unit 1 2 The source of all pressure differentials is Reference 9-21 3 FLB is not part of the licensing basis for plants with Model 44F/51F steam generators WCAP-17092-NP June 2009 Revision 0

WESTINGHOUSE PROPRIETARY CLASS 2 9-27 Table 9-7 Final H* Leakage Analysis Leak Rate Factors Control Rod Ejection Transient FLB-SLB/FLB 3

4 LRNOP VRate iSLBIFL Locked Rotor Leak Adjusted CRE/NOP VR3 Leak Rate Adjusted CRE LRF' Plant Name SLBNOP w @ Leak Rate @ Factor AP Ratio 3030 Factor SL/NP R7 eAP Ratio 2672 ppsia Lk R Factor(LRF) AP Ratio A2711 psia LR LRFI (High T vJ) 2 (LRF) psia (LRF)

Byron Unit 2 and 1.93 Braidwood Unit 2 Salem Unit 1 1.79 Robinson Unit 2 1.82 Vogtle Unit 1 and 2 2.02 Millstone Unit 3 2.02 Catawba Unit 2 1.75 Comanche Peak 1.94 Unit 2 Vandellos Unit 2 1.97 Seabrook Unit 1 2.02 Turkey Point Units 3 1.82 and 4 Wolf Creek 2.03 Surry Units 1 and 2 1.80 Indian Point Unit 2 1.75 Point Beach Unit 1 1.73

5. Includes time integration leak rate adjustment discussed in Section 9.5.

6. The larger of the AP's for SLB or FLB is used.

7. VR- Viscosity Ratio

8. FLB is not part of the licensing basis for plants with Model 51F SGs WCAP-17092-NP June 2009 Revision 0

Serial No. 09-455A Docket Nos. 50-280/50-281 ATTACHMENT 6 List of Regulatory Commitments VIRGINIA ELECTRIC AND POWER COMPANY (DOMINION)

SURRY POWER STATION UNITS 1 AND 2

Serial No. 09-455A Docket Nos. 50-280/50-281 Attachment 6 Page 2 of 2 LIST OF REGULATORY COMMITMENTS The following table identifies those actions committed by Dominion for Surry Power Station Units 1 and 2 with respect to the permanent alternate repair criteria for steam generator tube repair. These commitments supersede those in our July 28, 2009 license amendment request letter (Serial No.09-455).

Modifications to the commitments in the July 28, 2009 letter are identified in bold type.

Commitment Due Date/Event Dominion commits to monitor for tube slippage as part of the Starting with Unit 2 SG tube inspection program for Unit 1 and Unit 2. Refueling Outage 22 and during subsequent Unit 1 and Unit 2 SG inspections Dominion commits to perform a one-time verification of the Prior to the startup tube expansion to locate any significant deviations in the following Unit 2 distance from the top of tubesheet to the beginning of Refueling Outage 22 expansion transition. If any significant deviations are found, the and Unit 1 Refueling condition will be entered into the plants corrective action Outage 23 program and dispositioned. Additionally, Dominion commits to notify the NRC of significant deviations.

Dominion commits to plug eleven Unit 2 tubes that have been During the Unit 2 identified as not being expanded within the tubesheet in either Refueling Outage 22 the hot leg or cold leg.

Dominion commits to plug three Unit I tubes that have been During the Unit 1 identified as not being expanded within the tubesheet in either Refueling Outage 23 the hot leg or cold leg.

Dominion commits to the following: For the Condition For every operating Monitoring assessment, the component of operational cycle following leakage from the prior cycle from below the H* distance Unit 2 Refueling will be multiplied by a factor of 2.03 and added to the total Outage 22 and accident leakage from any other source and compared to Unit 1 Refueling the allowable accident induced leakage limit. For the Outage 23 Operational Assessment, the difference between the allowable accident induced leakage and the accident induced leakage from sources other than the tubesheet expansion region will be divided by 2.03 and compared to the observed operational leakage. An administrative operational leakage limit will be established to not exceed the calculated value.

ATTACHMENT 7 Westinghouse Electric Company LLC LTR-SGMP-09-108 Errata, "Errata: Responses to NRC Request for Additional Information on H*;

Model 44F and Model 51F Steam Generators" VIRGINIA ELECTRIC AND POWER COMPANY (DOMINION)

SURRY POWER STATION UNITS 1 AND 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3

• Westinghouse To: G. M. Turley D. H. Warren Date: September 8, 2009 D. C. Beddingfield D.L. Rogosky cc: D.A. Testa B. W. Woodman C. D. Cassino J. T. Kandra From: Steam Generator Management Your ref:

Ext: 724-722-5082 Our ref: LTR-SGMP-09-108 Errata Fax: 724-722-5889

Subject:

Errata: Responses to NRC Request for Additional Information on H*; Model 44F and Model 51F Steam Generators

Reference:

1. LTR-SGMP-09-108, "Responses to NRC Request for Additional Information, on H*; Model 44F and Model 51 F Steam Generators," Westinghouse Electric Company LLC, August 28, 2009 Reference 1 provided responses to NRC RAIs on the LAR submittals for the alternate repair criterion, H*, for the plants with Model 44F and Model 51 F steam generators. On page 49 of both attachments to Reference 1, LTR-SGMP-09-108 P-Attachment (proprietary) and LTR-SGMP-09-108 NP-Attachment (non-proprietary), the following correction should be made:

The header "RAI#20 References" should be "RAI#1 8 References" Please transmit this information to the affected H* program participants.

Author: Verified:

HOL* GWW* -

Hermann Lagally G.W. Whiteman Fellow Engineer Principal Engineer Steam Generator Management Programs Regulatory Compliance and Plant Licensing 1

• Electronicallyapproved records are authenticatedin the ElectronicDocument Management System

ATTACHMENT 8 Westinghouse Electric Company LLC LTR-SGMP-09-122 Errata, "Errata: "WCAP 17092-P, Rev. 0 Proprietary Information Clarification" VIRGINIA ELECTRIC AND POWER COMPANY (DOMINION)

SURRY POWER STATION UNITS 1 AND 2

Westinghouse Non-Proprietary Class 3

( Westinghouse To: D.L. Rogosky Date: September 9, 2009 cc: D.A. Testa H.O. Lagally From: Steam Generator Management Programs Ext: 724-722-5584 Our ref: LTR-SGMP-09-122 Errata Fax: 412-374-3846

Subject:

Errata: WCAP-17092-P, Rev. 0 Proprietary Information Clarification

Reference:

1. LTR-SGMP-09-122, "WCAP-17092-P, Rev. 0 Proprietary Information Clarification,"

Westinghouse Electric Company LLC, August 28, 2009.

Reference 1 provided clarification on how certain information has been marked as Westinghouse proprietary information within WCAP-17092-P, "H*: Alternate Repair Criteria for the Tubesheet Expansion Region in Steam Generators with Hydraulically Expanded Tubes (Model 511F4." The following corrections should be made to the pages included within Attachment 3 of this correspondence:

1. The page number 1-5 should be removed in the header on the page titled "Attachment 3." The title of this same page should also be corrected to read "Corrected Pages for WCAP-17092-NP (Non-Proprietary)."

2. Westinghouse Proprietary Class 2 should be removed from the heading on Pages 9-25, 9-26, 9-27 (Table 9-6 H* Plant Maximum Pressure Differentials During Transients that Model Primary-to-Secondary Leakage).

3. The page number for Table 9-7 Final H* Leakage Analysis Leak Rate Factors should be changed from 9-27 to 9-28. Also, Westinghouse Proprietary Class 2 should be removed from the heading of this page.

Please transmit this information to Dominion Virginia.

Author: Verified:

GWW* CLH*

Gary Whiteman Cheryl Hammer Regulatory Compliance and Plant Licensing Steam Generator Design and Analysis

• Electronically approved records are authenticated in the electronic document management system